puerto rico electric power authority...agreement. the report is based on the consulting engineer’s...

FORTIETH ANNUAL REPORT ON THE ELECTRIC PROPERTY

of the

PUERTO RICO ELECTRIC POWER AUTHORITYSAN JUAN, PUERTO RICO

UNDER TERMS OF TRUST AGREEMENT

Dated as of January 1, 1974, as amended,

to

U.S. BANK TRUST NATIONAL ASSOCIATION

TRUSTEE

JUNE 2013

No. CEPR-AP-2015-0001

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No. CEPR-AP-2015-0001

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URS Corporation

One Canal Park

Cambridge, MA 02141

Tel: 617.621.0740

Fax: 617.621.9739

No. CEPR-AP-2015-0001

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No. CEPR-AP-2015-0001

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FORTIETH ANNUAL REPORTON THE ELECTRIC PROPERTY

of the

PUERTO RICO ELECTRIC POWER AUTHORITYSAN JUAN, PUERTO RICO

UNDER TERMS OF TRUST AGREEMENT

Dated as of January 1, 1974, as amended,

to

U.S. BANK TRUST NATIONAL ASSOCIATION

TRUSTEE

JUNE 2013

No. CEPR-AP-2015-0001

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No. CEPR-AP-2015-0001

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EXECUTIVE SUMMARYThis report is the 40th Annual Report by the Consulting Engineers in compliance with the 1974 TrustAgreement. The report is based on the Consulting Engineer’s inspections, interviews and review of relevantdata pertaining to the operation of the Puerto Rico Electric Power Authority electric System during the fiscalyear 2013, ending June 30, 2013.

The Authority’s reported total energy sales in fiscal year 2013 were 0.6% more than the previous year, but still7.0% less than in fiscal year 2008. During the past fiscal year energy sales increased in the residential and com-mercial sectors and declined in industrial. The decline in the industrial sector was its seventh consecutive yearand reflected the continuing impact of the recession in Puerto Rico. The Authority’s Current Forecast for fis-cal years 2014 through 2018 predicts a 1.3% growth in total energy sales for fiscal year 2014, with an averageannual growth rate of 1.2% in fiscal years 2014 through 2018. The DOE Energy Information Agency forecaststhe energy sales growth rate for mainland utilities during the same period will be 1.1%. Consistent with theinterim-period forecast, the predicted slow growth of peak demand indicates the historic peak set in fiscal year2006 will not be reached during the forecast period.

In fiscal year 2013 the Authority’s electric sales revenues fell by 4.2% over the previous year as a result of thetotal cost of fuel declining 10.3% and purchased power increasing by 10.5% from the previous year. In fiscalyear 2013 the Authority’s net generation declined by 5.4%, while its average cost of fuel per equivalent barreldropped 6.1%, aided by the lower cost of the natural gas burned at its Costa Sur plant. The total cost of fuelis forecasted to decline 17.6% in fiscal year 2014 from 2013, with purchased power costs increasing 6.6%.Total electric sales revenues, including theft recoveries, are projected to decline by 7.4% from fiscal year 2013to 2014.

Net revenues, as defined by the 1974 Agreement, in fiscal year 2013 increased by 13.8% over the previous yearas total current expenses fell by 6.6%, while total revenues were down 4.0%. The Authority forecasts its totalrevenues will decline by 6.8% in fiscal year 2014 from the results of fiscal year 2013; total revenues throughfiscal year 2018 are projected to remain little changed from the fiscal year 2014 level. During the five-year fore-cast period through fiscal year 2018, the Authority projects its current expenses will also remain relatively sta-ble as lower costs of fuel are offset by increased costs of purchased power. The resulting net revenues areforecasted to increase by 9.5% in fiscal year 2014 over 2013. In fiscal years 2015 through 2018 the net rev-enues are projected to increase 3.6%, drop 0.1%, and then increase 2.2% and 1.0%, respectively.

With the forecasted net revenues and the projected annual debt service through fiscal year 2018 in theAuthority’s budget used for this report, the projected debt service ratio based on the 1974 Agreement debt willrange from 1.34 to 1.42 in the five fiscal years ending 2018. The budgeted financings may incur higher inter-est rates than forecasted and the ability to capitalize interest may be constrained as well. Both of these wouldincrease the Authority’s projected principal and interest requirements in the intermediate term, thereby low-ering the forecasted debt service coverage ratio.

The largest operational issue facing the Authority is complying with the EPA hazardous air pollutant regula-tions by 2015. The Authority’s plan to dramatically switch from fuel oil to natural gas was endorsed by theisland’s major stakeholders in a Commonwealth government convened public/private sector committee dur-ing fiscal year 2012. The committee identified alternative plans, but did not recommend a specific method forimplementing the large increase in natural gas supply for the island. In the face of strong local opposition,projected cost escalations and regulatory uncertainty, during fiscal year 2012 the Authority stopped work onthe proposed 92 mile pipeline from the south coast to three plant sites in the north. The Authority’s currentapproach to expand the supply of natural gas on the island has been an offshore gasification facility for LNGdeliveries near its Aguirre power complex on the southeast coast. The proposed Aguirre Offshore Gas Port(AOGP) will be a floating facility to receive and gasify LNG shipments. The Authority plans that the AOGPwill be installed by a vendor under a long term agreement and the Authority has continued with the coordi-

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nated air permit effort with that vendor for both the AOGP scope and the Aguirre plants. The proposed per-mitting schedule would enable gas to be available for the Aguirre plant by the MATS compliance date of April2015, with no margin for unanticipated delays.

During fiscal year 2013 the Authority continued its due diligence on the contractual structure of the gas sup-ply infrastructure and was evaluating alternative supply arrangements for natural gas to the north of theisland. The Authority is evaluating the structure of the LNG commodity supply agreements, which would beseparate from the infrastructure development. The Authority plans to select the bases for establishing thedevelopment of the natural gas infrastructure and fuel supply during fiscal year 2014. These will lead to qual-ifying bidders and soliciting proposals by the end of that fiscal year.

Based on projected fuel costs, the Authority’s initiative to expand gas firing at its generating plants to meetenvironmental regulations will also lower the Authority’s cost of fuel, thereby benefitting the economy ofPuerto Rico. During fiscal year 2013 the Authority operated Costa Sur Units 5 & 6, each a 410 MW unit, withnatural gas providing most of the fuel for those units. The power generated from natural gas in these unitsaccounted for 10.8% of the total power for the System; adding the power from the EcoEléctrica cogenerationplant put the total gas fired generation at almost 28% during fiscal year 2013. The Costa Sur units were thefirst steam units to be converted for dual fuel firing (burn oil and/or gas) because they are located adjacent toEcoEléctrica’s LNG facility, which supplied the fuel under a short term contract that is scheduled to be rene-gotiated in fiscal year 2014.

The Capital Improvement Program (CIP) through fiscal year 2018 includes budgets to complete the dual fuelconversion work at the steam-electric units in accordance with plans for compliance with the EPA emissioncriteria, as well as the San Juan combined cycle units. By the end of fiscal year 2013 the Authority had per-formed much of the conversion work at various units during scheduled outages, and had completed the fullscope for the two large units at Costa Sur. The next priorities are its two largest steam units at the Aguirreplant. Four steam units in the San Juan metropolitan area will be converted after the schedule for gas deliv-eries has been established. With sufficient fuel being available the Authority plans to add gas firing capabilityto the Authority’s two most efficient units, San Juan Units 5 & 6, which are combined cycle units presentlyburning high cost distillate fuel.

Expenditures on capital improvement program projects during fiscal year 2013 were $327.7 million, whichwas 9.2% over budget; it was, however, 6.7% less than during the preceding fiscal year. The Authority hasdeveloped a lean capital expenditure plan for the five fiscal years through 2018, with plans to hold capitalexpenditures to an annual average of $310 million in that span. These budgets do not include constructionof the natural gas supply infrastructure discussed above; the Authority plans to establish the funding struc-ture for this work utilizing third party participants.

Fiscal year 2013 was the first during which renewable energy sources contributed meaningful amounts of theenergy transmitted and distributed within the System; the Authority purchased energy principally from fourrenewable energy projects—an additional small wind turbine provided power occasionally. Together these proj-ects produced 0.7% of the total System power. At the end of fiscal year 2013 the Authority had signed a totalof more than 60 Agreements to Purchase Power from proposed renewable energy projects with a total capacityof approximately 1,660 MW. In the past fiscal year the Authority began renegotiating its agreements with manyrenewable energy project developers to lower their energy costs to the Authority and incorporate the minimumtechnical requirements that were revised in 2012 after many agreements had been signed. This has been an on-going process that applies to all new projects as well. In fiscal year 2014 the Authority plans to perform a morerefined analysis to identify the maximum generation from projected renewable energy resources that can beaccommodated by the System. The Authority has forecasted that renewable energy projects will contribute4.7% of the System power by fiscal year 2015 and stabilize at that level through 2018.

The Authority’s System performed reasonably well during fiscal year 2013. The equivalent availability of theAuthority’s production plant at the end of fiscal year 2013 was 77%, the same level as one year earlier. The avail-ability of the steam electric units in the past year was constrained by the continued program of overhauls and

URS Corporation

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gas conversion work at the Authority’s largest units. In addition, the Authority adopted a policy to minimizepremium work time on scheduled outages to reduce its costs; extending the duration of the outages alsoreduced availability. The generating efficiency of the Authority’s thermal plants in 2013 matched the average ofthe preceding three years. The reliability of electric service to the Authority’s clients in fiscal year 2013, as meas-ured by interruptions, consistently bettered their goals of less frequent and shorter interruptions.

Since 2000 and 2002 the Authority has utilized two private cogeneration facilities for fuel diversity, naturalgas and coal, respectively; these sources also provide cost stabilization for a portion of the System’s generationresources. During fiscal year 2013 these two plants produced approximately 34% of the System power anddemonstrated reliable operation.

The Authority’s total credits and costs to the Commonwealth for Contributions in Lieu of Taxes (CILT) andOther (comprised of three subsidies and an energy credit) were $180.6 million in fiscal year 2013, or 25% ofthe Authority’s net revenues for the fiscal year, using the 1974 Agreement accounting. The Authority’s fiscal year2013 CILT credits (which apply to the municipalities) were well short of its actual obligations for that fiscalyear, consequently the unpaid balance will be paid over the next three years. CILT credits during fiscal year2013 included installment payments on unpaid CILT obligations from fiscal years 2010, 2011 and 2012. At theend of fiscal year 2013, the outstanding deferred CILT balance totaled $323.6 million. Recent legislationexcludes municipal power consumption for money raising activities from the CILT amount. The Authority hasfactored this reduction into projected CILT obligations, which are structured to avoid increasing the accumu-lated deferred CILT balance. In addition to CILT, which benefits the municipalities, the Authority also incurredcosts of $54.4 million for certain Commonwealth subsidies during the fiscal year and for the amortization ofthe outstanding line of credit used in the 2004 settlement of the lawsuit by the municipalities.

The 1974 Agreement obliges the Consulting Engineers to make specific assessments of the Authority’s oper-ations and make recommendations for deposits into certain Funds established under the 1974 Agreement.These are discussed in depth in the report and summarized below:

In the opinion of the Consulting Engineers, the properties of the System are in good repair and sound oper-ating condition.

The Consulting Engineers believes the Authority will receive sufficient revenues in fiscal year 2014 with theexisting rates to cover current expenses, to make all required deposits in accordance with the 1974Agreement’s dictates and to exceed its 120% debt service coverage requirement. Based on the outstanding debtat the end of fiscal year 2013, the debt service coverage was 138% in fiscal year 2013 and is forecasted to be141% in fiscal year 2014, prior to adjustment for planned financings during fiscal year 2014.

The Consulting Engineers reviewed and approved the Authority’s Annual Budget of Current Expenses andCapital Expenditures for fiscal year 2014, which was adopted in May 2013. The budget for fiscal year 2014includes the first year of the Authority’s five year Capital Improvement Program. In fiscal year 2014 theAuthority is projected to contribute 7.6% or $22.7 million in internally generated funds to capital expendi-tures. The Consulting Engineers continues to recommend the Authority should pursue as aggressively aspracticable the goal of achieving and maintaining annual levels of internal funding above that last met in fis-cal year 2010 when it was 16%.

The Reserve Maintenance Fund was last used in fiscal year 2008 as an interim source of funds for the recov-ery following the fire at the Palo Seco Steam Plant. The balance in this fund was $15.8 million at the end offiscal year 2013. The Consulting Engineers recommends the Authority make no deposits to the ReserveMaintenance Fund during fiscal year 2014.

At the end of fiscal year 2013, the Self-insurance Fund’s balance was $92.2 million. This fund was also lastused in fiscal year 2008 to cover uninsured losses associated with the Palo Seco Steam Plant fires. Based onthe current fund levels, the Consulting Engineers recommends the Authority need not deposit any moneysinto the Self-insurance Fund.

URS Corporation

One Canal Park

Cambridge, MA 02141

Tel: 617.621.0740

Fax: 617.621.9739

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TABLE OF CONTENTSINTRODUCTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1

SYSTEM DESCRIPTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2

SYSTEM’S OPERATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Production Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4

Status of Production Units . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8

Steam-Electric Production Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10

Aguirre Steam Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10

Costa Sur Steam Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12

Palo Seco Steam Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15

San Juan Steam Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18

Combined-Cycle Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .20

Aguirre Combined-Cycle Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .21

San Juan Combined-Cycle . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .23

Combustion-Turbine Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .25

Cambalache Combustion-Turbine Power Blocks . . . . . . . . . . . . . . . . . . . . .25

Other Combustion-Turbine Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .27

Hydro Production Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .29

Diesel Generators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .30

Fuels . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .30

Battery Energy Storage System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .32

Spare Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .32

Production Plant Capital Improvements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .32

Environmental. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

Cogenerators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

EcoEléctrica, L.P. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .35

AES-PR . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .36

Transmission and Distribution Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .37

230 kV System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .37

115 kV System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .38

38 kV System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .40

Transmission Plant Capital Improvements . . . . . . . . . . . . . . . . . . . . . . . . . .41

Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .41

Selected 13.2 kV Projects . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .41

Other Distribution Work . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .42

Distribution Plant Capital Improvements . . . . . . . . . . . . . . . . . . . . . . . . . .42

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Maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .43

Transmission and Distribution Systems Reliability . . . . . . . . . . . . . . . . . . . . . . .44

Reliability Indices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .44

Technological Systems Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

Energy Management System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .46

Asset Management Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .46

Production Plant Asset Management Systems . . . . . . . . . . . . . . . . . . . . . . .46

Transmission & Distribution Asset Management Systems . . . . . . . . . . . . . .47

Remote Meter Reading . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .48

General Facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

CONDITION OF THE SYSTEM’S PROPERTIES . . . . . . . . . . . . . . . . . . . . . . 50

CURRENT FORECAST. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

Economy of Puerto Rico . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Econometric Projections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52

Macroeconomic Projections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .52

Current Forecast Projections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .53

Consumption of Electricity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

DEMAND AND ENERGY FORECAST . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

Generation Forecast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54

Peak Demand Forecast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 55

Demand-Side Management and Energy Conservation Programs . . . . . . . . 56

CAPACITY AND ENERGY RESOURCE PLANNING . . . . . . . . . . . . . . . . . . 57

Overview . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

Availability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .57

Capacity Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .57

Purchased Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .58

Energy Resource Planning . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59

Alternative Energy Sources. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60

Fuel Mix . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62

Authority’s Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .63

ENERGY SALES FORECAST . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64

Short-to-Intermediate Term Energy Sales Forecast. . . . . . . . . . . . . . . . . . . . 64

Residential Sector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .65

Commercial Sector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .65

Industrial Sector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .66

Other Classes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .68

Total Electric Energy Sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .68

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RATES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

Rate Schedules. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 69

Classifications and Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .69

Rate Stabilization Fund . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .71

Rate Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .71

Price Comparisons . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .71

Subsidies and Credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 72

Residential Fuel Subsidy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .72

Residential Rate Subsidy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .73

Hotel Subsidy Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .73

Charitable Organizations Subsidy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .73

Life Preservation Subsidy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .73

Agricultural Subsidy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .73

Irrigation Service Subsidy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .73

Common Area Lighting Subsidy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .74

Other Subsidies and Credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .74

Selected Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

Public Housing Residential Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .74

Special Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .74

Large Industrial Service Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .75

Time-of-Use Rates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .75

Standby Service Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .75

Power Producers at Bus Bar Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .76

Security Cameras Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .76

Cost of Service. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

Consulting Engineers Recommendation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76

FINANCIAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

Annual Budget . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

Expenses. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

Operating and Maintenance Expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77

Net Revenues . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 78

Debt Service Coverage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

Depreciation Expense . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 79

Accounts Receivable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

Contributions to the Commonwealth . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 80

Contributions in Lieu of Taxes and Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .80

Economic Incentives Act . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .82

Financing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

Long-term Capital Financing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .83

Interim Financing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .83iii

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Lines of Credit and Notes Payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .83

Capital Improvement Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 83

Production Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .85

Transmission Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .85

Distribution Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .86

General Plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .86

Preliminary Investigations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .86

Funding of the Employee’s Retirement System. . . . . . . . . . . . . . . . . . . . . . . . 86

Inventories and Other Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87

Insurance . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87

FUNDING RECOMMENDATIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88

Reserve Maintenance Fund . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89

Self-Insurance Fund. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 89

Capital Improvement Fund . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 90

HUMAN CAPITAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

Human Resources. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

Labor Affairs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 92

Employee Safety. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 93

LEGAL AFFAIRS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 94

SUPPLEMENTARY INFORMATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

Executive Director Changes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

PREPA Subsidiaries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 96

230 & 115 KV TRANSMISSION SYSTEM MAP

APPENDICES

I INTERMEDIATE-TERM FINANCIAL PLANNING FORECAST

II INCOME STATEMENT

III DETAIL OF OPERATING and MAINTENANCE EXPENSES

IV ANNUAL NET GENERATION, FUEL CONSUMPTION, FUEL AND PURCHASED POWER COSTS

V DEBT SERVICE COVERAGE UNDER THE 1974 TRUST AGREEMENT

VI CAPITAL EXPENDITURES

VII SOURCES OF FUNDS FOR CAPITAL EXPENDITURES

VIII SYSTEM CAPABILITY

IX DEPRECIATION EXPENSE

X DETAILS OF CAPITAL IMPROVEMENT PROGRAM

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URS I June 2013 Annual Report

INTRODUCTIONThis is the Fortieth Annual Report by the Puerto RicoElectric Power Authority’s (Authority) ConsultingEngineers, URS Corporation (Consulting Engineers),filed to comply with the provisions of Section 706 ofArticle VII of the Trust Agreement, dated as ofJanuary 1, 1974, as amended and supplemented,between the Authority and U.S. Bank Trust NationalAssociation, the successor Trustee for the 1974 TrustAgreement.

Act No. 83 of the Legislature of Puerto Rico, approvedMay 2, 1941, as amended, reenacted and supple-mented (the “Authority Act”), created the Authority abody corporate and politic constituting a public cor-poration and governmental instrumentality of theCommonwealth of Puerto Rico. Hereinafter, we willrefer to Act No. 83 of the Legislature of Puerto Rico,approved May 2, 1941, as amended, reenacted andsupplemented as the Authority Act.

With the release of the 1947 Trust Indenture on June9, 1996, the 1974 Trust Agreement, dated as ofJanuary 1, 1974, as amended and supplemented,became the sole document governing all of theAuthority’s long-term financings, with the exceptionof minor subordinated interim debt. Throughout thisreport we will refer to the 1974 Trust Agreement,dated as of January 1, 1974, as amended and supple-mented, as the 1974 Agreement.

Section 706 of the 1974 Agreement provides the fol-lowing:

It shall be the duty of the Consulting Engineers toprepare and file with the Authority and with theTrustee on or before the 1st day of November ineach year a report setting forth their recommenda-tions as to any necessary or advisable revisions ofrates and charges and such other advices and rec-ommendations as they may deem desirable.After...the release of the 1947 Indenture, it shall bethe duty of the Consulting Engineers to include insuch report their recommendations as to theamount that should be deposited monthly duringthe ensuing fiscal year to the credit of the ReserveMaintenance Fund for the purposes set forth inSection 512 of this Agreement, deposited during theensuing fiscal year to the credit of the Self-insur-ance Fund for the purposes set forth in Section512A of this Agreement, if any, and deposited dur-ing the ensuing fiscal year to the credit of theCapital Improvement Fund for the purposes setforth in Section 512B of this Agreement.

The Authority further covenants that theConsulting Engineers shall at all times have freeaccess to all properties of the System and every partthereof for the purposes of inspection and examina-tion, and that its books, records and accounts maybe examined by the Consulting Engineers at all rea-sonable times.

This Annual Report is based, in part, upon ourknowledge of the Authority’s operations gained overthe more than 65 years that we (ConsultingEngineers and its antecedent companies) have beenretained as Consulting Engineers. We were initiallyretained in accordance with the provisions of Section704 of Article VII of the Authorizing Resolution,dated January 1, 1944, and subsequently in accor-dance with Section 704 of Article VII of the 1947Trust Indenture from its inception until its release, aperiod of 53 years. We have also served as ConsultingEngineers in accordance with Section 706 of ArticleVII of the 1974 Agreement since its inception.

Each year, in fulfilling our duties as ConsultingEngineers, we visit and note the condition of all thesteam production facilities a minimum of three times;all the remaining production facilities at least onceeach year; one-third of the approximately 380 distri-bution substations and transmission centers; and arepresentative cross-section of all additional propertyowned and operated by the Authority. We regularlyreview the Authority’s various reports and records,meet with the Authority’s management and staff todiscuss present operations and future plans, and per-form a number of analyses relying primarily on dataand information provided by the Authority. We alsoparticipate in all regular bond issue financings under-taken by the Authority by assisting in the preparationof the Official Statements, by providing several signedEngineers Certificates, and by participating in mostbond rating agency presentations.

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SYSTEM DESCRIPTIONThe Authority’s System supplies virtually all of theelectricity consumed in Puerto Rico and the smallerislands of Vieques and Culebra. In the past fiscal yearthe Authority generated approximately 66% of theelectricity itself and purchased the remaining. Thetwo largest sources were the cogenerators,EcoEléctrica, L.P. located in the Municipality ofPeñuelas and AES-PR located in the Municipality ofGuayama. Power from five new renewable energyprojects contributed 0.7% of the island’s electricity forthe last year. During fiscal year 2013, which ended onJune 30, 2013, the System served on average1,485,150 clients.

The Commonwealth of Puerto Rico is the eastern-most of the islands comprising the Greater Antillesand is approximately 110 miles in length and 35miles north to south. Central mountain ranges withpeaks as high as 4,390 feet extend the length of theisland from east to west. Coastal lowlands formed bythe erosion of the central mountains extend inwardson the north coast for 8 to 12 miles and for 3 to 8miles in the south. The northern coastal lowlands arehumid while those on the south side of the island aresemi-arid. The island’s population density is high;approximately 58% of the island’s 3.65 million inhab-itants live in the broader metropolitan area of SanJuan; the next most populous urban areas are Ponceand Mayagüez, with 12% and 7% of the island’s pop-ulation, respectively. The rural population is approxi-mately 6% of the total and resides in the numeroussmall towns located along the island’s perimeter andin the remote mountainous interior. Data from the2010 census show the population of Puerto Ricodeclined by 2.2% in the ten years since the previouscensus; this was the first observed decline in theisland’s population. Data collected since 2010 indi-cate the decline in the island’s population has contin-ued with an additional estimated loss of 1.9% through2012. Taken together Puerto Rico’s geography, cli-mate, and the dispersion of its clients within theCommonwealth present the Authority with manychallenges as it designs, builds, operates, and main-tains its System. The Authority serves its clients in 26districts through seven regional offices, each of whichincorporates a technical office.

Puerto Rico is in the path of many of the tropicalstorms and hurricanes that cross the Greater Antillesduring the hurricane season, which runs from Junethrough November. The Authority’s transmission anddistribution systems, more than 90% of which areabove ground, are particularly vulnerable to the highwinds, torrential rains, and erosion that are associated

with tropical storms and hurricanes. The last hurri-cane to drastically affect both the island’s economyand the System, Hurricane Georges, struck the islandon September 28, 1998.

An electric power system is made up of production,transmission, distribution, communication and ancil-lary facilities, not all of which are physically con-nected, operated as a single integrated whole. Theflow of electricity within the system is maintainedand controlled by a dispatch center. It is the responsi-bility of the dispatch center’s operators to match thereal-time supply of electricity with the simultaneousdemand for it. In order to carry out their responsibil-ities the System’s dispatchers are authorized to buypower to complement the System’s own generationand to economically dispatch it based on Systemrequirements.

The Authority’s primary dispatch center, which isunder the direction of the Director of Generation, islocated at Monacillos, approximately seven milessouth of metropolitan San Juan. A SupervisoryControl and Data Acquisition (SCADA) system, anintegral part of the dispatch center’s control system,has the ability to control total load flow on the islandand can remotely control many of the Authority’s sub-stations and all of the large generating units. A sec-ondary dispatch center is located in Ponce; it iscontinuously available to assume control if the pri-mary control center has problems. Both centers arefully staffed during System emergencies, coordinatingall restoration efforts.

The three major components of the System are theProduction Plant, the Transmission system, and theDistribution system. They account for approximately86% of the $11.7 billion Plant-in-Service investment.Below is a brief description of each of these components.

The production plant’s dependable generating capac-ity, to the nearest megawatt, is 4,878 MW comprisedof 2,892 MW of steam-electric capacity, 846 MW ofcombustion-turbine capacity, 1,032 MW of com-bined-cycle capacity, 100 MW of hydroelectric capac-ity, and 8 MW of diesel capacity. The 2,892 MW ofsteam-electric capacity consists of 14 units at foursites: Palo Seco–602 MW (four units) and SanJuan–400 MW (four units), both on the north side ofthe island; Aguirre–900 MW (two units) and CostaSur–990 MW (four units), both on the south side ofthe island. The last reduction in the Authority’scapacity and number of steam-electric units occurredat the end of fiscal year 2008 when Costa Sur Units 1& 2, which had a combined capacity of 100 MW, wereremoved from service. While the Authority has addi-tional older steam-electric plants, there are no present

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plans to retire them, although the future use of cer-tain older plants may be limited as part of theAuthority’s strategy to meet new air emission stan-dards. The Authority’s 1,032 MW of combined-cyclecapacity is comprised of two units at the Aguirre com-plex with a capacity of 592 MW and two units locatedin the San Juan Station with a total capacity of 440MW, which came into service during fiscal year 2009.The 846 MW of combustion-turbine capacity consistsof 29 units at nine sites around the island, the three-unit 248 MW Cambalache Station being the largest.The 100 MW of hydroelectric capacity consists of 21units at 11 sites around the island, the 25 MW YaucoNo. 1 being the largest unit. The Authority has twodiesel generators each with 3 MW of capacity onstandby reserve on the island of Vieques. On theisland of Culebra four diesel generators having a com-bined capacity of 2 MW provide standby reserve. TheAuthority also has a mobile 1 MW diesel unit onCulebra; it is not connected to the System and is notlisted as standby reserve capacity.

During fiscal year 2009 ten units came into initialservice and four simple cycle combustion turbineswere retired; these changes are reflected in the dataabove. The two largest new units were San Juan Units5 & 6 combined cycle units, each having a depend-able capacity of 220 MW. At Mayagüez four 21 MWcombustion turbines were retired and removed fromthe site and replaced by eight aero-derivative simplecycle combustion turbines. The replacement combus-tion turbines increased the available capacity at theMayagüez station from 84 MW to 220 MW.

The Authority’s Sabana Llana battery energy storagesystem was designed to provide up to 20 MW forpower factor correction and reserve capacity, how-ever, the battery system has not been available forservice since fiscal year 2006. At the end of fiscal year2013 the Authority was evaluating proposals for sal-vaging the facility’s batteries.

To supplement its own capacity, the Authority pur-chases power from two cogenerators under the termsand conditions of Power Purchase OperatingAgreements (PPOAs). The Authority is in the thir-teenth year of a 22-year PPOA for 507 MW of gas-fired capacity from EcoEléctrica, L.P. and is in thetenth year of a 25-year PPOA for 454 MW of coal-fired capacity from AES-PR. The 961 MW of capacityprovided by the cogenerators brings the total depend-able capacity available to the Authority to 5,839 MW.(See Appendix VIII, System Capability.)Since few projects were operating the prior year, fiscalyear 2013 was the first year in which renewable energyprojects provided a meaningful amount of power to

the System, all were under 20 year PPOAs. The oper-ating renewable sources were the Pattern wind farm inSanta Isabela with a nominal rating of 75 MW, PuntaLima wind farm in Naguabo with a nominal rating of26 MW, the 1 MW wind turbine at the Bechara watertreatment facility in San Juan, the AES Iluminia 20MW solar farm in Guayama and the 2.1 MWWindmar solar farm near Ponce. Additional renewableprojects are scheduled for completion and operationsin fiscal year 2015. All of these renewable energy proj-ects are intermittent sources of power because theyrely on the availability of wind or sun light, conse-quently they are not considered reliable capacity.

The Authority’s transmission system is an intercon-nected network of 230 kV, 115 kV, and 38 kV powerlines that carry electrical power from the productionplants to numerous distribution centers from where itis distributed to clients for consumption.

At the close of fiscal year 2013, the transmission sys-tem was comprised of 2,478 circuit miles of lines: 375circuit miles of 230 kV lines, 727 circuit miles of 115kV lines, and 1,376 circuit miles of 38 kV lines.Included in the transmission system totals areapproximately 35 miles of underground 115 kV cable,63 miles of underground 38 kV cable and 55 miles of38 kV submarine cable. In addition to the high volt-age lines, the transmission system includes trans-formers at the generating plant substations,transmission centers for interconnection of differentvoltage systems and switch yards and gear for connec-tion or separation of portions of the transmission sys-tem operating at the same voltage. High voltagetransformers installed in the Authority’s transmissionsystem and its production plants have a total trans-former capacity of 19,207 MVA.

As of June 30, 2013, the Authority’s distribution sys-tem consisted of approximately 31,550 circuit milesof distribution lines (with operating voltages rangingfrom 4.16 to 13.2 kV) and 333 substations (with atotal installed capacity of 5,018 MVA). The distribu-tion system has more than 1,800 circuit miles ofunderground lines. The Authority has 22 portabletransformers with a total capacity of 349.6 MVA tosubstitute for existing transformers during mainte-nance or outages; similarly the Authority has twoportable capacitor banks each rated at 18 MVAR.There are 813 privately owned substations (with atotal installed capacity of 3,266 MVA). The distribu-tion system also includes approximately 1,485,200client meters.

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SYSTEM’S OPERATIONSPRODUCTION PLANTThe Authority continues its commitment to an ongo-ing, long-term program to extend the life and to main-tain the high level of availability of its generating units.The program consists of three components: formaloperator training, comprehensive preventative mainte-nance, and design modification. The formal operatortraining part of the program emphasizes safety, operat-ing efficiency, and equipment integrity. The compre-hensive preventative maintenance part of the programrequires the Authority to remove all major generatingunits from service for maintenance at regularly sched-uled intervals to ensure their reliability. These intervalsare referred to as “scheduled outages” in the text of thisAnnual Report. A residual life assessment of criticalcomponents is an integral part of the Authority’s pre-ventative maintenance practices.

The design modification part of the program repre-sents the Authority’s commitment to improve theoperation of its generating units by installingredesigned, improved components, or by undertakingconversions. Examples of design modificationsinclude upgrades of the eight 50 MW combustionturbines with original equipment manufacturer(OEM) improvements and the completion of modifi-cations enabling them to burn distillate or naturalgas. During fiscal year 2012 the Authority began thedesign modification of Costa Sur Unit 6’s boiler,burner, and control system to support full load gas fir-ing. These modifications were completed in the firsthalf of fiscal year 2013; similar modifications to CostaSur Unit 5 were completed by the end of fiscal year2013. The initial phase of the modification of theAguirre Steam Units to enable them to burn naturalgas was completed during fiscal year 2012. The instal-lation of the remaining design modifications to theAguirre Steam Electric units are scheduled to coin-cide with the availability of natural gas at the station.The Authority also plans dual fuel conversion at othersteam electric units and the combined cycle units atthe San Juan Station over the next several fiscal years.

Years ago the Authority also converted all of its“forced draft” thermal plant boilers to “balanceddraft” operation. These modifications allow theequipment to be operated at design or increasedcapacity with greater operational efficiency and relia-bility. Among the Authority’s current projects arethose that aim to increase the efficiency of its steamturbines by improving the performance of the associ-ated steam condenser. These projects have included:

retubing condensers; replacing condenser vacuumequipment; replacing cooling water filtration systems,and improving condenser backwash capabilities. TheAuthority has installed continuous condenser clean-ing systems on several units; vendor owned continu-ous condenser cleaning systems are operated on apay-for-performance basis. Turbine efficiency is alsobeing improved through the installation of high effi-ciency seals, through turbine control upgrades, andthrough the installation of redesigned turbine blades.

The Authority purchased asset management softwarefor its production plant and high voltage electricalequipment during fiscal year 2010 to replace andexpand the existing system which was becoming out-moded. Among the expected benefits of the new pro-gram will be the improvement of the availability ofcritical generation and the reliability of certain highvoltage transmission assets. The program was fullyimplemented during the past fiscal year for the pro-duction plant assets. During fiscal year 2011 theAuthority’s engineers participated in factory accept-ance tests (FAT) of components of an upgrade to theirEnergy Management System (EMS). After operatingthe new EMS in parallel with the existing system todemonstrate its capabilities and reliability the newEMS was placed in service during fiscal year 2013.Both of these programs are more fully described inthe Technological Systems Operations section below.

We visit all the steam-electric production facilities aminimum of three times each year and all of theremaining production facilities at least once each year.We examine numerous operations reports and we reg-ularly meet with the Authority’s management and staffto discuss present operations and future plans.

In accordance with an agreement approved by theSecretary of the Puerto Rico Department of Labor,Puerto Rico’s Jurisdictional Boiler Inspector hasallowed the Authority to increase the intervalbetween boiler certifications from 12 months, as nor-mally required by Commonwealth law, to 18 months.Nevertheless, at the end of fiscal year 2013 theJurisdictional Boiler Inspector had certified all of theAuthority’s boilers within the previous 12 months.

MAINTENANCE

Routine maintenance activities are performed duringenvironmental outages and during planned majoroutages which have broader scopes of work.Significant production plant upgrades or design mod-ifications are accomplished during major overhauls.The routine maintenance activities are chargedagainst the plant’s maintenance budget. As is com-


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mon in the electric utility industry, expenditures asso-ciated with significant production plant upgrades anddesign modifications are capitalized rather thancharged as a current maintenance expense. Typicallythese activities are performed during scheduled majoroutages, although occasionally the Authority installscapitalized components during a scheduled environ-mental outage. During scheduled outages theAuthority also performs non-destructive testing(NDT) examinations of representative critical compo-nents to establish their condition and perform orschedule appropriate repair work. The scope of NDTexaminations includes boiler pressure parts, powerpiping, steam turbine components, electrical genera-tors, transformers, and switchgear.

The duration of an outage varies based on the scopeof work, availability of personnel and material, andbudgetary constraints. Where the Authority routinelyused extended work hours and temporary workersfrom other plants to shorten the duration of an out-age in the past, present budget constraints haveforced the Authority to minimize premium worktime. The Authority has judged the cost savings asso-ciated with extending an outage are cost effectivegiven the good reliability of its plants and the com-fortable reserve capacity margin it has over recentdemand.

The Authority schedules their fourteen steam-electricgenerating units out of service for an environmentaloutage at intervals of twelve to eighteen months.During an environmental outage the boiler and othercomponents are cleaned to meet the requirements ofthe Air Compliance Preventative MaintenanceSchedule contained in the Authority’s Consent Decreewith the Environmental Protection Agency (EPA).The Authority may keep a unit in service up to aneighteen-month limit subject to the unit’s compliancewith the emissions criteria in the Consent Decree.Frequently the Authority will advance the start of anenvironmental outage to ensure that adequate capac-ity is available during a period of high demand or toavoid having several units out of service concurrently.The following paragraph describes some of the clean-ings, inspections, and replacements that theAuthority performs during an environmental outage.

At the start of an environmental outage slag isremoved from the boiler and the water walls arecleaned. The superheater, reheater, air heater, andeconomizer areas are washed and inspected, as are theexhaust gas ducts and the stack. Air heater compo-nents; seals, baskets, casing, and sector plates areinspected and replaced as necessary. Ductwork is

repaired. Hoppers are emptied and cleaned, expan-sion joints are inspected for corrosion and leakage.Fuel handling equipment is inspected, repaired, andrecalibrated as necessary. The forced and induceddraft fans and the gas recirculation fan are cleaned,noise and vibration levels monitored, adjustmentsmade and repairs completed. Motors for fans andmain boiler pumps are cleaned and inspected.Dampers are inspected and adjusted. The windbox,burners, combustion air instrumentation, combus-tion controls, and soot blowers are inspected; dam-aged or worn components are either repaired orreplaced. Monitors for opacity, oxygen, and furnacepressure are cleaned, recalibrated, or as necessaryreplaced. Pumps, feedwater heaters, the deaerator,and associated valves are inspected. Lubricating oilsystems are inspected. Power transformers areinspected and breakers tested and adjusted. If a pres-surized part of the boiler has been replaced the boilerpart will be pressure tested before the unit returns toservice. Life extension inspections and NDT activitiesare completed on critical systems and components inpreparation for future programmed outages.

In the discussions regarding the status of productionunits that follow, the narrative will note the durationof a unit’s environmental outage and describe workcompleted during the outage, which is in addition tothat routinely performed during an environmentaloutage.

All of the Authority’s fourteen steam-electric generat-ing units were in service during fiscal year 2013. Tenof the 14 steam-electric generating units that were inservice during fiscal year 2013 either completed orbegan an environmental outage during the fiscal year.The other four steam electric units were scheduled tobegin the Consent Decree mandated environmentaloutage in the first or second quarter of fiscal year2014. At the end of fiscal year 2013 all 14 of the steamelectric units had completed an environmental outagewithin the 18 months allowed in the Consent Decreewith the EPA.

With few exceptions the Authority sequences sched-uled outages so that the large steam electric units areavailable for service from May through November, themonths of maximum demand and greatest risks ofweather disturbances. This strategy seeks, to theextent possible, to maximize the availability of theSystem’s capacity while maintaining compliance withthe Consent Decree with the EPA.

Steam turbines are internally inspected every five-to-seven years. This work, which is typically scheduledfor a period of three-to-five months duration,


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includes opening the high-, intermediate- and/or low-pressure section of the steam turbine, turbine controlvalve inspection, generator testing and repair, the dis-assembling, repairing, or replacing of major compo-nents; the scope of work is more comprehensive thanan “environmental outage”. It is identified as a “majoroverhaul” in the descriptions of the status of produc-tion units that are discussed below. Major overhaulsfrequently include rehabilitation work on the boilerand balance of plant systems.

One exception to the scheduled interval betweenmajor overhauls is Palo Seco Unit 2, which has beenin service more than ten years between major over-hauls. The Authority completed the overhaul of theHP, IP, and LP turbines of the 85 MW unit in May2002. During the reconditioning of each of the PaloSeco units following a major fire in December 2006the Authority examined critical components of eachunit and determined that an extensive overhaul ofUnit 2 was not required. Given the anticipated lowlevel of dispatch of this unit following the Authority’scompliance plan for the MATS clean air emissionstandards discussed in the Environmental section theAuthority has not scheduled a major overhaul of thisunit, however environmental outages and targetedmaintenance will continue. Palo Seco Unit 2 recordedan equivalent availability of 87% during fiscal year2013.

Occasionally the scope of work performed during amajor overhaul will cause the schedule to beextended beyond the three-to-five months required tocomplete the turbine work. These events are detailedin the unit descriptions that follow.

The Authority’s remaining production plant alsoincludes both simple cycle and combined-cycle com-bustion-turbines, and a number of relatively smallhydroelectric plants.

The Authority schedules maintenance on its 39 com-bustion-turbines (29 operated in simple cycle config-uration and ten operated in combined-cycleconfiguration) based upon the number of “equivalentfired hours” of operation as specified in manufactur-ers’ manuals. The equivalent fired hours concepttakes into account the wear and tear associated withstarting up the units as well as other operating factorsthat reduce the actual number of hours that units canbe run between inspections. Eighteen of theAuthority’s simple cycle combustion-turbines are 21MW Frame 5 machines, located at seven sitesthroughout the island. During the 1990’s theAuthority improved the performance of these com-bustion turbines by upgrading them to model “PA”

configuration. One of the benefits of the “PA” mod-ernization is that the interval between certain inspec-tions increased the equivalent fired hours as follows:fuel nozzles of these units are inspected every 1,125equivalent fired hours or 2,250 equivalent fired hoursfor units with air atomization; combustion sectioninspections are conducted every 4,500 equivalentfired hours; and intermediate inspections are con-ducted every 9,000 equivalent fired hours.Compressor and power turbine sections are rebuiltduring major overhauls, which are scheduled every18,000 equivalent fired hours.

In 2004 the Authority began a program to replace cer-tain components in 16 of its eighteen 21 MW com-bustion turbines. The program included thereplacement of the ratchet and torque converterthereby improving starting reliability, the installationof a universal fuel system, turbine modifications, anupgrade of the turbine control system, and new digi-tal controls for the exciter. The final combustion tur-bine in the program is scheduled for the upgrade infiscal year 2014.

Lubricating oil analysis and other preventative main-tenance and diagnostic tests are performed monthly.

Eight new FT8 aero-derivative simple cycle combus-tion turbines went into service at the Authority’sMayagüez plant during fiscal year 2009. These eightcombustion turbines comprise four unit blocks. Thecombustion turbines are connected in opposed pairs,between each pair is a 55 MW generator. The fourunits are capable of 220 MW; they replace the four 21MW combustion turbines that were previously sitedat the Mayagüez plant. The new units will beinspected and maintained at the following intervals:

“A” Inspection the sooner of every 1,000 hours orannually, during which borescope inspections areperformed and preventative maintenance completedunder the direction of a technical advisor.

“B” Inspection performed every 12,500 hours is a hotsection inspection of the combustors, the power tur-bine sections and the seals and bearings. The unit isdisassembled and shipped to a shop for the inspec-tion.

“C” Inspection performed at 25,000 hours includesthe inspection and refurbishment of the combustionturbine’s intermediate case, the bearing compart-ments, pumps, in addition to the componentsinspected during a “B” inspection.

“D” Inspection performed at 50,000 hours entails theshop inspection of all sections of the combustion tur-

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bine and the refurbishment or replacement of worncomponents.

The three 82.5 MW Model GT 11N combustion-tur-bines power blocks at the Cambalache Combustion-Turbine Station are inspected and maintained inaccordance with the schedule below:

Class “A” Inspection every 4,000 equivalent firedhours: the combustor, burners, and turbine blades areinspected; the duration of the inspection is approxi-mately six days.

Class “B” Inspection every 8,000 equivalent firedhours: the instrumentation is recalibrated; the com-bustor, burners, and turbine blades are inspected; andthe once-through steam generator (OTSG) is washed;the duration of the work is approximately six days.

Class “C” Inspection every 16,000 equivalent firedhours: the blades in the compressor section arereplaced; the combustor is removed for inspection;the combustor liner is replaced; thermal tiles andholding rings are replaced; the turbine is opened; thefirst three rows of blades in the high-pressure sectionof the turbine are replaced; auxiliaries are inspectedand repaired as necessary; the duration of the work isapproximately 31 days. The removed combustor linerand turbine blades are refurbished for use duringfuture outages.

The Authority completed the upgrade of the last ofthe Frame 7 combustion turbines at the AguirreCombined Cycle Station to a modified Frame 7EAdesign during fiscal year 2007. The upgrade allowedthe Authority to increase the number of equivalentfired hours a combustion turbine is in servicebetween scheduled maintenance inspections to thehours cited below:

Combustion inspections during which burner noz-zles, check valves, filters, and associated instrumenta-tion are inspected are scheduled every 5,300equivalent fired hours. Prior to the design upgradecombustion inspections were performed at 4,000equivalent fired hours intervals. Combustion outagestake less than a week.

Hot-gas-path inspections, during which the liner, thefirst stage turbine blades, rotor bearings, burners, etc.,are inspected, are scheduled approximately every15,900 equivalent fired hours. The turbine inspectionports are opened; turbine blades are replaced as dic-tated by the degree of blade corrosion. A hot-gas-pathinspection is typically completed over an eight-weekperiod.

Major overhauls, during which the turbine and com-pressor are opened and blades in the first stage of theturbine are replaced, are scheduled after 31,800equivalent fired hours. In addition, reduction gearsand other turbine components and auxiliaries areinspected and repaired. Duct sections, baffles, theexhaust stack, the generator, and other electricalequipment are also inspected and repaired. Filtermedia in the air intake system are also replaced at thistime. A major overhaul is typically completed over asixteen-week period.

The steam turbines of the Aguirre combined-cycleplant are maintained in accordance with the sameguidelines as those followed for the 16 steam-electricturbines; however because their service is intermit-tent and most often at partial load the years betweenscheduled overhauls may exceed those of the steam-turbines. The service intervals for these two steamturbines are discussed in the Aguirre Combined CyclePlant section below.

During October 2008 the Authority’s two 220 MWcombined-cycle units, San Juan Units 5 & 6, wentinto commercial service. Each unit is comprised of asingle combustion turbine with a capacity of 160 MWand a steam turbine with a capacity of 60 MW. TheAuthority has signed a long term service agreement,LTSA, with the combustion turbine vendor ofapproximately eight years duration during which thevendor will be responsible for the maintenance of thecombustion turbine generator and the steam turbinegenerator. The Authority will be responsible for themaintenance of the combined-cycle plant’s auxil-iaries. Combustion turbine inspections will be per-formed on the basis of equivalent service hours, ESH,as follows:

8,000 ESH – Modified Combustion Inspection – fuelnozzles, combustor baskets, transition pieces, turbineblades in rows 1, 2, 3, and 4, and turbine vane andring segments in rows 1 and 2 will be replaced.Inspections of the inlet, compressor, turbine, andexhaust sections of the combustion turbine are com-pleted.

16,000 ESH – Combustion Inspection – fuel nozzles,combustor baskets, transition pieces, turbine bladesin rows 1, 2, 3, and 4, and turbine vane and ring seg-ments in rows 1 and 2 will be inspected and replacedas necessary. Inspection of the inlet, compressor, tur-bine, and exhaust sections of the combustion turbineare performed.

24,000 ESH – Major Inspection of the combustionturbine is completed with inspection and replace-

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ment of blades in the compressor section and in theturbine section.

San Juan Units 5 & 6 Steam Turbine Generator inspec-tions will be performed on the following frequencies:

Steam Turbine Generator Valve Inspections will beperformed every 18 months. The scope includes thecleaning, NDT, and adjustment of HP stop and controlvalves, reheat stop valves, and intercept valves.

Major Inspections of the steam turbine generator areperformed every 50,000 ESH.

The Authority has significantly reduced the durationof unscheduled outages of some of its large generatingunits by maintaining an inventory of critical sparecomponents. On a long-term basis this practice hascontributed to the improvement of both unit andSystem availability. Refer to the Spare Componentssection below for a listing of the major spare compo-nents.

The hydroelectric generating units are inspected on anannual basis and opened every five years.

Maintenance expenditures outlined below includecosts associated with the thermal plants as well as thehydroelectric generating plants. These costs do notinclude the cost of the new capitalized units of prop-erty, and therefore they do not completely reflect theAuthority’s total cost of maintaining its fixed assets. Asshown in Appendix III, Detail of Operating andMaintenance Expenses,maintenance expenditures forthe production plant, including the hydroelectric, forfiscal year 2013 totaled $102.2 million. While mainte-nance costs were under the budget, the actual expen-ditures of $71.7 million for operations of theproduction plant exceeded that budget and erased thepotential savings. The Authority’s budget for opera-tion and maintenance of the production plant for fis-cal year 2014 is 2.4% more than the actual expenses infiscal year 2013. The total operation and maintenancebudgets for fiscal years 2015 through 2018, respec-tively, decline 6.5%, increase 1.1%, increase 0.3% andare level for the last two fiscal years.

STATUS OF PRODUCTION UNITS

The statuses of the Authority’s production units aredescribed in the following sections based on their condi-tion as of the week of June 30, 2013

The table below provides a brief profile of each unit(capacity data, age, annual heat rate, and annualequivalent availability). The annualized heat rate is ameasure of a unit’s operating efficiency, which can beaffected by its level of dispatch and other factors, suchas capacity limitations caused by out of service equip-

ment or sub-systems. Since heat rate is measured interms of required fuel heating value input to produceone kilowatt of power, better performance is indicatedby a lower heat rate. During fiscal year 2013 theAuthority’s generation based on fossil fuels achieved anet heat rate of 10,696 Btu/kWh, which was very closeto the average for the previous three years.

Annual equivalent availability is defined as the per-centage of time a generating unit was available, at itsrated capacity, for service in a rolling 12-monthperiod. For this Annual Report that period was the fis-cal year ended June 30, 2013. The equivalent availabil-ity of the Authority’s production plant for fiscal year2013 was 77%, which was consistent with the previ-ous year. The system availability in the past fiscal yearwas constrained by the six month outage of Costa SurUnit 5 for a major overhaul and gas conversion work.The Authority’s policy to minimize premium worktime for scheduled outages has extended the durationof these outages, which will also lower the equivalentavailability.

The annual capacity factor of a generating unit isbased on its total net generation over the last fiscalyear divided by the maximum power it could haveproduced based on operating every hour of the year.

A summary of annual performance data for each unitis presented on the table to the right:

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ANNUALDEPENDABLE INITIAL HEAT EQUIVALENTCAPACITY OPERATION RATE AVAILABILITY

STEAM PLANTS

Aguirre Unit 1 450 1971 10,197 86%

Aguirre Unit 2 450 1971 11,003 91%

Aguirre Station 10,615 89%

Costa Sur Units 1 & 2 Removed from service 4/30/08

Costa Sur Unit 3 85 1960 13,198 73%

Costa Sur Unit 4 85 1962 12,705 60%

Costa Sur Unit 5 410 1969 11,280 42%

Costa Sur Unit 6 410 1972 10,858 70%

Costa Sur Station 11,163 58%

Palo Seco Unit 1 85 1959 11,171 88%

Palo Seco Unit 2 85 1959 11,147 87%

Palo Seco Unit 3 216 1967 10,566 60%

Palo Seco Unit 4 216 1968 10,596 82%

Palo Seco Station 10,765 76%

San Juan Unit 7 100 1964 11,384 72%

San Juan Unit 8 100 1964 11,434 88%

San Juan Unit 9 100 1966 11,390 81%

San Juan Unit 10 100 1965 11,525 82%

San Juan Station (excl 5 & 6) 11,435 81%


COMBINED CYCLE UNITS

Aguirre Combined Cycle Unit 1 296 1976

Combustion Turbine 1-1 50 12,704 99%




Steam Turbine 1 96 64%

Aguirre Combined Cycle Unit 2 296 1975






Aguirre Combined Cycle Plant 10,582 87%


COMBINED CYCLE UNITS (continued)

San Juan Unit 5 220 2008 7,959

Combustion Turbine 5 160 79%


San Juan Unit 6 220 2008 8,665

Combustion Turbine 6 160 100%


San Juan Combined Cycle Units 8,253 85%

COMBUSTION TURBINES

Cambalache CT Power Blocks

CCTP 1 82.5 1997 - 0%

CCTP 2 82.5 1997 12,208 90%

CCTP 3 82.5 1998 11,750 99%

Cambalache CTs 11,989 63%

Frame 5 GT Power Blocks

9 Blocks of 2 GT’s 378 1971-1973 15,583 88%

Mayagüez

GT 1 55 2009 9,821 27%

GT 2 55 2009 10,625 99%

GT 3 55 2009 10,411 86%

GT 4 55 2009 10,039 99%

Mayagüez GTs 10,317 78%


THERMAL SYSTEM

4,770 10,696 77%

ANNUALDEPENDABLE INITIAL SERVICE EQUIVALENTCAPACITY OPERATION FACTOR AVAILABILITY

HYDRO

Total for 21 Hydro Units 100 1929 - 1953 10% 63%

DIESEL GENERATORS

Total for 6 DG sets 8 1980 - 2006 0% 95%

AUTHORITY’S PRODUCTION PLANT SUMMARY PERFORMANCE FISCAL YEAR 2013

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Steam-Electric Production PlantTotal Generating Capacity 2,892 MW

The generating units within a steam-electric generat-ing station are identified by acronyms in the follow-ing manner: Unit No. 1 in the Aguirre Steam Plant isintroduced as ASP Unit No. 1; Unit No. 3 at Costa SurSteam Plant is CSSP Unit No. 3, and so on. The nar-ratives on the generating units in this section gener-ally present information by paragraph in thefollowing sequence:

The first paragraph provides historical and annual-ized operational data and summarizes the types andnumber of outages the unit experienced during thefiscal year. In this paragraph and in the followingparagraphs turbine sections are identified in the fol-lowing manner: high-pressure (HP), intermediate-pressure (IP), and low-pressure (LP).

The second paragraph describes the number andtypes of scheduled outages (major overhaul, environ-mental outage, or maintenance outage) the unit expe-rienced during the fiscal year. The work performedduring maintenance outages is described if the outagewas longer than 24 hours. However, if a unit wasscheduled out of service repeatedly for the same rea-son, the cause of the maintenance outages and theirresolution will be noted regardless of the brevity ofthe outage. The time assigned to scheduled reserveeconomic shutdown, in which the unit is availablebut excluded from dispatch, will also be noted.

The third paragraph describes the number of timesand the duration of forced outages and unit limita-tions the unit experienced during the fiscal year. Thecause of the outage or limitation and the action(s)taken to return the unit to full service is describedwhen the forced outage or limitation was of morethan 24 hours duration. Repeated outages or limita-tions attributed to the same cause are noted, despitebeing of less than 24 hours duration. The Authoritytracks unit limitations as “equivalent outage hours”(EOH), which are a measure of the hours the unit’soutput was restricted below full capacity; for exam-ple, operating for 24 hours while the unit output islimited to 50% is equivalent to 12 hours of outage forthe unit at full capacity.

The fourth paragraph notes the next scheduled out-ages for the unit that are planned for fiscal year 2014or beyond, including the scheduled start of the unit’snext major overhaul. The discussion addresses equip-ment and system replacements and upgrades that areincluded in the Capital Improvement Program (CIP).

The planned CIP expenditures for station servicesthat impact a number of the station’s units areincluded in the narrative of the station’s first unit.

The federal air quality requirements that will restrictthe Authority’s use of residual oil are discussed in theEnvironmental section and are referred to as MATS,for mercury and air toxics standards. In this sectionreferences to the NPDES (national pollutant dis-charge elimination system) sections 316 (a) and (b)program apply to the Authority use of cooling water;these requirements are also addressed in theEnvironmental section

Aguirre Steam Plant

ASP Unit No. 1 (nominal 450 MW) was not in serv-ice on June 30, 2013, because it was in the middle ofa scheduled environmental outage. During fiscal year2013 the unit was scheduled from service five times;once for a programmed outage and four times formaintenance. Scheduled outages kept the unit fromavailable status a total of 38 days in the past fiscalyear. It was forced from service five times for a total ofslightly more than nine days; each of the two longestof these outages was between three and three and ahalf days in duration. The unit accrued approxi-mately three equivalent outage days, attributed to sixdifferent events over the course of the year. While inoperation during the past fiscal year this unit gener-ated an average net power of 270 MW. Unit 1 was inservice 7,615 hours during the fiscal year and had anannual capacity factor of 52%.

During the past fiscal year the unit was scheduledfrom service four times for maintenance before itbegan an environmental outage on June 3, 2013; thestart of the environmental outage was prompted by afault in the motor drive of boiler feed pump (BFP) 1-2 earlier that day. Each of the first three maintenanceoutages was two days duration. The first in Julyinvolved repairs to reheater tube leaks, replacementof one of the boiler circulating water pumps(BCWP), inspecting the lube systems on all BCWPs,testing the burner management system (BMS), test-ing the breaker for the motor driven boiler feedpump (BFP) and rebalancing the induced draft fan(IDF) 1-2. The second outage addressed repairs toone of the superheater temperature control spraylines. In December the third outage was to installthermocouples in the superheat and reheat sectionsof the boiler to collect performance data for firingnatural gas. The fourth maintenance outage took fivedays at the end of May to repair leaks in the genera-tor hydrogen cooling system.

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Unit 1 was forced from service for one day inSeptember to repair a service breaker associated withthe normal station service transformer (NSST) 1-A. Amonth later the unit was forced from service for threedays to repair a leak in the generator’s stator coolant;while those repairs were being performed a deaeratorleak was repaired and the condenser gates wereinspected and adjusted. In November the unit wasforced out for a day to repair superheater tube leaks.During this outage the proper operation of the forceddraft (FD) fans’ control vanes was verified, and theBMS and NSST were inspected. An eight hour forcedoutage in June was caused by a fault in the motordrive of BFP 1-2; this outage was continued as theenvironmental outage discussed above. The unit hadsix episodes of limitations during the fiscal year.Three occurrences were caused by condenser tubesleak, which amounted to one equivalent outage day.An electrical ground fault caused five hours equiva-lent outage hours in February. In May, problems withfouling of the regenerative air pre-heater (APH) cou-pled with a generator hydrogen leak accounted fortwo days equivalent outage hours. This unit was notplaced in economy shutdown at any time during fis-cal year 2013.

The next major outage for Unit 1 is scheduled tobegin in July 2014 and last 20 weeks, with its primaryobjective being the conversion of the boiler for firingnatural gas, in addition to heavy oil. The previousmajor outage was completed in February 2012, dur-ing which the control systems were upgraded for dualfuel operation. During the upcoming major outagethe scope of work will include an environmental out-age plus boiler modifications to the convection sec-tion (superheat and reheat) headers and tubes to becompatible with gas firing. Other work will includerepairs to thermal insulation, installation of newmotor control center (MCC) and switchgear for thecirculating water pumps.

The replacement of equipment and upgrades to sys-tems during major overhauls are funded through theCapital Improvement Program, CIP. The CIP allocatesa total of $23.6 million for the two Aguirre steamunits in fiscal year 2014 and $41.8 million the follow-ing year; these amounts include environmental proj-ects at the facility.

The Authority has a five year program to improve thequality and quantity of its plant water supply. Thefirst phase included installing a reverse osmosis (RO),unit and adding a demineralized water storage tank.The second phase involves improvements to thewater supply from PRASA in which two 2.5 million

gallon retention ponds, filtration equipment and pip-ing will be installed. Much of this scope is eligible forlow cost financing from the Commonwealth. Duringthe last year the Authority completed the refurbish-ment of one of the station’s fuel storage tanks; workon the next tank will begin in fiscal year 2014. Thereplacement of the boiler structural steel is continu-ing on both units. The CIP has also budgeted for therequalification of the HP/IP turbine rotor and of thegenerator rotor that was removed during the overhaulthat was completed in February 2012. The Authoritywill receive the replacement for the failed main powertransformer at Aguirre during fiscal year 2014.

ASP Unit No. 2 (nominal 450 MW) was in serviceand capable of full output on June 30, 2013. Duringfiscal year 2013 the unit was scheduled from servicenine times, these outages kept it from service for atotal of more than 18 days; there were nine forcedoutages causing the unit to be out eleven days. Theunit was in service for 8,046 hours during the fiscalyear. During the past fiscal year Unit 2 generated anaverage net output of 286 MW and recorded anannual capacity factor of 55%.

The three outages for repairs to the main boiler feed-water control valve (FCV-1) accounted for more thanhalf the year’s scheduled outage hours. Two of theseoutages were for more than four days: in January theelectrical to hydraulic actuator for the control valvewas cleaned and refurbished; in May a leak in thecontrol valve was repaired. In February during a twoday outage the stem on FCV-1 was replaced. InAugust a two day outage was scheduled to repairleaks in the boiler feedwater piping and some boilertubes. During the outage, maintenance was per-formed on the opacity meters, a burner isolation valvewas replaced, a small steam line leak was repaired, theBMS was tested, and the motor was replaced on themotor driven boiler feed pump. Most of the balanceof scheduled outage hours for this unit were for prob-lems with the superheater tubes and steam cooledhangers. The troublesome steam cooled hangers willbe replaced as part of the convection section redesignfor the conversion to gas firing. Repairs to the super-heater section were included in a two day outage inOctober and two outages in March totaling almostthree days. In March a leak in the superheat tempera-ture control spray water line was repaired in a one dayoutage.

The longest forced outage resulted from a breaker fail-ure that tripped the unit from service; repairs werecompleted and the unit returned to service 34 hoursfollowing the trip. The three other outages were less

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than half a day in duration. The Authority maderepairs to the generator brush assembly during twobrief forced outages, the longer of which was fourhours in duration. At the onset of a transmission sys-tem event the Authority put the unit in reserve shut-down and returned it to service 20 hours later.

Unit 2’s next overhaul is an extended environmentaloutage scheduled to begin in November 2013. In addi-tion to the full scope of an environmental outage’scleaning, inspection and maintenance, the scope ofwork will include the repair of the pendant superheatsupports, evaluation of the reheat elements and thereplacement of sections of boiler steel. The low pres-sure feed water heaters will be examined for usefullife. Thermal insulation will be repaired as necessary.

In fiscal year 2016 Unit 2 is scheduled for a majoroutage. During the overhaul the installation of gaspiping, pressure reducing valve stations, and burnerscapable of firing natural gas will be completed to sup-port full gas firing. A new turbine control system willbe installed, as will a new automated voltage regula-tion (AVR) system. The HP/IP turbine rotors and theturbine control valve will be replaced and the stopvalve inspected and refurbished. The generator statorwill be rewedged and the generator’s rotor will berewound. The deaerator will be replaced, as will thegates at the water boxes of the auxiliary condenser.The pipe type high voltage underground cable will berefurbished.

Costa Sur Steam Plant

CSSP Unit No. 1 and CSSP Unit No. 2 (both nom-inally 50 MW) these two units, which entered servicein the 1950s, were taken out of service in fiscal year2004. During fiscal year 2008 the Authority’s stoppedreporting on the availability of these two units andidentified systems within these units that provideservice to one or more of the other Costa Sur units;these units no longer house or support componentsor systems that service the balance of the plant. In thepast year the Authority solicited bids for the removalof these units. The bids confirmed that the cost todemolish these units will be difficult to fund in thecurrent environment of budgetary constraints. TheAuthority has deferred awarding the demolition workfor at least a year.

CSSP Unit No. 3 (nominal 85 MW) On June 30,2013 this unit was in reserve shutdown for economy;it was available for service with its output limited to65 MW due to chronic problems of boiler casing airinfiltration and with the air preheaters (APH). Thisunit was placed in reserve shutdown (RSH) for econ-

omy for approximately 204 days during fiscal year2013. It was in service the equivalent of 83 days dur-ing the fiscal year. Unit 3 was scheduled from servicetwice during fiscal year 2013 for a total of 76 days; thesecond scheduled outage was environmental. It wasforced from service once for less than three days. Theunit’s output was limited for the equivalent of almost19 days. When operating, Unit 3 generated an aver-age net output of 54 MW, it had an annual capacityfactor of 14%, and was in service 1,987 hours duringfiscal year 2013.

In August there was a four day maintenance outagefor boiler repairs. This unit began an environmentaloutage on October 1, 2012. The start was delayeduntil the completion of the Unit 6 environmental out-age, which had priority. Given the low dispatch ofUnit 3, plant labor issues in October and budgetaryconstraints, the outage schedule was extended toavoid overtime. During the outage the condenser wascleaned, condenser water gates were adjusted, sealson condenser vacuum equipment were replaced toreduce leakage, oil leaks on the BFPs were repaired,APH elements were cleaned, maintenance was per-formed on the forced draft (FD) and induced draft(ID) fans, damaged thermal insulation was replaced,large motors were cleaned and inspected, breakersand critical electrical equipment, including relays,were cleaned and inspected. When the unit’s environ-mental outage was complete the unit went into RSHstatus in December.

Unit 3 was forced from service once by boiler tube fail-ures. The repair of tube leaks kept the unit from avail-able status for almost three days in February. The unitwas in service with its capacity limited seven timesduring the fiscal year. The unit’s capacity was limitedthree times during the fiscal year while its condenserwas cleaned. The unit accrued the remaining equiva-lent outage days due to unresolved problems with theAPHs and boiler casing air infiltration and theirimpact on the ID fan performance. The Authority hasevaluated the cost to restore the APHs and boiler cas-ing and concluded the expenditure would not be costeffective given the prospective limited service hourscontemplated for this unit in the future,

The Authority returned Unit 3 to service on comple-tion of its most recent major overhaul in January2004. Since then the unit has accumulated less than48,000 service hours towards the 60,000 hour bench-mark for its next overhaul. In view of its low dispatchin the last five years, and the possible retirement orgreatly reduced service hours of this unit as part ofthe Authority’s compliance plan for MATS in the com-

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ing years, the Authority has not scheduled Unit 3 fora major overhaul. The next environmental outage isscheduled for March 2014.

The following discussion applies to projects that sup-port the entire Costa Sur Steam Plant and will be inservice after the potential retirement of the two 85MW units. The CIP includes $5.8 million for theseprojects in fiscal year 2014. During fiscal year 2013work continued on the turnkey construction of a newreverse osmosis (RO) facility, including the founda-tion, structure and equipment, to improve the qualityof make-up water supplied for demineralization.Electrical work continued on the RO facility’s newpower supply, which is scheduled for completion bymid-year fiscal 2014. The RO facility is scheduled togo into service in the third quarter of fiscal year 2014.Improvements to the foam fire protection system ofthe fuel storage tanks continued in the past year, thiswork had been delayed by the initial contractor’sfinancial problems. Piping for the foam protectionsystem to the reserve fuel tanks is scheduled to begincommissioning by mid-year fiscal 2014. The mainfuel tanks dike improvements were completed at theend of fiscal year 2013; the Authority plans to com-plete reinstallation of the recirculation piping withinsix months afterwards. The reserve tank dikes arescheduled for completion in the same timeframe.Rehabilitation of the main bridge crane for Units 5 &6 was completed in the past fiscal year.

The Authority has developed a program for compli-ance with the NPDES 316 (a) and 316 (b) require-ments regarding its cooling water systems impact onthe bay. The CIP for the three years 2014 through2016 includes $25.0 million for these projects. Thescope of work includes new floating barriers to divertfish at the intake, new higher capacity circulatingwater pumps and a bypass cooling water system tolower the temperature of the water returned to the bay.

CSSP Unit No. 4 (nominal 85 MW) On June 30,2013 this unit was in an environmental outage andunavailable for service. When the unit was availablefor service in the past fiscal year its output was lim-ited to 65 MW due to chronic problems of boiler cas-ing air infiltration and with the air preheaters (APH).Since Unit 4 is a duplicate of Unit 3 it is not unusualthat they have similar problems. This unit was placedin reserve shutdown (RSH) for economy for approxi-mately 148 days during fiscal year 2013. It was inservice the equivalent of 95 days during the fiscalyear. Unit 4 was scheduled from service once duringfiscal year 2013 for a total of 103 days. It was forcedfrom service six times for a total of 19 days. The unit’s

output was limited for the equivalent of 26 days.When operating, Unit 3 generated an average net out-put of 47 MW, it had an annual capacity factor of14%, and was in service 2,287 hours during fiscalyear 2013.

Unit 4’s environmental outage began in late March. Asdiscussed with Unit 3, the schedule for the outagewill be extended to avoid overtime and ensure main-tenance personnel are made available for work athigher priority units, such as Cost Sur Unit 5 andAguirre Unit 1. The primary scope of the outage willbe the cleaning, inspections, tests, and replacementscalled for by the Consent Decree with the EPA. Inaddition, the Authority plans to replace some of theAPH baskets and clean the balance of the baskets andadjust the APH seals to improve the boiler perform-ance. Major power system equipment will beinspected, including: FD and ID fans, large pumpsand motor drives, and the condenser. Relays will betested and recalibrated as necessary. The replacementcable from the generator breaker to the normal sta-tion service transformer (NSST) will be inspected.Generator auxiliaries will be inspected, cleaned andadjusted as necessary. Components of the distributedcontrol system and burner management system willbe selectively tested and adjusted as required for reli-ability. Process piping leaks will be repaired. All ofUnit 4’s RSH hours were accumulated in the sixmonths of October through March, when it was avail-able but operated only during February.

The unit was forced from service for the repair of tubeleaks in the boiler’s economizer section twice in Julyfor a total of six days. In February repairs of boilertube leaks forced the unit from service twice more fora total of almost eight days. In August the unit wasforced out when heavy rain lead to a detected fault inthe generator’s 13kV breaker; the situation wasresolved in two days. In February there was a fault inthe bus bars from the generator breaker to the NSST,leading to a three day outage during which insulatedcable was installed to replace the bus bars. Almost allof the 26 equivalent outage days accrued during fiscalyear 2013 were attributed to problems with the boilerair infiltration and APH fouling causing the ID fan tobe overloaded and exceed the capacity of its motor.Less than one day of equivalent outage time wascaused by condenser cleaning.

Unit 4 returned to service on completion of a majoroverhaul in February 2007. Since then the unit hasbeen in service approximately 39,000 hours towardsthe 60,000 service hour benchmark for its next over-haul. In view of its low dispatch in the last five years,

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and the possible retirement or greatly reduced servicehours of this unit as part of the Authority’s compli-ance plan for MATS in the coming years, theAuthority has not scheduled Unit 4 for a major over-haul. The next environmental outage will be sched-uled for 18 months after initial return to service fromthe current outage to comply with the requirementsof the Consent Decree.

CSSP Unit No. 5 (nominal 410 MW) was offline onJune 30, 2013 nearing the completion of a majoroverhaul. During fiscal year 2013 this unit was sched-uled from service for 210 days by the Authority. Amajor overhaul for full gas firing accounted foralmost all the outage days and two maintenance out-ages accounted for an additional three days; the unitwas placed in RSH for two days. One forced outageaccounted for less than a day on which the unit wasunavailable. The unit’s capacity was limited for theequivalent of two and half days during the fiscal year.Unit 5 generated an average net output of 281 MW,had an annual capacity factor of 28%, and was inservice 3,641 hours during fiscal year 2013.

Unit 5 was removed from service in the first week ofDecember to begin a major overhaul. The principalfocus was to make modifications to enable the unit tooperate continuously at full load with all natural gasfuel, as well as dual fuel firing of natural gas with theoriginal design fuel of residual fuel oil; the scope wassimilar to that already performed on Unit 6. Duringthe outage the scope of an environmental outage wasalso accomplished. The extensive scope of work per-formed during the major outage included repairs andmodifications to the boiler, overhaul of the main tur-bine generator, and repairs or refurbishments tomajor auxiliary systems. The work on the boilerincluded a condition assessment to inform life exten-sion measures for the boiler components, modifica-tions to the convection section headers, tubing,supports and baffles to accommodate the higher fur-nace gas temperature associated with natural gas fir-ing, thermocouples were installed, sections of thewaterwall tubing were replaced, and refurbishing thegas recirculation fan discharge ductwork. The gasburners were cleaned and inspected. Repairs to boilerstructural steel were performed. The deaerator pumpwas refurbished. Welds in the main steam line at theturbine regulating valves were repaired. The mainturbine HP, IP and LP rotors were overhauled and theseals were replaced. The generator stator windingswere rewound and new bushings installed. A Mark VIelectro- hydraulic control system for the turbine wasinstalled. The tubes in feedwater heater 3 were

replaced. The turbine lube oil cooler was retubed andthe lube oil system was pressure tested. The con-denser was retubed, its waterboxes were blasted cleanand coated, and the cathodic protection system wasrecalibrated. The unit is scheduled to return to serv-ice early in July, the first month of fiscal year 2014.The first of two maintenance outages was in July torepair a superheater line, it lasted 56 hours. The sec-ond scheduled outage was in November to repair abreak in the reheat temperature control spray waterline, it took 13 hours. In an unusual event, the unitwas placed in reserve shutdown (RSH) for economyfor 58 hours in July because of a transmission lineconstraint in the 115 kV system.

The single forced outage occurred in August as resultof heavy rain causing a field ground alarm; it wasresolved in 15 hours. In the past year there were fourinstances of limitations that totaled 62 hours; thethree attributed to condenser cleaning accounted for56 of the equivalent outage hours.

When the unit returns to service it will have com-pleted both a major overhaul and environmental out-age. The next major overhaul for this unit has notbeen scheduled within the next five years. The nextenvironmental outage is scheduled to begin inDecember 2014.

The Authority’s CIP includes $12.3 million in fiscalyear 2014 for capital projects at Units 5 & 6. Sincethese are twin units the scopes of required work aresimilar and their common design promotes sharingequipment. The CIP includes funds for a replacementboiler feed pump barrel assembly, which is the pump’scomplete internal operational unit. The spare assem-bly is scheduled for delivery in fiscal year 2015 andwill be compatible with the main feed pumps at CostaSur Units 5 & 6 as well as the Aguirre Units 1 & 2.The CIP also includes funds for replacing the highpressure feedwater heaters 6 & 7 of both Units 5 & 6;they are scheduled for delivery in fiscal year 2015.

CSSP Unit No. 6 (nominal 410 MW) was in serviceand capable of generating at its rated capacity on June30, 2013. In early July the unit began an environmen-tal outage with an expanded scope to upgrade theunit for full natural gas firing. This outage lasted 85days; subsequently there were two shorter scheduledoutages totaling three and half days. It was not placedin economy shutdown in the past fiscal year. Duringthe fiscal year 2013 Unit 6 had eight forced outagesthat accumulated to 18 days; the longest outageaccounted for half of that total. The unit’s capacitywas limited for the equivalent of less than one andhalf days during the past fiscal year. Unit 6 generated

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an average net output of 304 MW, had an annualcapacity factor of 52%, and was in service 6,204 hoursduring fiscal year 2013.

This unit began an expanded environmental outagein the first week of July; it returned to service at theend of September. In addition to performing the man-dated scope of an environmental outage, theAuthority performed a wide range of maintenanceand rehabilitation activities and made extensive boilermodifications to enable the unit to operate continu-ously at full load with all natural gas fuel, as well asdual fuel firing of natural gas with the original designfuel of residual fuel oil. The work on the boilerincluded a condition assessment to inform life exten-sion measures for the boiler components, modifica-tions to the convection section headers, tubing,supports and baffles to accommodate the higher fur-nace gas temperature associated with natural gas fir-ing, thermocouples were installed, sections of thewaterwall tubing were replaced, and refurbishing thegas recirculation fan discharge ductwork. The gasburners were cleaned and inspected. The reheat spraywas replaced, the superheat spray control valve wasrefurbished, safety valves were inspected repaired andtested, air heaters were cleaned and inspected. TheFD, ID, and GRF fans were inspected and mainte-nance performed. The GRF fan discharge duct wasrefurbished. Flue gas duct expansion joints wererepaired. Non destructive testing (NDT) was per-formed on four welds at the main steam turbine con-trol valves; the welds were last repaired in 2009. NDTwas performed on a superheat line and on the deaer-ator. The generator, stator and hydrogen cooling sys-tems were inspected and maintained, as was thegenerator’s seal oil system and the excitation system.The Authority replaced the bundle in the turbinedrive BFP 6-1 & 6-2 and the motor on BFP 6-2.Turbine CV 3 was repaired as was the discharge valveon BCWP 6-3. Station batteries and chargers wereinspected. Electrical equipment, motors, breakers,transformers were inspected and the maintenance toensure reliable service was performed. Routine main-tenance was carried out on the air compressors anddryers. Damaged or deteriorating thermal insulationwas replaced as necessary. At the conclusion of theoutage in September there was a brief outage toresolve startup issues. In November a maintenanceoutage lasting slightly more than three days was takento remove stop valve screens installed during theboiler overhaul.

The unit was unavailable for service for two days inOctober as the result of two events. The first was

caused by a clogged instrument air line to the ID fans,which restricted fan control. The second was toreplace the relief valve on high pressure feedwaterheater 7. In February there were two successiveforced outages that accounted for ten outage days.The initial event was to repair boiler tubes, whichtook less than a day, followed by repairs to welds inthe main steam piping at the turbine control valves –these were the same welds that had passed examina-tion during the environmental discussed above. Theweld failure prompted the Authority to re-evaluatethe problem and increase scheduled inspections. Thesame area was subsequently repaired in Unit 5 basedon the latest evaluation. In March the unit was forcedout for more than three days by a ground fault in theauxiliary transformer; a bushing was replaced. In Maythere were three forced outages, two were less thanone shift, while the longest was more than a day. Thisoutage was caused by low lube oil pressure in one ofthree boiler circulating water pumps, which trippedthe pump. The unit’s output was limited twice duringthe past year for an equivalent total of less than a dayand half, first by the inability to fully open a turbinecontrol valve (TCV), which was repaired during theextended outage, and secondly by broken condensertubes causing high conductivity in the condensate.

Unit 6 returned from its most recent major overhaulin November 2009. Recognizing that the scope of theextended outage in the past fiscal year included sig-nificant portions of a major overhaul, the next over-haul will be scheduled for fiscal year 2018.Environmental outages will be performed within 18month intervals.

Palo Seco Steam Plant

PSSP Unit No. 1 (nominal 85 MW) was in serviceand capable of 80 MW, on June 30, 2013. During fis-cal year 2013 the unit was scheduled from servicetwice and was forced from service eight times. TheAuthority completed an environmental outage, whichlasted almost 13 days, on this unit in October 2012.The scheduled maintenance outage in June alsolasted 13 days. The eight forced outages kept the unitfrom available status for a total of almost 14 days. Theunit’s output was limited five times; the Authorityplaced the unit in reserve shutdown for economyonce for a total of 13 days. The unit was in service fora total of 7,508 hours during the fiscal year; it gener-ated an average net output of 58 MW while in serviceand had an annual capacity factor of 59% for fiscalyear 2013.

The environmental outage was performed during thefirst two weeks of October. The scope included the

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routine activities for an environmental outage, plusrepairs to the boiler and other systems. Repairs weremade to the boiler casing to reduce air infiltration.Burners were inspected, cleaned and leaks repaired.Drains valves and traps for the superheater and mainsteam drain valve were refurbished or replaced. Thedrain valve on the lower boiler drum was replaced.The soot blowers were repaired, as was a steam leakat the turbine. A leak in the normal station servicetransformer (NSST) was repaired. The hydrogen cool-ers were inspected. The condenser tubes werecleaned. An updated distributed control system(DCS) was installed to support dual fuel (oil and nat-ural gas) firing. The scheduled maintenance outage inJune to repair a leak at a generator hydrogen seallasted almost 13 days. During April the Authorityplaced the unit in RSH for a total of 13 days.

In the past fiscal year the unit had the eight forcedoutages, however one accounted for the bulk of the13 total forced out days. At the end of March the unitwent off line to repair a failed APH main trunnionsupport bearing. The bearing had failed from 40 yearsof service. The plant fabricated two new bearingssince replacement parts were not readily available andreturned the unit to service in 11 days. In Januaryacidic water from Unit 2 contaminated Unit 1through a common condensate header. The unit wasout for almost two days to restore the correct boilerwater chemistry. Each of six remaining outages lastedless than five hours. In the course of the year the unitoutput was limited five times for an equivalent totalof four days.

The last major overhaul was completed in April 2008.Based on the forecasted service hours the next majoroverhaul that was originally scheduled for August2015 has been indefinitely deferred. The next envi-ronmental outage is scheduled for March 2014.

There were no capital projects budgeted specificallyfor Unit 1 during fiscal year 2013 and there are nonebudgeted for fiscal year 2014. The Authority repairedboiler casing, and seals on air heaters to reduce air inleakage and improve unit efficiency during times thatthe unit was in RSH for economy.

The CIP for fiscal year 2014 includes $4.4 million forthe Palo Seco steam units; it is principally directed tosupport Units 3 & 4. In fiscal year 2012 a second dis-tillate fuel transfer line between the Palo Seco and SanJuan Steam Plants went into service. This eight inchpipe-line increased the amount of distillate fuel read-ily available for San Juan Units 5 & 6, thereby easinga distillate storage constraint at San Juan Station. TheCIP includes funds for refurbishments to the original

pipeline during fiscal years 2014 and 2015. TheAuthority plans to finish the foam fire protection sys-tem for the fuel storage tanks at Palo Seco during fis-cal year 2014, with a total cost of $4 million. PaloSeco Units 1 and 2 entered service more than fiftyyears ago; the Authority has not budgeted for the con-version of these two units to gas firing.

PSSP Unit No. 2 (nominal 85 MW) was on line onJune 30, 2013, however, its capacity was restricted to55 MW because of condenser tube leaks. This unithad two brief scheduled outages for maintenanceduring the fiscal year. It was forced from service eighttimes; these outages kept the unit from available sta-tus for 24 days. This unit’s capacity was limited seventimes; it was placed in reserve shutdown for economyfor a total of 42 days. The unit was in service for atotal of 6,999 hours during the fiscal year; it gener-ated an average net output of 55 MW while in serviceand had an annual capacity factor of 52% for fiscalyear 2013.

The first scheduled outage in December lasted lessthan two days, it was to repair boiler tubes. The sec-ond maintenance outage lasted four days in Februaryto repair a generator hydrogen seal leak. Half of theunit’s RSH time of 42 was accumulated duringJanuary; the balance of the RSH hours were inOctober, December, and April.

Unit 2 was forced from service in July for more thanfour days to repair fuel oil line leak and replace pip-ing at a feedwater valve. In August the unit was forcedout for more than 12 days to repair a generator hydro-gen seal leak, this was the longest single outage. InSeptember the unit was unavailable for less than threedays to replace the failed main power transformer andreserve relay. Rainwater leaking into control boxescaused two outages, once each in October andNovember, these lasted less a day in total. In April theunit was forced out by condenser tubes leaks for lessthan four days. Since the condenser tubes were lastedreplaced in 2011 and the recent failures do not followa pattern, these premature failures are disconcerting.The Authority will perform additional inspectionsand testing to search for the root cause of the prob-lem. During fiscal year 2013 this unit accrued morethan 15 equivalent outage days while in service withlimited capacity; the most frequent cause was con-denser tube leaks.

Unit 2 is scheduled for its next environmental outagein October 2013; it returned to service on completionof its most recent major overhaul in November 2007.The next major overhaul of this unit that was sched-uled to begin in fiscal year 2014 has been indefinitely

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deferred, based on the forecasted service hours.While the Authority will continue with routine main-tenance, there are no capital projects for the unit bud-geted during fiscal year 2014.

PSSP Unit No. 3 (nominal 216 MW) On June 30,2013 this unit was out of service while performing anenvironmental outage that began on April 29, after afive day forced outage. During fiscal year 2013 theunit was scheduled from service seven times; onceearly in the fiscal year for an environmental outage,five times for maintenance and again for an environ-mental outage late in the year. Scheduled outagesaccounted for 93 days during the fiscal year. The unitwas forced from service eight times; these unsched-uled outages kept it from available status for a total of47 days. Unit 3 was placed in reserve shutdown foreight days during fiscal year 2013. The unit was inservice for a total of 5,215 hours during the fiscalyear; it generated an average net output of 153 MWand had an annual capacity factor of 42% for fiscalyear 2013.

Unit 3 began an environmental outage in early Julyand returned to available status 19 days later. In addi-tion to the mandated scope of an environmental out-age, routine cleaning, inspections and maintenance ofauxiliary systems were performed and controls wereinstalled for dual fuel firing, that is fuel oil and natu-ral gas. Four days after returning to service there wasa maintenance outage of less than one day duration torepair a pipe leak in the superheat spray system. A twoday maintenance outage in August was taken to rebal-ance the LP turbine. During another two day outage inSeptember boiler leaks were repaired and the APHcleaned. The second environmental outage began atthe end of April following a forced outage that was ini-tiated by broken refractory clogging the air preheaterbaskets and then subsequently when the LP turbineencountered high vibration during restart. Six of theeight days in RSH were accumulated in January.

Two of the eight forced outages were one shift induration, the other six ranged from one to 18 days inlength. In October the unit was forced from servicefor 18 days to replace LP turbine bearing 1, followingover temperature and vibration. In November theboiler water pH became too acidic leading to a oneoutage to remedy. In December there two outages torepair boiler tube leaks, these lasted a total of tendays. Repairs to the furnace waterwall and boilertubes forced a two day outage in January. In Februarythere was a fire caused by a ruptured flexible fuel hosein one burner corner; repairs to this forced outagetook 13 days. In April failed duct refractory fell onto

the unit’s APH. The clogged baskets restricted air flowand the unit taken out of service for cleaning. Duringrestart after the outage the LP turbine exhibited highvibration. Based on the severity of the vibration theunit was scheduled to begin its environmental outageearly. Examination of the LP turbine revealed stage L-1 blade movement and collateral damage; bearing 3was also in poor condition. During the outage NDTwas performed on the main steam piping to confirmits condition was satisfactory, although its design isthe same as that on Unit 4 which had cracks. Duringthe past fiscal year the unit operated with some limi-tations principally due to cooling issues with the cir-culating water system, these totaled five equivalentoutage days.

The schedule for the next environmental outage forUnit 3 will be established after the unit returns toservice from the repairs of its LP turbine. The unitreturned to service following completion of its mostrecent major overhaul in November 2009. Its nextmajor overhaul is included in the projected CIP forfiscal years 2016 and 2017 when it will be coordi-nated with the modifications to make this unit capa-ble of firing gas. The CIP for fiscal year 2014 includesfunds for repairs to the LP turbine and rehabilitationof the boiler. The scope of the boiler work includesreplacing boiler corners and superheat header 5,repair of superheater header 6, and replacing air pre-heater baskets and seals.

PSSP Unit No. 4 (nominal 216 MW) was in service,capable of full output on June 30, 2013. This unit wasscheduled from service for a total of 49 days duringfiscal year 2013 for three maintenance outages and anenvironmental outage. It spent one day in reserveshutdown for economy. In the past fiscal year the unitaccumulated six forced outage days from ten inci-dents, of which four lasted one day each. The unit’soutput was limited four times, with the total equiva-lent outages of ten days. The unit was in service for atotal of 7,421 hours during the fiscal year; it gener-ated an average net output of 144 MW and had anannual capacity factor of 57% for fiscal year 2013.

The unit was scheduled from service for three andone half days in August to clean the APH baskets; thedeteriorating baskets had become a chronic problemthat limited the unit’s capability. In November theunit began a 33 day environmental outage. In addi-tion to the required maintenance, cleaning, inspec-tions and tests, the Authority installed an upgrade tothe distributed control system (DCS) for dual fuel fir-ing, that is natural gas in addition to fuel oil. Duringthe outage the APH baskets and seals were replaced;

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the normal station service transformer (NSST) wasreplaced with one of more capacity. Refurbishing thetwo air preheaters increased the boiler’s performanceand the unit’s capacity. There was a one day mainte-nance outage in March to replace the seat of a boilersafety valve. In April the unit was out for ten days torepair the main steam piping at the stop valve andperform NDT on the opposite line; Unit 3’s similarpiping was also examined. This unit was placed inRSH for one day in December.

Unit 4 was forced from service ten times for a total ofsix days. There were four one-day forced outages, thebalance of unscheduled outages were random andbrief. In November the unit was forced from servicefor a day because of low pH in the boiler water, whichresulted from a failed pH meter. The unit was forcedout for one day in December to repair boiler tubeleaks and another day to repair an internal fault in themotor control center feeding the boiler feed pump. Acontractor punctured a buried cooling water line inMay while extending the fire protection foam pipingto a fuel oil tank; the unit was out for one day. Theunit remained in service with limited capacity for atotal of ten equivalent outage days principally due tofouled APH baskets prior to their replacement.

The next environmental outage is scheduled for April2014. The unit returned to service following comple-tion of its most recent major overhaul in July 2009. Itsnext major overhaul is included in the projected CIPfor fiscal years 2016 and 2017 when it will be coordi-nated with the modifications to make this unit capa-ble of firing gas. The CIP for fiscal year 2014 includesfunds for a training simulator of the plant, includingthe high voltage gas insulated switchgear interface,and rehabilitation of the boiler, during which it willreceive new boiler corners, burners, valves, and a newburner management system. The CIP includes fundsfor the rehabilitation of the turbine generator as partof the next major overhaul.

San Juan Steam Plant

Units 1, 2, 3, & 4 have been retired from service formore than three decades. Units 5 & 6 are discussedunder the Combined Cycle Plant section.

SJSP Unit 7 (nominal 100 MW) was not in service onJune 30, 2013; it was out for repairs to the circulatingwater traveling screens. During fiscal year 2013scheduled outages kept Unit 7 from service for 100days. The longest outage was an environmental andthere were six maintenance outages. Unit 7 wasplaced in reserve shutdown for economy for ninehours during the past fiscal year. There were four

forced outages that kept the unit from service for 30hours in total. The unit’s operating limitations werethree equivalent outage hours in the past year. Duringthe 6,326 hours that Unit 7 was in service it generatedan average net output of 74 MW and had an annualcapacity factor of 54%.

The environmental outage for Unit 7 began late inFebruary. In addition to all the required inspections,cleanings and tests required for compliance with theConsent Decree, the scope of work included mainte-nance on turbine control valves, cleaning the boilerfeed pump motors, repairing boiler tubes, assessmentof the boiler’s condition, and beginning the installa-tion of new control wiring from the electrical room tothe control room for regulation of the unit output, toreplace old and damaged wiring. The scope of workwas expanded to include removal of known asbestosinsulation where the metal jacketing was deterioratingand beginning to expose the asbestos insulation. Allthe insulation containing asbestos was abated from thelow pressure feedwater heaters and piping. The unitwas out of service for 82 days for this extended outage.Previously, in August the unit was scheduled out for afour day maintenance outage to repair turbine controlvalves and clean the coolers for the turbine’s main oiltank. There were two maintenance outages inSeptember for less than two days in total to repairleaks in the fuel oil heaters and clean the condensatefilters. There was a three and a half day scheduled out-age in January to repair leaks in the auxiliary steampiping. There as a brief maintenance outage in mid-June to replace deteriorated wiring at the main turbinecontrol valve. Late in June the unit began a mainte-nance outage to repair circulating water travelingscreens; the work extended into early July.

During the past year the unit was forced from servicefour times for a total of 30 hours, of which one out-age accounted for 20 hours. In November the unitwas forced out for almost a day to replace a failed tur-bine lube oil pump motor. Two other forced outageswere to replace a burner control system solenoid anda failed motor control relay for a boiler feed pump.The last forced outage was in February to repair leak-ing boiler tubes; after an hour this outage transitionedto the scheduled environmental outage.

Since all the steam plant units at San Juan have expe-rienced an increase in trips associated with variouscontrol system’s reliability, the Authority hasincreased its focus on improvements to control sys-tem maintenance activities, including replacing oldcables, and operator training.

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Unit 7’s next scheduled outage will be an environ-mental outage in May 2014. It is scheduled for anoverhaul late in fiscal year 2015. During the overhaulthe turbine, generator and boiler will be refurbishedto the extent consistent with the unit’s forecasted lowutilization for compliance with the air regulationsthat will be in effect after that. The unit is not sched-uled for conversion to gas firing. This unit’s last over-haul was completed in fiscal year 2008.

The station’s capital projects in the CIP for the foursteam units for fiscal year 2014 total $4.7 million.The funds are directed to improvements in the plantcirculating water traveling screens, cathodic protec-tion of the condensers, revisions to discharge waterstreams for compliance with the NPDES criteria. Inaddition the Authority will continue its program ofrehabilitation of the plant fuel storage tanks.

SJSP Unit 8 (nominal 100 MW) was online, capableof full output on June 30, 2013. This unit was sched-uled from service four times for maintenance duringfiscal year 2013 for a total of 33 days. Unit 8 wasplaced in reserve shutdown for economy for four andone half days during the past fiscal year. The unit wasforced from service sixteen times, accruing a total ofless than nine forced outage days during the fiscalyear. During the 7,644 hours that Unit 8 was in serv-ice it generated an average net output of 72 MW andhad an annual capacity factor of 63%.

The unit’s first maintenance outage was in Septemberto clean the condenser waterboxes and tubes; itreturned to service after three days. In Novemberthere was a 12 day maintenance outage to repair tubesin feedwater heater 6 and clean the oil side of the tur-bine lube oil cooler. In December the unit was sched-uled out for five days to replace the bonnet gasket inthe main stop valve and to plug tubes in feedwaterheaters 2 and 3. There was a 14 day outage beginningin late May to repair tubes in feedwater heater 5 andinspect the generator hydrogen cooling system forleaks at the bearing and coolers. This unit was placedin reserve shutdown for economy for four days inNovember.

Three of the forced outages for boiler waterwallrepairs in Unit 8 during the past year accounted for65% of the total hours lost to forced outages; only onemore forced outage lasted a day. Some of the dozenremaining outages were caused by problems withaging control elements (such as switches, sensors andrelays) and control wiring, consequently theAuthority has increased inspections and replacementof suspect components in the plant’s controls. As withUnit 7, the Authority has begun replacing old control

wiring with new control wiring in Unit 8 from theelectrical room to the control room for regulation ofthe unit output. Except for those discussed below,forced outages were brief and the unit usuallyreturned to service following completion of correctiveaction within one shift. In July, October andDecember the unit was out of service for a total ofalmost six days to repair boiler waterwall tube leaks.Unit 8 was forced from service in April for the repairof a circulating water pump coupling, the repair wascompleted and the unit was placed in service in oneday. This unit had no equivalent outage days in thepast fiscal year.

Unit 8’s next scheduled outage will be an environ-mental outage in August 2013. It returned to serviceon completion of its most recent major overhaul inNovember 2010. It is scheduled for a major overhaulearly in fiscal year 2017. During the overhaul the tur-bine, generator and boiler will be refurbished to theextent consistent with the unit’s forecasted low uti-lization for compliance with the air regulations thatwill be in effect after that. The unit is not scheduledfor conversion to gas firing.

SJSP Unit No. 9 (nominal 100 MW) was online,capable of full output on June 30, 2013. Unit 9 beganservice during the past fiscal year in August; servicewas delayed for installation of the refurbished LP tur-bine. The unit was scheduled from service seventimes for maintenance during fiscal year 2013 for atotal of 33 days. Unit 9 was placed in reserve shut-down for economy for 14 days during the past fiscalyear. The unit was forced from service nine times,accruing a total of 38 forced outage days during thefiscal year, including the LP turbine outage that beganthe year. During the 6,720 hours that Unit 9 was inservice it generated an average net output of 72 MWand had an annual capacity factor of 55%.

The first two scheduled maintenance outages were inAugust to support testing and make adjustments fol-lowing startup after the LP turbine was restored; theselasted eight days in total. Transport time and refur-bishment of the LP turbine in a mainland shop hadtaken effectively all of fiscal year 2012, consequentlythe unit did not begin recovery startup until the firstof August. In October the unit was scheduled out forless than a day to repair leaks at various vents anddrains. There was a ten day maintenance outage inDecember to repair boiler waterwall tube leaks. InMarch the unit was scheduled out for 12 days tochange a recirculation valve for one of the boiler feed-water pumps and to correct a hydrogen leak at thegenerator bearing 5. During a brief maintenance out-

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age in April a leak in the main steam stop valve seatdrain was repaired. In May the unit was scheduled outfor less than two days to repair tube failures in the pri-mary superheater. The unit was placed in reserve shut-down for economy for 14 days in March and April.

The longest forced outage was the continuation of theforced outage caused by the LP turbine blade failureat the beginning of fiscal year 2012. This outageaccounted for 32 of the 38 days the unit was forcedout during fiscal year 2013. In August the unit wasforced out of service for two days to repair boilerwaterwall tubes. There was a two day outage in Mayto repair tubes in the boiler reheat section. The otherforced outages were brief, with four related to variouscontrol system problems and one operator error. Theunit’s only equivalent outage hours were five inFebruary.

The unit is scheduled for an environmental outage inNovember 2013. It is scheduled for conversion to gasfiring in fiscal year 2017, in conjunction with modi-fied scope of a major maintenance. The unit’s lastmajor maintenance was completed in August 2012.

SJSP Unit No. 10 (nominal 100 MW) was unavail-able for service after being forced from service torepair a failed air preheater trunnion thrust bearinglate in June 2013. Repairs are scheduled for comple-tion in the first ten days of fiscal year 2014. This unitwas scheduled from service three times for mainte-nance and once for an environmental outage; in totalthese outages kept it from service for 48 days. Theunit was placed in reserve shutdown for economy forone day. It was forced from service 13 times; as aresult of these outages the unit accrued 16 outagedays. The unit accrued one equivalent outage daywhile unable to generate at its nominal capacity.During the past fiscal year Unit 10 was in service7,198 hours, it generated an average net output of 72MW and had an annual capacity factor of 58%.

In July the unit was scheduled for a maintenance out-age to repair the thrust collar on the air preheater(APH) 10-1 trunnion bearing. During the nine and ahalf day outage the plant fabricated and installedreplacement parts; the unit then returned to service.A 29 day environmental outage began during the firstweek of September, ending in October. In addition toall the required inspections, cleanings and testsrequired for compliance with the Consent Decree, thescope of work included the transition to an upgradeddistributed control system and beginning improve-ments to control wiring from the electrical room tothe control room for regulation of the unit output, toreplace old and damaged wiring, and removing aban-

doned control wiring from cable trays. During thisoutage the repair fabrications for the trunnion bear-ing in APH 10-1 were inspected by NDT and foundsatisfactory. Two weeks after returning from the envi-ronmental outage the unit was scheduled for a main-tenance outage of less than three days to repair tubeleaks in feedwater heater 5. In January the unit wasscheduled out of service for seven days to repair mul-tiple leaks in the extraction steam piping and to repairleaks in the atomizing steam at the burners. The unitwas placed in reserve shutdown for economy twicefor a total of one day.

The longest forced outage for this unit occurred inJanuary when high condensate conductivity forcedthe unit from service. Leaking condenser tubes wereplugged; the unit returned to service eight days afterbeing removed from service. A variety of control sys-tem problems accounted for five days of the remain-ing forced outages, many of which were brief. InOctober the unit tripped three times due to instabilityin the boiler water level control, the third trip was ini-tiated by electric system transients; these outagesresulted in two days out of service. The boiler waterlevel controls were adjusted. In November the unitwas tripped once by a false signal of loss of fuel andthen by control problem resulting in high main steamtemperature. In March the unit was tripped by a faultin the generator lockout caused by a defective cablethat was replaced. This unit tripped twice in May. Thefirst was caused by an electric system rapid loadchange while the unit was operating in regulation,resulting in a trip from low boiler water level; theboiler water level controls were retuned. The secondoutage in May was caused by operator error inadver-tently energizing a generator protective relay. The lastforced outage of the past fiscal year was to repair thetrunnion bearing on APH 10-1 at the end of June. Thefabricated repair parts installed a year earlier did notsurvive the duty. New replacement bearing compo-nents were being installed at the end of the fiscal year.

Unit 10 is scheduled to begin an environmental out-age in November 2013. The unit returned from amajor overhaul in August 2009 and is scheduled for amajor overhaul in fiscal year 2016, when the scope ofthe work will include gas conversion.

Combined-Cycle PlantTotal Generating Capacity 1,032 MW

The combined-cycle units located within the Aguirregenerating complex contain 592 MW and the SanJuan Units 5 & 6 located within the San Juan SteamPlant add 440 MW of dependable combined cycle

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capacity to the System. The status of these combinedcycle units is discussed below.

Aguirre Combined-Cycle Plant

This combined-cycle plant is comprised of two dupli-cate units, both rated at 296 MW. Each unit consistsof four combustion-turbines (CTs), each rated at 50MW, with individual heat recovery steam generators(HRSGs), i.e. boilers, powering a single 96 MW steamturbine-generator (ST). This configuration yields aunit capacity of 296 MW and a total plant capacity of592 MW. These units are primarily used for cyclingduty. During fiscal year 2013 the Aguirre CombinedCycle plant recorded a net capacity factor of 6% whilegenerating 1.5% of the total System’s net generation.The station’s net generation for fiscal year 2013 wasapproximately 20% less than the previous fiscal year.At the end of fiscal year 2013 the steam turbine forUnit 1 was unavailable, the steam turbine-generatorin Unit 2 was available with significant limitation andall of the eight CTs were available for service.

In the following discussion the CTs and steam tur-bine-generators at this plant are identified by unit andnumber and with respect to CTs by order within theunit, i.e. the second CT in Unit No. 1 is numbered CT1-2 and the steam turbine-generator in Unit 2 is iden-tified as ST-2.

When the four CTs of a unit are in combined servicethe associated steam turbine-generator is rated ashaving a design capacity of 96 MW. Compromisedsteam production caused by exhaust duct seal leakageand poor steam condenser performance have com-bined to impose long term limitations on the capacityof the steam turbine-generators in both units, how-ever. In fiscal year 2004 the Authority began a pro-gram to replace the poorly sealing diverters upstreamof each HRSG. The diverters were leaking hot com-bustion turbine exhaust gases to atmosphere beforethe hot gases passed through the HRSG. The loss ofhot gas reduced the amount of steam generated ineach HRSG to below the quantity required for itsassociated steam turbine to generate at design condi-tions. The last of the eight new design diverters wasinstalled in fiscal year 2012. Since the seals on severalof the replacement diverters have been in service foreight or nine years they are now in need of replace-ment. Consequently, the Authority has begun a sec-ond round of replacing the diverter seals.

In addition to the losses attributed to poorly sealingdiverters, the two steam turbine- generators are alsolimited by inefficient condensing operations. Thehigh temperature of the cooling water in the closed

loop cooling system is a major factor limiting the effi-ciency of the condensers. Periodic cleanings andremoval of scale deposits from the condenser tubeshave improved condenser vacuum and each unit’sheat rate. The Authority plans to refurbish the cool-ing towers and replace old vacuum pumps duringscheduled overhauls.

Recognizing the age of the original combustion tur-bines’ technology, the Authority has completed anupgrade of the combustion system on all eight of thestation’s CTs. The upgrade brings the CTs to a modi-fied Frame 7EA design, which gives the CT the capa-bility of operating at a higher combustiontemperature, thereby improving its efficiency.Additionally the fired hours between combustioninspections, formerly every 4,000 equivalent firedhours (EFH), is increased to every 5,300 EFH. Thisincrease in EFH has increased the interval betweencombustion inspections by six or more months. Thereplacement of the air inlet filter houses and filtermedia was performed concurrent with the CT’supgrade. An upgrade of the distributed control sys-tem (DCS) has been completed in both units.Following the decision in 2009 to suspend the con-struction of a pipeline that would have brought natu-ral gas to these CTs the Authority blinded off theeight modules that gave the station dual fuel firingcapability, put the nozzles in protected storage, andinstalled climate control air conditioners in each ofthe modules. The dual fuel modules have not beencommissioned. During the past year the OEM beganan evaluation of the turbines for conversion to drylow NOx combustors firing natural gas. This technol-ogy would increase the potential operating hours onnatural gas by reducing its emissions. The combinedcycle plant will utilize a portion of the natural gasslated for delivery to the Aguirre plant.

The Authority’s CIP for fiscal year 2014 includesfunds for completion of the overhaul of the steam tur-bine for Unit 1, rehabilitation of the cooling towersand scheduled inspections the combustion turbinesCT 2-1 and CT 2-3. The budget for these projects infiscal year 2014 is $7 million.

ACCP Unit No. 1 was available for service and capa-ble of generating 200 MW on June 30, 2013. The fourCTs that comprise this unit were available for serviceat their rated capacity of 50 MW. The steam turbine-generator was out of service for the overhauldescribed below.

CT 1-1 was available for service 8,718 hours duringfiscal year 2013 and was in service 471 hours. ThisCT had two brief maintenance outages and four

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forced outages in the past year. None of the outageslasted more than ten hours and none of the causeswere repeated. The maintenance outage in Februarylasted eight hours to reconnect the auxiliary trans-former to CT 1-2. In March there was a seven hourmaintenance outage to replace a breaker at the stationtransformer. Both of these maintenance outageseffected all four CTs in Unit 1, except for CT 1-3which was already out of service in March for gener-ator rotor repairs. One forced outage of nine hours forCT 1-1 was caused by a false high temperature signalfrom the main power transformer which tripped allfour CTs in Unit 1 in August.

CT 1-2 was available for service 8,716 hours duringfiscal year 2013 and was in service 608 hours. In addi-tion to the two common maintenance outages andone common forced outage, this CT had three forcedoutages. Two forced outages were initiated by highpressure alarm in the exhaust duct, these lasted fourhours in total. In February the repair of the combus-tion turbine cooling fan forced the unit out for 17hours.

CT 1-3 was available for service 5,625 hours duringfiscal year 2013 and was in service 601 hours. In addi-tion to the common February maintenance outageand the one common forced outage, this CT hadanother scheduled maintenance outage and six forcedoutages, one of which extended into a maintenanceoutage. In October CT 1-3 and CT 1-4 were sched-uled out of service for five hours to repair an oil leakin their shared main power transformer. Three of theforced outages totaled seven hours. Repair of a fuelpressure instrument line forced the unit out for 17hours in October. In December the unit was forcedout for 15 hours to repair a leak in the instrumenttubing at the high pressure fuel filter. In February theunit was forced out with a failed restart; the generatorrotor required rewinding. In March the outage wasclassified as a maintenance outage. The repaired rotorreturned to the plant and was installed before the endof June.

CT 1-4 was available for service 8,717 hours duringfiscal year 2013 and was in service 794 hours. ThisCT had three common scheduled outages as dis-cussed above for CT 1-3. The CT also shared oneforced outage with the others in Unit 1. In additionCT 1-4 had one forced outage in June lasting 19 hourscaused by mis-operation of the generator breaker. Inthe past fiscal year the hours of operation for CT 1-4were second only to CT 2-1.

ST-1 was available for service 5,703 hours in the pastfiscal year and was in service 701 hours. During fiscal

year 2013 the steam turbine had three scheduled out-ages and five forced outages. Four of the forced out-ages accumulated 20 hours and all were less than tenhours in duration. A forced outage in January lasted13 hours to correct faulty condenser hotwell levelcontrol. The first scheduled outage lasted 33 hours inOctober to repair an oil leak in the unit’s main powertransformer and repair a breaker. In February thesteam turbine was scheduled out with the Unit 1 CTsfor eight hours to reconnect the auxiliary transformer.Later in February the steam turbine was scheduledout of service to repair hydrogen leaks at the genera-tor bushings. In April ST-1 began a scheduled majorinspection. The previous major inspection was com-pleted in 2000. The planned work is scheduled to becompleted in the first quarter of the fiscal year 2014.

During the turbine outage the Authority plans toaddress maintenance activities, including structuralrepairs to the cooling tower and installing new cool-ing tower fill. The condenser vacuum pumps will berefurbished, the condenser will be mechanically andchemically cleaned, the condenser expansion jointswill be replaced and the condenser waterboxes will berepaired. The boiler feed pump will be requalified andthe circulating water pump impellers will be trimmedto prevent overloading its motor. The 48” and 60”diameter cooling piping from the cooling tower willbe inspected. The major inspection of the steam tur-bine will include rewedging the generator stator,rewinding the generator rotor, and replacing the LPfirst stage buckets. Electrical inspections of bushings,auxiliary components, and transformers are sched-uled.

ACCP Unit No. 2 was available for service and capa-ble of generating 265 MW on June 30, 2013. Theunit’s four CTs were available for service, each wascapable of generating 50 MW; ST-2, the steam tur-bine-generator was available but limited to 65 MWdue to condenser performance issues.

CT 2-1 was available for service 8,584 hours duringfiscal year 2013 and was in service 1,109 hours.During the past fiscal year this CT was scheduled outof service four times and forced out once. The oneforced outage lasted two hours to replace a defectivecontrol card. In November the CT was scheduled outof service 55 hours to repair a faulty flame scanner.The following month the CT was out for 100 hours forscheduled maintenance on the main power trans-former. In January the CT was out seven hours whileits auxiliary transformer was reconnected. A corrodedsection of fuel piping was replaced in February duringa six hour outage.

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This CT is scheduled for an inspection during fiscalyear 2014. CT 2-1 had the best net heat rate of all theCTs and its service hours were more than any other CT.

CT 2-2 was available for service 8,193 hours duringfiscal year 2013 and was in service 689 hours. Duringthe past fiscal year this CT was scheduled out of serv-ice three times; it was forced out twice. DuringDecember the CT had a scheduled combustioninspection. The air intake ducts were replaced, aswere the radiators and fuel oil recirculation line. Thelube oil tank was cleaned. While the CT was out ofservice, scheduled maintenance on the main powertransformer was performed. In January the CT wasout seven hours, along with CT 2-1, while its auxil-iary transformer was reconnected. In June the CT wasout of service to allow replacement of the expansionjoint at the HRSG diverter. In September this CT wasforced out for six hours to replace a defective relaycontrol card. In December it was forced out of servicefor 106 hours to correct problems caused by low levelin the lubricating oil system.

CT 2-3 was available for service 8,709 hours duringfiscal year 2013 and was in service 632 hours. Duringthe past fiscal year this CT was scheduled out of serv-ice two times; it was forced out three times. The twoscheduled outages accrued 11 hours out of service;one outage was to replace a cable from the NSST andthe other was to replace a radiator. A forced outage inSeptember lasted six hours to replace a defective relaycontrol card. Two events, in October and December,added two hours more of forced outage time for thebalance of the fiscal year. During fiscal year 2014 thisCT is scheduled for a major inspection during whichits compressor section will be replaced with the sparecompressor section. The compressor from CT 2-3 willbe sent for refurbishment; it will be stored as a sparefollowing its return.

CT 2-4 was available for service 7,998 hours duringfiscal year 2013 and was in service 522 hours. Duringthe past fiscal year this CT was scheduled out of serv-ice three times; it was forced out twice. In October theCT was scheduled out for seven hours to replace acable from the NSST, concurrent with CT 2-3. InFebruary the CT had a combustion inspection. Basedon prior inspections by a technical advisor, bearing 2was replaced. This outage lasted 517 hours and theCT returned to available status. In March the CT wasinspected to verify alignment of the mechanicalaccessories, this outage lasted eight hours.

ST-2 was available for service 7,837 hours in the pastfiscal year and was in service 1,062 hours. During fis-cal year 2013 the steam turbine had four scheduled

outages and ten forced outages. Two of the scheduledoutages and one forced outage were to repair circulat-ing water system piping. In August the steam turbinewas unavailable for 60 hours to repair corrosion / ero-sion in the 60” diameter circulating water line at thepump discharge. The turbine was forced out of serv-ice for 67 hours in September to repair a break in thecirculating water piping manhole at the condenser.Scheduled repairs in October to the buried circulatingwater piping and manhole required an additional 740hours. Two brief scheduled outages in March accruedten hours in total. In September the steam turbinewas forced out twice more, the first lasted six hours torepair a protective relay for the main power trans-former; the second was caused by the turbine controlvalve failing to operate over its full range, this wasrepaired in 18 hours. The remaining seven forced out-ages were brief and accumulated 20 hours in total.

San Juan Combined Cycle

Units 1, 2, 3, & 4 have been retired from service formore than three decades. Units 7, 8, 9 & 10 are dis-cussed in the Steam-Electric Production Plant section.

SJ Unit 5 (Dependable Capacity of 220 MW) is a com-bined cycle unit comprised of CT 5, a combustion tur-bine with a capacity of 160 MW and ST 5, a steamturbine with a capacity of 60 MW. The unit begancommercial operation in October 2008. During fiscalyear 2013 Unit 5’s combustion turbine was availablefor service 6,909 hours and in service 4,394 hours,which was a decline of one-third in the service hoursfrom the previous year. When in service the combus-tion turbine’s average net generation was 114 MW. Infiscal year 2013 the unit’s steam turbine was in service4,250 hours of the 8,438 hours that it was available forservice; it generated an average of 40 MW. For fiscalyear 2013 Unit 5 generated 3.2% of the total Systempower and achieved a net capacity factor of 35%.

The Authority has a long term multi-year serviceagreement with the combustion turbine vendor toprovide technical advice and to perform inspectionsof the combustion turbine generators and the steamturbine generators that comprise San Juan Units 5 &6. The Authority is responsible for the inspection andmaintenance of auxiliary equipment in these units. Adiscussion of the frequency of the contracted inspec-tions and their scope is found in the Maintenancesection above.

SJ CT 5 was available for service and capable of gen-erating 160 MW on June 30, 2013. During fiscal year2013 this CT was scheduled from service eight times;these outages kept it from service for a total of 64

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days. It was forced from service eight times andaccrued a total of 14 forced outage days as a result.CT 5 was in service approximately 183 days and wasin reserve shutdown 105 days.

This combustion turbine had six scheduled outagesbetween July and October, prior to its scheduledModified Combustion Inspection at 32,000 ESH. TheCT was scheduled out of service twice in July andAugust for a total of two days to do weld repairs onthe generator hydrogen piping. An equal amount oftime was spent in August and September during twooutages to replace the turbine inlet pre-filters. InSeptember the CT was scheduled out twice for a totalof less than a day while the ST 5 circulating water fil-ters at the condenser were cleaned. The Authorityreplaced the inlet air filters in a two day scheduledoutage in June. The operating life of the inlet filtersand pre-filters has improved since completion of con-struction of the GIS structure, its associated improve-ments and paving the areas that are adjacent to Units5 & 6 combustion turbines. The scheduled inspec-tion took the combustion turbine out of service fromOctober to mid-December. The scope of the ModifiedCombustion Inspection includes replacement of fuelnozzles, combustor baskets, transition pieces, turbineblades in rows 1, 2, 3, and 4, and turbine vane andring segments in rows 1 and 2. Inspections of theinlet, compressor, turbine, and exhaust sections of thecombustion turbine were also performed. The returnto service was delayed by observed high vibration andrebalancing the power turbine.

The longest forced outage for CT 5 was caused byrepairs of a steam control valve dump at the con-denser of Unit 5’s steam turbine. This forced CT 5from service for a total of almost six days in the begin-ning of July. A leak in the circulating water pipingsprayed sea water on the condensate pump motorcausing the pump and the steam turbine to trip; thisoutage lasted nine hours. Additional repairs to thecirculating water piping in March forced a steam tur-bine outage lasting less than three days. Temporaryrepairs were completed and the CT returned to avail-able status; permanent repairs have been added to theplant’s CIP. During three forced outages in May theCT accrued more than four days out of service as theresult of incorrect set points or logic in the DCS; thesestemmed from migration of old files into the updatedDCS. These values were checked and corrected. Thetwo other events that forced CT 5 from available sta-tus were each resolved in one shift or less and theircauses were unrelated.

The Authority has scheduled CT 5 to come out ofservice in January 2014 for a Combustion Inspection.During this work the generator will be rewedged andupgrades to the HRSG will be incorporated. The CIPincludes funds for purchasing the parts to modifyboth of the combustion turbines for dual fuel capabil-ity, firing natural gas or distillate. The conversionwork is scheduled for fiscal year 2017.

SJ ST 5 was capable of generating 60 MW on June 30,2013. During fiscal year 2013 it was in service 177 ofthe 352 days that it was available for service. In thepast fiscal year this steam turbine was scheduled formaintenance four times during which it accrued fourdays out of service. Seven unscheduled service inter-ruptions forced ST 5 to be unavailable for service fora total of ten days in the past fiscal year. TheAuthority placed the steam turbine in reserve shut-down for economy for 175 days during the fiscal year.

This steam turbine was scheduled out of service ontwo successive days in September to clean circulatingwater filters at the condenser; the operation took oneday in total. In March the turbine was scheduled outfor 6 hours to replace its hydraulic control system oilfilters. The last scheduled outage was in June whileCT 5 air filters were replaced, which lasted two days.

The longest forced outage was to repair a steam con-trol valve dump at the condenser of Unit 5’s steamturbine. This forced ST 5 and CT 5 from service for atotal of almost six days in the beginning of July.Repairs to the circulating water piping in Marchforced a steam outage lasting less than three days.Temporary repairs were completed and the STreturned to available status; permanent repairs havebeen added to the plant’s CIP. The three forced out-ages in May for CT 5 described above had similarconsequences on ST 5, which accrued 15 hoursunavailable from these incidents.

SJ Unit 6 (Dependable Capacity of 220 MW) is func-tionally a duplicate of the combined cycle Unit 5, withCT 6 being a 160 MW combustion turbine and ST 6being a 60 MW steam turbine, ST 6. This unit alsobegan commercial operation in 2008. On June 30,2013 both the combustion turbine and steam turbinein Unit 6 were available. During fiscal year 2013 theunit’s combustion turbine was available for service8,741 hours and was in service 3,071 hours; whileoperating it generated a net average of 127 MW. In thepast fiscal year the steam turbine was available for serv-ice 4,414 hours and was in service 2,183 hours; whileoperating it generated a net average of 42 MW. For fis-cal year 2013 Unit 6 generated 2.3% of the Systempower and achieved a net capacity factor of 25%.

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SJ CT 6 was available for service and capable of gen-erating 160 MW on June 30, 2013. During fiscal year2013 this CT was not scheduled from service; it wasforced from service six times and accrued a total of 18forced outage hours as a result. CT 6 was in serviceapproximately 128 days and was in reserve shutdown236 days.

For CT 6 the average duration of each forced outagewas three hours; the causes were not repetitive andtheir occurrences were infrequent. In chronologicalorder, the outages were caused by a failure in the 480volt auxiliary electrical system, weld repairs to a fuelline, repair of the master trip relay associated withnew control system components, CT exhaust gas pathcondition trip, incorrect operation of a 115 kVbreaker and failure of the air conditioning units forthe generator exciter room.

The Authority has scheduled CT 6 to come out ofservice in August 2013 for a Combustion Inspection.During the outage the turbine will be inspected toidentify the cause of high vibration in bearing #2. TheCIP includes funds for purchasing the parts to mod-ify both of the combustion turbines for dual fuelcapability, firing natural gas or distillate. The conver-sion work is scheduled for fiscal year 2017.

SJ ST 6 was capable of generating 60 MW on June 30,2013. During fiscal year 2013 it was in service 91 ofthe 184 days that it was available for service. Thissteam turbine began the past fiscal year out of servicewhile waiting for the return and installation of therepaired generator rotor. This repair work plus a sec-ond repair cycle for the rotor put the steam turbineinto outages totaling 180 days in fiscal year 2013.Four short unscheduled service interruptions forcedST 5 from service for less than a day in total. TheAuthority placed the steam turbine in reserve shut-down for economy for 93 days during the fiscal year.

The failure of CT 6’s generator late in fiscal year 2011had caused the Authority to put ST 6 in reserve shut-down for economy. In fiscal year 2012 it was accruingdays in reserve shutdown for economy when Unit 5’ssteam turbine generator rotor failed. To return Unit 5’ssteam turbine to available status, the Authorityinstalled the Unit 6 generator rotor into ST 5’s genera-tor. This switch enabled Unit 5 to return to combinedcycle service in the second quarter of fiscal year 2012.The generator rotor from ST 5 was sent to a mainlandfacility to be refurbished. It was returned to PuertoRico for installation in ST 6 in August; the steam tur-bine was ready for service in September. After lessthan 100 hours in operation the rotor failed again. InOctober the OEM removed the rotor and sent it for

repairs. The repaired rotor returned to the island inDecember and the steam turbine was available forservice in January. In each of the next four monthsthere was a single forced outage; these accrued 19forced outage hours in total. Two of the outages weretriggered by trips in the combustion turbine.

During the scheduled outage of CT 6 in August thegenerator will be cleaned and inspected. TheAuthority plans on performing full maintenance andpotential upgrades to ST 6 while CT 6 is in its nextmajor inspection. During fiscal year 2014 theAuthority has scheduled performance tests to identifypotential improvements in the steam turbine.

Combustion-Turbine PowerTotal Generating Capacity 846 MW

Cambalache Combustion-Turbine Power Blocks

These units were designed to provide rapid responsespinning reserve, to ensure System stability in theevent of the unanticipated loss of a large generatingunit and thereby improve the reliability of service tothe Authority’s clients. The three combustion tur-bines at Cambalache comprise a plant rated at 247.5MW. Prior to the return of the four Palo Seco unitsand the addition of new combined cycle capacity atSan Juan in 2009, the Authority had dispatched atleast one unit daily at partial load. During the pastfour years, however, the Cambalache units have beendispatched sparingly and were not in daily service.The low level of dispatch has been driven by the highcost of Cambalache’s distillate fuel and lower Systemdemand. Unit 1 was unavailable for service for all offiscal year 2013, consequently the station had anavailability factor of 63%, however, the two operableunits averaged 95% availability. The two operableunits produced approximately 0.3% of the totalSystem’s generation in the past fiscal year.

Despite their high availability Units 2 and 3 eachoperated less than 500 hours during the past fiscalyear. Given the low dispatch rate, it was typical that aunit could return from an outage or inspection and beavailable, but not be promptly placed in service. Toensure their reliability the Authority rolls each unittwice weekly. The plant’s air permit allows 780 unitstarts per year, the equivalent of five starts per unitper week; the number of starts in the past fiscal yeardid not approach the allowable number of starts.

The Camabalache units are located near Arecibo onthe island’s north coast, approximately 40 miles westof the San Juan metropolitan area. As discussed in theCapacity and Energy Resource Planning section, by

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the end of fiscal year 2012 the Authority had electedto pursue alternative off-shore natural gas supplyarrangements and stop work on the Via Verde Projectwhich would have routed a gas pipeline close to theCambalache plant. With no firm plans for the supplyof natural gas in the vicinity of the plant, theAuthority deferred work to convert the Cambalacheunits to dual fuel firing, with the addition of naturalgas. While the Authority has awarded a contract tothe original turbine manufacturer for the conversionsof the three combustion turbines and the componentsfor the conversion are in storage at the station, thevendor has not been released to install the equipment;this work is no longer included in the CIP. The scopeof the fuel conversion is well defined and each unitwould be unavailable for approximately 30 days forthe conversion. Before starting these conversions theAuthority will need a revised Prevention ofSignificant Deterioration (PSD) Air Permit. Since itcan be prepared relatively quickly, the Authority didnot submit the PSD application to the EPA during fis-cal year 2013.

Although the Cambalache combustion turbines oper-ate in an open cycle, each machine exhausts to a heatrecovery steam generator that provides steam forNOx control and power augmentation. The steamgenerators are referred to as a once-through steamgenerator (OTSG) and were specifically designed towithstand dry operation, i.e. the hot exhaust gasescan pass through the steam generator while it isempty and producing no steam. The steam from theOTSGs is made from demineralized water producedon site in a water treatment facility common to allthree units. Raw water is drawn from local wells andstored on site in a 1.25 million gallon tank; half ofthat capacity is reserved for fire fighting. The watertreatment facility includes storage of 2.4 million gal-lons of demineralized water. During startup and fastload ramping, demineralized water is injected intothe combustion turbines to compensate for insuffi-cient steam.

Combustion turbine technology has continued toadvance since the development of the turbinesinstalled in Cambalache and the original equipmentmanufacturer (OEM) has offered improvements thatcould increase the power of each machine by approx-imately 16 MW. The Authority decided to defer thiscapital commitment indefinitely, however theupgrade can be pursued in the future.

During fiscal year 2013 Authority personnel per-formed routine inspections on each of the combus-tion-turbines. The Authority also uses a technical

services contract with the OEM to assist with inspec-tions and maintenance work. Under this contract theOEM provide a full time technical assistant (TA) dur-ing class C inspections and for the replacement partsneeded in the hot gas path during class C inspectionsof the combustion turbine. These services have beenextended through the next eight class C inspections.The Authority’s employees are responsible for theinstallation of the replacement parts. The serviceagreement also establishes the basis for the provisionof additional technical assistance as required forscheduled maintenance. Refer to the Maintenancesection for a description of the scope of a class Cinspection.

While operating with the original blades in service,each CT experienced a failure of compressor sectionblades. The failures were attributed in part to the cor-rosive effect of airborne contaminants. The Authorityreplaced the media in the air intake filter houses andthe OEM tested a number of sacrificial anti-corro-sion/erosion coatings on compressor blades to deter-mine the most durable coating, with the goal of up to100,000 hours of protective service for the compres-sor blades. Based on the OEM’s analysis and recom-mendation, blades with the special coating wereinstalled in the first ten rows of the compressor sec-tion of Unit 3. With the completion of a class Cinspection of Unit 3 early in fiscal year 2009 thecoated blades were installed in all three Cambalacheunits. The coated blades have been reliable since the2009 installation. With the new blades the Authorityno longer performs online compressor section wash-ings. Compressor section cleanings are now donetwice a year with the unit off line. The OEM has alsorecommended that the Authority synchronize eachunit to the System and operate it at 50 MW for aperiod of a half to one hour each week.

The station’s air permit establishes the maximum fir-ing rate of distillate fuel oil at 104 gallons per minuteper unit. Adherence to this fuel oil consumption rateimpacts the capacity of these units. The amount ofthe limitation is subject to ambient air temperature.Higher air temperatures decrease a unit’s power out-put while cooler temperatures, only rarely experi-enced in Puerto Rico, increase power output. On June30, 2013 the one CT that was available was limited to77 MW. Typically a CT would be limited to 80 MWindicating a 2.5 MW limitation.

During fiscal year 2013 work was deferred complet-ing the rehabilitation of the main crane shared by theunits; this work is approximately 70% complete.With the main crane unavailable the Authority has

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used rented mobile equipment to service equipment.The Authority has a program to install fire suppres-sion systems in all three units. Included in these proj-ects are the replacement of the CO2 fire suppressionsystem’s controls, replacement of corroded piping,and the replacement of components of the foam firesuppression system. The CO2 system provides pro-tection to the enclosed turbine areas; a foam systemprovides fire suppression at the storage tanks. At theend fiscal year 2013 the progress on this work was60% for Unit 1, 85% for Unit 2 and 10% on Unit 3.

The CIP for the Cambalache plant includes $2.5 mil-lion for the scheduled “C” inspection of Unit 2 in fis-cal year 2014; CIP budgets for fiscal years 2015 –2018 have been deferred pending resolution of theavailability of natural gas to the site.

Please refer to the Maintenance section above for afull description of what constitutes a class “A”, “B”,and “C” inspection referred to in this section.

CCTP Unit No. 1 (nominal 82.5 MW) was out ofservice for all of fiscal year 2013 due to a failure in thehot gas path during startup in September 2011. Whilethe unit was in stable startup, a control system faultallowed high pressure steam from the OTSG to causea flameout in the combustor, followed by anattempted re-ignition; the unburned fuel from thefailed restart subsequently exploded. The explosioncaused severe damage to the combustor and damagedrows of blades and a bearing in the compressor sec-tion. The OEM updated its control cards to preventrecurrence of this fault and these new control cardswere installed in all three Cambalache turbines.

The OEM made an initial inspection of the damagedcombustion turbine, confirmed by a more detailedinspection and submitted a quotation for repair partsand services. The OEM also provided the recom-mended procedures for long term preservation of theturbine which the Authority are following, pendingfinal disposition of the matter.

CCTP Unit No. 2 (nominal 82.5 MW) was unavail-able for service on June 30, 2013 while a class Cinspection was being performed. During fiscal year2013 this CT was available 90% of the year, it was inservice 496 hours and had no unit trips.

The only forced outages occurred twice in Februaryand were caused by fuel system problems; each out-age lasted less than four hours.

Unit 2 began its scheduled class C inspection in lateMay and is scheduled to extend 60 days, in partbecause the Authority will avoid premium time labor

for this work, which is consistent with the Authority’scurrent policy on scheduled outages. In addition to theroutine scope of the class C inspection the Authorityplans to replace an air cooled auxiliary heat exchanger,rebuild the exhaust gas duct upstream of the OTSG,replace the hot gas exhaust housing with that fromUnit 1 and rebuild sections of the roof and doors.

The next scheduled inspection for Unit 2 will be aclass A late in fiscal year 2015, based on the currentoperating level.

For fiscal year 2013 this CT generated an average of69 MW and had an annual capacity factor of 5%.

CCTP Unit No. 3 (nominal 82.5 MW) was availableon June 30, 2013 but limited to 77 MW based on ambi-ent conditions, as discussed above. During fiscal year2013 this CT was available 99% of the annual hours, itwas in service 452 hours and had no unit trips.

There were two maintenance outages in fiscal year2013 that totaled less than two days duration. InFebruary the Authority replaced the battery chargerfor the instrument DC power supply. In April thecompressor section was washed off line.

The class A inspection scheduled for mid-year fiscal2013, was rescheduled to the first quarter of fiscalyear 2014 based on its accumulated equivalent oper-ating hours. Work on the fire suppression system isscheduled during the class A inspection. The currentprojections are that Unit 3 may be ready for a class Cinspection late in fiscal year 2015, however, theAuthority plans to defer the class C inspection untilthe equivalent operating hours meet the criteria dis-cussed in the Maintenance section above. The CIPfor fiscal years 2014 through 2018 does not includefunds for this inspection.

In fiscal year 2013 Unit 3’s average generation was 67MW and its annual capacity factor was 5%.

Other Combustion-Turbine Power

The Authority has a total 26 combustion turbines oper-ated in simple cycle, i.e. they do not have exhaust heatrecovery for steam production and power augmenta-tion as utilized at Cambalache. The oldest machinesare nine Combustion-Turbine Power Blocks, each withtwo simple cycle machines. In fiscal year 2009 theAuthority installed four pairs of aero-derivative com-bustion turbines at the existing Mayagüez plant; theyare configured with each pair driving a common powergenerator. In the paragraphs that follow the terms com-bustion turbine and gas turbine are synonymous; thesemachines are identified as GT, in accordance with theAuthority’s convention.

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The original eighteen gas turbine units went intoservice between 1971 and 1973, are located at sevensites and have an aggregate capacity of 378 MW. Theyare distillate-fired Frame 5 gas turbines, each capableof generating 21 MW. These old units are in serviceonly occasionally. The eight new aero-derivative com-bustion turbines installed in the Mayagüez plantreplaced four of the Frame 5 GTs that had been inservice at the plant since 1972. The new GTs providethe Authority with 220 MW of capacity at Mayagüezand increased the System’s total simple cycle combus-tion turbine capacity to 598 MW. The Authority hasoffered two of the redundant Frame 5 GTs fromMayagüez for sale and is using two for spare parts.Twenty-one of the GT units were in service during thepast fiscal year and were available for service on June30, 2013. For fiscal year 2013 the GTs had a com-bined equivalent availability of 77%.

While the total net generation of the GTs during fis-cal year 2013 was almost twice that of the previousyear, the GTs contributed only 0.6% of the totalSystem’s net generation. During fiscal year 2013 theMayagüez aero-derivative units accounted for 91% ofthe net generation of all GTs, which was consistentwith recent years. The Mayagüez units have a heatrate approximately 30% lower than the older Frame 5gas turbines and were dispatched more frequently.However, due to low System-wide demand and theavailability of lower cost generating capacity, theMayagüez units only achieved a capacity factor of 6%while recording an EA of 78% for fiscal year 2013.

The availability of the Mayagüez units was reduced inthe past year because the four turbines comprisingUnits 1 & 2 require replacement and modifications tothe turbine first stage blade and seals at the OEMmainland shop. The four turbines in Units 3 & 4 hadbeen modified during production. While at the fac-tory the OEM is installing upgrades under warranty.The Authority has rotated one turbine at a time forthe repair; by the end of fiscal year 2013 two wereupgraded and in service, one was in the OEM’s shopbeing prepared for shipment back to the island andthe last was scheduled to be sent to the OEM in earlycalendar year 2014. In the past fiscal year Unit 3B’scontrol system software was updated under warrantyfor improved vibration sensor processing, all theother Mayagüez units will share the control systemupdates. The CIP for fiscal year 2014 for the plantincludes funds for replacing the electrodeionization(EDI) water demineralizers that have been unreliablerecently. High purity water is required since it is

injected to reduce NOx but must not leave deposits inthe turbine.

All of the Frame 5 gas turbines combined were inservice less than half the hours of the Mayagüez unitsduring fiscal year 2013. Of the Frame 5 GTs thatoperated in the past fiscal year, the average annualservice was less than 100 hours. Consequently theseturbines have accumulated equivalent operatinghours at a low pace and scheduled inspections havebeen adjusted. The Authority has continued routineoperation in which engineers perform preventativemaintenance tests and inspections of GTs at pre-scribed weekly and monthly intervals.

The Authority’s CIP includes $3.3 million for plannedinspections of the Mayagüez turbines for the five fis-cal years 2014 through 2018. The CIP also allocates$12.2 million for three major inspections of GTs inthe same period. The scope of planned work includescompletion of the program to install new fire suppres-sion systems at the combustion turbine sites.

Since the Authority relies on the GTs to provide reli-able power it is essential that their diesel starting sys-tems be in good operating condition. As discussedbelow the Authority has repaired or replaced three ofthe diesel motors in the last two years in the 18 Frame5 GTs.

Jobos 1-1: During fiscal year 2010 the Authoritycompleted an intermediate inspection of this GT. Aspart of the inspection the generator rotor wasrewound in a mainland shop. While conducting pre-acceptance testing late in fiscal year 2010, the gener-ator’s rotor vibrated excessively possibly caused bycrossed windings. During fiscal year 2012 the rotorwas removed, inspected and balanced on site by thecontractor under warranty. In fiscal year 2013 the GTwas reassembled. It is scheduled for testing prior toits return to available status in fiscal year 2014.

Daguao 1-2: The Authority completed a major over-haul of this unit during fiscal year 2012. Its generatorstator was rewound and the generator’s rotorreplaced, a new excitation system and a Mark VI tur-bine control system were installed. The turbine andcompressor sections were replaced, as was the ratchetand torque converter. The GT was repainted. Duringtesting the Authority encountered problems with theturbine control system and with the diesel motor. Thediesel motor was replaced and the control system wastuned. An electrical fault in one phase of the stationpower output delayed returning the unit to availablestatus, which is forecasted for fiscal year 2014.

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Aguirre 2-2: This GT did not operate in fiscal year2013. During preventative maintenance testing thediesel motor failed late in fiscal year 2012. TheAuthority has hired a local firm to repair the dieselmotor, along with one for Palo Seco 1-1. This unit isexpected to return to available status at the end of thefirst quarter of fiscal year 2014.

Palo Seco 1-1: The diesel motor failed in the secondquarter of fiscal year 2012. Since the Palo Seco GTunits have a backup power feed directly from theadjacent Palo Seco Steam Plant, the loss of a startingdiesel is less disruptive for these units than others.Nevertheless the Authority sent the failed diesel tothe same repair shop as the Aguirre 2-2 motor. Thisunit is expected to return to available status at the endof the first quarter of fiscal year 2014.

Vega Baja 1-1: This unit was unavailable for morethan half of fiscal year 2013 to replace turbine bear-ing number 1. The GT returned to available status forthe last two months of the past fiscal year.

Hydro Production PlantTotal Generating Capacity 100 MW

The Authority has 21 hydroelectric generating unitsat eleven locations. They have an aggregate capacityof 100 MW. The Authority reported that for fiscal year2013 the hydroelectric generating units had an aggre-gate equivalent availability of 63% and generated90,900 MWh, which was 73% of their net generationduring fiscal year 2012 and 61% of their output in fis-cal year 2011. The hydroelectric units had an annual-ized service factor of 10% in the past fiscal year.Recent power generation from the hydroelectricplants has been constrained in part by low rain falland accumulating sediment that compromises theuseful capacity of reservoirs.

On June 30, 2013 the hydroelectric system was capa-ble of generating 43.5 MW. Thirteen of the 21 unitswere reported as available for service. Two of these,the Patillas units with a combined capacity of lessthan two megawatts, have not been in service formore than eight years. Budget constraints havelengthened the time to repair units and return themto available status; this was most evident following aforced outage event. Sixteen units were forced fromservice; on average each of these units accrued a totalof 3,012 forced outage hours during fiscal year 2013,which was 15% less than the previous year. Five ofthe 21 units were scheduled from service for mainte-nance and scheduled inspections during fiscal year2013. These outages accumulated 4,800 hours, thattotal was one-tenth of those for the forced outages. As

discussed below, the Authority’s largest hydroelectricunit, Yauco 1, was dispatched at less than half of itsrated 25 MW capacity during the 1,921 service hoursthat it accrued during the fiscal year. The three unitsat Dos Bocas averaged 2,282 hours each in servicewhich was the most of all the Authority’s hydroelec-tric plants in fiscal year 2013. Housekeeping at thehydroelectric stations was uniformly good, logbookswere well maintained, inspections, and operationaldata were well documented. Preventative mainte-nance activities were completed at specified intervals.

During fiscal year 2013 the Authority spent $1.8 mil-lion on capital rehabilitation improvements of existinghydroelectric facilities. The Capital ImprovementProgram includes $3.2 million for the refurbishmentof hydroelectric units in fiscal year 2014; a portion ofthe fiscal year 2014 CIP budget will be directed toongoing work carried forward from the previous fiscalyear. From fiscal years 2015 through 2018, however,the CIP includes significant budget increases for capi-tal projects at hydroelectric facilities. A total of anadditional $11 million is allocated for rehabilitationprojects and $13 million is budgeted for partial dredg-ing of the sedimentation in Dos Bocas reservoir whichfeeds the Dos Bocas and Coanillas hydroelectricplants. The low level of funding in the past two yearsforced planned inspections to be delayed andincreased the potential impact of a critical equipmentfailure or unplanned event on the corresponding unit’savailability and capacity. These impacts will be dimin-ished as the scheduled improvements are performed.

The following is a brief discussion of work at hydro-electric plants during during fiscal year 2013:

Caonillas 1-1: With a design capacity of 9 MW theunit experienced excessive turbine vibration whenoperating above 6 MW. These vibration issues arosefollowing the forced outage of Caonillas 1-2. Theunit was removed from service for inspection in fis-cal 2012. The Authority has identified improve-ments in the controls which should resolve theinstability. These new controls were ordered for bothCaonillas units in fiscal year 2013. Delivery andinstallation of the improved controls is scheduledfor fiscal year 2014.

Caonillas 1-2: The Authority found water leaks at thewicket gates of this 9 MW unit in April 2011. Repairswere completed before the end of the past fiscal year,however, the unit did not return to service during fis-cal year 2013, pending installation of the new controlsystem discussed above.

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Caonillas 2-1: This unit’s 3.5 MW of capacity has notbeen available since Hurricane Georges struck theCommonwealth in 1998 and filled Lake Vivi withsedimentation. The current five year CIP does notfund the removal of the sedimentation making areturn to available status unlikely in the foreseeablefuture.

Garzas 1-1: This 5 MW unit was unavailable for serv-ice during fiscal year 2013. It was forced from servicein fiscal year 2012 when the generator’s excitor failed.The contract award for the replacement excitor wascontested; the procurement process was repeated.The rewound generator is scheduled to be returned inthe first quarter of fiscal year 2014.

Rio Blanco 1-1 & 1-2: Each unit is rated to be capa-ble of generating 2.5 MW; they both were forced fromservice in fiscal year 2012 by breaks in the penstockand did not return in the past fiscal year. Penstockrepairs were completed, but the penstock supportshad not been tested and accepted by the end of fiscalyear 2013. While these repairs were in progress theAuthority sent the two generator rotors out forinspection, repair, and rebalancing. Both rotors werereturned at the end of fiscal year 2013. The units arescheduled to return to available status during thethird quarter of fiscal year 2014, after the integrity ofthe penstock has been confirmed.

Yauco 1: With a design capability of 25 MW, this isthe Authority’s largest hydroelectric unit. The waterpassing through the unit is used for irrigation.Damage to turbine nozzles, the turbine, and othermechanical components have limited its capacity to10-12 MW for the past several years. In preparationfor the unit’s overhaul a water bypass system wasinstalled during fiscal year 2011. The bypass system’sdischarge lines were modified during fiscal year 2012and testing of the bypass system began late in the fis-cal year. During testing the Authority determined thatthe bypass control valve was undersized and filed aclaim against the design contractor for the replace-ment of the valve with one of the appropriate capac-ity. In fiscal year 2013 the Authority solicited bids forthe replacement bypass control valve, but the order isnot scheduled to be placed until fiscal year 2014. Theschedule for further work on the repairs is subject tothe bypass system demonstrating safe operation. Alsoduring fiscal year 2012 the tunnels bringing water tothe station were inspected and new trash rakes wereinstalled. Trash removal continued in fiscal year2013. To reduce the overhaul cost the Authority plansto replace the most severely damaged turbine bucketswith spare buckets that the Authority has in storage,

the scope also includes replacement of several turbinebearings, and miscellaneous repairs. Once the safeoperation of the bypass control valve is assured, theAuthority estimates the repairs can be performed inless than a year.

Yauco 2-1 & 2-2: Although the Yauco 2-1 was avail-able 6,861 hours in the past fiscal year, its generatorexciter needs repair or replacement. The Authoritymay defer this work until fiscal year 2016 when itplans to refurbish both units. The schedule of theoverhaul is dependent on installing new main isola-tion gate valves for the units.

Diesel GeneratorsThe diesel generators installed by the Authority onthe islands of Vieques and Culebra provide backuppower in the event of an interruption of the powerdelivered by submarine cables to these islands.

During fiscal year 2012 the Authority began work toreplace the four diesel generators on Culebra, with acombined capacity of 2.0 MW, with three new 2 MWdiesels. The first step was the installation of a tempo-rary back-up 2 MW diesel generator to provide emer-gency generation while the replacement of the foursmall diesels was in progress. During fiscal year 2013the temporary diesel was in service a total of 14 hoursand generated 5 MWh. The three 2 MW diesel gener-ators are scheduled to be installed on Culebra in fis-cal year 2014. Site development, erection of the fuelstorage tank and other work that will precede theinstallation of the new units continued during thepast fiscal year. The new units bring 6 MW of capac-ity to Culebra and are scheduled to enter service latein fiscal year 2014. Following their commissioningthe Authority will remove the temporary 2 MW dieselgenerator that provided emergency capacity while thethree new diesel generators were being installed.Expenditures on this project were $770,000 in fiscalyear 2013, with the budget of $2.5 million in the CIPto complete.

On Vieques the Authority’s two 3 MW diesel genera-tors were in service a total of 28 hours during the fis-cal year and generated 49 MWh while in service.During the last fiscal year the Authority installedreplacement control systems for the two diesel gener-ators on Vieques. The replacement system has anopen architecture for ease of troubleshooting whichwill expedite repairs.

FUELS

Since March 2007 the Authority has been burning aresidual fuel oil with a sulfur content not exceeding

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0.5% by weight in all of its large steam electric gener-ating stations. Following the switch to the low sulfurfuel, the two stations on the south side of the islanddiscontinued the use of fuel additives. In fiscal year2009 the Authority revised its distillate fuel specifica-tion and since making the revision has been burninga distillate fuel oil with a sulfur content not exceed-ing 0.05% sulfur in its simple and combined cycleunits. This standardization has helped the Authorityto realize better pricing and supply options.

The Authority’s standard practice for the supply offuel oil is based on one-year contracts with the optionof extending the contract for an additional year orless. The fuel oil pricing is structured on the com-modity market with a fixed adjustment to account fordelivery to Puerto Rico and the local delivery require-ments of smaller barges for the plants on the northcoast. The Authority selectively employs differentstrategies to minimize the commodity price volatilityin these contracts; these strategies include fixed pricecontracts and commodity hedges.

During the first two months of fiscal year 2013 resid-ual oil was supplied to the Aguirre Steam Plant incompletion of a six-month contract that went intoeffect on the first of March 2012. A four-month con-tract to another supplier was effective as of September1, 2012 and was in effect until the end of calendaryear 2012. The Authority placed a one-year contractwith a third supplier for the supply of residual fuel oilfor the Aguirre and Costa Sur steam electric unitsbeginning in January 2013. This contract is in effectthrough calendar year 2013, with a four month exten-sion clause. The Authority has three residual oil stor-age tanks at Aguirre, each with a capacity of 260,000barrels. The Aguirre units typically receive 70,000barrels of residual fuel oil every three days. Duringfiscal year 2013 these units consumed an average ofapproximately 21,700 barrels per day (BPD) of resid-ual fuel oil when both were in service.

The contracts for the supply of residual oil to theCosta Sur Steam Plant followed the same sequence asthe Aguirre Steam Plant outlined above. Units 5 & 6are the dominant production units at Costa Sur andhave been converted to burn natural gas, as discussedin the Capacity and Energy Resource Planning sec-tion. Since the Authority plans that natural gas will bethe principal fuel in these units their consumption ofresidual fuel oil will be less than previously. TheAuthority has 800,000 barrels of residual oil storagecapacity at the Costa Sur Steam Plant. The stationreceives 250,000 barrels of residual fuel oil every twoto three weeks. On average these units consumed

approximately 10,100 BPD of residual fuel oil whenin service during the past fiscal year.

The one-year contract for the supply of residual oilfor the Palo Seco and San Juan Steam Plants that wasawarded in January 2013 includes an option for afour-month extension. As described above, prior toawarding this contract the Authority placed a four-month contract with a different supplier for the sup-ply of residual fuel oil to these plants through the endof calendar year 2012. At the Palo Seco Steam Plantthe Authority has the capacity to store 450,000 bar-rels of residual oil; at the San Juan Steam Plant thereis an additional 138,000 barrels of storage capacity forresidual fuel oil. These stations receive a combinedtotal of 250,000 barrels of residual fuel oil every tendays. Over the course of the full year these stationsconsumed a combined average total of 22,400 BPD ofresidual fuel oil in fiscal year 2013.

The Authority’s contract for the supply of natural gasto the Costa Sur Plant is for two years and runsthrough April 30, 2014. The gas is supplied from thegasification facility at the EcoEléctrica cogenerationplant adjacent to the Costa Sur Plant. The quantity ofgas available gas under this contract will meet thecombined consumption of Units 5 & 6 firing only gaswith a capacity factor of approximately 60%. TheAuthority plans to restructure and rebid this contractduring the next fiscal year.

The Authority’s contracts for the supply of distillatespecify that the distillate not contain more than0.05% sulfur by weight. In July 2012 the Authorityawarded a contract for the supply of distillate fuel tothe Cambalache and Mayagüez gas turbines, and tothe combined cycle units at Aguirre and San Juan.The contract is in effect for one year and does notinclude the option for an extension. Distillate fuelsare delivered to a south coast storage facility andfrom there are barged to each of the four stations.During fiscal year 2011 the CAPECO facility wasacquired by Puma Energy Caribe; remediation workand restoration of fuel storage capacity is progress-ing. A portion of the restored storage capacity for dis-tillate fuel oil could be available to the Authorityduring fiscal year 2014.

The Authority has not entered into a long term con-tract for the supply of distillate fuel oil for theAuthority’s Frame 5 gas turbines. As discussed in theOther Combustion Turbine Power section, these unitsare located in nine power blocks around the islandand they accumulated very few service hours in thepast year; because of their high production costs theyare forecasted to remain backup power capacity. In

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practice the fuel consumption at each Frame 5 gasturbine block requires only an infrequent truck deliv-ery of distillate fuel oil, which is paid based on themarket price at delivery.

BATTERY ENERGY STORAGE SYSTEM

The 20 MW Battery Energy Storage System, BESS, atSabana Llana was commissioned in August 2004. Theplant was designed to provide ready reserve capacityin response to a System disturbance and power factorcorrection when needed. The plant consisted of twounits, 1A and 1B, each with more than 3,000 batter-ies. Within two years of commissioning a fire in thebatteries of one unit forced it from service. TheAuthority alleges that design faults with the batteriescaused the fire, consequently neither unit wasreturned to service.

Since 2008 the parties have engaged in complex liti-gation with extended discovery. In succession the bat-tery manufacturer, its Puerto Rican partner, and mostrecently the bonding company have all failed anddeclared bankruptcy. The litigation continues, how-ever, it is unlikely that there will be much recovered.The Authority continues to evaluate the future use forthe BESS building as well as the salvage value of themore than 6,000 batteries and the associated obsoleteelectronic gear.

SPARE COMPONENTS

To reduce the unscheduled outages of various units,the Authority has purchased a number of criticalspare components (see the following list). Usingsuch spare components during an emergency outagehas expedited a unit’s return to service. Once thedamaged component is repaired, it becomes thespare. This practice has significantly reduced thedowntime of some of the Authority’s large unitsthereby helping to maintain both unit and Systemavailability.

The value of these spares is included in the value ofthe Authority’s inventoried equipment and materialreported in the Inventories and Other Properties sec-tion.

The following is a list of major spare components:� HP/IP and LP turbine rotors for Aguirre Unit

Nos. 1 & 2� HP/IP and LP turbine rotors & diaphragms for

Costa Sur Unit Nos. 5 & 6 � Generator rotor for Aguirre Unit Nos. 1 & 2� Motors for FD, ID, GRF, & air heaters for Costa

Sur Units Nos. 5 & 6 and Aguirre Unit Nos.1& 2

� Normal Station Service Transformer adaptableto Costa Sur Units Nos. 5 & 6 and Aguirre UnitNos.1 & 2

� Motors and pumps for condensate, boiler cir-culating, & boiler feed water for Costa Sur UnitNos. 5 & 6

� Emergency Station Service Transformer forAguirre Steam Station

� LP turbine rotor for Palo Seco Unit Nos. 3 & 4� Generator rotor for Palo Seco Unit Nos. 1 & 2� Main Power Transformer for Palo Seco Unit

Nos. 3 & 4� CT generator rotor for the Aguirre Combined-

Cycle Plant� CT turbine rotor for the Aguirre Combined-

Cycle Plant � Main Power Transformer for Aguirre

Combined Cycle Station� Two generator rotors for the Frame 5 gas tur-

bines� Compressor rotor assembly for a 21 MW gas

turbine� Service transformer for San Juan Station Units� Replacement motors for all large pumps� Replacement rotors for FD, ID, & GRF fans � Large pumps and vacuum equipment for com-

bined cycle & steam-electric units� Burners, soot blowers, air heater components

for steam-electric units

PRODUCTION PLANT CAPITALIMPROVEMENTS

Production plant capital expenditures in fiscal year2013 amounted to $148.3 million. As shown inAppendix VI, Capital Expenditures, production plantcapital expenditures in millions are forecasted to be$96.4, $115.9, $110.4, $128.5, and $124.7 in fiscalyears 2014 through 2018 respectively. Details byBudget Item Number for these five fiscal years areshown in Appendix X, Details of CapitalImprovement Program.

ENVIRONMENTALThe Environmental Protection and Quality AssuranceDivision is responsible for assisting the Authority’soperating directorates to comply with applicableFederal and Commonwealth environmental laws andregulations. These responsibilities include the devel-opment of comprehensive programs to achieve theAuthority’s environmental performance goals. Thisdivision is charged with obtaining the permitsrequired to increase or modify any Authority ownedcapacity assets prior operating within the System.

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In December 2011 the EPA signed regulations underthe Clean Air Act (CAA) that reinforced theAuthority’s long standing objective to maximize theutilization of natural gas in its generating units.While the Authority’s principal objectives have beenfuel diversity and lower cost, natural gas has the ben-eficial feature of being a much cleaner fuel than resid-ual oil. The EPA regulations established new nationalemission standards for hazardous air pollutants underthe mercury and air toxics standards (MATS). Theseregulations apply to certain solid waste incineratorsand large commercial and industrial boilers; these areprincipally coal and oil fired steam electric generatingunits larger than 25 MW. The pollutants subject toregulation are heavy metals, including mercury,arsenic, chromium, nickel and acid gases such ashydrogen chloride and hydrogen fluoride, sulfurdioxide, and also particulate matter and carbonmonoxide. If pollution abatement equipment isrequired to reach the mandated emission levels ofthese hazardous air pollutants, the EPA will requirethe installation of up to the maximum achievablecontrol technology (MACT), which is based on thebest demonstrated performance technology regard-less of cost. The MACT for the Authority’s units couldconsist of various retrofitted emission control sys-tems, such as filter baghouses and flue gas desulfur-ization equipment and associated ancillary systems.The high cost and restricted space at most steamplants make this approach impratical.

Since compliance with MATS will be established onthe basis of individual units, the Authority’s compli-ance strategy is to convert its eight largest oil firedsteam generating units to dual fuel firing, burning nat-ural gas fuel in addition to or in place of oil, and torestrict the operation of the remaining six steam unitsto 8% capacity per year to qualify as limited use liquidoil fired generating units (LULOF). The EPA’s initialschedule for the implementation of MATS requirescompliance by April 2015, with two one-year exten-sions potentially available. The Authority plans torequest some extensions since the necessary gas sup-ply infrastructure will not be in place by April 2015 tosupport gas firing at all eight of the steam units.

The Authority’s current strategy to expand the supplyof natural gas on the island has been an offshore gasi-fication facility for LNG deliveries near its Aguirrepower complex on the southeast coast. During fiscalyear 2013 the Authority continued its due diligenceon the contractual structure of the gas supply infra-structure and was evaluating alternative supplyarrangements. Meanwhile the Authority continued todevelop a coordinated air permit application for boththe off-shore scope in addition to the Aguirre plants.

The Authority has focused first on its four largeststeam units for dual fuel conversion—gas in additionto oil—on the south coast. The four steam units inthe San Juan metropolitan area will be converted afterthe schedule for gas deliveries has been established.With sufficient fuel being available the Authorityplans to add gas firing capability to the Authority’stwo most efficient units, San Juan Units 5 & 6, whichare combined cycle units presently burning high costdistillate fuel.

During fiscal year 2011 Costa Sur Units 5 & 6 wereconverted to dual fuel burning capability.Subsequently the boiler internals were modified tosupport continued full load operation with all gas fir-ing; this work was performed for Unit 6 during fiscalyear 2012 and completed for Unit 5 by the end of lastfiscal year. Initial stack testing with dual fuel firinghas demonstrated compliance with MATS criteria.The natural gas was supplied by EcoEléctrica L.P. viaa pipeline from its facility adjacent to the Costa SurSteam Plant. During fiscal year 2013 EcoEléctricainstalled and made operational two additional regasi-fiers. Additional regasification production is possiblewith the installed equipment, however this wouldrequire a revised permit from the Federal EnergyRegulatory Commission (FERC).

During fiscal year 2013 the Authority performedenvironmental protection or environmental remedia-tion projects at each of its major generating stationsand at numerous transmission and distribution facil-ities. Environmental projects performed in the last fis-cal year were budgeted at $8.1 million; actual 2013expenditures were $2.2 million. The Authority’s five-year capital improvement program (CIP) for fiscalyear 2014 through 2018 identifies environmentalprojects valued at $62.8 million. During fiscal year2014 the Authority has budgeted $12.6 million to bespent principally on modifications to cooling watersystems and spill prevention projects.

In fiscal year 2014 at the Costa Sur Steam Plant theAuthority has budgeted $5 million to fund section316 (a) & (b) Clean Water Act projects; these proj-ects address mitigation of the cooling water intakeand discharge systems. The section 316 (a) & (b)projects are each budgeted to cost $27.1 million overthe five years to completion in fiscal year 2018. Theseare the two largest and most costly environmentalprojects that the Authority has currently funded.After several years of work, in fiscal year 2012 theAuthority completed the rehabilitation of the station’soutflow channel walls which was another environ-mental project at the Costa Sur Steam Plant.

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The Authority has pursued a long term program torefurbish its large fuel oil storage tanks and contain-ment dikes at all its steam electric plants. In fiscalyear 2013 it has budgeted $1.1 million for the refur-bishment of fuel storage tanks at the San Juan SteamPlant. The refurbishment of the fuel storage capacityat the Aguirre and Costa Sur Steam Plants is sched-uled to continue through fiscal year 2017; at a bud-geted cost of five million dollars.

Although the Authority has had an active asbestosabatement program for decades some equipment andfacilities still have asbestos containing material whichhas been secured until such time when maintenanceactivities require its removal; $1.5 million of the envi-ronmental program budget for fiscal year 2014 is ded-icated to asbestos remediation projects. Theseprojects enable the Authority to reduce exposures toand release of asbestos containing materials throughencapsulation and removal. The abatement worktakes place during programmed outages such as themajor overhaul of a steam unit.

Since discovery in 1997 of oil contaminated soil at thePalo Seco Steam Plant and in the area of the Palo SecoWarehouse, the Authority has taken steps to remedi-ate contamination from oil with a low concentrationof PCB that was found in monitoring wells; this workincluded investigations and removal of contaminatedsoil. Based on a letter notice from the EPA inDecember 2011, further investigation and remedia-tion activities at this site will not be required pendingsubmittal of the Authority’s final report and accept-ance by the EPA. The Authority expects the conclu-sion from the EPA during fiscal year 2014.

The Authority has a program to comply with SpillPrevention Control and Countermeasures (SPCC)regulations regarding containment of potential leak-age from oil containing electrical equipment in itsdistribution substations. During fiscal year 2011 theAuthority completed the installation of signage andspill response material at all its substations. By theend of fiscal year 2013 it had completed the construc-tion of compliance containment at 42 of the 58 sub-stations that need to be upgraded and will completethe balance during fiscal years 2014 and 2015.

The Authority completed a program many years agoto remove from service and dispose of all of its trans-formers and electrical equipment with PCB concen-trations greater than 499 ppm. Since then theAuthority has continued with a long standing pro-gram to remove transformers with oil containing PCBbetween 50-499 ppm. The Authority has catalogedless than two hundred remaining transformers forremoval. All of the transformers and electrical equip-

ment with PCB concentrations greater than 499 ppmwere removed from service and disposed of years ago.

In February 1992 the EPA conducted a multimediainspection of the Authority’s four steam electricpower plants (Aguirre, Costa Sur, Palo Seco, and SanJuan) and the Monacillos Transmission Center. InDecember 1992, the EPA identified several instancesof noncompliance related to air emissions, water dis-charges, and to the Spill Prevention Control andCountermeasure (SPCC) compliance program at theAuthority’s four major steam electric generating sta-tions and at the Monacillos Transmission Center.These findings led in March 1999 to an agreementbetween the agencies of the federal government andthe Authority, which became the basis for the courtapproved Consent Decree, which while subsequentlyamended, is still in effect. The Authority agreed thatstarting in March 2003 the residual fuel oil burned inthe steam electric generating stations at Palo Seco andSan Juan on the north coast of the island would havea sulfur content not exceeding 0.5% by weight. SinceMarch 2007 the Authority has been burning a fuel oilwith a sulfur content not exceeding 0.5% by weight atits south coast steam electric generating stations atAguirre and Costa Sur. For more discussion on thisrefer to the Fuels section of System’s Operations.During fiscal year 2007 the Authority completed proj-ects to reduce NOx emissions at steam electric gener-ating stations at Palo Seco, Aguirre, and Costa Sur. Asa condition of receiving certain permits the units atSan Juan Station had previously been modified toreduce NOx emissions. The Authority and the EPAmonitor compliance with the lower NOx emissionsrequirements.

During the past fiscal year the Authority reportedachieving compliance in excess of 99% with its in-stack opacity requirements and with its Air QualityCompliance Program and also achieving the samehigh level of compliance with Clean Water Act regu-lations. At the end of fiscal year 2013 none of theAuthority’s generating stations was on probation withthe EPA. There were no events, leaks or spillsreported during fiscal year 2013 that could lead tosignificant administrative action.

COGENERATORSThe Authority has entered into long-term PowerPurchase Operating Agreements (PPOAs) with theowners of two cogeneration plants in Puerto Rico.These plants, one fueled by natural gas (vaporizedLNG) and the other by coal, bring fuel diversity to theisland’s generation mix. The Authority’s PPOAs withthe cogenerators establish the technical and commer-cial principles under which they mutually operate.

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These include the methods for calculating the capac-ity and energy costs of the delivered power, which areadjusted for a twelve-month period at the start ofeach calendar year. The plants incorporate emissioncontrol technologies enabling them to comply withcurrent environmental standards; both plants arehighly efficient. The Authority controls the dispatchof the cogenerators’ power. During fiscal year 2013the cogenerators accounted for 33.7% of the System’snet generation, up from the 31.3% in the precedingfiscal year. (For further discussion of these powerproducers see the Capacity and Energy ResourcePlanning section)

The Authority treats its purchased power costs as anoperating expense in its various financial schedulesand recovers them from its clients utilizing a pur-chased power charge similar to its fuel charge. TheAuthority’s purchased power costs from the cogener-ators were $735.1 million in fiscal year 2013. Theamount of $755.7 million shown in Appendix III,Detail of Operating and Maintenance Expenses, forpurchased power includes the renewable energy proj-ect. For fiscal years 2014 through 2018 the Author-ity’s forecasts of purchased power include the costsand power contributions from additional renewableenergy projects coming on line as discussed in theCapacity and Energy Resource Planning section com-ing on line. The Authority, however, projects that thecogenerators will be the largest sources of purchasedpower through fiscal year 2018. As shown in Appen-dix IV, Annual Net Generation, Fuel Consumption,Fuel and Purchased Power Costs, during the five yearperiod beginning with fiscal year 2014 the Authorityforecasts the costs of cogenerator sourced purchasedpower in millions of dollars will be $702.8, $732.5,$759.8, $789.2, and $817.9, respectively.

EcoEléctrica, L.P.

On March 21, 2000, the Authority began buying 507MW of power from EcoEléctrica, L.P. in accordancewith a 22-year PPOA. The plant consists of two com-bustion-turbines (CTs) each with a heat recoverysteam generator (HRSG), i.e., boiler, combining topower a single steam turbine-generator, STG. Each ofthe CTs is capable of generating 167 MW; the steamturbine-generator is capable of generating 173 MW.The plant’s waste heat is used in a desalinization plantcapable of producing 2 million gallons of fresh watera day. The water is for its own use and for sale to thePuerto Rico Aqueduct and Sewer Authority and theAuthority for its use at the Costa Sur plant. TheEcoEléctrica, L.P. complex also includes an LNG

unloading dock, an LNG storage tank, LNG vaporiz-ers, and associated facilities.

In accordance with the PPOA each calendar yearEcoEléctrica fixes the fuel cost per million BTU forthe first 76% of the station’s capacity for that year. Forcapacity in excess of 76% the Authority has beencharged based upon a spot fuel price that was set byEcoEléctrica at the time the excess capacity was dis-patched. From time to time the Authority has agreedto purchase power at a capacity above the facility’snominal rating of 507 MW, however power purchasesat these levels has not been formally incorporated inthe PPOA.

The EcoEléctrica plant is located in close proximity tothe Costa Sur generating complex and a gas pipelinefrom the EcoEléctrica facility has been installed to theCosta Sur plant. The Authority has contracted withEcoEléctrica to store and regasify LNG in sufficientquantity to supply the Authority with natural gas forthe Costa Sur Units 5 & 6 which have been convertedto dual fuel capability. To supply sufficient natural gasfor itself in addition to Costa Sur Units 5 & 6,EcoElectrica has installed two new regasifiers in addi-tion to the existing two. Of the two regasifiers initiallycommissioned for service, one was needed to regasifyLNG for EcoElectrica’s two combustion turbines andthe second regasifier was a full spare backup thatwould be used if the other regasifier were not avail-able. To satisfy the Authority’s need for natural gas atCosta Sur and have spare capacity, EcoEléctricainstalled two additional LNG regasification units dur-ing fiscal year 2012. While EcoEléctrica then had fourregasification units, they did not have FERC’sapproval to put more than one additional regasifierinto continuous service. Under the present FERC per-mit the third and fourth regasifiers are spares and apermit revision would be required to increase thenumber of LNG ship deliveries per year or the num-ber of regasifiers in concurrent operation; this sce-nario could be associated with increased gasutilization by EcoEléctrica at its facility or expandedgas firing by the Authority at the Costa Sur plant.Based on projected demand and System dispatch, thegas supply from two regasifiers will support both ofthe large Costa Sur units firing 100% with gas, inaddition to the EcoEléctrica units. If additional poweris required from Costa Sur Units 5 & 6, these unitscan use residual oil in conjunction with natural gas oras the only fuel, within the limitations of the air per-mit criteria.

For fiscal year 2013 EcoEléctrica achieved an equiva-lent availability of 91.4%, considerably lower than the

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equivalent availability of 95.0% achieved during fiscalyear 2012, and less the contractual target of 93%, con-sequently reducing EcoEléctrica’s capacity payments.Although the plant’s availability dropped during thepast fiscal year, its annual capacity factor increasedfrom 77% to 80% while generating 4.3% more energyin fiscal year 2013 than in fiscal year 2012.

CT 1 was scheduled out of service twice and forcedout three times during fiscal year 2013. The sched-uled outages totaled ten days, while the unscheduledaccrued 16 days. The first scheduled outage inJanuary was for six hours to isolate from the steamturbine which was beginning its major inspection. InFebruary this combustion turbine was out for tendays for its scheduled annual maintenance. The com-bustion turbine was out of service for two days inAugust to resolve high temperature differential in acombustor. In September it was unavailable for sixhours due to a failure in an LNG pump. The last ofthe three unscheduled outages was for almost 14 daysto resolve problems with the generator stator.

CT 2 was scheduled out of service twice and forcedout four times during fiscal year 2013. The scheduledoutages totaled 15 days, while the unscheduledaccrued eight days. The first scheduled outage inJanuary was for seven hours to isolate from the steamturbine which was beginning its major inspection. InFebruary this combustion turbine was out for 15 daysfor its scheduled annual maintenance. The combus-tion turbine was out of service for seven hours in Julyto repair a loose connection on protective relays forone phase of the generator. In September it wasunavailable for eight hours due to a failure in an LNGpump. In October this combustion turbine was outfor four hours to repair damaged fuel tubing at a com-bustor. The last of the unscheduled outages was foralmost seven days to resolve the same problems withthe generator stator as applied to CT 1.

ST During fiscal year 2012 this 173 MW steam tur-bine was fully or partially unavailable for approxi-mately 43 days; 32 of which accrued during ascheduled major inspection beginning in January.During the inspection the steam turbine valves werecleaned and inspected. The turbine internals wererefurbished as necessary. Preventative maintenancewas completed on unit auxiliaries. The steam turbinewas unavailable for an additional eight days followingthe inspection to rebalance the rotating elements toresolve high vibrations. The loss of an LNG pump inSeptember that took out both combustion turbinesforced the steam turbine out for seven hours. Thesteam turbine also accrued several equivalent outage

hours associated with the forced outages for CT 1 inAugust and CT 2 in October discussed above.

In fiscal year 2013 EcoEléctrica provided 17.0% of theSystem’s power, exceeding the Authority’s forecast of15.3% of the System’s net generation during the pastfiscal year. The Authority forecasts that EcoEléctrica,L.P. will generate 17.5% of the power sold by theAuthority during fiscal year 2014.

AES-PR

AES-PR’s coal-fired steam-electric cogeneration sta-tion began commercial operation in November 2002.The owners of the facility have entered into a PPOAwith the Authority to provide 454 MW of power for aperiod of 25 years. The station is made up of two sim-ilar units; each is comprised of a circulating fluidizedbed steam generator employing clean coal burningtechnology and a steam turbine-generator capable ofgenerating 227 MW. AES-PR has assured theAuthority that its units will readily comply with thenew MATS standards, discussed in the Environmentalsection, which will apply to the coal firing plantbeginning in April 2015. During fiscal year 2013 AES-PR produced 16.7% of the power sold by theAuthority, compared to the 16.1% of the System’s netgeneration that the Authority had forecast for AES-PR. The net generation by AES-PR in fiscal year 2013was 9.5% more than in fiscal year 2012 and more than4% above its previous five-year average. TheAuthority’s forecast for power from AES-PR for fiscalyears 2014 through 2018 are based on output compa-rable to the five-year average of fiscal years 2009through 2013. For the remaining years of the PPOA’sterm, the plant has a target equivalent availability of90%, a target it did not achieve in the five years pre-ceding fiscal year 2013.

During the past fiscal year AES-PR achieved an equiv-alent availability of 91.1%, which was a significantimprovement over the 87.4% in fiscal year 2012. Thescheduled maintenance in Unit 1 was the longest out-age event for the two units in fiscal year 2013. Theplant achieved a capacity factor of 88.3% for all of fis-cal year 2013. The Authority forecasts that AES-PRwill generate 15.8% of the power sold by theAuthority during fiscal year 2014.

Unit 1: was scheduled out of service once and forcedout four times during fiscal year 2013. The scheduledmaintenance outage lasted 27 days, while theunscheduled events accrued 25 days. Unit 1 came outof service in March at the start of its scheduled outagefor annual maintenance. During the outage auxil-iaries were cleaned and inspected, refractory repairs

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completed; routine cleanings, inspections, and pre-ventative maintenance was completed on burners,mechanical equipment, coal, limestone, and ash han-dling systems. The turbine was opened and inspected.In August this unit was forced from service for tendays to repair tube failures in the fluidized bed heatexchanger (FBHE). Two additional heat exchangerfailures required repairs in February and March,accruing 12 days unavailable. In September the unitwas forced from service for three days to repair thegenerator exciter system controls.

Unit 2: During fiscal year 2012 this 227 MW unit wasfully or partially unavailable for approximately 25days. There was no scheduled maintenance during thepast fiscal year, the next is scheduled for the secondquarter of fiscal year 2014. Three incidents accountedfor 97% of the total equivalent lost generation for thisunit in fiscal year 2013. In October the unit was out ofservice for six days to repair the superheater ash regu-lating valve. Repairs to the boiler heat exchangerforced the unit out for ten days in December. Theunit’s output was limited by 83 MW for nine daysbeginning in May because of vibration in one of theboiler feed pump hydraulic couplings. Seven otherbrief incidents accounted for the balance of the limita-tions and outage hours for the past fiscal year.

TRANSMISSION AND DISTRIBUTIONSYSTEMSThe Authority’s transmission and distribution sys-tems is comprised of an island-wide network ofpower lines, switchyards, substations and electricalequipment that carry the electrical power from theproduction plants to serve the Authority’s clients.

On an annual basis the Consulting Engineer’s person-nel visit and note the condition of approximately one-third of the Authority’s 333 distribution substationsand 45 transmission centers (TCs). In order toobserve a representative sample, we select substationsfrom among the 78 municipalities in the 26 districtsserved by the Authority. The scope of the inspectionsinclude a representative portion of the Authority’s230/115 kV transmission lines.

TRANSMISSION

The Authority’s transmission system consists of highvoltage power lines, switchyards and electrical equip-ment that carry the electrical power from the produc-tion plants to the dispersed substations, both theAuthority’s and privately owned substations, whichserve the System load. The backbone of the transmis-sion system is the 230/115 kV network that movesbulk power. The balance of the transmission system is

the 38 kV lines and equipment that serve the wholeisland and also provide the submarine service to theislands of Vieques and Culebra. For reference whenreading this section, a map of the Authority’s 230 kVand 115 kV transmission systems precedes theAppendices. The map shows the existing transmis-sion system with the planned modifications to thesystems through fiscal year 2018.

230 kV SystemThe existing 230 kV system is comprised of 375 cir-cuit miles of transmission lines that encircle and sec-tionalize the island. The 230 kV system has twonorth-south corridors which divide the system intothree principal loops—the western loop, the centralloop and the eastern loop. Each north-south trans-mission line originates at a major production facilityin the south and carries power to the load centers inthe north.

The central loop has been in operation for manyyears. It was the first 230 kV transmission line to tiethe generating plants located on the island’s southcoast to the load concentrated in the San Juan metro-politan area via the Aguas Buenas TC south of thecity. A parallel 230 kV line in the center of the islandconnects the Costa Sur and EcoEléctrica productionunits in the south with the Manatí TC locatedbetween San Juan and the Cambalache combustionturbine station on the north coast. The central loop isjoined by east-west transmission lines connecting theCosta Sur units with the Aguirre plant in the southand a line on the north side of the island connectingManatí to Aguas Buenas via Bayamón.

The western loop connects the Costa Sur andEcoEléctrica production units in the south with theMayagüez switchyard and production units, on thewest coast of the island, and from there to the north-ern cities of Aguadilla, Hatillo, and Arecibo. Thewestern loop was completed in fiscal year 2002 fol-lowing the construction of the segment connectingMayagüez and the Cambalache TC. The loopincreased the transmission system’s capacity and reli-ability and improved the quality of electric service inthe north-western municipalities.

The most recent expansion to the 230 kV transmissionsystem was the eastern loop that went into serviceduring fiscal year 2006. The eastern loop was installedto support the load growth in the northeastern area ofthe island, complete the encirclement of the island bythe 230 kV system, and improve the transmission sys-tem reliability and capacity by increasing the availabletransmission lines to move electrical power from the

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complex of generating plants in the south to majorload centers in the north. The eastern loop runs fromthe large power production units in the southern plainat the Aguirre units in Salinas and the AES plant inGuayama to the eastern part of the island throughYabucoa and Río Blanco and terminates in SabanaLlana, southeast of the San Juan metropolitan area.Large sections of the new 230 kV eastern transmissionline run along existing 115 kV rights of way. The proj-ect required the relocation of 16 miles of existing 115kV lines between Río Blanco and Quebrada Negrito.The scope of the eastern loop project also included theexpansion of the 230 kV facilities at the Sabana Llanaand Yabucoa TCs.

The Authority is presently installing two new trans-mission line projects and recently completed con-struction of a new transmission center to expand the230 kV transmission system. In addition to increasingthe system capacity, the new transmission lines willprovide additional redundancy for power flow fromthe major production units in the south, therebyimproving operational flexibility for the system andsupport economic dispatch, as well as enhancingvoltage stability at the major load centers and improv-ing system reliability.

The Authority’s priority project for expansion of the230 kV transmission lines will connect the Costa Surplant and the EcoEléctrica, L.P. cogeneration plant,both of which are on the south side of the island, withthe key switchyard at the Cambalache combustionturbine station near Arecibo, which is on the northside of the island. The total length of the line will be38 miles, however, more than half of its length con-sists of upgrading existing 115 kV line and structuresto 230 kV, thereby shortening the construction sched-ule of the 230 kV line from the Costa Sur plant to thetransmission center at Dos Bocas. Construction onthis section of the new transmission line was com-pleted late in fiscal year 2012. During the past fiscalyear the new line entered service operating at 115 kVuntil the balance of the route to Cambalache is com-pleted, when the entire line will be interconnectedwith the 230 kV system. The section of the new 230kV line between Dos Bocas and Cambalache will uti-lize a new right of way. The Authority’s current CIPshows spending on this project for completion in fis-cal year 2014 will total $8.1 million; expenditures infiscal year 2013 were $21.2 million. Completion ofconstruction has been delayed pending resolution ofcertain disputed acquisitions of rights of way, howeverthe Authority has scheduled the end of fiscal year2014 to finish construction of the new 230 kV line.

The Authority plans to expand the 230 kV transmis-sion system with a new line from the Aguirre genera-tion complex to Aguas Buenas TC, via an extension inthe Cayey TC. The transmission line project is sched-uled for completion in fiscal year 2017 with expendi-tures of $889,000. The new line is scheduled to use anew right of way to provide an additional measure ofredundancy and capacity for moving power from thecritical generation source at Aguirre to the load cen-ters in the north. This project will coordinate with anew 230 kV interconnection with the AES cogenera-tion plant to the east of the Aguirre complex.

The Authority has a long-term project for expansionof the 230 kV transmission system with a new 50 milelong line being constructed between the Costa SurSteam Plant in Guayanilla and the Aguas Buenas TC,located south of the San Juan urban area load center.During the past fiscal year expenditures were $2.2million and the project was approximately 66% com-plete. The estimated cost of the new line is $110 mil-lion, with completion planned in fiscal year 2020.Construction work is scheduled to resume in fiscalyear 2018, with a budget of $5.0 million for that year.

Consistent with the installation of new transmissionline projects the Authority expanded the capacity ofthe existing 230 kV switchyards at the Costa Surplant and the Cambalache combustion turbine sta-tion. The initial expansion at the Costa Sur switch-yard cost $2.8 million and was placed in serviceduring fiscal year 2012. The $2.5 million expansionat Cambalache was completed in fiscal year 2013. Infiscal years 2015 and 2016 the Authority plans to add230 kV switchgear at the Aguirre plant and the AEScogeneration facility, with a total cost of $3.1 millionfor the two projects.

115 kV SystemThe 115 kV system is comprised of 727 circuit milesof transmission lines that encircle and cross the inte-rior of the island; the 155 kV system includes 35 cir-cuit miles of underground lines. The 115 kV systemwas the first high voltage transmission system put intooperation on the island to improve the efficiency andreliability of the bulk distribution of power. The 115kV lines and substations serve all the major load cen-ters on the island. Many of the 115 kV transmissionline corridors were subsequently used as rights of wayfor the 230 kV system lines as that system grew.

In its plans for the long term expansion and improve-ments to the 115 kV system, the Authority has priori-tized a number of new and rehabilitation capitalimprovement projects for 115 kV transmission centers

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and other components of the system. Given the scope,complexity, and cost of these projects, their executiontypically spans many years between initial work andplacement into service.

Over the five fiscal years ending in fiscal year 2018,the Authority plans to complete two new 115 kV lines.The first new line is scheduled to start in fiscal year2016 and will feed the planned 115/38 kV Bairoa TC,north of Caguas. The work is forecast for completionin fiscal year 2017 at a cost of $7.2 million. The nextproject will provide a second feed to the new HatoTejas 115/38 kV TC; the line will run from the PaloSeco plant to the Hato Tejas TC in Bayamón. Thisproject is scheduled to be worked on in fiscal years2017 and 2018 with a total cost of $10.6 million.

During fiscal year 2013 the newly constructed 150MVA 115/38 kV Hato Tejas transmission centerlocated in the region of Bayamón was placed in serv-ice. Also during the past year the Authority continuedwork on two new 115/38 kV transmission centers.The first is a new 150 MVA 115/38 kV transmissioncenter in Barraquintas. This new transmission centeris located between existing transmission centers inAguas Buenas and Juana Díaz and is scheduled forcompletion in fiscal year 2014. The Authority plansto continue work on a new 150 MVA 115/38 kVtransmission center in Bairoa, part of Caguas; the

project is scheduled to be completed in fiscal year2016. During fiscal years 2014 and 2015 theAuthority plans to install a new 115/38 kV transmis-sion center at the existing Buen Pastor substation inMonacillos. Each of the new transmission centers issituated where it will help to reinforce the 38 kV sys-tem capacity and reliability by providing for addi-tional operational contingencies. The budgets forthese three projects total $13.4 million for the fiscalyears 2014 through 2016. The CIP for fiscal years2016 through 2018 includes $7.5 million for a new115/38 kV transmission center in Venezuela, near RioPiedras in San Juan; the project schedule has beenextended to allow for resolution of local issues. Alsoin fiscal years 2016 through 2018 the Authority plansto install second transformers in three 115/38 kVtransmission centers around the island for increasedcapacity.

The Authority continued work on the 115/38 kVswitchyard utilizing gas insulated switchgear (GIS) atthe San Juan plant during the past fiscal year. Thenew GIS will provide interconnection with the 38 kVsystem; interconnection to the 115 kV system will bevia the existing aerial lines. The Authority plans a sec-ond phase of the GIS project to provide a permanentinterconnect with the underground 115 kV system,meanwhile that connection can be accomplished onan interim basis if required. The final phase of the GIS

project is scheduled for completion in fiscalyear 2015.

During fiscal year 2014 the Authority plans toinstall and place into service two sectionalizersnear the San Juan metropolitan area; the sec-tionalizers provide switchable isolation of por-tions of the 115 kV system, thereby improvingoperational flexibility to minimize the impactof a local problem. The Authority also plans toextend the busbar at the 115/38 kV Hato ReyTC located in San Juan. The scope of the workincludes additional structures and breakers.The Authority plans five more extension proj-ects at 115/38 kV transmission centers fromfiscal year 2015 through 2018. The totalbudget for projects within this scope of workduring the five fiscal years ending in 2018 is$12.9 million.

To protect the integrity of the transmission sys-tem in the San Juan urban area during and fol-lowing extreme weather events, the Authorityinstalled a 28-mile underground loop of 115kV transmission cables that link the majorcomponents of its System in the metropolitan

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area; the scope included four new 115/38 kV GIS sub-stations, three of which are in operation. The generalconfiguration of the loop is shown on the 115 kVunderground system map, which is color coded todemarcate the construction phases. The system canbe fed through existing transmission centers in theloop and by the Palo Seco units which are intercon-nected with the new transmission loop. The perma-nent interconnection of the San Juan units is plannedfor fiscal year 2015.

The principal function of the underground cable is toprovide a robust measure of redundancy so that theAuthority will be able to maintain continuity of serv-ice in San Juan’s central business district, perhaps atpartial load, in the event overhead lines are lost dur-ing a hurricane or other disaster. In addition, thecable will be available for back up service to theAuthority’s existing overhead transmission linesunder normal circumstances. The scope of this proj-ect was prompted by the devastation caused byHurricane Georges in fiscal year 1999. The FederalEmergency Management Agency (FEMA) reimbursedthe Authority a total of $73 million of the project’scost of $195.8 million for the underground cable andductbank scope of work.

The 115 kV underground work was installed in fourmajor phases between fiscal years 2002 and 2008. Allthe underground 115 kV cable was fabricated usingcross-linked polyethylene (XLPE) cable. While theXLPE cable was more expensive than cable insulatedby oil or other chemical compounds it eliminated thepossibility of environmental contamination if suchcompounds were to leak into the surrounding terrain.

The Authority incorporated provisions in the com-pleted work for a future extension of the 115 kVunderground system from the Isla Grande substationto the Covadonga substation in Old San Juan. Thisunderground cable could provide increased load flowunder normal and emergency conditions to the gov-ernment buildings located in the Old San Juan area.The Covadonga 38 kV gas insulated switchgear distri-bution substation was constructed in a dedicatedbuilding that includes space for future 115kV equip-ment fed by an underground duct bank.

The 115 kV underground system includes four newsubstations incorporating gas insulated switchgear,providing for compact and enclosed substations. Thefirst two new substations at Isla Grande and MartínPeña have been in service since fiscal year 2008.These substations were designed to support existingand anticipated load growth in their respective areas.The third and fourth substations are located at the

Palo Seco and San Juan Steam Plants. The Palo SecoGIS has been in operation since fiscal year 2009.

38 kV SystemMore than half of the Authority’s transmission systemcircuit miles operate at 38 kV, which is considered its“sub-transmission” level. While most of the sub-transmission system is near load centers, it is also theprimary transmission system to some of the island’smost inaccessible interior regions. At the end of fiscalyear 2013 there were 1,375 circuit miles operating at38 kV, including 63 miles of underground line and 55miles of submarine service to the islands of Viequesand Culebra.

The 38 kV system feeds approximately two-thirds ofthe Authority’s distribution substation capacity andalmost all of the private substations on the island.Given that the 38 kV system is an essential compo-nent in the Authority’s transmission network, formany years the Authority has been pursuing a systemwide rehabilitation program to upgrade the reliabilityand capacity of the 38 kV system. In addition, theAuthority continues to invest in new 38 kV systemlines, switchyards and expansions. Both rehabilitationand new work are included in the Authority’s CIP.

The scope of the rehabilitation work includes replac-ing old conductors with new, replacing aging woodenpoles with steel poles and upgrading the system forforecasted local loads. In some areas, certain sectionsof the rehabilitated 38 kV lines have been installedalong new rights of way to facilitate its installation aswell as future maintenance.

In fiscal year 2013 the Authority expended $12.6 mil-lion on 24 projects of 38 kV line rehabilitation work.The largest project involved the major reworking of aline in the island’s interior from Aguas Buenas toBarranquitas, which constituted approximately onehalf of the total 38 kV line rehabilitation expendi-tures. The project is budgeted for $5.2 million for fis-cal year 2014, when it will be completed. Typically 38kV line rehabilitation projects are located throughoutthe island and reflect the extent and age of the 38 kVsystem. During fiscal year 2014 the Authority hasbudgeted $15.1 million and plans to work on 25 linerehabilitation projects in the 38 kV system.

With regard to the 38 kV system transmission lines,the Authority’s focus has been on rehabilitating exist-ing lines. During fiscal year 2014 the Authority hasbudgeted $1.5 million for five projects to extend orincrease the capacity of aerial 38 kV lines; the budgetfor fiscal years 2015 through 2018 for these expan-sions is $3.7 million, with funding for eight projects in

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total. Expenditures in the past fiscal year were approx-imately one half million dollars for two projects.

The 38 kV system also includes more than 60 miles ofunderground cable in mostly urban areas. In responseto civic and business leader requests, the Authority isexpanding the scope of the underground cable inurban and industrial areas. During fiscal year 2013the Authority expended $2.4 million completing anexpansion underground 38 kV project in the Bairoasector of Caguas. The Authority has deferred essen-tially all new 38 kV underground lines during fiscalyears 2014 and 2015, but is planning to resumeselected projects in 2016. The total budget for fiscalyears 2016 – 2018 is $17.9 million for four projects.

Transmission Plant CapitalImprovementsThe transmission plant funding forecasts in theAuthority’s current CIP address a wide range ofimprovements covering the entire transmission sys-tem. Transmission capital expenditures in fiscal year2013 amounted to $69.7 million. The Authority isplanning to spend $66.3 million on capital improve-ments to its transmission system in fiscal year 2014:$26.7 million for expansion projects and $39.7 mil-lion for rehabilitation projects. The Authority plans tospend $329.5 million on its transmission system overthe next five fiscal years. These expenditures are dis-cussed in the Capital Improvement Program sectionand are itemized in Appendix X, Details of CapitalImprovement Program and summarized in AppendixVI, Capital Expenditures.

DISTRIBUTION

The Distribution System is the final link between theAuthority’s production plants and TransmissionSystem and its clients, with the exception of the smallnumber of commercial and industrial clients whopurchase power at the transmission level. TheDistribution System includes Authority owned sub-stations that reduce the power from transmissionvoltage to the level at which it is locally distributed;the three voltage levels serving most clients are 4.16kV, 8.32 kV and 13.2 kV, with a small portion distrib-uted at 7.2 kV. At the end of fiscal year 2013 therewere approximately 31,550 circuit miles in the distri-bution system. The circuit miles operating at 13.2 kVand 8.32 kV are each approximately 24% of the totaldistribution circuit miles, with 4.16 kV lines account-ing for most of the balance.

While most of the Authority’s primary distributionsystems are overhead, almost 6% of the Authority’sdistribution circuit miles are underground. The

Authority’s aerial distribution systems are convention-ally located along road rights of way, although someare located along rear lot lines or installed along theAuthority’s rights of way. To improve operational reli-ability the Authority has a program to relocate highvalue lines from rear lot lines to more accessible rightsof way. Service ties from the distribution lines andmeters complete the connection to clients’ premises.

Selected 13.2 kV ProjectsThe Authority has a long-standing program in placeto upgrade its primary distribution level to 13.2 kV.The higher voltage is a cost effective method thatenables the existing conductors to carry more load,while updating older distribution equipment such astransformers, switches, capacitors and reclosers. Inaddition, operating at 13.2 kV reduces line losses andallows for longer circuits runs, thereby providingmore flexibility in making system interconnections.During fiscal year 2013 the Authority expended $3.5million on the construction and extension of newoverhead 13.2 kV lines in nine projects. During thepast fiscal year the Authority expended $6.6 millionfor new and extending 13.2 kV feeders at 24 substa-tions. Including the special project in Ponce dis-cussed below, expenditures for underground 13.2 kVlines during fiscal year 2013 were $15.5 million.

The Authority makes on-going investments in newdistribution substations to support new or increasingload, such as in areas with increasing residential con-struction, to improve system performance and toreplace aging equipment. The Authority has stan-dardized on two sizes of permanent substations basedon the transmission system supply voltage. This stan-dardization expedites the engineering, procurement,and construction cycle, increases flexibility in poten-tially utilizing equipment as spares, and provides acost effective installed capacity margin for loadgrowth. In situations where the Authority needs addi-tional substation capacity on an interim basis or withshort lead times, the Authority installs temporarysubstations that are standardized unitized metal cladequipment, which can be relocated as required.

During fiscal year 2013 the Authority completed theconstruction of new 13.2 kV substations at RíoBayamón II and Hato Tejas, both in the Bayamónregion, and completed work to increase the capacityof substations at Cayey in Caguas and at Palmer TCin Carolina. In the past fiscal year work was com-pleted to install an additional transformer at theGrana II substation in San Juan. All are scheduled toenter service early in fiscal year 2014. During fiscalyears 2014 and 2015 the Authority plans to construct

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five new 13.2 kV substations. These substations willbe at Sea Land (Caparra) in Guaynabo, at CharcoHondo in Arecibo, at Añasco in the west coastal areaof the island, at Morovis in the central region west ofSan Juan, and at Las Piedras in the eastern centralregion. The Authority has allocated a total budget of$27.4 million for 12 new substation projects duringthe five years through fiscal year 2018; $5.8 million isbudgeted for increasing the capacity of existing sub-stations during the same five years.

In compliance with a settlement with the municipal-ity of Ponce, the Authority agreed to improve theelectric distribution system in the historic district ofPonce. The project involves upgrading the existingoverhead 4.16 kV system to a 13.2 kV undergrounddistribution system. The Authority has taken the leadin the underground work in the historic districtwhich requires coordination with the telephone com-pany and the water and sewer utility who are alsoconcurrently relocating buried utilities in the samedistrict. The scope of the entire project is being exe-cuted in four sequential phases to minimize disrup-tions to the neighborhoods and local traffic. The firsttwo phases of the work have been completed andplaced in service. The third phase of work began infiscal year 2011 and was essentially completed by theend of the past fiscal year; expenditures during thepast fiscal year were $8.9 million. Work on the finalphase is targeted to begin late in fiscal year 2014 orearly the next fiscal year, with a duration of fouryears. The CIP budget for this project through 2018is $12.9 million.

Other Distribution WorkConsistent with the wide use of lower voltage distri-bution lines and equipment, during fiscal year 2013the Authority expended $34.2 million on improve-ments to the distribution system and overhead distri-bution lines at 4.16 kV – 8.32 kV. Expenditures onimprovements to underground distribution linesoperating at 4.16 kV – 8.32 kV totaled $10.3 millionin fiscal year 2013; these improvements typically arein urban areas.

To improve client service and reduce operating costs,the Authority is expanding the installation of variousdistribution automation equipment systems torespond to line faults. The fault detection, isolationand restoration (FDIR) system selected for prioritydistribution lines will automatically isolate the faultand transfer loads to an alternative feeder to minimizethe duration and number of clients impacted by thefault; the system provides real time information to theAuthority’s operation center on its actions and status.

The FDIR system has the capability to isolate faultsand restore service in response to multiple contingen-cies, such as might happen during severely inclementweather. The Authority has also installed reclosers forfault detection and isolation without automatic loadtransfer, however these systems include remote com-munication to facilitate manual response. TheAuthority’s CIP budget for the five fiscal yearsthrough 2018 is $4.0 million for the installation ofdistribution automation equipment.

The Authority has an on-going program to complywith recent EPA’s requirements on Spill PreventionControl and Countermeasures (SPCC) Plans pertain-ing to their electrical distribution system equipmentcontaining oil. The Authority’s SPCC Plan includesspill response material and notification signage at allsubstations. This scope of the plan was fully imple-mented during fiscal year 2012. In addition, theSPCC Plan has identified 58 substations in whichspill containment dikes will be installed under trans-formers and oil containing circuit breakers. By theend of fiscal year 2013 the Authority had installed themajority of these modifications at 42 substations.Authority plans to complete all the required SPCCworks modifications at the affected substations in fis-cal year 2015.

The Authority owns 22 portable distribution substa-tions that enable them to perform substation mainte-nance with minimal or no interruption of service, tospeed recovery after a substation failure, and forenhanced operation during line clearance constraints.The portable equipment ranges in size from 10 MVAto 44 MVA at 38 kV and 115 kV, and includes twocapacitor banks at 38 kV 18 MVAR.

Distribution Plant Capital ImprovementsThe Authority’s capital expenditures on the distribu-tion system were $127.9 million in fiscal year 2013.The scope of these expenditures included $16.0 mil-lion in the past year for the remote read meters pro-gram discussed below. The Authority is planning tospend $99.9 million on capital improvements for itsdistribution system in fiscal year 2014: $18.8 millionfor expansion projects and $81.1 million for rehabili-tation projects and other distribution expenses, suchas remote read meters, line transformers, breakers,sectionalizers, and reclosers. The remote read clientmeters discussed below have been a long term capitalcommitment by the Authority and they account for12% of the Distribution CIP budget for fiscal year2014. The Authority plans to spend $465.1 millionon its distribution system capital improvements over

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the next five fiscal years; this is 30% of the totalplanned capital expenditures over that period.

MAINTENANCE

The Authority generally maintains its transmissionand distribution equipment using a time-based sys-tem. In some cases the maintenance intervals havebeen modified to meet the challenging tropical envi-ronment or relevant operating experience. As anexample of routine periodic inspections, theAuthority performs infrared inspections of all substa-tions and switchyards twice a year. The infraredinspections are used to identify “hotspots” which arefaulty connections that are overheating and are likelycandidates for failure. In addition to performing elec-trical and mechanical testing, the equipment ispainted on a periodic basis to help prevent corrosion.

The Authority’s inspection and maintenance programfor high voltage electrical equipment is based on thecriticality of the equipment’s service, with the scopeand frequency of the inspections and maintenanceguided by the manufacturer’s standard recommenda-tions. Main power, transmission and substation trans-formers are inspected on a four year cycle. TheAuthority takes oil samples annually from all highvoltage transformers in an effort to identify internaldeterioration before it leads to failure. The Authority’soil analysis program relies on a recognized industryconsultant’s recommendations, coupled with its ownoperating and maintenance experience, to performmore frequent monitoring or eventually repair. Asmany major transformers approach their design serv-ice life this program has become increasingly impor-tant in maintaining the system operating reliability.

The inspection and testing frequency for other highvoltage equipment in the maintenance programinclude: gas circuit breakers—six years; oil circuit andvacuum circuit breakers—four years; and protectiverelays—no more than three years for calibration andtesting. Relays protecting major equipment, such astransmission transformers, are tested more frequentlybased on when the equipment is out of service.

In response to sporadic theft of aluminum structuralbracing members for their scrap metal value fromtransmission towers in past years, the Authority hasincreased inspections of transmission towers usingboth the helicopter patrols and inspections from theground. Any deficiencies identified in these inspec-tions are repaired on a priority basis.

In fiscal year 2013 the total operation and mainte-nance expenses for the Transmission and Distributionsystems was $277.1 million. While this level

exceeded the budget, it equaled the average expendi-tures for the most recent three fiscal years 2011through 2013. The budget for total operations andmaintenance of the Transmission and Distributionsystems for fiscal year 2014 is $271.0 million, whichis 2.2% less than the previous year’s actual expenses;the differences between the budget and the previousyears’ actual expenses are principally reductions inoperations costs. The maintenance budget for the fivefiscal years 2014 through 2018 for the Transmissionand Distribution systems through 2018 is forecastedto be 4.9% above the actual expenditures of fiscal year2013. The Authority’s total Transmission andDistribution operation and maintenance budgets forthe four fiscal years 2015 through 2018 are forecastedto decrease 7.4% in fiscal year 2015, increase 1.1%and 0.3% in 2016 and 2017 respectively and remainunchanged in 2018.

Transmission system maintenance expenses, shown inAppendix III, Detail of Operating and MaintenanceExpenses, totaled $30.0 million in fiscal year 2013; theexpenditures were 2.7% less than budget. For fiscalyear 2014 the Authority has reduced the annual trans-mission maintenance budget to $17.4 million, withthe five-year average through fiscal year 2018 being$17.1 million. In these same time frames the budgetfor transmission system operations increased from theactual expenses of $19.3 million to a budget of $26.1million; the five-year average through fiscal year 2018is $25.0 million for transmission operations. Activitiesincluded in the maintenance budget include fundingfor tower maintenance, tree trimming, insulatorreplacement, helicopter patrolling of transmissionlines, and right of way management. The costs associ-ated with the transmission system portion of substa-tion maintenance are also included in these budgetedexpenditures.

Distribution system maintenance expenses, alsoshown in Appendix III, Detail of Operating andMaintenance Expenses, totaled $74.7 million in fiscalyear 2013; the expenditures were 18.6% over budget.For fiscal year 2014 the Authority has increased theannual distribution maintenance budget to $94.9 mil-lion, with the five-year average through fiscal year2018 being $92.8 million. In these same time framesthe budget for distribution system operationsdecreased from the actual expenses of $153.0 millionto a budget of $132.6 million; the five-year averagethrough fiscal year 2018 is $126.6 million for distri-bution operations. The distribution maintenanceexpenditures include distribution system related

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expenditures similar to those described under trans-mission system maintenance expenses.

TRANSMISSION AND DISTRIBUTIONSYSTEMS RELIABILITY

The principal guideline in the operation of a utilityelectric system is to continuously balance the real timedemand for electricity (the load) and the simultaneousproduction of power while maintaining regulation ofthe system’s voltage and frequency. The electric systemis designed to meet this requirement across a widerange of operating conditions, which include loss ofan operating transmission line or other key systemcomponent. Analyses of these design conditions estab-lish the required redundancies in the system and oper-ating criteria. Consistent with industry practice, theAuthority has designed the entire transmission systemto maintain continuous operation with at least onecontingency event (loss of an operating component)and two contingencies for critical lines that movepower from the major production plants.

Reliability IndicesReliability standards have been in place within theNorth American electric utility industry for manydecades. Following recent wide spread power lossesin America, such as the Northeast blackout in August2003, the electric power industry and its regulatorshave reaffirmed the importance of reliable service tosupport the requirements of the economy. This wasreinforced in the Energy Policy Act of 2005, whichcalled for mandatory reliability standards for theinterstate bulk power systems. The Authority’s expe-rience is consistent with the industry in that while the

notorious blackouts are caused by the transmissionsystems, most interruptions to client service arecaused by problems in the local distribution system.

Two industry criteria generally accepted for measur-ing an electric system’s reliability of service to itsclients are the following:

System Average Interruption Duration Index(SAIDI)- The average duration of sustained serviceinterruptions per client occurring during the preced-ing twelve-month period. It is the average time a typ-ical client was without power over a rollingtwelve-month period. The average is determined bydividing the sum of the durations of all sustainedclient interruptions by the total number of clientsserved. The Authority reports its SAIDI duration sta-tistics in hours.

System Average Interruption Frequency Index(SAIFI)- The average frequency of sustained inter-ruptions per client occurring during the precedingtwelve-month period. It is calculated by dividing thetotal number of sustained client interruptions by thetotal number of clients served.

SAIDI and SAIFI indices take into account only sus-tained outages; they do not reflect momentary inter-ruptions or voltage irregularities, which can affectsensitive electronic equipment. For both SAIDI andSAIFI, lower index values indicate better client serv-ice, i.e. shorter and fewer service interruptions.

Throughout the electric power industry the generalprocedure for calculating reliability indices has beenimplemented by most utilities with their own specificadjustments to reflect their service conditions. The

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Authority’s SAIDI and SAIFI data include only out-ages longer than fifteen (15) minutes and excludemajor events, such as the effects of tropicalstorms/hurricanes and disruptions from multiplecontingencies.

The charts provide perspective on the short termtrend of the Authority’s SAIDI and SAIFI data over theperiod beginning in January 2010, when theAuthority established the goals still in place and end-ing on June 30, 2013. During this timeframe the aver-age duration and frequency of service interruptionshave usually stayed in a relatively narrow band, buthave trended on a gradual downward slope. In com-parison to the reliability indices of five years ago,however, the recent SAIDI and SAIFI data are consid-erably below the levels in fiscal year 2008. To achievethese significant reductions in service interruptionsthe Authority prioritized improving the reliability ofthe distribution system. A critical component in theAuthority’s program was to re-establish emphasis ontree trimming and vegetation control programs thatspecifically address a major cause of service interrup-tions. The scope of the Authority’s on-going programincludes both transmission and distribution lines, aswell as public education of appropriate plantingslocated near overhead power lines. To reinforce itsobjectives over the last ten years the Authority pro-gressively dropped the performance index goals offewer and shorter interruptions (lower SAIDI /SAIFI). The most recent reduction in January 2010lowered the target SAIDI by 10% and SAIFI by 30% to

reflect the Authority’s objectives in continuing toimprove client service.

As the Authority’s SAIDI and SAIFI goals havedropped and become more challenging to achieve andmaintain, the margin between the goals and actualperformance has shrunk. This past fiscal year contin-ued a general trend that began in fiscal year 2009indicating that additional significant reductions in theaverage duration and frequency of interruptions maybe difficult to achieve in the near term.

The average total duration of a client’s sustainedinterruptions during the past fiscal year, as shownabove in the Authority’s 12-month rolling average ofSAIDI, was consistently below the Authority’s currentgoals although it trended somewhat higher as the yearprogressed.

During fiscal year 2013 the twelve-month rollingaverage of the number of sustained outages per clienttrended in a relatively narrow band that was consis-tently below the Authority’s SAIFI goals for the year.As mentioned above, the observed performance wasbasically consistent with the interruption frequencyfor more than the last three fiscal years.

As the Authority reduces the outages caused by treesand vegetation, one key to further improving theAuthority’s reliability performance will be the identi-fication of the cause of service interruptions. Thepotential integration of the proposed, improved auto-mated systems and Remote Meter Reading may allowmore detailed analysis of reliability data. In addition,

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it would be possible to acquire data on an individualclient’s actual experience rather than relying on com-posite averages.

TECHNOLOGICAL SYSTEMSOPERATIONSThe Authority employs numerous automated controlsystems to ensure safe and reliable operation of itsSystem. These systems coordinate with or are inte-grated into larger systems that support the Authority’sroutine technical and commercial operations. This sec-tion addresses selected automated systems employedby the Authority for control and operation of the gen-eration, transmission and distribution systems.

ENERGY MANAGEMENT SYSTEM

Consistent with good operating practice in the indus-try the Authority uses a sophisticated control systemto regulate operation of its production sources toalways match in real time the System’s consumptionof electric power while maintaining the proper volt-age and frequency.

In fiscal year 2010 the Authority contracted with theenergy management system (EMS) supplier to mod-ernize the EMS that had been in operation for morethan 11 years by that time. The vendor of the latestgeneration EMS was chosen to facilitate the design ofthe new EMS to meet the Authority’s new require-ments, provide continuity of operator interface andminimize potential issues during the transition to thenew system. Although the EMS in operation since1999 had continued to function properly with theexisting System, the EMS hardware and software wereaging and the Authority’s performance requirementshad evolved to include operation of the System withintermittent renewable energy generation sources andwheeling mandated by Commonwealth legislation.

Following completion of several factory acceptancetests, in fiscal year 2012 the new system and trainingmodules were installed in the Authority’s control cen-ters. Since the new EMS was developed by the samevendor who supplied the present system, similaritiesin their architecture facilitated the training; the oper-ator training simulator also includes distributed gen-eration and wheeling. During the first half of the pastfiscal year the Authority operated the new system inparallel with the existing for many months to demon-strate reliable operation of the new before retiring theexisting from service.

The new EMS also updates the Authority’s cyber-security system for compliance with North AmericaElectric Reliability Council’s (NERC), critical infra-

structure protection (CIP) standards.. Approximatelyone half of the funding for the $7.5 million replace-ment EMS was obtained through the U.S. Departmentof Energy’s “Recovery Act Smart Grid InvestmentGrant Program”. The new EMS can interface with thedistribution management system, which is an impor-tant communications link for “Smart Grid” technolo-gies. In addition, the vendor of the new EMS systemoffers pre-engineered features if the Authority wishesto expand the system’s scope.

Concurrent with the development of the new EMS,the Authority has been upgrading the supervisorycontrol and data acquisition (SCADA) system func-tionality. The SCADA system is the secure communi-cations network linking the central EMS with all thegeneration sources and substations.

The scope of work for the new EMS includes newhardware and software to replace the existing controlsystem in both the primary energy control center inMonacillos and the back-up control center in Ponce.The upgraded EMS will enhance the Authority’s abil-ity to respond to critical situations if the primarycontrol in Monacillos is limited or compromised,based on continuous real-time data synchronizationbetween the two control centers and enhanced sys-tem error detection and failure determination. TheEMS features include extension of the Authority’sload forecasting and load flow analysis. The auto-matic generation control (AGC) is based on revisedeconomic and security criteria. Among the networkapplications are power scheduling opportunities,improved software for the analysis of disturbances,phase angle and frequency monitoring and for thedetection and analysis of inter-area oscillation. Thenew EMS will more accurately identify fault loca-tions thereby facilitating faster service restorationand interface with the distribution outage manage-ment system.

ASSET MANAGEMENT SYSTEMS

During fiscal year 2013 the Authority implementedan upgraded program of work and asset managementsystems for its users responsible for generation andthe high voltage electrical system, while evaluatingprograms for transmission and distribution activities.

Production Plant Asset ManagementSystemsIn fiscal year 2010 the Authority began a program toupgrade its enterprise asset management systems(AMS) that support its generation and high voltageassets to more effectively monitor and manage thesecritical assets and associated inventory. The objective

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has been to improve their reliability, safety and avail-ability, while reducing costs. The previous system hadbeen in place for more than a decade and had beensuperseded by newer technology. The supplier of thenew AMS suite of programs is well established in thisfield and has direct relevant experience with electricutilities; the supplier is also the successor to the pre-vious AMS vendor. The new AMS is designed toimprove coordination with the numerous directoratesthat are involved in the management of the produc-tion and high voltage electrical assets. It will facilitatethe integration of data into the different programsused within the human resource, financial, engineer-ing, procurement, and management disciplines.

Following acceptance testing, establishing the data-bases for the new AMS based on the earlier AMS pro-gram as well as with new data, and widespreadtraining, the Authority fully implemented the newAMS during the past fiscal year.

The new AMS scope includes modules that addresswork and asset management through maintenanceoptimization, life extension, work planning, predic-tive failure, materials and planning, monitoring ofcritical equipment on a real time basis, and analysis ofhistorical performance data to improve repair orreplace decisions. The suite of programs are designedto support effective management of supply chainresponsibilities, maintenance of critical spares, pur-chasing, expediting, material receipt, management ofaccounts payable, and quality control. In addition theAMS includes safety and compliance managementcomponents that identify requisite safety trainingrequirements for the work being performed, possiblechemical exposures, permit requirements, documentcontrol procedures, and environmental compliance.

Transmission & Distribution AssetManagement SystemsPresently the Transmission & Distribution operationsof the Authority use a multi-faceted work and assetmanagement system that is more than ten years old.The Authority’s transmission and distribution assetmanagement system integrates a work managementsystem, a geographic information system and an out-age management system into an Integrated ResourceManagement System that is known by its Spanishacronym of AIRe (Administracion Integrada deRecursos).

The AIRe system is structured to maintain its data-bases as well as interface with existing computerizedsystems in other Authority areas such as Finance,Human Resources, and Procurement. The objectives

of the AIRe are improved client service; reducedO&M expenses; improved emergency response; bet-ter planning; improved and consistentengineering/design and estimating practices; archivedmaintenance records; and, real-time system statusreporting.

Since the AIRe system was implemented more thanten years ago, the applicable vendors, hardware andsoftware technologies have evolved. During fiscalyear 2011 the Authority re-evaluated various optionsto replace the existing AIRe system that was originallysupplied by a vendor who was subsequently acquiredby a larger vendor; the new vendor agreed to supportthe old system for only a limited time. The Authorityestablished continuity of the user interface withwhich the transmission and distribution users wereaccustomed as an essential feature in selecting itsreplacement state of the art asset management sys-tem. The evaluation process of alternative AMS sys-tems continued through the past fiscal year. TheAuthority plans to make its selection in fiscal year2014, at which time the schedule for implementationof the new system will be established. The Authorityplans that the new asset management system fortransmission and distribution work will includeinterfaces with the production AMS, as well as inter-face with the outage management system and geo-graphical information system with web basedtechnology.

The work management system (WMS) component ofthe AIRe system has been in service in all of theAuthority’s districts since 2001. The WMS tracks theprogress of all construction and maintenance workfrom start to completion. The functions of the systeminclude estimating, engineering, scheduling, requiredapprovals, the generation of bills of material ofapproved equipment in accordance with Authoritystandard designs, and the accumulation of labor andmaterial costs for each project.

The geographical information system (GIS) compo-nent of the AIRe system is a comprehensive geospa-tial model of the entire transmission and distributionsystems including an inventory of all components.The GIS database is designed to interface with theWMS and the outage management system (OMS), aswell as providing an engineering tool for modifica-tions, new work, and circuit analyses. Completing theGIS was a major task since the global positioning sys-tem (GPS) coordinates of every pole on the island hadto be plotted and all the associated equipment physi-cally inventoried. Subsequently the Authorityexpanded the scope of the GIS to include validating

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the location of client meters to improve the precisionof the outage management system discussed below.The GPS coordinate data are utilized with a one-meter resolution satellite map database of the entireCommonwealth that was developed by a PuertoRican interagency governmental group.

The outage management system (OMS) has been inisland-wide operation since the end of fiscal year2008. The OMS is designed to improve the Authority’srecovery efforts following a hurricane or tropicalstorm by generating: a damage assessment reportbased on data received from various system transpon-ders and the Customer Information System; a com-plete inventory of equipment needing replacement;maps of all areas affected by the outage(s); and, an up-to-the-minute report of the System’s status. When therestoration work is underway, the AIRe system moni-tors and records the labor and material costs.

In conjunction with the OMS system the Authorityexpanded the use of an automatic vehicle location(AVL) system to 750 vehicles. The AVL system iscapable of providing the real-time location of anyAuthority vehicle fitted with the GPS receiver andcommunication link to the Authority’s local dispatchcenter. Vehicle location information has been usefulin reducing travel time to respond to problems androuting assistance to work crews if required. The AVLalso enhances the safety of the crews by providingtheir location whenever it may be needed, such asduring wide area power restoration work. Since theexperience with the AVL system has been favorable,the Authority plans to eventually install it in all emer-gency vehicles.

Since the Authority completed the installation of thework management system in each district and imple-mented the interface with the Customer InformationSystem, Customer Services operators can access theWMS to provide timely information to clients. Duringemergencies, all the commercial offices located acrossthe island are integrated into the work managementsystem, allowing trouble orders to be immediatelygenerated electronically. The implementation of theseautomated systems has allowed the Authority to con-solidate many of its Customer Service centers.

REMOTE METER READING

In fiscal year 2000 the Authority began the island-wide installation of an automated meter reading(AMR) system. The primary goal that the new meterssupport is the ability of the Authority to remotelyread the parameters measured by the meter of allclients. Industrial and commercial clients served at

transmission voltage are a small portion of the totalclient base; the high voltage meters for these clientsare not included in this discussion, however thesemeters do provide remote reading capability. Duringthe course of the remote meter reading program themeters have gone through technological evolutions,which are discussed below. Capital expenditures forthe AMR system in fiscal year 2013 were $16.0 mil-lion, bringing the total to approximately $225 mil-lion; $43.4 million is budgeted for fiscal years 2014through 2018. The continuing program consists ofactively replacing old and defective meters and theselective installation of new design digital meters. Bythe end of fiscal year 2013 automated meters hadbeen installed in effectively all of the Authority’sclients. The system being installed utilizes a propri-etary technology that communicates between metersand remote controllers by superimposing a frequencymodulated signal on the Authority’s existing distribu-tion lines between the client meter and theAuthority’s substation. Because it uses the electricpower wires, this technology’s performance is notimpaired by the island’s varied terrain.

Communication between the AMR system centralprocessor and the individual meters is through dedi-cated transformers and communication equipmentinstalled in the substation serving the associatedclient’s meter. The processed signals from the AMRsubstation equipment are routed to the centralprocessor via the Authority’s existing fiberoptic,microwave systems or secure internet. The AMRequipment is installed at all the Authority’s activesubstations and all new substations include the AMRequipment with the original construction.

The Authority’s early experience with the AMRmeters exposed weaknesses in the meter’s resistanceto tampering. During the first ten years of deploy-ment the meter technology evolved from electro-mechanical meters with communication modules torugged digital meters, fitted with the same communi-cation module. Over the years the Authority hasworked with meter vendors to develop increasinglyrobust units to resist tampering. It has also enhancedsealing of the plastic case of meters that were alreadyin inventory but had not been deployed. TheAuthority now buys meters with the most robust anti-tampering specifications commercially available;these meters also include internal memory good forstoring many months of data, which might be used iftampering or theft were suspected, or for data recov-ery if the AMR communications were disrupted.Beginning in fiscal year 2011 the Authority has been

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installing meters with an integral disconnect/connectfeature. These meters have greatly reduced the timerequired for customer service disconnections andreconnects for short term clients or in problematiclocations. In most instances these meters enable aclient to re-establish disconnected service after mak-ing a secure payment of an overdue invoice by phoneor internet within minutes of that payment. By theend of fiscal year 2013 there were approximately170,000 meters with this technology installed.

During fiscal year 2013 the Authority continued itsaggressive theft detection and prevention program.Amongst other detection techniques, the programutilizes the comparison of local/temporary meters onthe distribution lines versus the aggregate of the indi-vidual served meters, a comparison of a client’s pres-ent electricity usage versus historical data,unannounced meter inspections, and a toll free hotline for anonymous reporting of suspect electricitytheft. Based on recent experience, the Authorityanticipates the theft recovery program will generateconsiderable additional revenues and help deter fur-ther theft. As discussed in the Legal Affairs section theAuthority has established legally binding administra-tive processes to recover contested billings for theftfrom culpable clients.

As the technology for remote meter reading hasevolved the Authority has identified certain applica-tions which may benefit from enhanced access to theclient meter data. The meter data management systemmay be used for enhanced data input to the OMS dis-cussed above. The Authority is also evaluating usingthe AMR system to provide data to support theupgraded EMS, discussed above, which will be theprincipal system for controlling the generation andtransmission of power on the island. The electricalpower consumption data could also be used to sup-port analyses of operational performance and timebased pricing structures that may be evaluated in thefuture.

The Authority plans to upgrade the AMR communi-cation equipment at its large substations to improvedata transfer speed. In addition, the Authority plansto install internet communication with the AMRcommunication gear at many of its substations toimprove reliability and provide operational flexibility.

Although they are not among the AMR system fea-tures now being installed, the AMR has the capacityto incorporate at a later date the ability for theAuthority to simultaneously monitor and control theperformance of key components of its distributionsystem. This two-way communications is a critical

attribute of the “Smart Grid”. By controlling suchdevices from a central location, the Authority wouldbe able to enhance its capability to control load flow,manage restoration of service from an outage, andimprove the operational power factor. If added, thistype of control could reduce operating costs, improveclient satisfaction, and facilitate Demand-SideManagement & Energy Conservation (DSM & EC)programs by allowing the utility to control its clients’energy use; refer to the Demand and Energy Forecastsection.

GENERAL FACILITIESThe budget for capital improvements for the GeneralPlant encompasses General Land and Buildings andEquipment. During fiscal year 2013 the budget forGeneral Plant capital improvements amounted to$29.3 million. The actual expenditures during fiscalyear 2013 were $22.3 million; the savings from budgetresulted principally from reductions in expendituresfor improvements to buildings and grounds foradministration services and improvements to ware-houses. As shown on Appendix X Details of CapitalImprovement Program, the expenditures for GeneralPlant for fiscal years 2014 through 2018 are forecastedto be $33.8 million, $31.3 million, $29.9 million,$32.8 million, and $32.2 million, respectively.

Maintenance expenses for the General Plant in fiscalyear 2013 were $6.9 million. While this level wasbelow the original budget of $9.3 million, it waswithin 6% of the previous three-year averageexpenses. The Authority’s maintenance budget forGeneral Plant in fiscal year 2014 is $8.8 million.

The extensions and improvements planned for fiscalyear 2014 include $7.2 million for General Land andBuildings. The largest budget item in this group is forthe acquisition of transmission and distributionrights of way and land for planned expansions. Otherexpenditures within this category are for improve-ments to the Authority’s warehouses, workshops,offices, buildings, and grounds. The CapitalImprovement Program for fiscal year 2014 includesfunds to complete the structural rehabilitation of theplaza at the Authority’s headquarters in Santurce, SanJuan, as well as other improvements to variousadministrative services buildings.

The total expenditures for Equipment in fiscal year2013 were $17.8 million; office and computer equip-ment accounted for $9.0 million, overhaul of the largehelicopter used for installing and rehabilitating trans-mission lines cost $1.9 million and $3.8 million wasexpended on replacement vehicles. For fiscal year

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2014 the total Equipment budget is $26.6 million;this is comprised of four budget subgroups, as fol-lows: The Office and Computer Equipment budgetfor fiscal year 2014 is $5.6 million. The largest proj-ect is $2.8 million for improvements to the informa-tion services systems as part of a long term upgradethat has a budget of $18.4 million for the five fiscalyear 2014 – 2018. The Transportation Equipmentbudget is for repairs or improvements to theAuthority’s aircraft and for purchase and replacementof the Authority’s vehicles; the budget for fiscal year2014 is $8.3 million. The CommunicationEquipment budget is $4.2 million for fiscal year 2014;this budget is directed to improving and expandingthe communication network used by the Authorityfor operation of the System. The projects includeimprovements to the fiber optic network and upgrad-ing the microwave system between essential facilities.The last Equipment subgroup is Other Equipment,which has a budget of $8.5 million for fiscal year2014. The scope of this subgroup spans a wide rangeof equipment including miscellaneous tools used forthe installation of transmission and distribution lines,environmental monitoring equipment, specializedpower quality monitoring equipment, vehicle repairstools, and small construction tools.

CONDITION OF THESYSTEM’S PROPERTIES

The Consulting Engineers visited and noted the con-dition of each of the Authority’s steam-electric gener-ating facilities three or more times during fiscal year2013 and also visited the other production facilities atleast once during the fiscal year. In addition, we alsovisited and noted the condition of approximately one-third of the Authority’s three hundred and eightytransmission centers and distribution substations. Inthe course of these visits we observed other propertyin the production, transmission, distribution, andgeneral plant functional groups.

In conjunction with our field activities, we havereviewed various maintenance reports of theAuthority, specific maintenance activities, and theplanned actions for the next fiscal year. We have alsoreviewed reports submitted by manufacturers’ repre-sentatives.

In the opinion of the Consulting Engineers, the prop-erties of the System are in good repair and soundoperating condition.

CURRENT FORECASTDuring the second half of every fiscal year theAuthority prepares a forecast entitled Presupuesto deIngresos (Revenue Budget) that projects energy salesby service sector, revenues, and number of clients, aswell as projected generation, annual peak demandand fuel costs. This annual report references theAuthority’s Revenue Budget as the “CurrentForecast”. The Current Forecast contains detailedshort to intermediate-term projections of energy salesrevenues, number of clients, and fuel prices based onEnergy Information Agency (EIA) projections andother sources; the forecast also includes projections oflong-term generation and long-term peak demand.The remainder of this section will describe the resultsof these forecasts and the methodologies used in itspreparation.

The preparation of the Current Forecast is timed sothat its projections may be used to develop short-term(1-2 years), intermediate-term (3-5 years) and long-term projections (6 years and beyond) of variousfinancial and operational parameters. The initial yearof the short-term financial projection is used for theAuthority’s Annual Budget of Current Expenses(Annual Budget) for the ensuing fiscal year. The shortto intermediate-term energy projections are utilizedto establish the Authority’s needs for capital require-ments and the projected income statements, whichare used in turn to project its ability to meet the nec-essary requirements of its Trust Agreement covenantsregarding net revenues to projected debt service.

The long-term peak demand and generation projec-tion through fiscal year 2040 are generally used fortrends of generating capacity that may be needed inthe future. (See Capacity and Energy ResourcePlanning) The Authority developed a CurrentForecast in April 2013 as the basis for the fiscal year2014 budget, financial projections through fiscal year2018 and long-term generation and peak-demandprojections through 2040.

To establish energy sales data for fiscal year 2013,which is the base year in the Current Forecast, theAuthority’s Planning Directorate used actual energysales from July 2012 through February 2013 and pre-liminary generation data for March 2013. Theseenergy sales do not include the adjustments appliedprincipally to the industrial class sales to avoid dis-torting the base year of the forecast; the adjustmentsare discussed in the Energy Sales Forecast section.The estimate for energy sales for the remainingmonths of fiscal year 2013 were extrapolated from

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generation data for the comparable months in thefive-year period ending in fiscal year 2012, while salesby service sector were estimated to follow the averagedistribution of the 12 months through March 2013.The projections for energy sales and related data forthe period of fiscal year 2013 and after were based oneconometric modeling of energy sales by service sec-tor. Macroeconomic indicators provided by economicconsultants are key dependent variables for thesemodels. The Authority also has extrapolations ofenergy sales by service sector based on monthly datasince fiscal year 1993 and annual data since 1983.Generation requirements are derived from sales pro-jections, adjusted to reflect system operating losses.The forecast methodology reduces data to a dailybasis to allow adjustment for leap years.

The short-term and intermediate-term forecasts proj-ect sales, revenues, number of clients, generation, andmaximum demand on a monthly basis for the remain-der of fiscal year 2013 and for all of fiscal year 2014and on an annual basis thereafter through fiscal year2018. Projections of fuel costs are also providedthrough fiscal year 2018. The long-range forecastprojects annual generation (in GWh) and peakdemand (in MW) through fiscal year 2040.

The projected revenues in the Current Forecast arederived from the forecast energy sales by classifica-tion using existing base rates and the appropriate pro-jected adjustment charges for the cost of fuel andpurchased power. The Current Forecast also includesprojections for the reductions due to subsidies andcredits applied to the fuel and purchased power rev-enues and the hotel subsidy, but these reductions arenot incorporated in the total revenue forecasts. TheAuthority’s forecasted revenues and payment obliga-tions are discussed in the Financial section.

ECONOMY OF PUERTO RICO Since the present depressed state of the economy ofPuerto Rico is unprecedented in recent history, eco-nomic forecasting for the island is currently difficultand more uncertain. The demand for electric energyin Puerto Rico has historically tracked the island’seconomy and its attendant economic development.Puerto Rico’s economy has evolved from primarily anagriculture economy in the early 1900s to one domi-nated by manufacturing in the 1940s through the1970s and, finally, moving to a mixed economylargely comprised of the manufacturing and servicesectors over the past three decades.

According to census data the population of PuertoRico declined 2.2% between 2000 and 2010. This was

the first recorded drop in population on the island,but was consistent with the prolonged weak economydiscussed below. Subsequent census data have shownthe decline has continued at a steeper rate. The cen-sus data showed the population drop was due to a lowbirth rate and increased emigration; the populationlosses were disproportionately in urban areas andamongst the young and middle age. The rural popu-lation actually grew modestly in the same period. Thetrends from the census data indicate that 15% of thepeople were over the age of 65 years in 2010 and thatportion is projected to continue growing. Accordingto GDB statistics the 2012 estimated populationgrowth rate was negative 0.44%, and the net migra-tion rate minus 0.82 migrants per 1,000 of the popu-lation. A report issued by the Puerto Rico PlanningBoard attributed the declining birthrate to migrationof the people in their child bearing years, an economythat discourages family growth, more women marry-ing later in life, the drop in population of those inreproduction age, and family planning policies.

According to a Puerto Rico Labor Department reportthe unemployment rate remained high at 13.5% inJuly 2013, but this was still less than the highest per-centage of 16.9% in May 2010. The labor participa-tion rate in July 2013 was 41 percent.

The Puerto Rico Government Development Bank’sdata published as of January 2013, states that thecomposition of the Puerto Rico Gross DomesticProduct (GDP) by sector is as follows: manufacturing48.6%; finance, insurance, and real estate 17.8%;services 12.7%; government 8.3%; trade 7.6%; trans-portation and utilities 2.9%; construction and mining1.4%; and agriculture 0.7%.

The Planning Board is the official Commonwealthagency that collects and reports the macroeconomicindicators utilized in the Current Forecast, includingthe Gross Domestic Product (GDP), and the GrossNational Product (GNP), of the Puerto Rico economy.As measured by the GNP the Puerto Rican economywas robust in the three fiscal years ending in 2005;subsequently the economy grew marginally by 0.5%in fiscal year 2006 and then began five years ofdecline with contractions of 1.2% in fiscal year 2007,2.9% in fiscal year 2008, 3.8% in 2009, 3.6% in 2010,1.7% in 2011 and finally positive growth of 0.9% in2012. During the five fiscal years from 2007 to 2011Puerto Rico’s economy receded by over 12%, a mag-nitude not seen since the Great Depression. For fiscalyear 2013 the Planning Board reports a marginalgrowth rate of 0.3%.

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The Government Development Bank of Puerto Ricomeasures the island’s economic activity with theEconomic Activity Index (EAI). This index is similarto the Gross Domestic Product Index; it is keyed tofour major local monthly economic indicators. As canbe seen by the data, the GDB-EAI returned to growthin December 2011 which lasted approximately oneyear. This was the first period of growth since theisland’s economy recession began in 2006. The EAImaintained some positive growth on a 12 monthrolling basis through calendar 2012, however thebrief recovery ended at the beginning of calendar year2013 and had declined by 5% in the next six months.

The Planning Board attributes the modest recovery inthe economy of Puerto Rico during fiscal year 2012 tothe moderate expansion of the U.S. economy, theadditional revenue provided by the temporary excisetax on sales of Controlled Foreign Corporations man-ufacturing companies to affiliates, the additionalCommonwealth revenue provided by the Tax ReformAct, a drop in the employee’s social security tax rate,and an resurgence in demand in consumption andprivate investment in Puerto Rico.

ECONOMIC PROJECTIONSThe Current Forecast is based on econometric mod-els which attempt to correlate the future consump-tion of electricity with recent consumption data,industrial sector power costs and selected historicaland projected macroeconomic indicators. Thesemacroeconomic indicators are: personal disposableincome, used in part to forecast residential energysales; GDP, used in part to forecast commercial energy

sales; and GNP, used as a factor in forecasting indus-trial energy sales.

MACROECONOMIC PROJECTIONSIn the preparation of the Current Forecast theAuthority typically incorporates analyses of the PuertoRico economy that are prepared each year by threeindependent economic consultants. The forecasts pre-pared by the Commonwealth of Puerto Rico’sPlanning Board (Planning Board) were unavailablewhen the Authority performed its analyses for thisyear’s Current Forecast. The Authority used the twoforecasts that were available, which were the eco-nomic projections developed by the Inter-AmericanUniversity of Puerto Rico – IHS Global Insight (IAU-GI) and Advantage Business Consulting Group(ABC). A summary of the economic consultant’s pro-jections on the key indicators on the five-year outlookare as follows:

Puerto Rico Economic Indicator ProjectionsFive year Compound Annual Rate 2013-2018

ABC IAU-GI

Gross National Product 0.99 1.28Personal Disposable Income 1.64 1.75Gross Domestic Product 1.58 1.63

The key economic indicator projections correlatewith the resultant predictions by the Authority forelectric sales by major classification as describedbelow.

In view of the uncertainties in the economic forecaststhe Authority generally uses the least optimistic five-

52


3.0%

2.0%

1.0%

0.0%

-1.0%

-2.0%

-3.0%

-4.0%

-5.0%

-6.0%

Jan 2010

Mar 2010

May 2010

Jul 2

010

Sep 2010

Nov 2010

Jan 2011

Mar 2011

May 2011

Jul 2

011

Sep 2011

Nov 2011

Sep 2012

Nov 2012

Jan 2012

Mar 2012

May 2012

Jul 2

012

Jan 2013

Mar 2013

May 2013

Jul 2

013

PUERTO RICO Economic Activity Index

No. CEPR-AP-2015-0001

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year intermediate-term energy sales projections forfinancial planning purposes and the most expansiveeconomic projections for capacity and operationalplanning. In the Current Forecast the Authorityselected ABC’s projections as the bases for its fiscalyear 2014 annual budget as well as the financial pro-jections through fiscal year 2018, yielding a five-yearcompounded annual growth rate (CAGR) of 1.22% inits electric energy sales model.

The expansive projections, those of IAU-GI, yielded afive-year CAGR of 1.43% in the Authority’s electricenergy sales model which were used in its loadgrowth forecast for capacity planning.

For many years the short-term energy sales projec-tions in the Authority’s Current Forecasts were usu-ally conservatively close to actual performance; thesewere during a period of almost continuous electricsales growth only interrupted by the impact of hurri-canes. In fiscal year 2006, however, short-term con-sumption forecasts began to understate the actualdecline in consumption. To improve the accuracy ofits projections, in 2008 the Authority revised themodeling of residential and industrial sector con-sumption to reflect the clients’ sensitivity to the priceof electricity.

CURRENT FORECAST PROJECTIONSIn developing the Current Forecast the Authority uni-formly employs the economic indicators from eacheconomic consultant. The resulting projection ofenergy sales over the five-year intermediate term fore-cast period are summarized below:

TOTAL ENERGY (GWH) SALES PROJECTIONS

Fiscal ABC Annual IAU-GI AnnualYear Change Change

2012 18,112.5 18,112.5

2013 17,966.7 -0.80% 17,966.7 -0.80%

2014 18,199.0 1.29% 18,191.5 1.25%

2015 18,267.8 0.38% 18,431.2 1.32%

2016 18,476.0 1.14% 18,699.3 1.45%

2017 18,756.9 1.52% 18,988.1 1.54%

2018 19,090.6 1.78% 19,292.7 1.60%

5-yr CAGR 1.22% 1.43%

ABC’s model dated April 2013 considered a widerange of factors while developing its economic fore-cast. As reported in the Current Forecast, these fac-tors included the following exogenous variables:growth of the U.S economy of between 1.8% and

2.4%, the price of a barrel of oil (WTI) of between$103.25, an increase over the current price of $95.07;U.S. federal funds target rate of 0.25% until 2014 and0.5% to 1.15% through 2018 and the 10-year treasuryrate of 1.80% to 3.00%.

There were several endogenous variables consideredby the ABC projections. Those listed are: that therewould no further degradation of the Authority’spower bonds to non-investment grade, that the fiscalausterity period would extend until 2014 or early2015, very moderate growth in real public expendi-tures, public investment begins to recover vigorouslyafter 2015, that in 2016 the elimination of the struc-tural deficit of the central government would beachieved, and that the rate of inflation over the yearsof the projection would be controlled between 2.5%and 2.6%.

CONSUMPTION OF ELECTRICITYOver the period from the mid-1980’s through 2006,the annualized rate of growth in the consumption ofelectricity in Puerto Rico was generally greater thanthat of the U.S. mainland. Interruptions in this pat-tern were principally caused by major weather events.The event with the greatest impact occurred in 1998when Hurricane Georges devastated the island, caus-ing severe damage to the Authority’s system and adramatic, short-term curtailment in energy sales. Byfiscal year 2000, however, the annual growth rate inthe Authority’s energy sales rebounded back to arobust 6.8%. The growth rates for energy sales in fis-cal years 2001, 2002, and 2003, were moderate at3.2%, 2.2% and 4.0% respectively. For fiscal years2004 through 2007 the decline in the annualizedgrowth rate for energy sales continued with marginalgrowth rates of 1.9%, 1.2%, 0.6% and 0.3%, respec-tively. For fiscal years 2008 and 2009 energy salesdeclined sharply resulting with negative growth ratesof 5.2% and 5.5%, respectively. In fiscal year 2010, thenegative trend in energy sales reversed when totalenergy sales increased by 3.9%, principally as a resultof a 10.8% jump in energy sales in the residential sec-tor. However, during fiscal years 2011 and 2012energy sales continued the previous negative trendwith declines of 3.8% and 2.1%. As discussed in theEnergy Sales Forecast section, the reported energysales for fiscal year 2013 show an increase of 0.6%over the previous year.

As shown on the comparative chart, Electric RetailSales-All Sectors US & PR, the rate of growth in elec-tric sales contracted in Puerto Rico and the U.S. main-land during 2008 and 2009. Both Puerto Rico and theU.S. mainland experienced robust electric sales

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growth in 2010. However, as the U.S. mainland recov-ered from its recession electric utilities posted modestelectric energy sales growth in 2011 and are projectedto produce marginally positive electric energy salesgrowth less than 1% annually to 2018. Although theGNP of Puerto Rico increased marginally by 0.9%during fiscal year 2012, electric sales were off 2.1%from the previous year. For reference, the comparablestatistics in fiscal year 2011 were a decline of 1.7% inthe GNP and 3.8% decline in electric sales. In theCurrent Forecast the Authority projected a decreasein electric energy sales of 0.8% in fiscal year 2013, incontrast to the reported increase of 0.6%. The CurrentForecast projects growth in electric energy sales in2014 of 1.3%, followed by steady growth in the fol-lowing four years from 0.4% in fiscal year 2015 to1.8% in fiscal year 2018.

It should be noted that in the comparison chart theAuthority’s energy sales for fiscal year 2013 are thereported actual energy sales and preliminary electricenergy sales replaced the forecasted energy sales forU.S. electric utilities in calendar year 2013. The fore-casted percentage change for Puerto Rico in the sub-sequent year 2014, however, reflects the CurrentForecast projected change. By updating the 2013 datafor the US the percentage, the change to 2014 may beslightly different than that formally estimated or pro-jected. The data for the U.S. mainland are derivedfrom EIA’s Annual Energy Outlook 2013 (AEO 2013),prepared in June 2013.

DEMAND AND ENERGYFORECAST

GENERATION FORECASTThe total net generation during fiscal year 2013,including hydro-power and power purchased fromthe cogenerators and renewable energy projects, was21,009 GWh, which was a 0.9% decrease comparedto that generated in fiscal year 2012. In 2014 theAuthority projects that total net generation willincrease by 1.4%. With the exception of fiscal year2010, net generation has been in decline since fiscalyear 2008, when it was 9.1% more than fiscal year2013.

Electric generation projections in the CurrentForecast track with forecasted sales. The contributionto the System of power from renewable energy proj-ects is forecasted to grow from 0.7% in fiscal year2013 to more than 4.5% of the total for the fiscal years2015 through 2018. The growth of renewable energyprojects will displace generation from the Authority’sleast efficient and most costly units. The CurrentForecast projects a decline in net generation by theAuthority of 1.8% in fiscal year 2015, followed byincreases of 1.6%, 2.2% and 2.9 % in fiscal years 2016through 2018.

Each year in the Current Forecast the Authoritydevelops a ratio, referred to as the system efficiency,based on total energy sales as a percent of the total ofthe Authority’s gross generation plus the net amount

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Actual & Forecast 2009–20186.0%

4.0%

2.0%

0.0%

-2.0%

-4.0%

-6.0%2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

-3.4%

4.3%

0.5%

-0.3%

-0.6%

0.7%

1.3% 1.1% 1.3% 1.1%

-5.5%

-3.8%

3.9%

-2.1%

0.6%

-0.1%

0.4%

1.1% 1.5%

1.8%

No. CEPR-AP-2015-0001

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of purchased power, which is the net output of thetwo cogenerators plus the output of the renewableenergy projects. The annual generation for the fore-cast period was determined utilizing a system effi-ciency that was the System’s 12-month average for theperiod ending February 2013, based on the sales andgeneration methodology in the Current Forecast. Theactual and projected generation by plant are pre-sented in Appendix IV, Annual Net Generation, FuelConsumption, Fuel and Purchased Power Costs.

PEAK DEMAND FORECASTConsistent with the Authority’s conservativeapproach to planning for expansion of generationcapacity the Current Forecast used the projectionsthat resulted in the most expansive forecast for thedevelopment of the peak demand forecast. For thisyear’s Current Forecast the projections from IAU-GImet that criterion and were the basis of the peakdemand forecast. For a comparison of the economicconsultants kWh sales projections refer to theEconomic Projections section above.

For the seventh consecutive year the System did notreach a new peak demand. The current historic sys-tem peak of 3,685 MW was established in September2005, in fiscal year 2006. From fiscal years 2008 to2013 the five-year compound average growth rate(CAGR) in actual peak demand contracted by 0.5%.

The peak demand for fiscal year 2013 was 3,265 MWwas 1.2% less than that reached during fiscal year2012 and 11.4% less than the historic system peakdemand.

The Current Forecast utilized a system load factor of77.2% to predict peak demand for the duration of thegeneration forecast. The system load factor is the ratioof the average demand in kilowatts supplied during adesignated period, in this case the fiscal year throughMarch 2013, to the peak or maximum demand alsomeasured in kilowatts. The most expansive model inthe Current Forecast predicts that the 3,685 MWpeak demand established during fiscal year 2006 willnot be exceeded during the duration of the long-termforecast. The forecast peak demand projects a CAGRgrowth of 1.4% for the five years through fiscal year2018, with effectively no growth in peak demand forthe balance of the forecast period.

Since 1993 the Authority has included explicit recog-nition of the potential effects of its DSM & EC pro-grams in its peak demand forecasts; these programsare discussed below. The Long-Term Peak DemandForecast graph shows the degree in which the peakdemand forecast has declined over the last four years.

2010 Peak Demand Forecast 2009 Peak Demand Forecast2013 Peak Demand Forecast 2012 Peak Demand Forecast 2011 Peak Demand Forecast

Fiscal Year2012

20132014

20152016

20172018

20192020

20212022

20232024

20252026

20272028

20292030

Long-Term Peak Demand Forecast

Peak D

em

an

d (M

W)

4,600

4,400

4,200

4,000

3,800

3,600

3,400

3,200

3,000

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DEMAND-SIDE MANAGEMENT ANDENERGY CONSERVATION PROGRAMSElectric utilities offer programs to encourage clientsto modify their levels and patterns of electric con-sumption. The implementation of such programs,known collectively as Demand-Side Management &Energy Conservation (DSM & EC), achieve twoobjectives; energy efficiency and load management.DSM initiatives such as load management programsare designed to shift load from peak hours to nonpeakperiods. Energy efficiency measures reduce theenergy consumption of end-use devices and systemsby promoting high-efficiency equipment and energyefficient building design. Successful DSM & EC pro-grams promote energy efficiency and achieve cost-effectiveness for utilities and clients thereby delayingthe need for new capacity. DSM & EC programs helpto conserve fossil fuel resources, reduce air pollution,and lower a utility’s need for additional capital and itscarrying costs.

As part of its Load Management Program theAuthority promotes: Time-of-Use (TOU) rates toimprove or smooth out its load curve; the purchase ofenergy-efficient motors and air conditioners; and theuse of more efficient lighting. TOU rates offer eco-nomic incentives to Industrial and Commercialclients who modify their patterns of energy consump-tion, i.e., adding load to off peak hours and reducingload during peak hours. (For more information onTOU rates see the Rates section.) The Authority, witha limited staff, also offers advice to clients on powerfactor improvement that benefits both the client andthe Authority.

During recent years the Commonwealth Govern-ment’s Energy Affairs Administration (EAA) has pro-moted a succession of programs and incentivespromoting cost effective energy saving. These haveranged from encouraging the replacement of incan-descent light bulbs with compact fluorescent bulbs tovoucher initiatives that subsidize purchasing energyefficient home appliances. The EAA has been active inencouraging projects to access federal grant moneythrough the stimulus funding from the AmericanRecovery and Reinvestment Act and the Departmentof Energy’s “Energy Efficiency and ConservationBlock Grant” (EECBG) program. Some EECBGgrants, such as light bulb exchange programs, are alsodirectly administered through larger cities. In addi-tion to weatherization projects for the private sectorand vouchers for high efficiency appliances, the EAAhas promoted energy savings agreements betweenpublic agencies and a specialized private company for

the installation of energy savings equipment with aprovision that the savings in energy costs would beshared between the two entities.

In February 2013 the EPA and the Commonwealthannounced new guidelines for energy efficient homesin Puerto Rico. These guidelines, developed by theEPA under the federal Energy Star program, were for-mulated based on Puerto Rico’s Caribbean climate toestablish energy efficiency standards and practices forlocal home construction. The goal of the energy effi-cient homes is to identify features that will reduceenergy use by an estimated 20 to 30% compared tostandard homes. The efficiency features include: highquality energy efficient windows; efficient systems forheating, ventilating and cooling; comprehensivewater management systems to protect floors, wallsand foundations from moisture damage; and energyefficient lighting and appliances.

The Commonwealth government created a GreenEnergy Fund following passage in 2010 of the PuertoRico Green Energy Incentives Act. The six-year pro-gram began in fiscal year 2012 with a budget of $20million for each of the first two fiscal years and $25million in fiscal year 2014. The fund is structured toprovide grants to business and homes that invest inrenewable energy technologies such as photovoltaic,wind, and renewable biomass combustion. Under theGreen Energy Fund incentives are available for up to60% of the eligible costs for small renewable energyprojects, and up to 50% for larger projects. The incen-tives do not apply to an installation which generatespower that exceeds it internal requirements asdefined based on the technology.

The Authority, as it has for the past several years,projects that the savings from its DSM & EC programwill lower peak demand by 1 MW per year (see pre-vious section).

The Authority is evaluating its long term meteringplans to potentially expand the operational features ofits automated meter reading system to include a loadcontrol component. This feature would increase theimpact of load reduction by allowing the Authority tocontrol clients’ equipment, such as air conditioners,for periods when load management is desirable.

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CAPACITY AND ENERGYRESOURCE PLANNING

OVERVIEWThe Authority periodically updates its Capacity

Expansion Plan (CEP) to ensure its ability to meetexpected long term electric load growth with reliable,cost effective and environmentally compliant electricpower. To address cost and reliability, the Authorityemploys system-planning software that is widelyaccepted throughout the electric utility industry.

Consistent with its goals to provide reliable, costeffective electric energy the Authority has also pur-sued fuel diversification for many years, with the pri-mary focus being on increasing the utilization ofnatural gas in its production plants. Conversion of oilfired production plant to dual fuel firing of naturalgas and / or oil would both reduce air pollution andprovide the Authority’s ratepayers with reduced elec-tric energy costs.

As discussed in the Environmental section, regula-tions issued by the EPA in fiscal year 2012 have addedother imperatives for the Authority to reduce itsdependence on fuel oil and switch to natural gas forelectric generation. The Authority’s environmentalcompliance strategy involves dual fuel firing conver-sion at its eight largest steam plants. By the end of thepast fiscal year the two 410 MW units at the SouthCoast plant were capable of full firing on natural gas,which was purchased by the Authority from thenearby regasification facility at the EcoEléctricacogeneration plant. The development of the naturalgas supply infrastructure is discussed in the EnergyResource Planning section below.

AVAILABILITYOver the last two decades the Authority has directedmuch of its production capital expenditures onimprovements to extend the life of its generatingfacilities, reduce the need for extended scheduledoutages, and lower the frequency of forced outages,thereby increasing the percentage of time its generat-ing units are available for service. As the Authority’sdual fuel conversion strategy has been implementedthe largest units have been through extended outagesto implant the scope of required work.

Since the availability data reflect accumulated per-formance over the preceding twelve months, anextended outage of a large unit can impact the systemdata well beyond its return. This was observed fol-lowing the outages at the Palo Seco plant due to fires.During fiscal year 2010 the Palo Seco units were fully

restored to service. The availabilities of both thesteam plant and total system steadily increased duringfiscal years 2010 and the first half of 2011 reaching82%, as routine maintenance at other plants that hadbeen delayed while the Palo Seco outages were per-formed.

In October 2011 the Authority removed the 450 MWAguirre Unit 1 from service for a major overhaul andto perform initial boiler modifications for its conver-sion to dual fuel firing. Later in 2012 the 410 MWSouth Coast Unit 6 was removed from service forfinal boiler conversion modifications, allowing theunit to increase its gas firing capability. The removalfrom service of these large generating units reducedtotal system availability to 78% from December 2011through September 2012, after which availabilityincreased again to 80%. In January 2013 the 410 MWSouth Coast Unit 5 was removed from service for thefinal boiler conversion upgrades similar to that ofSouth Coast Unit 6, reducing total system availabilityto 77% by the end of fiscal year 2013. Concurrentwith extended outages for dual fuel conversion work,the Authority has adopted the policy of avoidingovertime for scheduled outages to reduce their costs.This work practice has extended the duration of theseoutages and negatively impacted availability.

The Authority’s overall production plant equivalentavailability for the five-year period ending June 30,2013 is shown in the chart based on rolling twelvemonth data. Performance is shown by theAuthority’s total system and by the three majorkinds of generation — steam, combustion turbine,and combined cycle. Prior to fiscal year 2010, theavailability of San Juan Units 5 & 6 was includedwith the steam portion of the system. Beginning infiscal year 2010 San Juan Units 5 & 6 were trackedin the combined cycle group.

CAPACITY PLANNINGThe Authority’s current capacity expansion plan isbased on the Authority’s most recent Current Forecastdated April 2013. Based on these projections the pre-vious peak demand will not be exceeded within thehorizon of the Authority’s capacity planning. TheCurrent Forecast foresees relatively modest increasesin peak demand averaging 0.7% per annum over thefirst ten years of the forecast period. The previous sys-tem peak was 3,685 MW, established in fiscal year2006; in fiscal year 2013 the peak was 3,265 MW. TheCurrent Forecast projects the peak demand in tenyears will be 3,499 MW and the previous peak willnot be exceeded even within the long term horizon ofthe Authority’s forecast.

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Details of existing generating capacity of the Systemare shown in Appendix VIII, System Capability. TheAuthority does not plan to add or retire capacitythrough fiscal year 2018.

The Authority has numerous proposed renewableenergy projects under power purchase agreements,however, none meet the criteria for firm and reliablecapacity therefore these projects are recognized asonly sources of energy; this is also consistent withtheir characteristically low capacity factor.

PURCHASED POWERIn parallel with the internal program to improve pro-duction plant performance, the Authority enteredinto long-term purchased power operating agree-ments with the owners of two privately owned andoperated cogeneration facilities. These relatively newplants were selected to aid the Authority in providingfor electric load growth. They reduce the island’sdependence on fuel oil, and continue to improve theSystem reliability.

Prior to the Authority purchasing power from thecogenerators, nearly 99% of the energy sold by theAuthority was produced by its oil-fired units. In fiscalyear 2013 the cogenerators produced 33.7% of theSystem total power. Subject to dispatch and actualavailability, the combined generation of EcoEléctrica,L.P. and AES-PR is forecasted to be 33.3% of the totalSystem generation in fiscal year 2014.

In accordance with a 22-year power purchase operat-ing agreement (PPOA) that commenced in March2000, the Authority has been purchasing 507 MW ofpower produced by EcoEléctrica, L.P.’s gas-fired com-bined-cycle cogeneration facility. The PPOA outlinescapacity and energy charges to be paid by theAuthority based on the performance and electricaloutput of the facility. A principal condition of theagreement is a progressive reduction in the monthlycapacity charge, paid by the Authority, subject to thefacility meeting a minimum 93% availability on a 12-month rolling average. EcoEléctrica’s availability dur-ing fiscal year 2013 was 91.4%, down from 95% in theprevious year. In fiscal year 2013, EcoEléctrica, L.P.represented 8.6% of the System’s capacity and pro-vided 17.0% of its power. For fiscal year 2014 theenergy provided to the Authority’s from EcoEléctricais forecast to be 17.5% of the System total.

The Authority also has an agreement with AES-PR topurchase 454 MW of power from its coal-fired steam-electric plant. The plant, which consists of two iden-tical fluidized-bed boilers and two steam turbines,uses clean coal-burning technology. The facility com-menced commercial operation in November 2002.The 25-year PPOA with AES-PR is similar toEcoEléctrica, L.P.’s. The minimum guaranteed avail-ability for AES-PR is 90%, slightly lower thanEcoEléctrica, L.P.’s, but typical of coal-fired electricgenerating plants. The availability of AES-PR for the12 months ended June 30, 2013 was 91.1%; its avail-

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ability was 87.4 % during fiscal year 2012. AlthoughAES-PR comprises 7.7% of the System’s capacity, thiscogenerator provided 16.7% of its energy during fis-cal year 2013. It is anticipated that the plant will pro-vide 15.8% of the System’s total generation in fiscalyear 2014.

These PPOA’s have allowed the Authority to reduceits dependency on fuel oil, mitigate the economic riskof its electric system operation, and to schedule theretirement of some of its older, less efficient generat-ing units. For further discussion on EcoEléctrica andAES-PR, refer to the Cogenerators in the System’sOperation section.

The operating agreements with both cogeneratorsinclude provisions for fixing the cost of fuel used togenerate electricity for each year of the contract at thebeginning of such year. Annually, the fuel portion ofthe energy charge per kWh is based on actual fuel-related energy charges for the preceding year,adjusted using inflation and other indices. The fixednature of the fuel cost reduces short-term variationsin the Authority’s energy costs by bringing purchasedpower costs out of step with price changes in othercomponents of the Authority’s fuel mix. The fixedfuel costs also afford the Authority the opportunity tobetter dispatch its electric production plant.

ENERGY RESOURCE PLANNING With the prospect of adequate generation reserves formany years, the Authority’s focus has been on devel-oping an environmental compliance program dis-cussed in the Environmental section, while reducingand stabilizing future electric power costs, bydecreasing its dependence on oil. The Authority hasidentified the first step in this process is to expand itsuse of natural gas, which would be supplied to theisland as liquefied natural gas (LNG). Typically theprice structure of LNG provides more stable energyprices in comparison to oil. The availability of com-peting, alternative fuels may also benefit theAuthority in its negotiations with fuel suppliers.

The Authority’s first proposed program to expand gasfiring was a planned gas pipeline on the island’s southcoast from the LNG regasification facility at theEcoEléctrica cogeneration plant in Guayanilla to theAuthority’s Aguirre plant approximately 40 miles tothe east. The first units scheduled to use the surplusgas capacity from EcoEléctrica were the two existing296 MW combined cycle units at the Aguirre plant,which had been converted to dual fuel capability. Thepipeline project had raised significant local opposi-tion and controversy from its inception. Construction

on the pipeline was in its early stages when theCommonwealth decided to terminate the project in2009.

The Authority subsequently developed a broader pro-gram to expand natural gas firing in its units. Thisprogram was based on a pipeline from the LNGregasification facility at the EcoEléctrica cogenerationplant to certain Authority plants on the north coast.The proposed 92 mile long pipeline route was norththrough the island’s interior and then east to the SanJuan area. By fiscal year 2012 the Authority had madesignificant progress in the permitting process, duringwhich the Authority responded to numerous recom-mendations with respect to routing, safety and envi-ronmental mitigation. As the completion of thepermitting process drew near, the US Army Corps ofEngineers, who were the lead permitting agency,extended its review after several federal agencies sub-mitted additional concerns or revised comments.During this period contentious opposition to thepipeline within the Commonwealth continued togrow; in addition, it was determined that the pro-posed pipeline would not have enough capacity tosupport the Authority’s compliance with the MATSenvironmental objectives.

In view of the seriousness of the situation, as discussedin the Environmental section, the Commonwealth’sgovernment appointed a select committee presidedover by the chairman of the Environmental QualityBoard of Puerto Rico to evaluate the alternatives forcompliance with MATS. The committee concurredwith the Authority that conversion from oil to naturalgas was the best method. The committee’s general rec-ommendations included employing one or more off-shore regasification and delivery systems for LNG, butacknowledged other technologies such as compressednatural gas (CNG) should be considered. The 92 milepipeline project was judged to be not viable, due toconstrained capacity, projected cost escalation andcommunity opposition.

After cancellation of the southern pipeline to Aguirre,the Authority decided to utilize the excess gas storagecapacity which it was leasing at EcoEléctrica by con-verting the boilers at the 410 MW Costa Sur Units 5& 6 to dual fuel. These units were selected because oftheir proximity to the LNG facility, resulting in ashort pipeline from EcoEléctrica to the Costa Surplant and the relatively low capital cost and shortschedule to convert the units to dual fuel. During fis-cal year 2011 the Costa Sur Units 5 & 6 were con-verted to dual fuel burning capability. Since then theunits have operated with at least partial gas firing.

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Subsequently the boiler internals were modified tosupport continued full load operation with all gas fir-ing; this work was performed for Unit 6 during fiscalyear 2012 and completed for Unit 5 at the end of fis-cal year 2013.

The quantity of natural gas available to Costa Surfrom EcoEléctrica has been constrained under theterms of the short term fuel purchase agreementwhich is scheduled to expire late in fiscal year 2014.The maximum quantity of fuel had been based on thecapacity of the regasification facility. During fiscalyear 2013 EcoEléctrica installed and made opera-tional two additional regasifiers. Under their FERCpermit EcoEléctrica regasification capacity enables itto provide sufficient gas for its own consumption aswell as Costa Sur Units 5 & 6 at approximately 55%capacity factor. Additional gas production is possiblewith the installed equipment, however this wouldrequire a revised FERC permit.

The Authority’s current approach to expand the sup-ply of natural gas on the island has been an offshoregasification facility for LNG deliveries near its Aguirrepower complex on the southeast coast. The proposedAguirre Offshore Gas Port (AOGP) will be a floatingfacility to receive and gasify LNG shipments. The nat-ural gas will be delivered to the Aguirre plant bypipeline from the AOGP. The Authority plans that theAOGP will be installed by a vendor under a long termagreement and the Authority has continued with thecoordinated air permit effort with that vendor forboth the AOGP scope and the Aguirre plants. Theproposed schedule at the end of fiscal year 2013would enable gas to be available for the Aguirre plantby the MATS compliance date of April 2015, with nomargin for unanticipated delays.

During fiscal year 2013 the Authority continued itsdue diligence on the contractual structure of the gassupply infrastructure and was evaluating alternativesupply arrangements for natural gas to the north ofthe island. The Authority is evaluating the structureof the LNG commodity supply agreements, whichwould be separate from the infrastructure develop-ment. The Authority plans to select the bases forestablishing the development of the natural gas infra-structure and fuel supply during fiscal year 2014.These will lead to qualifying bidders and solicitingproposals by the end of that fiscal year.

The Authority has focused first on its four largeststeam units for dual fuel conversion on the southcoast. The four steam units in the San Juan metropol-itan area will be converted after the schedule for gasdeliveries has been established. With sufficient fuel

being available the Authority plans to add gas firingcapability to the Authority’s two most efficient units,San Juan Units 5 & 6, which are combined cycle unitspresently burning high cost distillate fuel.

ALTERNATIVE ENERGY SOURCESTo promote the use of renewable resources for the pro-duction of electric energy and further expand energydiversification, the Commonwealth passed Act 82 in2010 that established new initiatives to stronglyencourage the development and implementation ofrenewable energy sources in Puerto Rico. The legisla-tion effectively sets a target renewable portfolio stan-dard that requires an increasing percentage of retailelectric power be provided from renewable energysources. The initial target calls for 12% of total energysales should be from renewable energy production bythe end of calendar year 2015, increasing to 15% by2020 and 20% by 2035. These targets are premised onthe basis that the renewable energy projects will notcompromise the continued safe and reliable operationof the island’s electric system. The legislation creates afinancial incentive to meet these standards by estab-lishing Renewable Energy Certificates that can be soldif the standards are exceeded or must be purchased ifthe standard is not met.

As more renewable energy projects have entered serv-ice the electric utility industry has been analyzing theimpact of these intermittent resources on systemoperations and stability. The Authority has performedsimilar screening studies to evaluate the impact ontheir System operation which is inherently more sus-ceptible to disturbances given that as an island theylack an interconnected external transmission andgeneration network. To corroborate earlier studies,the Authority plans to perform refined analyses dur-ing the coming fiscal year; the analyses will identifythe maximum generation from projected renewableenergy resources that can be accommodated by theSystem. As the percentage of renewable capacityincreases within the System, the inherent uncertaintyof these sources imposes conditions on reserves andeconomic dispatch which could increase overall sys-tem electric production costs. Also the electrical char-acteristics of some renewable technologies affect thetransmission and distribution of electric energyrequiring the implementation of mitigating technolo-gies to maintain electric system stability. In 2012 theAuthority revised their minimum technical require-ment (MTR) standard, which establishes the techni-cal parameters for integration of renewable projectsinto the Authority’s electric system.

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25.00Cost o of Selected Fossil Fue

U.S. Electric Utility els 2002 - 2013

y Costs

5.00

10.00

15.00

20.00

0.00

Coa

200 2004 2003 2002

al Natural Gas

2008 2007 2006 05

Petroleum Liquids

2 2011 2010 2009 20132012

In the past fiscal year the Authority began renegotiat-ing its agreements with many renewable energy proj-ect developers to lower their energy costs to theAuthority and incorporate the revised MTR. This hasbeen an on-going process that applies to all new proj-ects as well.

As of the end of fiscal year 2013 the Authority hadsigned a total of 63 power purchase agreements fromrenewable energy projects with a total capacity of1,661 MW. All of these agreements are for onlyenergy. As tabulated, few of these were in operationby the end of fiscal year 2013. The preponderance ofthe pending projects had not begun construction bythe end of the past fiscal year. The total energy fromthe operating renewable sources accounted for 0.7%of the System total during fiscal year 2013. TheAuthority projects the contribution from renewableswill increase to 4.7% by fiscal year 2015, where it willstabilize at that level through 2018.

RENEWABLE ENERGY PROJECTS STATUS

FISCAL YEAR 2013

Category Number Associated Operating Associated

of Projects Capacity Projects Capacity

Wind 10 382.9 3 102

Solar Photovoltaic 46 1157.4 2 22.1

Landfill Gas 4 11.5

Waste-to-Energy 3 109.0

Total 63 1660.8 6 124.1

Fiscal year 2013 marked the first year during whichrenewable energy sources contributed meaningfulamounts of the energy transmitted and distributedwithin the System. During fiscal year 2013 theAuthority purchased energy principally from fourrenewable energy projects; an additional small windturbine provided power occasionally.

The largest capacity renewable source was the Patternwind farm in Santa Isabel, in the southeast of theisland. Its initial capacity was planned for 75 MW;pending certain changes it is anticipated that thefacility will operate at 95 MW seven months of theyear and 75 MW for the balance. The second largewind farm provides 26 MW from the Punta Limafacility in the east of the island near Naguabo. Bothwind turbine facilities began commercial operationsin December 2012. Finally, the Authority installed a 1MW wind turbine in the Bechara section of San Juanthat went into operation late in fiscal year 2012. Theturbine is located at a PRASA (Puerto Rico Aqueductand Sewer Authority) facility which uses basically allthe output.

During the past fiscal year the largest solar photo-voltaic facility on the island was the 20 MW solarproject in Guayama, on the south coast. This plantbegan commercial operation in October 2012. The2.1 MW Windmar Cantera Martinό solar facility inPonce began operations at 1.7 MW in 2011 andexpanded in October 2012.

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FUEL MIXFor information on the types of fuel used in theAuthority’s various generating units see the Fuels sec-tion under System’s Operations.

The mix of generation by energy type for theAuthority’s System during fiscal year 2013 consistedof 54.4% being oil generated, 10.8% from natural gasat the Authority’s Costa Sur plant, 17.0% from natu-ral gas at the EcoEléctrica’s facility, 16.7% from AES’scoal burning facility, and 0.4% from the Authority’shydroelectric plants. The amount of power generatedfrom natural gas in fiscal year 2013 totaled 27.8%, upfrom 18.9% in the previous year. Fiscal year 2013marked the first year during which the renewableenergy projects produced meaningful quantities, with0.7% of the System’s generation.

As discussed in the Fuels section in System’sOperations the Authority regularly purchases its fueloil under one year contracts that include provisionsfor extension. These contracts are structured toreflect physical clearing prices, and avoid speculationin the market. Frequently the Authority uses variousstrategies such as fixed price contracts and commod-ity hedges to minimize fuel cost volatility. In addition,the pricing structures of the two cogenerators arebased in part on annual indices to provide stable pric-ing for purchased power. These strategies, however,

do not isolate the Authority from changes in energycosts in the global market; all production related fuelexpenses are currently recovered through the fuelcomponent of the adjustment charge.

The total projected use of each type of fuel—residualor distillate oils, natural gas and the production fromthe cogenerators and renewable energy projects—isbased on the generation required to meet the energydemand forecasts which are developed in the CurrentForecast, as discussed above. The contribution to theSystem of power from renewable energy projects isforecasted to grow from 0.7% in fiscal year 2013 tomore than 4.5% of the total for the fiscal years 2015through 2018. Since the Authority is obliged toalways take the power from the renewable energyproject, except in unusual circumstances, the growthof renewable energy projects will displace generationfrom the Authority’s least efficient and most costlyunits. The Authority utilizes an economic dispatchsimulation of all generating sources in the System todetermine the lowest cost generation plan. This dis-patch simulation takes into account the heat rate,operational characteristics and fuel costs specificallyfor each plant. As discussed in the Current Forecastsection, this information was developed for theremaining months of fiscal year 2013 and summa-rized annually for the five-year intermediate-term

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A & PREP PA 3

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forecast through fiscal year 2018. The actual annualresults of generation, fuel use and costs for fiscal year2013 and those forecasted over the five-year periodare presented in Appendix IV, Annual Net Generation,Fuel Consumption, Fuel and Purchased Power Costs.

Although the data in the charts of the costs of selectedfuel for utilities are based on mainland electric pro-duction facilities, the oil and coal pricing are indica-tive of trends applicable to Puerto Rico. The chartsshow the variations in the cost of selected fossil fuelson an MMBtu basis as reported to the EnergyInformation Administration’s (EIA), the reportingarm for the Department of Energy; the first chart is onan annual basis from 2002 to 2013, the second showsmonthly data from July 2011 to July 2013. It shouldbe noted that the natural gas data in the chart reflectpipeline gas, while the only natural gas available inPuerto Rico is liquefied natural gas (LNG), which hasa different and higher pricing basis. This differentialin price would be due to the high capital costs ofinfrastructure to liquefy, store and regasify the LNG,specialized transportation vessels and the energy con-sumed in its liquefaction, transportation, storage andregasification.

AUTHORITY’S FUEL

The Authority’s average composite cost of fuel,including transportation and fuel-handling costs andthe cost of the fuel line of credit, in fiscal year 2013was $111.18 per barrel. The composite barrel cost isbased on the total cost of all the petroleum burned bythe Authority, both distillate and residual oils, plusnatural gas, which is equated to distillate on the basisof distillate’s nominal heating value in terms ofMMBtu per barrel. During fiscal year 2013 natural gaswas burned only at Costa Sur Units 5 & 6. The totalcosts of fuel for fiscal year 2013 and the five-year fore-cast period are shown in Appendix III, Detail ofOperating and Maintenance Expenses. During fiscalyear 2012 the Authority entered into a CommoditySwap Agreement that provided protection againstincreases in the price of No. 6 fuel oil. The premiumfor the swap was $29.2 million, which is being amor-tized from June 2012 to October 2013. The payout toits counterparties amounted to $21.9 million in fiscal2013 and $141,500 in fiscal year 2012.

Based on the Current Forecast, the Authority’s esti-mated costs of fuel per barrel excluding financecharges, fiscal years 2014 through 2018 are forecastedto be $95.25, $94.67, $88.71, $87.27 and $80.94,respectively. The projected composite average fuelcosts per barrel include natural gas, equated to distil-late as described above. The forecasted prices of fuel

are based on EIA indices for the types of fuel oil theAuthority burns adjusted for the Authority’s locationand incidental charges. The composite fuel cost isbased specifically on the mix the Authority has fore-casted to be utilized in its generating units. The fore-casted dispatch and fuel use are shown in AppendixIV, Annual Net Generation, Fuel Consumption, Fueland Purchased Power Costs.

In forecasting the price per barrel of all fuel oil theAuthority adds $0.40 for transportation and han-dling, and also approximately $0.40 for the intereston the Authority’s fuel credit line and aCommonwealth tax of $3.36 is also added to the costof distillate fuel oil. These projected fuel costs wereused to develop the annual costs of fuel and the fueladjustment revenues in the Authority’s CurrentForecast (See Appendix I, Intermediate-TermFinancial Planning Forecast).

Including rented fuel storage tanks, the Authority hascontinued to maintain a 30 day inventory of fuel oil.It is noteworthy that the Authority has never had tocurtail electric service from fuel oil shortages or fromproblems delivering fuel to its generating facilities.

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ENERGY SALES FORECASTThe Authority’s annual Current Forecast containsdetailed projections of short-to-intermediate-termenergy sales and revenues. The methodology andresults of the Current Forecast are discussed in theCurrent Forecast section above. In summary, theAuthority typically chooses the least expansive ormost pessimistic projection over the intermediatefive-year period for its financial forecast to accountfor the uncertainties inherent in economic forecast-ing. The Authority generally uses projections fromthree economic consultants. However, as was the caselast year, the Puerto Rico Planning Board’s projectionswere not available during the development of theCurrent Forecast, therefore only two economic con-sultants projections were used. Each consultant fore-casts three key macroeconomic indicators—GrossDomestic Product, Gross National Product andPersonal Disposable Income— which are used withother variables to project the intermediate-term elec-tric sales, revenues and number of clients.

The energy sales reported for fiscal year 2013 reflectcertain adjustments. These were principally carriedforward from the last three months of fiscal year 2012when the new customer and care billing system wentinto initial operation. While these adjustments didnot affect revenues, they increased the reportedenergy sales in fiscal year 2013. Taken together, theadjustments increase reported total energy sales forfiscal year 2013 by 1.4%. The bulk of the adjustmentswere in the industrial class. The projections devel-oped in the Current Forecast did not take intoaccount these adjustments for fiscal year 2013, toavoid skewing the data for the base year of the fore-casts. In the balance of this Annual Report, however,the energy sales reported for fiscal year 2013 reflectthese adjustments.

The projected numbers of clients in the residentialclass are based on an econometric model using regres-sion analysis. For the commercial class the economet-ric model for number of clients uses logarithmicregression analysis as a function of gross domesticproduct and population. The industrial class has a rel-atively low number of clients and the forecastedchange in the number of clients was based on extrap-olation of recent years.

SHORT-TO-INTERMEDIATE TERMENERGY SALES FORECASTIn three out of the last five fiscal years there has beena contraction of energy sales. The reported totalenergy sales in fiscal year 2013 increased 0.6 % fromthe previous year with Residential increasing by 1.5%

and Commercial increasing by 4.0%; the two remain-ing sectors decreased, with Industrial down by 7.2%and Other by 25.8%.

As shown in the summary table, total sales for fiscal year2014 are projected to increase by 1.3%. The CurrentForecast predicts the positive trend will continue withgrowth of 0.4% in fiscal year 2015, 1.1% growth in 2016,1.5% in 2017; and 1.8% growth in 2018.

Last year’s Current Forecast projected that energysales would increase at a CAGR of 0.9% over the five-year period ending in fiscal year 2017. Based on theCurrent Forecast for fiscal years 2014 through 2018electric energy sales are expected to increase with aCAGR of 1.2% over the five-year period.

The projected energy sales through fiscal year 2018,taken from the Authority’s Current Forecast, are sum-marized in Appendix I, Intermediate-Term FinancialPlanning Forecast.The table for Short-term Energy Sales Forecast datashows kilowatt-hour sales and percent change fromthe prior year by major client classifications for fiscalyears 2012 and 2013. It also shows the forecasted per-cent change and kilowatt-hour sales from the prioryear by major client classifications for fiscal years2013 and 2014 taken from the Authority’s respectiveCurrent Forecasts.

SHORT-TERM PLANNING AND

FINANCIAL FORECAST

(Million of kWh)

FY 2012 FY 2013 FY 2013 FY 2014Actual Forecast1 Actual2 Forecast3

Residential Sales 6,559.6 6,481.5 6,655.6 6,929.6

Annual Increase (2.2%) (0.8%) 1.5% 2.4%(Decrease)

Commercial Sales 8,300.1 8,417.8 8,635.2 8,591.1

Annual Increase (2.9%) (0.3%) 4.0% 1.5%(Decrease)

Industrial Sales 2,778.5 2,678.3 2,578.4 2,337.5

Annual Increase (3.6%) (2.6%) (7.2%) (2.2%)(Decrease)

Other Sales4 474.3 354.5 352.0 340.8

Annual Increase 31.3% 0.0% (25.8%) (1.6%)(Decrease)

Total Sales 18,112.5 17,932.0 18,221.2 18,199.0

Annual Increase (2.1%) (0.8%) 0.6% 1.3%(Decrease)1. From May 2012 Current Forecast2. Includes adjustments3. From April 2013 Current Forecast4. Other Sales are comprised of Agricultural, Other Public Authorities,

and Public Lighting

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The energy sales statistics for the U.S. cited in the fol-lowing discussions are taken from EIA reports:Annual Energy Outlook 20123 with Projections to2035 dated June 2013, US Electric Power Monthly -September 2013 and Short-term Energy Outlook –September 2013. The U.S. 2012 calendar year energysales are preliminary and 2013 are estimated.

RESIDENTIAL SECTOR

ENERGY SALESResidential sector energy sales increased by 1.5%annually in fiscal year 2013 following an annualdecrease in 2012 of 2.2%. Since the start of the eco-nomic downturn on the island in 2006, residentialenergy sales have dropped 8.2%. Over the past fivefiscal years, 2008 – 2013, the CAGR of residentialelectrical energy sales was negative 0.3%. TheCurrent Forecast projects that residential energy salesfor fiscal year 2014 will increase by 2.4% and projectsthat over the next five fiscal years through 2018 theCAGR will increase by 1.5%.

The EIA reports the CAGR of residential sales in theU.S. decreased by 0.1% from 2007 – 2012. U.S. resi-dential energy sales decreased 2.8% in calendar year2012 and are estimated to decrease by 0.3% in calen-dar year 2013. The projected five-year compoundgrowth rate in U.S. residential energy sales for calen-dar years 2013 through 2018 is 0.3%.

CLIENTSThe average number of residential clients from 2008to 2013 increased at a CAGR of 0.6%, in spite of thereported overall decline in the island’s population ofmore than 2% in that same timeframe. The average

number of residential clients the Authority servedduring fiscal year 2013 was 1,353,550—an increase of1.0% from the previous year. The Current Forecastprojects that the average number of residential clientswill increase by 1.1% in 2014 and continue toincrease at a CAGR of 1.1% over the five-year period2014 through 2018 as well.

CONSUMPTIONIn fiscal year 2013 the average annual electric con-sumption per residential client was 4,917 kWh,which was 0.5% more than the previous fiscal year. Inspite of the modest increase in the past year, over theprevious five-year period the average consumption ofthe residential client decreased by a CAGR of 0.9%. Infiscal year 2014 the average residential energy con-sumption is forecast to increase by 1.3%. The CurrentForecast projects that the residential sector consump-tion will increase at a five-year CAGR of 0.4%through fiscal year 2018. EIA data for recent perform-ance of the U.S. electric sales are preliminary.According to EIA statistics, the average electric con-sumption of the Authority’s residential clients isapproximately 31% of the average electric consump-tion of residential clients of the U.S. East SouthCentral Census Division which consists of the statesof Alabama, Kentucky, Mississippi and Tennessee.

COMMERCIAL SECTOR

ENERGY SALESCommercial energy sales for fiscal year 2013 increased4.0% from the previous fiscal year. This level, however,was still 1.2% below the corresponding sales in fiscalyear 2008. The Current Forecast projects that commer-

65


Change in Energy Sales and Average ConsumptionResidential Sector

2008 2009 2010 2011 2012 2013 2013 2014 2015 2016 2017 2018

12.00%10.00%8.00%6.00%4.00%2.00%0.00%-2.00%-4.00%-6.00%-8.00%

Energy SalesAverage Consumption

Ann

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No. CEPR-AP-2015-0001

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cial energy sales will increase 1.5% in fiscal year 2014and increase at a five-year CAGR of 1.6% through2018. In 2013 the government commercial classes con-sumed 32% of commercial energy sales.

Based on preliminary EIA data, U.S. commercial energysales increased by 0.8% in calendar year 2012 and areestimated to decrease by 1.5% in calendar year 2013.

The preliminary five-year CAGR in U.S. commercialenergy sales for calendar years 2007 through 2012 isnegative 0.1%. The projected five-year CAGR in U.S.commercial energy sales for calendar years 2013through 2018 is 0.7%.

CLIENTSDuring fiscal year 2013 the average number of com-mercial clients was 126,735 which was a drop of 1.4%from the previous fiscal year. According to theAuthority’s June 2013 Governing Board Report, gov-ernment and government agency clients made up18% of the total commercial sector. Over the past five-years the CAGR in commercial clients was negative0.5%. In fiscal year 2014 the average number of com-mercial clients is projected to increase by 1.9%, withcontinuous increase at a CAGR of 1.2% over the fiveyear forecast period through fiscal year 2018.

CONSUMPTIONThe average annual consumption per commercialclient during fiscal year 2013 was 68,136 kWh for anincrease of 5.6% over the previous year. In spite of lastyear’s boost, the Authority’s five-year CAGR in con-sumption per commercial client through fiscal year

2013 was a modest 0.3%. In fiscal year 2014 the aver-age energy consumption per commercial client is pro-jected to decrease 0.4%. The Current Forecast projectsa CAGR of 0.4% in electric consumption per commer-cial client over the five fiscal years through 2018.

According to EIA statistics, the average energy con-sumption of the Authority’s commercial clients isapproximately 5.9% more than the commercialclients of the East South Central Census Division ofthe United States.

INDUSTRIAL SECTOR

ENERGY SALESIndustrial energy sales for the fiscal year 2013decreased 7.2% compared to the previous year; morethan the previous year’s decline of 3.6%. This past fis-cal year marked the seventh consecutive year thatindustrial energy sales have diminished. Followingthe client reclassification discussed below, betweenfiscal years of 2010 and 2013, industrial energy salesdecreased by 15.4%.

During fiscal year 2009 the Authority reclassified 612government industrial clients from the industrialGeneral Service at Secondary Voltage tariff to com-mercial tariffs, to lower these clients’ rates. The trans-fer of these clients from the industrial to commercialbase reduced the size of the industrial sector by morethan 40%, however, the transferred clients accountedfor less than 10% of the industrial class’s power con-sumption. Due to these changes the industrial sector

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Change in Energy Sales and Average ConsumptionCommercial Sector

5.00%4.00%3.00%2.00%1.00%0.00%-1.00%-2.00%-3.00%-4.00%-5.00%


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chart shows annual average consumption data start-ing in fiscal year 2010.

To develop the projection of industrial sector electricsales in the Current Forecast the Authority analyzesthree groups: refineries and petrochemicals, cus-tomers with their own generation, and all the otherclients; the last group represents more than 93% ofthe sector sales.

The smallest group within the industrial sector is therefineries and petrochemicals plants whose consump-tion in the past fiscal year was approximately 0.4% ofthe sector total. The electric consumption of refineriesand petrochemicals was based on actual data for thefirst nine months of fiscal year 2013, with extrapola-tion for the balance of the fiscal year. The actual con-sumption totaled 9.3 million kWh, which was 19.7%less than the same period of the previous year.

The estimated electric usage of clients with their owngeneration facilities for fiscal year 2014 was based ondata from fiscal year 2012 applied uniformly over thefive years of the forecast. The total projected con-sumption by the three clients that own generation is147.0 million kWh or 6.3% of the total industrialsales in fiscal year 2014. The impact of net-meteringand wheeling tariffs were not considered in the inter-mediate term projection.

The Current Forecast projects that in fiscal year 2014industrial energy sales will continue to decrease by2.2%, followed by two more years of diminishing salesthen reversing the negative trend in 2017 graduallyhitting 0.6% in fiscal year 2018. The industrial sector

energy sales are forecasted to decrease at a CAGR of0.5% for the five-year period through fiscal year 2018.

Preliminary EIA data show total industrial U.S.energy sales increased 1.7% in calendar year 2012 andare estimated to decrease by 0.2% in calendar year2013. The preliminary five-year CAGR in U.S. indus-trial energy sales for calendar years 2007 through2012 is negative 0.7%. The projected CAGR in U.S.industrial energy sales for calendar years 2013through 2018 is 2.6%.

CLIENTSThe average number of industrial clients served bythe Authority at the end of fiscal year 2013 was 709,which was a modest drop from 733 in the previousfiscal year. Prior to the reclassification of more than40% of the clients out of the sector in fiscal year 2009,the number of industrial sector clients had beendeclining. During the period of fiscal years 2009through 2013 the number of industrial clients fell by21%, or 189 clients. The Current Forecast projectsthe number of industrial clients will decrease by 28clients in 2014 and continue to decrease by approxi-mately 25 clients per year over the next four years,resulting in an equivalent CAGR of negative 4.0%.

CONSUMPTIONThe average annual consumption of industrial clientsduring fiscal year 2013 was 3,636,652 MWh, adecrease of 4.1% from the previous year. The averageindustrial consumption for the period from 2010through 2013 declined 3.6%. The Current Forecast

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Change in Energy Sales and Average ConsumptionIndustrial Sector


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projects the average industrial client consumptionwill increase by 1.9% in 2014 and will increase at afive-year CAGR of 3.6% through fiscal year 2018.

According to EIA statistics, the average energy con-sumption of the Authority’s industrial clients isapproximately 62% less than those of the East SouthCentral Census Division of the U.S.

OTHER CLASSESThe “Other” sector is comprised of clients in the pub-lic lighting, agricultural and other public authoritiesclasses. In fiscal year 2013 energy sales in this sectorrepresented approximately 1.9% of the Authority’stotal energy sales, a decrease of 25.8% from the previ-ous year. Within this group public lighting representsapproximately 76%, agricultural is 8% and publicauthorities 16%. The change in energy sales in fiscalyear 2013 was basically due to the drop in consump-tion for public lighting down to historical levels. Thetotal number of public lighting clients increased by22% during the previous fiscal year, as the Authorityinstalled more meters.

The Current Forecast projects no change in the num-ber of clients in this group and only modest growth of0.3% CAGR over the five-year forecast period endingin 2018.

TOTAL ELECTRIC ENERGY SALESTotal reported energy sales in fiscal year 2013 were18,221.2 GWh, an increase of 0.6% from those of the

previous fiscal year. Total energy sales for the five-year period ended June 30, 2013 decreased at a CAGRof 1.5%. In the Current Forecast total energy sales areexpected to increase by 1.3% for fiscal year 2014, andincrease at a CAGR of 1.2% over the five-year periodending in fiscal year 2018.

The average number of clients that the Authorityserved during fiscal year 2013 increased by 0.8% to1,485,150. Over the five-year period ending in fiscalyear 2013 the CAGR in the number of clients was0.2%. The total number of clients is projected toincrease approximately 1.1% annually throughout thenext five fiscal year forecast period ending in 2018.

The average electric consumption of the Authority’sclients in fiscal year 2013 was 12,269 kWh, a decreaseof 0.5% from the previous year. Over the past five-year period the CAGR of average consumption wasnegative 1.9%. The Current Forecast projects theaverage consumption of the Authority’s clients willdecrease in fiscal year 2014 by 0.1%, and the futurefive-year CAGR is projected to increase by 0.1%annually through fiscal year 2018.

The preliminary data for total U.S. energy sales showa decrease of 0.3% in calendar year 2012. For calen-dar year 2013 total energy sales in the U.S. are esti-mated to decrease by 0.6%. The CAGR for the U.S.preliminary total energy sales during the five-yearperiod between calendar years 2007 and 2012 is neg-ative 0.2% and is projected to be 1.1% for the five-year period ending in 2018.

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1,600,000

1,580,000

1,560,000

1,540,000

1,520,000

1,500,000

1,480,000

1,460,000

1,440,000

1,420,000

1,400,000

CLIE

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S

20,000

19,500

19,000

18,500

18,000

17,500

17,000

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69

RATESSection 706 of the 1974 Agreement charges theConsulting Engineers to prepare each year a reportsetting forth their recommendations as to any neces-sary or advisable revisions of rates and charges

Section 502 of the 1974 Agreement details the Authority’sresponsibilities with respect to rates as follows:

The Authority further covenants that it will at alltimes fix, charge and collect reasonable rates andcharges for the use of the services and facilities fur-nished by the System and that from time to time,and as often as it shall appear necessary, it willadjust such rates and charges so that the Revenueswill at all times be sufficient.

(B) after the outstanding 1947 Indenture Bonds havebeen paid or provision has been made for their pay-ment and the release of the 1947 Indenture:

(a) to pay the Current Expenses of the System, and

(b) to provide an amount at least equal to one hun-dred twenty per centum (120%) of the aggregatePrincipal and Interest Requirements for the next fis-cal year on account of all the bonds then outstand-ing under this Agreement, reduced by any amountdeposited to the credit of the Bond Service Accountfrom the proceeds of bonds to pay interest to accruethereon in such fiscal year.

The revenues generated by the Authority’s various rateschedules provide the moneys necessary for it to meetall of its obligations as detailed in the 1974 Agreement.Among its obligations are: paying the current expensesof the System; financing future growth by issuingPower Revenue Bonds; making deposits to specifiedfunds; maintaining a minimum specified debt serviceratio; and paying Contributions in Lieu of Taxes.

Typically, the client’s bill consists of the appropriatebase rate and an adjustment charge. The base rateencompasses current expenses, i.e. operation andmaintenance (O & M) expenses (excluding the costof fuel and purchased power), monies for fundingrequirements, Contributions in Lieu of Taxes associ-ated with base rate revenue, depreciation and amorti-zation, insurance, and debt service. The base rate hasthree components—a demand charge, a customercharge, and an energy charge, except for clients thatreceive electric service at secondary voltage. The baserate for clients served at secondary voltage is com-prised of a customer charge and an energy-relatedcharge. The adjustment charge has two components:the charge for purchased fuel and the charge for pur-chased power. (For a discussion of these charges seeAdjustment Charge below.)

RATE SCHEDULESCLASSIFICATIONS AND REVENUESIn order to serve different segments of its clientele,the Authority provides electric service in six clientclassifications. Ranking these classes in their order ofrevenue generated during fiscal year 2013, they are:Commercial, Residential, Industrial, Public Lighting,Public Authorities, and Agricultural. Three of theseclassifications—Commercial, Residential, and Indus-trial—represented 98.1 % of the kilowatt-hour salesand 97.2% of the revenues from the sale of electricity.The remaining three classifications – Public Lighting,Other Public Authorities, and Agricultural – collec-tively represented the balances of the Authority’s kilo-watt-hour sales and revenue from the sale ofelectricity.

Four rate schedules apply to the large majority of theAuthority’s client base. These four rate schedules are:GRS (General Residential Service), GSS (GeneralService at Secondary voltage), GSP (General Serviceat Primary voltage), and GST (General Service atTransmission voltage). These four rate schedulesserve the majority of the Authority’s clients becausethey were designed for wide applicability and theyhave few, if any, load characteristic requirements. Tobroaden their usage, the GSS, GSP, and GST rateschedules are available to both commercial andindustrial clients. During fiscal year 2013 the corefour rates accounted for 86.5% of the Authority’s kilo-watt-hour sales and 87.8% of its revenues from thesale of electricity.

The following table shows the major contribution ofthese four rate schedules to the Authority’s electricsale and its total revenue. In each of the largest threeclassifications there is dominant rate schedule. Forexample, although four rate schedules apply to theResidential classification, the GRS rate scheduleserved 87.4 % of the Residential clients’ kilowatt-hoursales and accounted for 90.0% of the Residential classrevenue in fiscal year 2013. Within the Commercialclassification seven rate schedules applied in fiscalyear 2013, however, the GSP rate schedule, whichserved 8.1% of the Commercial clients, accounted for53.4% of the Commercial class revenue. The GSS rateschedule generated the second most revenue in theCommercial classification; it served 91.4% of theCommercial clients and accounted for 28.4% of theCommercial class revenue. While thirteen rate sched-ules applied to the Industrial classification in fiscalyear 2013, the GST rate schedule, which served30.7% of the Industrial clients, accounted for 45.7%of the Industrial class revenue.


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SUMMARY OF CORE RATE SCHEDULES

ALL CLASSES

Per Cent of Per Cent Price Range•Total MWH Sold of Total Revenue cents/kWh

General Residential Service 31.9% 31.1% 25.78

General Service Secondary Voltage 12.4% 14.3% 30.47 – 31.54

General Service Primary Voltage 26.0% 27.7% 28.25 – 28.63

General Service Transmission Voltage 16.2% 14.7% 24.22 – 23.87

* Commercial – Industrial Classes

The current rate schedules are comprised of more than80 subcategories to accommodate various service lev-els and load profiles; the Authority presently serves allclients under 42 of the subcategories. Six of the rateschedules are common to both the commercial andthe industrial classifications. Some of the rates servingfew clients with low consumption are consolidated inthe Rates Table presented in this report.

As shown on the Rates Table, the average cost perkWh for all power sold by the Authority was 26.46cents during fiscal year 2013. The lowest average costamong the four popular rate schedules was 23.87cents/kWh for GST - Industrial, with the highest aver-age cost being 30.47 cents/kWh for GSS - Industrial.

Average Total Average

Rate Schedule Number Total Revenue Costof Clients MWh ($000)1 Cents/kWh2

Residential Class3

103-104 (RH-3) 7,624 21,763 5,291 24.31

105-107 (RH-3) Revised 40,194 247,174 20,432 8.27

109,110 (LRS) 162,459 566,651 140,998 24.88

111,112 (GRS) 1,143,273 5,820,008 1,500,420 25.78

Total Residential Class 1,353,550 6,655,596 1,667,141 25.05

Commercial Class

060 Telephone Booth 59 10 3 32.35

070-080 Cable TV 17 13,730 4,111 29.94

082 Security Cameras 166 96 38 39.58

211 (GSS) 115,866 2,252,521 686,272 30.47

212 (GSP) 10,270 4,567,496 1,290,545 28.25

213 (GST) 357 1,793,680 434,508 24.22

862 1 7,632 2,004 26.26

Total Commercial Class 126,735 8,635,165 2,417,481 28.00

Industrial Class

311 (GSS) 135 4,841 1,527 31.54

312 (GSP) 304 164,060 46,973 28.63

313 (GST) 217 1,152,052 274,941 23.87

333 (LIS) 2 214,301 47,024 21.94

343 (PPBB) 2 1,157 1,865 161.24

363 (TOU-T) 13 422,922 96,843 22.90

393 (SBS-T-TOU) 1 40,963 9,989 24.39

603 (SR-GST) 20 300,158 62,070 20.68

613 (SR-GST) 5 67,939 15,016 22.10

623 (SR-TOU-T) 1 13,202 2,675 20.26

653 (SR-TOU-T) 5 93,096 20,860 22.41

753 (SRTOU-T) 2 70,817 15,461 21.83

963 (TOU-T) 2 32,879 7,014 21.33

Total Industrial Class 709 2,578,386 602,263 23.36

Average Total Average

Rate Schedule Number Total Revenue Costof Clients MWh ($000)1 Cents/kWh2

Other Classifications

Public Lighting

2-41 (Non Meter P/L) 877 235,313 104,274 44.31

72 (PLG Bus Shelter) 3 435 127 29.20

73 (PLG Police) 5 33 8 25.26

414 (LP-13) 10 3,065 984 32.11

421 (PLG) 103 1,926 596 30.94

422 (PLG) 78 1,319 362 27.44

423 (PLG) 712 4,146 1,176 28.35

424 (PLG) 1,138 19,163 5,283 27.57

050-056 (Dusk to Dawn) 0 2,922 726 24.85

Total Public Lighting 2,926 268,322 113,537 42.31

Agricultural

711 (GAS) 1,227 27,277 7,585 27.81

Total Agricultural 1,227 27,277 7,585 27.81

Public Authorities

513 (GST-Public Authority) 3 56,436 13,342 23.64

Total Public Authorities 3 56,436 13,342 23.64

TotalOther4 Classifications 4,156 352,035 134,463 38.20

Total 1,485,150 18,221,182 4,821,348 26.461 Includes the Adjustment Charge.2 Calculated differences are due to rounding.3 Includes the residential fuel subsidy.4 Includes Public Lighting, Agricultural and Public Authorities classes.

RATES TABLE

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The Authority’s ten largest non-governmental agencyindustrial clients accounted for 27.2 % of the classifi-cation’s consumption and paid an average of 22.55cents/kWh during fiscal year 2013. This was 3.5% lessthan the industrial class average.

The Rates Table shows all the rate schedules in useduring fiscal year 2013 by the Authority’s clients, withthe average number of clients, total annual powersales, total revenue and average pricing for each rateschedule.

RATE STABILIZATION FUND

Beginning in December 2011 the Authority imple-mented a temporary program to provide a measure ofrate relief to General Residential Service (GRS) clientswho were current in their payments, consumed morethan 425 kWh per month, and did not otherwisereceive any other subsidy. This Rate Stabilization Fundwas funded as part of a line of credit from theGovernment Development Bank (GDB) and wasdirected to reducing the monthly fuel adjustmentcharges to maintain parity with the fuel charges fromSeptember 2011. The program was revised late in May2012, with the same general objective; the new fuelstabilization program was established for 180 days.

During fiscal year 2013 the Authority used the RateStabilization program to subsidize a total of $53.2million in residential client fuel adjustment credits.

RATE STRUCTURE

Prior to October 1999 the Authority’s electric servicerates consisted primarily of a base charge and a fueladjustment charge. During that period the basecharge included a fuel charge of $2.00 per barrel. Thefuel adjustment charge recovered the Authority’s fuel-related costs in excess of the $2.00 in the base charge.For clients served at secondary voltage (such as theentire residential class) the base rate included ademand component, whereas for clients served at pri-mary and transmission voltages the demand chargewas a separate component of the bill.

The fuel adjustment clause was revised by theAuthority in November 1999 to recover the cost ofpurchasing power from EcoEléctrica, a cogenerationplant, during its test and start-up period. On March28, 2000, following the required public hearing, apermanent revision of the Authority’s rate structurewas approved that incorporated a purchased powercharge in the electric service rates to recover its costof purchased power from the EcoEléctrica plant.Since then the purchased power charge has beenapplicable for purchases from EcoEléctrica and, sub-

sequently the second cogenerator, AES-PR; the pur-chased power charge also applies to the renewablepower sources that began to come on-line during thepast fiscal year. The rate structure revision alsoremoved the $2.00 per barrel fuel charge from thebase charge and included all fuel related charges inthe newly defined adjustment charge. The fuel chargeand the purchased power charge, both of whichbecame effective June 5, 2000, are collectively shownon the client’s bill as the adjustment charge.

In May 2013 the Authority implemented revisions torecover the costs of renewable energy credits associ-ated with the purchased renewable energy. At thesame time the Authority revised the fuel adjustmentto explicitly include natural gas.

The base rates and demand charges were not revisedwith the adjustment charge discussed above andhave remained unchanged since they were estab-lished in 1989.

The Authority invoiced $3,707.3 million through theadjustment charge in fiscal year 2013: $2,862.0 mil-lion for fuel and $845.3 million for purchased power.The adjustment charge constituted 76.9 % of theAuthority’s $4,821.3 million in electric revenue.

PRICE COMPARISONSThe Authority’s average price per kilowatt-hour variessignificantly among its client classifications. ThePower Producers’ at Bus Bar Rate paid the highestaverage cost of 161.24 cents/kWh, which reflects therecurring high demand charges relative to infrequentconsumption; the average cost for this service was55.97 cents/kWh during the previous fiscal year. Themost expensive widely used rate was CommercialGeneral Service at Secondary voltage, with an averageof 30.47 cents/hWh. The lowest cost service was theResidential Public Housing Rate - Revised with theaverage cost of 8.27 cents/kWh. These price varia-tions are attributable to the differences in the cost ofproviding public service and socioeconomic objec-tives of the Commonwealth government and theAuthority.

The average prices in cents/kWh for the Authority,Hawaii, and the U.S. are shown in the following tablefor the year ended June 30, 2013. The data for theState of Hawaii are provided because its geographicalcharacteristics and fuel mix are similar to PuertoRico’s. The U.S. Department of Energy - EnergyInformation Administration (EIA) data were used asa reference to derive the pricing for the State ofHawaii and the U.S. The U.S. data are comprised of allfifty states and Washington D.C.

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2013 AVERAGE PRICE COMPARISON

(Cents/kWh)

Authority Hawaii U.S.

Residential 25.05 33.87 11.97

Commercial 28.00 32.30 10.19

Industrial 23.36 28.21 6.78

All Classes 23.46 31.20 9.98

SUBSIDIES AND CREDITSIn accordance with various Commonwealth laws andregulations, the Authority provides subsidies to lowconsumption residential clients, energy conservinghotels, charitable organizations, agricultural clients,low-income clients with life sustaining equipment andsmall water companies distributing potable water.

The Authority’s subsidies and credits benefited anaverage of 484,227 clients in fiscal year 2013, which isapproximately 33% of its client base. The total cost tothe Authority for the benefits credited to these clientsduring fiscal year 2013 was $80.0 million. The partic-ipation rate and cost to the Authority were unchangedfrom the previous fiscal year. Funds for these subsidieswere drawn from the Set Aside moneys discussed inthe Contributions in Lieu of Taxes and Other section inthe Financial section.

RESIDENTIAL FUEL SUBSIDYUnder provisions of Act No. 106 of the Legislature ofPuerto Rico, approved on June 28, 1974, theCommonwealth began to subsidize the fuel adjust-ment charge (now the fuel charge, a component ofthe adjustment charge). In 1991 the subsidy qualifi-cation criteria were made more restrictive, to focusthe subsidy on those clients truly in need. The newcriteria are still in place and apply to the Authority’sresidential clients who consume up to 425 kilowatt-hours of electricity monthly or 850 kilowatt-hoursbimonthly and meet the following criteria: those onthe “Lifeline” residential rate (LRS), the government-administered public housing rate (RH-3), full-timestudents, the handicapped, and those 65 years of ageor older. Additionally, all fuel subsidy recipients mustbe permanent residents of the Commonwealth ofPuerto Rico and may receive the subsidy on only onedwelling. The subsidy is provided in the form of acredit against the recipient’s electric bill. During fiscalyear 2013, there were an average of 302,771 clients or22% of the total residential classification who quali-fied for subsidization. The purchased power compo-nent of the adjustment charge is not subsidized.

The residential fuel subsidy was $26.4 million duringfiscal year 2013, which represented a 9.6% decrease

over the previous fiscal year’s level. TheCommonwealth’s contribution to the fuel charge sub-sidy program is deducted from the electric energysales Set Aside. (See Contributions in Lieu of Taxesand Other section).

Until fiscal year 1992, the residential fuel subsidy waspaid by the Commonwealth and was recorded as areceivable by the Authority. By the end of fiscal year1991, the Commonwealth owed the Authority $94.9million for the fuel charge subsidy program. InOctober 1991, the Authority and the Commonwealthentered into a non-interest bearing, fifteen-year pay-ment plan for payment of this past due amount. InJune 2004, the Legislature of the Commonwealth ofPuerto Rico superseded the 1991 agreement with arevised agreement containing an eight-year paymentschedule that totaled $55.7 million. This amountincludes an allocation for past due Commonwealthgovernment account receivables and the unpaid bal-ance of the fuel adjustment subsidy. TheCommonwealth made its final payment to theAuthority of $6.3 million in fiscal year 2013.

The Authority pays the entire fuel subsidy for all res-idential rate classifications until the price of oilreaches $18.00 per barrel. Once the price of oilexceeds $18.00 per barrel, the Commonwealth pays(by means of the electric energy sales Set Aside) theincremental price until it reaches $30.00 per barrel.This subsidy amount is capped at $100 million peryear. The client pays the incremental amount over$30. For the other recipients of the residential fuelsubsidy, the Commonwealth pays (once again, bymeans of the electric energy sales Set Aside) the entiresubsidy up to $30.00 per barrel. The Authority’smonthly average cost of fuel in fiscal year 2013ranged from a low of $105.69 per barrel in November2012 to a high of $120.51 per barrel in February2013. The weighted average fuel cost for the fiscalyear 2013 was $111.18 per barrel, which is down over6% from the previous year.

The residential fuel subsidy applies to the fuel adjust-ment charge for service at secondary voltage. Thesubsidy for qualifying residential clients is a slidingscale percentage that corresponds to their monthlyconsumption level. As shown on the table below, thesubsidy percentage decreases as monthly consump-tion increases. The subsidy is not cumulative throughthe incremental blocks of consumption; for example,a client with a monthly consumption of 325 kWhwould receive a 55% subsidy of the fuel adjustmentcharge. There is no subsidy if the monthly consump-tion exceeds 425 kWh.

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Monthly % of Total FuelConsumption Component

(kWh) Subsidized

0-100 90

101-200 75

201-300 65

301-400 55

401-425 *

Over 425 0

*For the first 400 kWh of consumption, 55% of the fuel charge will besubsidized; over 400 kWh the client will be charged 100% of the fuelcharge for each additional kilowatt-hour up to 25 kWh.

RESIDENTIAL RATE SUBSIDYThe Authority serves its residential clients using fourrates—GRS, LRS (Lifeline), and RH-3 (PublicHousing) and a revised RH-3 rate. In fiscal year 2013,84.5% of its residential clients were served using theGRS rate. The remaining residential clients wereserved using the LRS and RH-3 rates that are reservedfor those who qualify as low-income; these rates havelower customer and energy charge components ascompared to the GRS Rate.

During fiscal year 2013 the Authority served on aver-age 210,277 residential clients under the rates of LRS,RH-3, and RH-3 Revised, which is discussed inSelected Rates. In the past fiscal year an average of165,726 clients or about 12% of the residential clientsreceived the base rate subsidy at a cost to theAuthority of $15.6 million, little changed from the$15.4 million subsidy in fiscal year 2012..

HOTEL SUBSIDY PROGRAMUnder Act No. 101 of July 9, 1985, the Authoritystarted providing an 11% discount on its monthlyelectric bills to hotels that are certified by the PuertoRico Tourism Company. This subsidy is designed tohelp conserve energy and promote tourism. In orderto qualify for this discount the hotels are obligated to:develop programs for conserving and using energymore efficiently; submit evidence annually to theCommonwealth’s Energy Affairs Administration,which administers the program, showing that theyare implementing their programs; and remain currentin paying their electric bills. Small hotels are onlyrequired to demonstrate compliance every five years.If a participating hotel does not pay its bill within 60days, the hotel can be dropped from the program.

Act No. 266 of November 16, 2002, amended severalarticles of Act No. 101. The most notable change wasthe reduction in the number of rooms required toqualify for the discount from fifteen to only two. Thissubsidy, like the residential fuel subsidy, takes the

form of a credit on the client’s bill. During fiscal year2013, an average of 210 establishments benefitedfrom the $8.9 million in hotel subsidies.

CHARITABLE ORGANIZATIONS SUBSIDYThis subsidy applies to charitable organizations, suchas churches, which provide services to the commu-nity at no charge. The subsidy enables any qualifyingcharitable organization to use the GRS rate (averagecost of 25.78 cents/kWh during fiscal year 2013) inplace of the other applicable commercial rates (30.47cents/kWh for GSS or 28.25 for GSP). Applying theGRS rate in place of the GSS rate reduced the clientcost by almost 15% in fiscal year 2013, while the GRSrate in place of the GSP rate saved 9%.

The Authority subsidized $4.7 million to serve an aver-age of 4,390 charitable organizations in fiscal year 2013.

LIFE PRESERVATION SUBSIDYThe Life Preservation subsidy is available to qualify-ing low-income clients who require electrically pow-ered essential medical equipment. The subsidyprovides full credit for the electrical consumption ofthe medical device, based on the certification of needand hours of operation established by a physicianfrom the Department of Health of Puerto Rico.

This subsidy served approximately 4,800 clients andamounted to $4.6 million in fiscal year 2013, adecrease from the $5.1 million cost in the previousfiscal year.

AGRICULTURAL SUBSIDYThe Agricultural service rate (GAS) is available tofarmers, animal breeders and rural irrigation watersuppliers. This rate is available for the clients whoseload is up to 50 kVA. If the Authority did not providethe GAS rate to these clients they would be servedunder the more expensive GSS-Commercial rate. Infiscal year 2013 the average price differential betweenthe GSS-Commercial and GAS rates provided approx-imately a 9% reduction in costs to qualified clients.

This subsidy served an average of 1,278 clients, withtheir cost savings totaling $549,600 in fiscal year 2013.

IRRIGATION SERVICE SUBSIDYThe Authority originally was constituted as thePuerto Rico Water Resource Authority which gener-ated power from hydro-electric facilities. It includeddams and infrastructure that also provided most ofthe island’s water. The Authority still maintains juris-diction over all dams on the island, however thePuerto Rico Aqueducts and Sewers Authority(PRASA) is the current public agency that is respon-sible for the water system on the island.

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As part of its legacy responsibilities the Authority pro-vides certain technical and maintenance services fordams that supply PRASA and some irrigation users.During fiscal year 2013 the Authority incurred costsof $5.6 million for these services.

COMMON AREA LIGHTING SUBSIDY

Act 1060 passed by the Commonwealth’s legislaturein August 2008 established that lighting for commonareas of condominiums will be served under a ratebased on general service residential (GRS). In fiscalyear 2013 the average cost savings per kWh wasalmost 15% and totaled $1.3 million for condo-minium common area lighting.

OTHER SUBSIDIES AND CREDITSThe manufacturing industrial credit is provided to allnew manufacturing industry clients and to the clientswho expand their business operation. During fiscalyear 2013, the Authority provided its manufacturingindustry users a credit of $10.8 million to an averageof 28 clients; the credit amounted to an increase ofapproximately 7% over the previous fiscal year. Thiscredit is discussed below in Special Rates.

As discussed in the Contributions to the Common-wealth section, the Economic Incentives Act of 2008requires the Authority to provide certain energy creditsfor qualifying businesses; the costs of the energy cred-its are shared between the Commonwealth and theAuthority and are applied to the qualifying business’sincome taxes. During the ten year term of the legisla-tion the Authority’s share steadily increases from zeroto 80% of the credit. In fiscal year 2013 the Authority’scosts associated with this legislation were $1.2 million,based on tax credits for seven qualifying businesses.

In 2004 a subsidy was established for cooperativewater companies that provide potable water to ruralcommunities which were either not served or inade-quately served by PRASA. In order to qualify for thesubsidy, the rural water company must be registeredwith the Commonwealth, its operation must meetCommonwealth health standards and the water qual-ity must comply with US EPA criteria. During fiscalyear 2013 an average of 14 rural water companiestook advantage of this subsidy and received a benefitof approximately $3,900.

Since July 2, 2007, the Authority has allowed a 10%credit on its residential clients’ basic rate charge forthose clients who are current in their payments andpay the Authority directly from their personal bankaccount. In fiscal year 2013 approximately 3,900 res-idential clients took advantage of this credit andsaved almost $128,400.

The Authority provides a 10% credit for power, up toa maximum of $40 per month, to small commercialclients with less than seven employees on the weeklypayroll. This credit applies for up to three years.During fiscal year 2013 the credit provided wasapproximately $1,790 to six clients.

SELECTED RATESOver the last decade the Authority has developed anumber of specialized rates to address certain pricingand operational issues for some of its residential pub-lic housing, large commercial and industrial clients.By design, these rates have limited applications. Thecommercial and industrial rates are almost exclu-sively available to clients purchasing power at thetransmission level.

PUBLIC HOUSING RESIDENTIAL RATEAs shown in the Rates Table, approximately 3.5% ofthe Authority’s residential clients are served by theRH-3 public housing rate. In August 2009 theCommonwealth enacted legislation, under Act No. 69,entitled Special Law for Pricing Justice of Utilities forPublic Residents. The Special Law provides simplifiedlow cost water and electric utility rates for qualifyinglow income residents of public housing. The new elec-tric rates went into effect in February 2010, under thescope of RH-3 Revised. The rate structure establishesflat monthly charges based on the number of rooms:$30 for one room, $40 for two or three rooms, and $50for four or five rooms. The rate applies for usage up to425 kWh per month. For a client to transition fromRH-3 to the RH-3 Revised tariffs there must be anagreed payment plan if there are any overdue invoices.By the end of fiscal year 2013, over 84% of the totalRH-3 clients had opted for the RH-3 Revised rate.During the last fiscal year the clients served under theRH-3 Revised rate consumed approximately 92% ofthe total RH-3 power and contributed approximately79% of the total RH-3 revenue.

SPECIAL RATESIn order to promote an increase in industrial develop-ment in Puerto Rico, the Authority instituted five newspecial rates. These special rates offered a discount fornew industries and expansion of existing industrialson or after February 2002. New industrial clientsreceived a discount of approximately 11% on theirtotal electric bill. Also, existing industrial clients thatexpanded their operations received a discount ofapproximately 11% on the demand, energy, andadjustment charges associated with its expansion.These rates were available for five years effective July30, 2003. While these rates expired on July 30, 2008,they are available to existing users to complete the

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balance of their five year term. During fiscal year2013 these rates benefited qualifying industrialclients with savings of $14.3 million; the savings were$18.8 million in fiscal year 2012. The five specialrates are designated as follows:

• General Service at Transmission Voltage-Special (SR-GST)

• Time of Use Rate at Transmission Voltage-Special (SR-TOU-T)

• Large Industrial Service 115 kV-Special (SR-LIS)

• Standby Service at Transmission Voltage-Special (SR-SBS) and

• Time of Use Rate-Cool Storage AirConditioning Systems-Special (SR-TOU-C)

Only three of these rates —SR-GST, SR-TOU-T, andSR-SBS-TOU-T— were used during fiscal year 2013.The SR-GST rate was used by 25 clients with a com-bined average cost of 20.94 cents/kWh. The SR-TOU-T Rate served six clients at a combined average costof 22.14 cents/kWh; the SR-SBS-TOU-T Rate servedtwo clients with an average cost of 21.83 cents/kWh..

LARGE INDUSTRIAL SERVICE RATEIn September 1997, the Authority adopted the LargeIndustrial Service (LIS) rate in order to encouragelarge industrial clients to remain part of its clientbase. To be eligible for this rate clients must meet thefollowing criteria: receive service at 115 kV; have ademand of 12,000 kW or greater; a minimum loadfactor of 50% (see following discussion); and an aver-age monthly power factor of 95% or more. In view ofthe declining industrial client base, the Authority hasrelaxed the previously required 80% load factor to50% for LIS and SR-LIS through January 2016. The50% load factor, however, is then the minimum basisfor monthly billing. The Authority has served twoindustrial clients under the LIS rate for the past threefiscal years, up from only one client in fiscal year2010. The average cost per kWh for this rate was21.94 cents/kWh in fiscal year 2013, up approxi-mately 2% over the previous fiscal year.

TIME-OF-USE RATESTime-of-Use (TOU) rates are a component of theAuthority’s Demand-Side Management (DSM) pro-gram. (For a discussion on the DSM program refer tothe Demand and Energy Forecast section.) These ratesare designed to encourage shifting consumption fromon-peak hours to off-peak hours when the total systemdemand is otherwise lower. The Authority has severalTOU rates; currently these rates are only offered to theAuthority’s commercial and industrial clients.

In May 1996, the Authority’s Governing Boardadopted Resolution Number 2160, which approvedrevised load requirements, thereby increasing thenumber of clients eligible for TOU rates. At the end offiscal year 2013, a total of 24 clients were servedunder these rates, resulting in $152.8 million in rev-enues, which was approximately 25% of the totalindustrial classification’s revenue. One of these clientswas served under the SBS-T-TOU (standby service attransmission voltage) rate discussed below.

The average cost for all the TOU rates in fiscal year2013 was 22.68 cents/kWh, however, the costs forseparate rates varied considerably based on the pat-tern of client utilization and load characteristics.Amongst this group of rates the most frequently usedwas the TOU-T (time of use at transmission voltage)rate which accounted for more than 63% of the TOUrevenues. Thirteen clients were served using theTOU-T rate at an average cost of 22.90 cents/kWh.The second largest energy sales and revenues of thisgroup was the standby service rate discussed below, itprovided almost 15% of the TOU revenue.

The remaining TOU rates accounted for 21% of theenergy sales and revenues for this group. Six clientswere served under SR-TOU-T rates. The SR-TOU-TRates are available under Special Rates to manufactur-ing clients who are either new or have added to theirelectric load during the past fiscal year. The last TOUrate utilized in fiscal year 2013 was the TOU-T rate,which applies to industrial clients who have a loaddemand of 1,000 KVA to 3,000 KVA. During fiscalyear 2013 this TOU-T rate served two clients at anaverage cost of 21.33 cents/kWh.

Another available TOU rate is the Cool Storage AirConditioning Systems (TOU-A/C) commercial rate.Although this rate has been in existence for almosttwo decades, it attracted few clients and the last onechanged to a conventional rate several years ago.

STANDBY SERVICE RATEThe Standby Service Rate (SBS) is applicable to indus-trial or commercial clients who generate power fortheir own use and not for resale. This rate scheduleprovides four levels of service: supplementary, auxil-iary, maintenance, and interruptible power. When theclient’s generator is unable to generate enough powerneeded to satisfy its load, whether because of a limi-tation or a scheduled or forced outage, then the clientstarts to receive its needed power automatically fromthe Authority. The demand, customer, and energy-related costs for this rate are the same as those in thecorresponding service class that would apply, namelyGSP, GST, TOU-P, or TOU-T rates.

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During fiscal year 2013 there was only one standbyrate in use. It served one industrial client utilizing theSBS-T-TOU rate, discussed above. The average cost ofthe SBS rate for this industrial client was 24.39cents/kWh. The Authority received $10.0 million inrevenue from the sale of 40,963 MWh under this rate.

POWER PRODUCERS AT BUS BAR RATEIn March 2000, the Authority’s Governing Board,under Resolution Number 2812 approved the PowerProducers at Bus Bar (PPBB) rate. This rate, whichbecame effective in June 2000, is only available tolarge power producers who are connected at 230 kVand have a power purchase agreement with theAuthority for all its electrical output. In addition, thepower producer must have at least an 85% equivalentavailability. Under this rate a power producer canpurchase power from the Authority for startup,scheduled maintenance, and for backup power.

Presently, only EcoEléctrica and AES-PR qualify forthis rate. The black-start energy requirements forthese two power producers are 12.0 MW and 38.7MW, respectively. The Authority generated approxi-mately $1.9 million in revenues from the sale of 1,157MWh of power to the two cogenerators in fiscal year2013. The average cost for this rate was 161.24cents/kWh during the past fiscal year.

SECURITY CAMERAS RATEAs part of an increased public safety programthroughout the Commonwealth, security camera sur-veillance systems and wireless telecommunicationequipment have been installed on the Authority’spoles and structures.

The Authority instituted a temporary rate forunmetered small load service (USSL) in July 2007and subsequently added this new rate in its rate struc-ture in January 2008. The rate is applicable to allsecurity cameras and communication equipmentinstalled on the Authority’s electric poles anywhereon the island. Before installation of these securitydevices, the client is required to provide all equip-ment specifications to the Authority’s Director ofTransmission and Distribution. The electric con-sumption for each installed security camera may notexceed 200 kWh per month.

During fiscal year 2013 an average of 166 clients usedthis rate. The average monthly consumption was 48kWh per client, which was less than one-half the aver-age consumption in the previous fiscal year. Their aver-age cost was 39.58 cents per kWh for fiscal year 2013.

COST OF SERVICEA cost of service study is an analytical tool that deter-mines the proper allocation of capital investment andexpenses associated with providing electric power tovarious clients. The results of the studies are usedwhen designing various rate schedules.

The Authority’s most recent cost of service study wasperformed using data from fiscal year 2011. Thisstudy employed methodologies that are commonlyaccepted in the electric utility industry. The studyresults included the allocation of costs and revenues,as well as an analysis based on rate base and its rateof return

The revenues, expenses and recovered cost percent-age from the cost of service study based on fiscal year2011 for the major classes of service are tabulated :

COST OF SERVICE RESULTS BASED ON 2011 DATA

($ millions)

Cost to Recovered CostRate Schedule/Class Revenues Serve Percentage

Residential 1,586.4 1,851.9 85.7

Commercial 2,115.4 2,050.6 103.2

Industrial 598.7 590.6 101.4

Other Classes 125.1 201.9 62.0

It should be noted that the results of a Cost of Servicestudy are not the only criteria used to design rates.The Authority uses other important criteria includingsocioeconomic, energy conservation, and load man-agement objectives.

CONSULTING ENGINEERSRECOMMENDATIONThe 1974 Agreement stipulates that after payment ofall current expenses, the remaining net revenuemust equal or exceed 120 per centum of outstandingdebt service. The Consulting Engineers monitors onan ongoing basis that the Authority’s rate scheduleswill generate sufficient revenues to pay its currentexpenses and have adequate debt service coverage.The Authority’s debt service coverage ratio for fiscalyear 2013 was 1.38. The debt service coverage forfiscal year 2014 is forecasted to be 141% based onthe Authority’s Annual Budget discussed in theFinancial section.

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FINANCIALThe financial data used in this Annual Report arebased on statements in the Authority’s AuditedFinancial Statements and on information provided bythe Authority. The Authority’s Audited FinancialStatements prepared by the Authority’s Auditors forfiscal year 2013 includes Schedules II through VI,which present certain information in accordance withthe 1974 Agreement, including a reconciliation of NetRevenues under generally accepted accounting prin-ciples with the 1974 Agreement. The primary differ-ences are Net Revenues under the 1974 Agreementexcludes depreciation expense, other post-employ-ment benefits and payment on Power Revenue Bondsdebt service. The financial data in the Annual Reportare based on accrual basis accounting.

ANNUAL BUDGETThe Annual Budget, prepared in conformance withSection 504 of the Trust Agreement, consists of fourstatements and two exhibits. The four Statements are:a pro forma income statement for the ensuing fiscalyear; a projection of capital expenditures also for theensuing fiscal year; a summary of capital expendituresand the sources of construction funds to support theexpenditures; and a schedule of funds to be providedby the Government Development Bank for PuertoRico (GDB). The two exhibits are a five-year projec-tion of debt service and Contractual Obligations andContributions in Lieu of Taxes and Other. The AnnualBudget for fiscal year 2013 that is referenced in thisreport was prepared by the Authority during the lastquarter of fiscal year 2012.

The Proposed Annual Budget of Current Expensesand Capital Expenditures – Fiscal Year 2013-2014 wasapproved by the Consulting Engineers and adopted bythe Governing Board in May 2013.

REVENUESTotal revenues booked for fiscal year 2013 were$4,850,816,378 or 4.0% less than the previous years’actual results, but within 0.2% of the forecasted rev-enues. The decreased revenues were primarily theresult of lower fuel costs and therefore lower fueladjustment charges. Total revenues for fiscal year 2014are forecasted to be $4,494,211,000 or an annualdecrease of 7.4%. The Authority’s projected revenuesfor the five-year intermediate forecast include $30 mil-lion each year for billings of power lost to theft as aresult of the significant initiative to recover theselosses. For fiscal years 2015 through 2018 total revenues are forecasted to be $4,558,037,000,$4,538,771,000, $4,589,252,000, and $4,519,866,000,

respectively. The Authority’s income statements(including interest income) for fiscal years 2013through 2018 are presented in Appendix II, IncomeStatement. Revenues from electric sales are shown onAppendix I, Intermediate-term Financial PlanningForecast which breaks down the revenues by sectorand the three components that the revenue is basedon—the base revenue, the fuel adjustment charge andthe purchase power adjustment charge—for the sixyear period 2013 through 2018.

As shown on Appendix I, base revenues from sales ofelectricity for fiscal year 2013, excluding fuel and pur-chased power costs that are included in the adjust-ment charge, were $1,114,052,000 and are forecastedto be $1,109,790,000 for fiscal year 2014 or a decreaseof 0.4%. The base revenue projections move with theforecasted energy sales for fiscal years 2015 through2018, shown in the first category of the appendix askWh sales.

As discussed in the Rates section the Authority had atemporary rate stabilization program in effect duringthe first five months of fiscal year 2013. The programeffectively subsidized certain residential clients for$53.2 million. The reported revenues for the residen-tial sector reflect this 3.2% reduction.

EXPENSESThe Authority’s budget for Current Expenses for fiscalyear 2013 and the amounts actually expended, as wellas those budgeted for fiscal year 2014, are tabulated forreference. Expenses incurred during fiscal 2013 weremore than those budgeted by 2.1%. Extracting fuel andpurchased power the variance was 10.7% more thanthat budgeted.

The current expenses for fiscal year 2014 are forecast tobe 10.3% less than actual expenses in fiscal year 2013.The projected reduction in current expenses in fiscalyear 2014 is based primarily on the cost of fuel pro-jected to decrease by 17.6% and a 2.3% drop in thebudget for other current expenses, except purchasedpower, which is projected to increase by 6.6%. Over thefive-year intermediate forecast current expenses otherthan fuel and purchased power are projected todecrease by 2.4% in 2015, then increase by 1.1% in2016, increase 0.3% in 2017 and be unchanged in 2018.

OPERATING AND MAINTENANCEEXPENSESIn fiscal year 2013, total Operating and Maintenance(O&M) expenses were $4,125,390,000 and for fiscalyears 2014 through 2018 are forecasted to be$3,700,008,000, $3,734,895,000, $3,716,576,000,$3,749,204,000 and $3,671,427,000. Appendix III,Detail of Operating and Maintenance Expenses,

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shows O&M expenses by category for fiscal years2013 through 2018.

The cost of fuel is the largest component of O&Mexpenses. During fiscal year 2013 approximately 65%of the System’s energy was generated by theAuthority’s fossil fuel plants, with a total fuel cost of$2,603.6 million; this constituted 63.1% of the totalO&M expenses for the year. The total cost of fuel forfiscal year 2014 is forecasted to be 17.6% less than theactual costs in fiscal year 2013, driven by forecastednear term decreases in oil prices and the increased useof natural gas at the Authority’s Costa Sur steamplant. The costs of fuel in fiscal year 2013 and theforecasted costs during fiscal years 2014 through2018, including the type of fuel, are discussed in theCapacity and Energy Resource Planning sectionabove. In addition, Appendix IV, Annual NetGeneration, Fuel Consumption, Fuel and PurchasedPower Costs, shows the cost of fuel and the generat-ing efficiency (kWh generated per barrel) for eachmajor generating facility. Actual data are shown forfiscal year 2013 and forecast data through 2018.

In reference to Appendix III, Detail of Operating andMaintenance Expenses, the forecasted breakdown ofO&M expenses by category for fiscal years 2014through 2018 reflect the Authority’s programs to con-tinue to control and modestly reduce its portion ofthese expenses from recent levels. As discussedabove, the O&M expenses excluding fuel and pur-chased power (referred to here as the Authority’sExpenses) in fiscal year 2013 were 10.7% over thebudget, which had been set aggressively low. Theseactual costs in fiscal year 2013 effectively matched theAuthority’s average Expenses over the prior three fis-cal years and form the bases for the projectedExpenses. The Authority’s Expenses are budgeted to

decrease by 2.3% in fiscal year 2014 from fiscal year2013 actual costs; the reductions are in operations,while the maintenance budget is increased 9.1% forthe same time frame. The Authority’s Expensesbudget is projected to drop 2.4% in fiscal year 2015,then increase 1.1% and 0.3% in fiscal years 2016 and2017, and remain unchanged in 2018. The Authorityhas identified various cost reduction programs whichwere being evaluated at the end of the last fiscal year.Coupling these measures with reductions in the num-ber of employees by attrition provides the bases forachieving the forecasted budgets of the Authority’sExpenses.

The ratio of O&M expenses to total operating rev-enues in fiscal year 2013 was 85.0%, but is projectedto be approximately 82% throughout the five-yearforecast period, based in part on the reductions inO&M expenses discussed above.

NET REVENUESNet Revenues, as defined under the Trust Agreement,are shown in Appendix II, Income Statement, asBalance to Revenue Fund. During fiscal year 2013 NetRevenues were $725,427,000, which was 13.8% morethan the preceding year and 7.0% more than the aver-age Net Revenues for the five fiscal years 2008 through2012. For fiscal year 2014 net revenues are forecast toincrease by 9.5% to $794,203,000. Net Revenues areforecasted to increase again in fiscal year 2015 by 3.6%and remain relatively stable through 2018, with projec-tions of $823,142,000, $822,195,000, $840,048,000and $848,439,000, respectively. Achieving these pro-jected Net Revenues will depend on the Authoritymaintaining tight control over the Authority’sExpenses as discussed above.

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Current Expenses 2013 2013 Actual 2013 2014 2014 BudgetBudget Expenses Variance Budget vs 2013 Actuals

Fuel Cost $ 2,607,917 $ 2,603,578 $ (4,339) -0.2% $ 2,145,911 -17.6%

Purchased Power 740,867 755,686 14,819 2.0% 805,414 6.6%

Other Production (incl Hydro Plt) 55,181 71,655 16,474 29.9% 65,699 -8.3%

Transmission & Distribution 140,445 172,318 31,873 22.7% 158,731 -7.9%

Maintenance 212,872 213,890 1,018 0.5% 233,374 9.1%

Customer Actng & Collection 105,559 116,351 10,792 10.2% 115,369 -0.8%

Administrative & General 177,757 191,912 14,155 8.0% 175,510 -8.5%

Interest Charges – – – – –

Total $ 4,040,598 $ 4,125,390 $ 84,792 2.1% $ 3,700,008 -10.3%

Current Expenses Minus Fuel + Purch Power $ 691,814 $ 766,126 10.70% $ 748,683 -2.3%

COMPARISON OF FY 2013 & FY 2014 BUDGETED TO ACTUAL EXPENSES (in thousands)

No. CEPR-AP-2015-0001

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DEBT SERVICE COVERAGEBased on the amounts shown in Appendix II IncomeStatement, the Debt Service Coverage (DSC) was 1.38in fiscal year 2013. The Debt Service Coverage is pro-jected to be 1.41, 1.42, 1.39, 1.34 and 1.35 for fiscalyears 2014 through 2018, respectively. As part of eachyear’s budget the Authority develops a forecasted bor-rowing schedule to support its Capital ImprovementProgram through the subsequent five years. The pro-jected annual debt service through fiscal year 2018 inthe Authority’s budget and this report was preparedprior to the planned financing scheduled for early fis-cal 2014. In addition, the forecasted debt servicerequirements include capitalized interest to reduceearly year obligations in future borrowings. These newfinancings may incur higher interest rates than fore-casted and the ability to capitalize interest may be con-strained as well. Both of these would increase theAuthority’s projected principal and interest require-ments in the intermediate term, thereby lowering theforecasted debt service coverage ratio.

The Debt Service Coverage graph shows the five-yearhistory and the five-year projection of the ratio of NetRevenues to Principal and Interest Requirements. TheDSC in fiscal year 2012 was unusually high owing tothe repayment schedule of the Series 2012 A/B financ-ing in which capitalized interest and low early-yearprincipal and interest payments resulted in the debtservice being $267 million below the maximum

(reached in 2017) and $199 million below the obliga-tion for fiscal year 2013.

The projected DSC data are based on the sinking fundpayments steadily increasing from $527.4 million infiscal year 2013 to $626.2 million in fiscal year 2017.As discussed above and shown in Appendix II IncomeStatement, the Authority’s forecasted growth in NetRevenues may not keep pace with the rate of increasein the debt service which actually unfolds.

DEPRECIATION EXPENSEThe actual depreciation accrual for fiscal year 2013was $342,437,000, as shown in Appendix IX,Depreciation Expense. The estimates for the ensuingfive fiscal years are $353,129,000, $363,723,000,$374,635,000, $385,874,000, and $397,450,000,respectively. Depreciation Expense is excluded fromstatements required for Trust Agreement purposes.

The Consulting Engineers issued a comprehensivedepreciation review of the Authority’s Plant-in- Serviceas of June 30, 2009. The results were implemented infiscal year 2013 by the Authority. Compared with theprevious study the results show that there is no longera deficiency between the theoretical and bookeddepreciation reserves and the depreciation accrual rateshould be reduced. The review confirmed statisticallythat the production plant’s average service life contin-ues to increase. It also showed that net negative sal-vage (cost of removal less salvage) of retired capital

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2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Debt Service Coverage Fiscal Years 2009-2018

Actual Forecast

2.00

1.90

1.80

1.70

1.60

1.50

1.40

1.30

1.20

1.10

1.00

1.45

1.85

1.47

1.95

1.38 1.41 1.42

1.391.34 1.35

No. CEPR-AP-2015-0001

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equipment was no longer escalating at the rate thatwas shown in the previous study.

ACCOUNTS RECEIVABLEThe Authority reports its net accounts receivable forfiscal year 2013 was $1,494.2 million after anallowance of $251.3 million for uncollectableaccounts which is 16.8% more than the previousyear’s amount. Of the $1,494.2 million, $603.0 mil-lion applied to government clients, an increase of40.5% from the previous year, and $838.9 millionapplied to general clients, 2.4% less than the previousyear. The remaining balance was mostly for unbilledservices. The non-current account receivables balancefor year end 2013 was $117.7 million or 15.7% morethan the previous year’s balance.

At the end of fiscal year 2013 the following five gov-ernment agencies accounted for approximately 25%of Accounts Receivable balances owed to theAuthority by Public Authorities:

Client A/R Balance

Puerto Rico Sewer and Aqueduct Authority $57.8 million

Department of Education $30.5 million

Ports Authority $31.6 million

Cardiovascular Center $18.9 million

Urban Train Administration $14.3 million

The Authority is continuing its aggressive effort tocollect overdue accounts. The actions taken to collectfrom Public Authorities include working closely withthe Office of Management and Budget to expeditepayments. Actions taken for general clients includedisconnecting electrical service, referring clients tocollection and credit rating agencies, and setting up apayment schedule. In February 2011 the legislatureof Puerto Rico approved Act 239-2011 that allows theOffice of Management and Budget of theCommonwealth to estimate the monthly electricinvoices of agencies that depend on General Fundallocations and to coordinate with the Puerto RicoTreasury Department to submit payments to theAuthority at the beginning of each month. Since itsadoption on December 11, 2011 the TreasuryDepartment has been submitting current monthlypayments for the electric energy consumed by thecentral agencies of the Commonwealth. Therefore theaccounts receivable of these government agenciesshould not increase. As of June 30, 2013 the out-standing balances of public corporations was $216.1million of which 41% was for past due accounts.

In an effort to collect account receivables from gov-ernment agencies, in June 2013 the Authority’s Exec-utive Director appeared before the Commonwealth’s

legislature to request that a fund separate from theGeneral Fund be set up to make payment for moniesowed by government agencies.

CONTRIBUTIONS TO THECOMMONWEALTHCONTRIBUTIONS IN LIEU OF TAXESAND OTHERSince the Authority Act was originally enacted, theAuthority has been required to make certain paymentsto the Commonwealth government and the island’smunicipalities as contributions in lieu of taxes (CILT).These payments were designed to be funded with an11% mark up on electric sales— referred to as the SetAside—and to be paid or credited from Net Revenues,as defined by the 1974 Agreement. Over the years theCommonwealth’s legislature has revised and added cer-tain subsidies and revised certain provisions of the pay-ments to the municipalities, however, the basicframework of these contributions has remained. In ref-erence to the disposition of Net Revenues as shown onAppendix II, Income Statement, the Authority consid-ers the total amount of CILT and Other to include itscontributions to the municipalities, plus three subsi-dies, an energy credit for qualifying businesses and theamortization cost of a settlement with the municipali-ties regarding disputed CILT obligations prior to 2004.

Although the intent of the Act was to have theAuthority invoice and collect from the municipalitiestheir electric invoices, the Authority has opted to off-set monies owed for electric consumption with CILT.

For the last decade the contributions or credits to themunicipalities have constituted more than three quar-ters of the CILT and Other total. In fiscal year 2013 thetotal current annual amount of CILT and Others wasequal to 25% of the Authority’s Net Revenues, com-pared to the prior five-year average of 31%. As dis-cussed below, the most recent law establishing theAuthority’s CILT obligations provides for deferral ofcurrent year payments; since fiscal 2007 the Authorityhas deferred partial payment of an accumulating por-tion of the CILT. These obligations have been paid orcredited from the Authority’s Net Revenues after certaindefined expenditures, subject to compliance with itsobligations under the 1974 Agreement. While initiallythe contributions in lieu of taxes were paid to theCommonwealth’s Secretary of the Treasury for distribu-tion to the municipalities, for many recent years thesecontributions have amounted to a full credit to themunicipalities for their electric power consumption.

In 1998, the Municipality of Ponce filed a complaintseeking payment from the Authority for the fullamount of the contributions in lieu of taxes, plus a

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potential addition based on available net revenues, forprior fiscal years. The island’s other 77 municipalitiessubsequently joined the suit. The complaint chal-lenged the Authority’s disposition of net revenues inmaking deposits to certain funds under both the 1947Trust Indenture and the 1974 Agreement for the pur-poses of paying the costs of capital improvements. Themunicipalities sought retroactive payment of theamount by which their share of the contributions inlieu of taxes had been reduced by such application.The Authority settled this litigation with the munici-palities in 2004 by offering a monetary payment of$68 million and $57 million for electric infrastructureprojects, for a total of $125 million. At the end of fis-cal year 2013 the outstanding balance of the loan usedfor the monetary settlement was $9.7 million.

In 2004 legislation was enacted that revised the for-mula for computing contributions in lieu of taxes andset aside. The amended legislation requires the 11%mark up of the Authority’s gross electric energy salesbe distributed to fund all government rate subsidiesprograms, to pay contributions in lieu of taxes to themunicipalities, to finance the Authority’s CapitalImprovement Program and for other legal purposes.The amendment changed the calculation of contribu-tion in lieu of taxes payable to the municipalities inthat it will be the greatest of the following threeamounts:

1. twenty-percent of the Authority’s Adjusted NetRevenues (Net Revenues, as defined in the1974 Agreement), less the cost of governmentrate subsidies

2. the cost collectively of the actual annual elec-tric power consumption of the municipalities;

3. the prior five-year moving average of the con-tributions in lieu of taxes paid to the munici-palities collectively. If the Authority does nothave sufficient funds available in any year topay the contributions in lieu of taxes then thedifference will be accrued and carried forwardfor a maximum of three years.

The Authority’s municipal CILT obligation for fiscalyear 2013 was $260.8 million, which was the value ofthe electric power consumed by the municipalitiesduring the fiscal year. This represented an increase ofmore than 6% in the value over the previous year. Asdiscussed below, Commonwealth Law 233 passed in2011 offers the Authority the ability to exclude certainactivities from municipal consumption that wouldqualify for the CILT obligation. The Authority is pro-jecting a marked decline in their CILT obligation

beginning in fiscal year 2014 as a result of provisionsin Law 233.

The amount of $180.6 million for Contributions inLieu of Taxes and Other shown on Appendix II,Income Statement, is the sum of the partial CILTcredit for fiscal year 2013, plus the annual paymentsfor the three previous year’s unpaid CILT, plus certainsubsidies and an annual amortization cost describedbelow. During fiscal year 2013 the Authority was cred-ited with $37.8 million in payments and services forthe current year’s obligations, the difference of $223.1million will be carried forward for payment by theAuthority over a maximum of three fiscal years. In fis-cal year 2013 the Authority was also credited with$85.5 million towards the unpaid CILT balances fromfiscal years 2010, 2011 and 2012 respectively; theinstallment for fiscal year 2010 completed theAuthority’s outstanding CILT obligations for that year.At the end of fiscal year 2013 the unpaid CILT balancetotaled $323.6 million, an increase of $133.7 millionover the previous year. The deferred CILT balance hasgrown steadily since the end of fiscal year 2007 whenit was $34.3 million.

The Contributions in Lieu of Taxes and Other for fis-cal year 2013 includes a total of $54.4 million com-prised of three subsidies and an energy credit totaling$43.9 million and a payment of $10.5 million to amor-tize the outstanding line of credit used in the settle-ment of the lawsuit by the municipalities. Asdiscussed in the Rates section the three subsidies arethe hotel subsidy, the rural electrification and irriga-tion subsidy, and the residential fuel subsidy; theenergy credit is the Authority’s contribution based onthe Economic Incentive Act, Law 73 (discussedbelow). The Authority’s escalating costs under Law 73for the fiscal years 2014 – 2018 are anticipated to be$2.2 million, $2.9 million, $3.7 million, $6.4 million,and $9.2 million, respectively.

In December 2011 the Commonwealth enacted Law233 that clarified the scope of CILT by excluding theelectrical consumption by municipalities used to sub-sidize revenues from for-profit activities, rental prop-erty generating income, and activities involving anentrance fee. The Authority has a program to identifyand install additional meters to track this consump-tion which will reduce the municipal consumptionsubject to the CILT obligation; while identifying thisconsumption will not increase reported revenues, itwill increase collectibles. The Authority has loweredthe projected CILT for fiscal years 2014 through 2018by $49 million annually to account for the revenuesthat Law 233 will generate.

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Based on the adjusted municipal power consumption,plus the subsidies and energy credit discussed above,the Authority forecasts the CILT and Other costs forfiscal years 2014 through 2018 will be $201.0, $205.8,$208.9, $193.3, and $201.7 million, respectively.

The Authority’s projected budgets and CILT amountsare structured to avoid increasing the accumulateddeferred CILT balance of $323.6 million discussedabove, assuming the forecasted annual CILT obliga-tions are based on that current year’s municipal powerconsumption. The applicable law, as discussed above,provides for the CILT to be the greatest of threeamounts, however. With forecasted declines inmunicipal consumption, the prior five-year movingaverage of the contributions in lieu of taxes paid tothe municipalities collectively would be greater thaneither 20% of Net Revenues or the current year’spower consumption. Invoking the prior five yearaverage criteria would increase the Authority’sdeferred CILT balance by $55.6 million in fiscal year2014 and $46.9 million the following year, based onthe budget for those years. These levels of CILT obli-gation cannot be sustained.

ECONOMIC INCENTIVES ACTTo spur economic development the CommonwealthGovernment enacted the Economic Incentives for theDevelopment of Puerto Rico Act (EconomicIncentives Act – Law 73) in May 2008. The EconomicIncentive Act is scheduled to be in effect for ten yearsstarting on July 1, 2008. In comparison to the TaxIncentives Act of 1998, which expired at the end offiscal year 2008, the Economic Incentive Act expandsthe scope of businesses eligible for tax exemptionsand credits. The three sections of the EconomicIncentive Act that may most affect the Authority arethe Energy Investment Credit, the Energy CostCredit, and Wheeling. The tax credits in theEconomic Incentive Act are based on the preferentialincome tax on Industrial Development Income.

The Energy Investment Credit section establishes aonetime tax credit of fifty percent for investments byeligible businesses in systems and equipment for gen-erating electrical energy and for investments whichimprove efficiency. The energy generation may be forself consumption or for commercial resale. Theamount of the tax credit for new self-generated capac-ity is limited to 25% of the eligible firm’s income tax.The tax credit for commercial generation is limited to$8 million per eligible business and $20 million peryear in the aggregate.

The Energy Cost Credit allows eligible businesses toreceive a credit of 3% of the cost of their industrial

energy consumption against income tax. Additionalcredits are available based on the number of employ-ees and payroll cost up to a total maximum credit of10% of the payments made to the Authority for energyconsumed in the operation of the eligible business.The maximum credit will be reduced 1% per yearbetween 2013 and 2017. The aggregate amount forthis tax credit is capped at $75 million per fiscal yearand $600 million through fiscal year 2018. The cost ofthe credits were borne by the Commonwealth’s Gen-eral Fund for the first year; beginning in fiscal year2010 the Authority covered an escalating portion ofthe credit starting at 4% with uniform annualincreases to 20% in fiscal year 2014, then 35%, 50%,65% and 80% in fiscal years 2015 through 2018,respectively.

Under the Wheeling provision, the Authority wasrequired to establish by January 2010 the technicalcriteria and tariffs that would apply to qualifying gen-erators for moving their power—wheeling—on theAuthority’s system to the generator’s clients or for theAuthority to purchase the generator’s power for gen-eral distribution to the Authority’s clients TheAuthority held public hearings in 2010 and 2011regarding proposed wheeling tariffs. Based on com-ments from these hearings and the public examiner’srecommendations, the Authority has been evaluatingits wheeling tariffs and has begun revision to its tech-nical requirements for wheeling and interconnection.The Economic Incentive Act establishes a newadministrative entity, the Energy Affairs Office, whoseduties include overseeing the implementation of thewheeling provision. The Energy Affairs Office has thepower to assign an arbitrator to establish ratesbetween the Authority and a qualifying generator ifthere is a disagreement between the two parties.

Funding for the tax credits established by theEconomic Incentive Act will be drawn from theCommonwealth’s General Fund and from paymentsby the Authority, with the Authority’s portion increas-ing during the term of the Act, as described above.The Authority’s payments will be based on reductionsin operating costs, improved efficiencies, revenuesfrom wheeling and lower costs in purchased power.Under the law, the Authority’s payments may not inany way be subsidized or passed through to its clientsand the Authority is prohibited from reducing itsnumber of employees or payroll. The tax credit willend if the Authority’s average retail cost of power is 10cents/kWh for two consecutive years. Prior to fiscalyear 2012 the Authority had incurred only adminis-trative costs associated with the Economic IncentiveAct. In fiscal year 2012 the Authority contributed$866,000 for their 4% share of the total energy cred-

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its assigned to nine qualifying businesses for fiscalyear 2010. The Authority’s contribution in fiscal year2013 was $1.2 million. The escalating annual contri-butions under the Economic Incentive Act are pro-jected to cost the Authority $53.1 million during theten years the Act is in effect through fiscal year 2018.

FINANCINGLONG-TERM CAPITAL FINANCINGThe Government Development Bank for Puerto Rico(GDB) is the primary fiscal agent for theCommonwealth of Puerto Rico and is responsible foroverseeing and maintaining the Commonwealth’soverall creditworthiness. In this capacity it coordi-nates all bond issues and lines of credit for theAuthority as well as other agencies of the common-wealth government and municipal governments.

The Authority’s actual and forecasted capital expendi-tures for fiscal years 2013 through 2018 are summa-rized by category in Appendix VI, CapitalExpenditures. The projected expenditures as shownin Appendix X, Details of Capital ImprovementProgram are a breakdown by Budget Item Number ofthe expenditures shown in Appendix VI. TheAuthority’s sources of funds and anticipated financingneeds for fiscal years 2014 through 2018, as well asthose realized in fiscal year 2013, are presented inAppendix VII, Sources of Funds for CapitalExpenditures.As of June 30, 2013, the Authority had$8,048,485,000 in Power Revenue Bonds outstand-ing. (See Appendix V, Debt Service Coverage Underthe 1974 Trust Agreement.) In April 2012 the Authority issued $650 million ofPower Revenue and Power Revenue Refundingbonds. Ninety-three per cent of the proceeds wereused to fund the following: Construction Fund,$359.5 million; pay down GDB line of credit, $161.9million; and $82.6 million as capitalized interest. Theapproved amount of the line of credit issued by theGDB was $244 million of which $159 million hadbeen used; the Authority paid $2.9 million in intereston the line credit, resulting in the $161.9 million totalpayment.

Amongst other uses, in fiscal year 2012 the GDB lineof credit had been used to fund the Rate StabilizationAccount which provided $79.4 million in credits toresidential clients to reduce their fuel adjustmentcharges during fiscal year 2012 and for certain princi-pal and interest payments due under the 1974Agreement. The proceeds of Series 2012B bonds wereused to refund Power Revenue Bonds Series II.

As shown in Appendix VII, Sources of Funds forCapital Expenditures, the Authority plans additionalfinancing in fiscal years 2014, 2016 and 2018 princi-pally to fund the Authority’s Capital ImprovementProgram and other purposes.

INTERIM FINANCING

Lines of Credit and Notes PayableAs of the end of fiscal year 2013 the Authority hadfour lines of credit and one term loan.

The term loan financing relates to settled litigationwith the municipalities of Puerto Rico, whichamounted to $64.2 million. As of June 30, 2013 thebalance was $9.7 million.

The first line of credit is for $25.4 million, intendedfor the restoration of the Isabela Dam. The outstand-ing balance as of June 30, 2013 was approximately$743,000. This line of credit expires on June 30,2018. The Authority expects to be reimbursed by theCommonwealth Government for any payments madefor this term loan.

During fiscal year 2013 the Authority re-initiated a$100 million line of credit with the GBD for coveringcollateral on its power revenue bonds that are basedon interest basis swaps. This line of credit expires onDecember 14, 2014. As of June 30, 2013 $6.1 millionhas been withdrawn and there was $93.9 millionavailable for withdrawal.

The Authority has two other lines of credit to be usedfor fuel financing with two large commercial banks.The combined lines of credit amount to $750.0 mil-lion of which $744.4 million has been withdrawnleaving an available balance of $5.6 million.

CAPITAL IMPROVEMENT PROGRAMThe fiscal year 2014 Capital Improvement Program(CIP) projects a five-year period of expenditures forextensions and improvements to the System. Anoverview of the scope of these projects for fiscal year2014 is provided below and is summarized by func-tional group in Appendix VI, Capital Expenditures. Anexpanded presentation of the CIP is in Appendix X,Details of Capital Improvement Program, which liststhe extensions and improvements by Budget ItemNumber (BIN) through fiscal year 2018.

The Authority develops the CIP on the basis of sup-porting its objectives of providing dependable electricpower service to the island of Puerto Rico at the low-est cost, consistent with applicable environmentaland social obligations.

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The Authority’s capital expenditures reached a peakof $666.8 million in fiscal year 2008 when construc-tion of the Authority’s two newest production plantprojects, San Juan Units 5&6 and the new combus-tion turbines at Mayagüez, were in their final phases.The capital expenditures in subsequent yearsdropped significantly. The average capital expendi-tures during the most recent past three fiscal yearswas $363.4 million which marked a decline of 46%from the 2008 peak.

Capital expenditures were projected to continue thedecline in fiscal year 2013 with a budget of $300 mil-lion. Actual capital expenditures during fiscal year2013 were $327.7 million; these were 6.7% less thanthe expenditures in fiscal year 2012, but 9.2% abovethe budget. During the next five fiscal years theAuthority plans to reduce its level of annual capitalexpenditures to an average of $310.0 million, whichis consistent with the actual expenditures in the pasttwo fiscal years. The CIP budgets in millions of dol-lars are projected to be $300.0, $300.0, $300.0,$325.0 and $325.0 for fiscal years 2014 through2018, respectively. The figures do not include theContributions in Aid of Construction, i.e., capital

contributed by either the Authority’s clients, FEMAor the Commonwealth Government for special con-struction services. However, allowance for funds usedduring construction (AFUDC) and annual cost esca-lations are included.

The tabulated data show by functional group theamounts budgeted for the Capital ImprovementProgram, the amounts actually expended in fiscalyear 2013 and the budget for fiscal year 2014. Duringthe course of the year the Authority occasionally real-locates certain budgets, staying within the total framework. The budget amounts shown in the table do notreflect any reallocations.

As indicated, the Authority’s total CIP budget for fis-cal year 2014 is unchanged from the previous fiscalyear, but the allocations by function group have beenrevised to reflect completion of projects and currentpriorities; the budget for fiscal year 2014 is 8.4% lessthan the previous year’s actual expenditures.

In the past fiscal year the Authority contributed $17.0million from internal funds to the Capital Improve-ment Fund, which was 5.2% of the total expendituresfor the year. During fiscal year 2014 the Authority

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Actual Forecast

Capital Improvement Program (in thousands) 2009-2018

2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Budget 2014 vsBudget Actual Difference 2014 Actual 2013

Production $118,898 $ 107,810 ($11,088) -9.3% $ 96,375 -10.6%

Transmission 58,965 69,661 10,696 18.1% 66,347 -4.8%

Distribution 91,097 127,926 36,829 40.4% 99,884 -21.9%

Other 31,040 2,280 (8,761) -28.2% 37,394 67.8%

Total $ 300,000 $ 327,677 $ 27,677 9.2% $ 300,000 -8.4%

COMPARISON OF BUDGETED CIP TO ACTUAL CIP EXPENDITURES – FY 2013 (in thousands)

No. CEPR-AP-2015-0001

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plans to contribute $22.7 million, which is 7.6%, tothe Capital Improvement Program budget for the year.Funding for the Capital Improvement Program is dis-cussed further in the Capital Improvement Fund sec-tion of Funding Recommendations below.

The first year of the Authority’s five-year CapitalImprovement Program is included in the AnnualBudget of Current Expenses and CapitalExpenditures which is reviewed and approved by theConsulting Engineers prior to the beginning of eachfiscal year. The current CIP through fiscal year 2018includes funds to complete the planned conversionsto dual fuel firing of oil and natural gas at theAuthority’s large steam-electric production units andits combined cycle units. As discussed in the Capacityand Energy Resource Planning section, providing nat-ural gas to most of the converted units will require anextensive gas supply infrastructure, with the excep-tion of the Costa Sur units for which the gas supplypipeline is in service. Since the Authority plans thatthe gas supply infrastructure will be developed withalternative sources, funds are not included in theAuthority’s CIP for this work.

We believe that the moneys shown in the CIP forextensions and improvements to the System over theforecast period are reasonable. The CIP is comprisedof numerous budget items grouped into five generalcategories. The largest expenditures are in productionplant, transmission plant, and distribution plant. TheCapital Improvement Program chart shows the trendsand relative values of these groups over the five-yearbudget period.

PRODUCTION PLANT

The CIP for fiscal year 2014 includes $96.4 millionfor production plant related projects. All of these areconsidered rehabilitation projects. The scope of theseincludes work associated with dual fuel conversion toinclude natural gas, improvements to boilers andsteam turbines, as well as environmental projects.

As discussed in Diesel Generators in the ProductionPlant section, the planned production plant CIPincludes replacing old diesel generator capacity onthe small island of Culebra with new equipment.Civil work on the project began in fiscal year 2013,with the full scope scheduled for completion in fiscalyear 2015. The new generators will improve the reli-ability of service to Culebra, especially by reducingservice interruptions from heavy weather.

The principal focus for rehabilitation projects is themajor refurbishment work planned for the Authority’soperating production plants during scheduled major

overhauls and plant system upgrades. A representativescope of these projects is discussed in the ProductionPlant section for each plant. Within the CIP for pro-duction, boiler improvements account for approxi-mately one quarter of the fiscal year 2014 budget. Inaddition to the fuel conversions discussed below, thescope includes refurbishing major boiler componentssuch as waterwalls and ductwork, refurbishing andimproving boiler structural steel and platforms andthe procurement of a shared spare boiler feed pumpinternals for the largest four steam plants.Improvements to the steam turbines and the balancesof the steam plants constitute approximately anotherquarter of the production CIP budget for fiscal year2014. These activities include the planned improve-ments to the steam turbine at Aguirre Unit 2, replac-ing four high pressure feedwater heaters at Costa SurUnit 5 & 6, refurbishing water storage tanks, and theupgrade and expansion of the demineralized watertreatment plant at the Costa Sur station. The CIP proj-ects at production plants include improvements tovarious major systems at combined cycle, combustionturbine, and hydroelectric plants.

The CIP for fiscal years 2014 through 2018 includes$70.2 million to complete the conversion to dual fuelfiring capability, i.e. fuel oil and natural gas, at theAuthority’s eight largest steam plant units at Costa Sur(already completed), Aguirre, Palo Seco and San Juan.This is consistent with the Authority’s strategy forMATS compliance as discussed in the Environmentalsection. The CIP for fiscal years 2014 through 2018also includes $10.0 million for adding natural gas fir-ing capability to the combined cycle plants at San JuanUnits 5 & 6, which presently fires distillate.

The Authority has identified projects within the reha-bilitation category that are for pollution control, orfor environmental issues, that have a total value of$10.8 million for fiscal year 2014. Environmentalprojects include installing new continuous emissionsmonitoring systems (CEMS) at the steam plants inpreparation for MATS compliance, cooling water pol-lution control projects, and oil spill containment, pre-vention, control and countermeasures.

TRANSMISSION PLANTThe CIP for fiscal year 2014 includes $66.3 millionfor transmission plant related projects. Expansionprojects are budgeted at $26.7 million and rehabilita-tion projects have a budget of $39.7 million.

The expansion projects are the new transmissionlines, transmission centers, switchyards, high voltageequipment, and extensions at existing facilities to

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support the growth of the transmission system. Themajor planned projects for the 230, 115 and 38 kVsystems are described in the Transmission section.These projects include the new 230 kV line fromCosta Sur to Cambalache, the new 115 kV GISswitchyard at San Juan steam plant, the new 115/38kV transmission centers at Barranquitas and Bairoaand new 38 kV underground projects in variousmunicipalities around the island.

Improvements to the 230, 115 and 38 kV systemsconstitute the rehabilitation projects. These includereplacement of structurally deteriorating lines andpoles, especially in the 38 kV system, and the upgrad-ing of the supervisory control and data acquisition(SCADA) system.

DISTRIBUTION PLANTThe distribution system CIP budget for fiscal year2014 is $99.9 million and is comprised of $18.8 mil-lion for expansion projects and $81.1 million forrehabilitation projects.

The distribution expansion projects include new sub-stations and increases to the capacity of existing sub-stations. These scopes are represented by the 13.2 kVsubstations at Sea Land (Caparra), Añasco andCharco Hondo. The expansion projects also includenew underground distribution lines, temporary sub-stations and portable equipment, new 13.2 kV feed-ers, and work associated with service to new clients.

The rehabilitation projects to the distribution systeminclude improvements to existing substations andline facilities, replacement of distribution poles andlines, and the improvement of underground distribu-tion lines. Consistent with its widespread application,approximately 31% of the distribution CIP budget isdirected to improvements for aerial distribution linesthroughout the island. The rehabilitation scopeincludes the underground work in the historic districtof Ponce, that is budgeted for $3.0 million in fiscalyear 2014. The largest project in this category isdirected to the purchase of remote read meters, whichaccounts for more than 9% of the distribution CIPbudget. The balance of the distribution projectsaddresses numerous miscellaneous requirementssuch as the purchase and installation of breakers, sec-tionalizers, voltage regulators, capacitors, and similardistribution equipment and systems.

GENERAL PLANTThe fourth category within the CIP is the general plantwhich for fiscal year 2014 totals $33.8 million. Thiscategory is composed of $7.2 million for general landand buildings and $26.6 million for equipment.

General land and buildings includes funds for theacquisition of land and rights of way and for struc-tures. The land acquisition for new transmission linerights of way represents approximately 40% of thisbudget. Regarding structures and buildings, the gen-eral plant funds are for improvements to technicaloffices, buildings, warehouses, workshops and cus-tomer service facilities. The budget includes funds forthe rehabilitation of facilities at the Authority’s headquarters, the Luchetti building in San Juan.

The equipment group is made up of five subgroups.The CIP for fiscal year 2014 includes $619,000 foroffice equipment. In fiscal year 2014 the computerequipment budget is $5.0 million. Other equipmentsubgroups are transportation equipment (land andair) at $8.3 million, of which $7.8 million is for newtrucks and vehicles. The fiscal year 2014 budget forcommunications equipment is $4.2 million, whichincludes $3.3 million for upgrading the fiber optic andmicrowave systems for SCADA. The budget for otherequipment is $8.5 million. This includes a wide rangeof specialized tools and equipment, such as construc-tion tools, directional drilling rigs, environmental andplanning analytical tools, and maintenance tools.

PRELIMINARY INVESTIGATIONSThe final category in the CIP is for preliminary stud-ies and surveys. The fiscal year 2014 budget for theseactivities is $3.6 million. These studies are principallyperformed by the engineering, planning and environ-mental groups to support the evaluations of varioussystem improvements and environmental compliancealternatives. The scope of studies includes evaluatingthe integration of renewable energy sources into theelectric system. Other studies evaluate improvementsto the operation and maintenance of the transmissionand distribution system.

FUNDING OF THE EMPLOYEES’RETIREMENT SYSTEMThe Employees’ Retirement System of the Authorityis a separate trust fund created and administered bythe Authority. The Retirement System is funded bycontributions from both the Authority, based onannual actuarial valuations, and plan members. TheRetirement System’s independent actuary preparedan actuarial valuation for fiscal year 2012. The actu-arial evaluation concluded that: The valuation resultsindicate that the combined employer and membercontribution rates are sufficient to fund the normalcost for all members and the unfunded accrued lia-bility. The valuation report also states that the actu-arial assumptions meet the parameters for thedisclosures under Governmental Accounting Stan-

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dards Board Statements No. 25 and 27 and that theemployer contribution rate is sufficient to financethe promised benefit under Statements 25 and 27.

The Retirement System’s unfunded accrued liabilityhad increased from $1,512.6 million as of the end offiscal year 2011 to $1,700.9.6 million as of the end offiscal year 2012. For future calculations the Actuarialassumptions are: an 8.5% annual rate of return oninvestments; projected annual salary increases of 4.1 –5.4% depending on age; 2 – 8% cost of living adjust-ments depending on the amount of benefit with a min-imum of $25 per month and maximum of $50 permonth; and 3% inflation.

The following table further summarizes the status ofthe Authority’s Pension Plan for the year ending June30, 2012:

AUTHORITY’S PENSION PLAN

Number of Active Members 8,600

Number of Retired and Disabled Members and Survivors 10,975

Annual Benefits $191,526,901

Actuarial Value of Assets (in millions) $1,285.4

Actuarial Accrued Liability (in millions) $2,986.3

Unfunded Actuarial Accrued Liability (in millions) $1,700.9

Estimated Covered Payroll (in millions) $365.0

Recommended Contributions for Fiscal Year Ending 2014

Total Contribution Rate:

Normal 9.5%

Unfunded Accrued Liability 30.2%

Total Contribution Rate 39.7%

Average Member Contribution Rate 10.4%

Authority Contribution Rate 29.3%

Amortization Period 28 years

INVENTORIES AND OTHER PROPERTIESAs part of the Finance Directorate, the MaterialManagement Division’s mission is to support all ofthe Authority’s installations with the material andequipment necessary to accomplish the Authority’sgoal of providing electric service to clients at the low-est possible cost. The Warehouses subdivision uti-lizes 32 warehouses and manages an extensiveinventory. At the end of fiscal year 2013 the inven-tory was worth $217.7 million of which $85.9 mil-lion was transmission and distribution material and$109.2 was related to its production plant spareinventory and $22.6 was general inventory. Thespare parts inventory for transmission and distribu-tion plant includes the safekeeping of a number ofitems, such as: transformers; poles; fuses; breakers;structures; and insulators. Among the items for pro-

duction plant the inventory includes: spare rotors forunits at the Aguirre and Costa Sur Steam Plants; anda spare turbine rotor for Palo Seco Units No. 3 & 4.For a (partial) list of spare components for the pro-duction plant refer to the Spare Components sectionin the System’s Operations section.

INSURANCEThe Risk Management Office, within the FinanceDirectorate, manages the Authority’s InsuranceProgram. It is responsible for managing and control-ling the Authority’s resources to minimize risks ofaccidental losses. In addition, it analyzes, assesses, andrecommends insurance policies and bonds for con-tracts and purchase orders. It settles property claimsagainst the Authority valued at less than $10,000.

During fiscal year 2013 the Authority maintained alayered set of All Risk Property and Boiler andMachinery policies that provided coverage of $750million. The structure of the program includes inde-pendent layers of $200 million each for coverage forall risks, and boiler and machinery losses. In excess ofthese $200 million layers of coverage, the Authority’sinsurance program includes a $350 million of combi-nation of all risks and boiler and machinery coverage,providing up to a $750 million limit of coverage for acombined all risks and boiler and machinery loss.Transmission and distribution lines other than under-ground and fiber optic lines are excluded which iscommon in the electric utility industry.

The Authority retains the first $25 million in earth-quake losses, the first $25 million in windstorm loss,plus an additional $20 million of windstorm loss inthe $100 million excess of $100 million layer of cov-erage for a total of $45 million retention for wind-storm damages, and $10 million in boiler andmachinery losses. The retentions under all other cov-ered losses include a $2 million deductible and, $7.5million of the first $25 million for coverage of all othercovered loss retention totaling $9.5 million.

The business interruption coverage within the AllRisk Property Policy is capped at $300 million withthe Authority covering the costs from the first thirtydays of the interruption.

In addition to the two policies cited above theAuthority’s Insurance Program contains policies forPublic Liability, Commercial Auto Policy-PREPA,Personal Auto Policy-Employees, Crime, Directorsand Officers Liability, Fiduciary Liability, EmploymentPractices Liability, Aviation, Hull and Hull Risks,Personal Accident and Health, Owner ControlledInsurance Program (OCIP) Rolling Wrap-up, and

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Open Cargo. Among the policies included in the OCIPare; Commercial General Liability, Builders RiskInstallation Floater, Pollution Liability andProfessional Liability. The public liability coverageremains at $75 million with the Authority holding $1million self-retention and $1 million deductible / $2million annual aggregate deductible.

The Eleventh Supplemental Agreement created theposition of “Independent Consultant”, a consultant orconsulting firm or corporation to be employed by theAuthority under Section 706 of this Agreement tocarry out the duties of said Independent Consultant.Section 706 of the 1974 Agreement reads in part:

The Authority covenants and agrees…it will, for thepurpose of carrying out the duties imposed on theIndependent Consultant by this Agreement, employone or more independent firms having a wide andfavorable repute in the United States for expertise inrisk management and other insurance mattersrelated to the construction and operation of electricsystems. It shall be the duty of the IndependentConsultant to prepare and file with the Authorityand the Trustee at least biennially, on or before thefirst day of November, beginning November, 1999, areport setting forth its recommendations, based on areview of the insurance then maintained by theAuthority in accordance with Section 707 of thisAgreement and the status of the Self-insurance Fund,of any changes in coverage, including its recommen-dations of policy limits and deductibles and self-insurance, and investment strategies for theSelf-insurance Fund.

The cost of the Authority’s Insurance Program asrenewed with these changes is approximately $24.7million a 15% savings from the previous InsuranceProgram renewal.

The Tenth Supplemental Agreement created the Self-insurance Fund. This fund is to be used to pay for thecost of repairing, replacing, or reconstructing propertydamaged or destroyed from or extraordinary expensesincurred as a result of a cause that is not covered byinsurance. It can also be used, when approved by theConsulting Engineers, to cover loss of income due toa cause which is not covered by insurance. The mon-eys in the Self-insurance Fund allow the Authority toincrease its insurance deductibles, thereby lowering itsinsurance premiums. Refer to the FundingRecommendations section for the status of the Self-insurance Fund and the Consulting Engineer’s recom-mendations concerning contributions.

FUNDINGRECOMMENDATIONS

Section 706 of the 1974 Agreement reads in part: itshall be the duty of the Consulting Engineers toinclude in such report [this Annual Report] their rec-ommendations as to the amount that should bedeposited monthly during the ensuing fiscal year tothe credit of the Reserve Maintenance Fund…,deposited during the ensuing fiscal year to the creditof the Self-insurance Fund…and deposited duringthe ensuing fiscal year to the credit of the CapitalImprovement Fund.

These three funds were created and funded in 1996when the 1947 Trust Indenture was defeased.

There have been four major events that have causedlosses to the Authority since the Reserve Maintenanceand Self-insurance Funds were created.

The first was Hurricane Hortense in fiscal year 1997that caused an estimated $36.0 million in damages tothe Authority’s System. The entire loss of this eventwas borne by the Authority.

In fiscal year 1999 Hurricane Georges devastated theisland. Total damages to the System were estimated at$239.9 million of which $12.7 million was covered byinsurance, $168.0 million was provided by theFederal Emergency Management Agency (FEMA)and the remainder of $59.2 million was the responsi-bility of the Authority.

Tropical Storm Jeanne in fiscal year 2005 caused anestimated $60 million in damages to the System, ofwhich FEMA provided $11.8 million in aid and thebalance of $42.8 million came from various funds ofthe Authority.

The fires at the Palo Seco Power Plant during fiscalyear 2007 caused losses estimated to total $363.2 mil-lion, of which insurance payments to the end of fiscalyear 2012 amounted to $301.3 million.

In August 2011 Hurricane Irene (later Tropical StormIrene as it traveled northward) passed by the northcoast of Puerto Rico. While the storm caused windand flood damages and extensive power outages, itsimpact was significantly less than the eventsdescribed above. The Authority submitted claims toFEMA for $15.9 million, but had not received anypayments during the past fiscal year.

The specific utilizations of money from the ReserveMaintenance and Self-insurance Funds are discussedbelow.

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RESERVE MAINTENANCE FUNDSection 512 of the 1974 Agreement reads in part:

moneys held for the credit of the ReserveMaintenance Fund shall be disbursed only for thepurpose of paying the cost of unusual or extraordi-nary maintenance or repairs, maintenance orrepairs not recurring annually and renewals andreplacements, including major items of equipment.

At the end of fiscal year 2013, the ReserveMaintenance Fund’s balance was $15.8 million. TheReserve Maintenance Fund is a restricted fund inwhich the moneys are held in trust by the Authority.

Since the fund was created in 1996 there have beentwo instances when the Authority withdrew moneysfrom this fund.

The first instance occurred in fiscal year 2005, when$7.1 million was withdrawn and applied as part of the$45 million costs to repair the System following dam-ages caused by Tropical Storm Jeanne. Additionalsources of funds to restore the System came fromFEMA and the Authority’s Self-insurance Fund.

The second instance began in April 2007 when theAuthority sought the Consulting Engineers’ concur-rence regarding the use of the Reserve MaintenanceFund as an interim source of funds for increased costsassociated with the loss of the Palo Seco Steam Plant.The Consulting Engineers concurred, but stipulatedthat any moneys withdrawn from the ReserveMaintenance Fund should be replenished using theproceeds from the Authority’s insurance programwithin a reasonable timeframe. Consistent with theConsulting Engineers intent, the Authority borrowed$9.4 million from the Reserve Maintenance Fundduring fiscal year 2007 and $58.3 million during fis-cal year 2008, a total of $67.7 million. The with-drawals were carried as an inter-fund debt of theGeneral Fund as part of the Palo Seco Steam Plantrecovery project. During the same period theAuthority returned $14.7 million from insurance pro-ceeds, $5.0 million in fiscal year 2007 and $9.7 mil-lion in fiscal year 2008, netting a $53 millioninter-fund debt of the General Fund to the ReserveMaintenance Fund.

Consistent with the Consulting Engineers responsi-bilities under the 1974 Trust Agreement, theConsulting Engineers recommended that theAuthority deposit $5 million to the ReserveMaintenance Fund in fiscal years 2009, 2010 and2011. At the request of the Authority, the ConsultingEngineers agreed that the moneys would instead be

used to reduce the $53 million inter-fund debt; at theend of fiscal year 2013 this inter-fund debt wasapproximately $33 million.

The Consulting Engineers recommends the Authorityneed not deposit any moneys into the ReserveMaintenance Fund during fiscal year 2014.

SELF-INSURANCE FUNDSection 507 (g) of the 1974 Agreement reads in part:

to the credit of the Self-insurance Fund...suchamount, if any, of any balance remaining aftermaking the deposits under clauses (a), (b), (c), (d),(e), and (f) above, as the Consulting Engineersshall from time to time recommend; and

Section 512A of the 1974 Agreement reads in part:

moneys held for the credit of the Self-insuranceFund (1) shall be disbursed...only for the purposeof paying the cost of repairing, replacing or recon-structing any property damaged or destroyed fromor extraordinary expenses incurred as a result of acause which is not covered by insurance…or (2)shall be transferred to the Revenue Fund in anamount, approved by the Consulting Engineers,equal to the loss of income from the System as aresult of a cause which is not covered by insurance.

Section 512A of the 1974 Agreement further reads:

If the Authority shall have determined that all orany portion of the moneys held to the credit of theSelf-insurance Fund is no longer needed for thepurposes specified in the second preceding para-graph, the Authority may withdraw an amountequal to such portion from the Self-insurance Fundand transfer such amount to the credit of the BondService Account; provided, however, that no suchtransfer shall be made prior to the time that theConsulting Engineers shall have approved suchtransfer in writing.

As of the end of fiscal year 2013 the balance of theSelf-insurance Fund was $92.2 million. Similar to theReserve Maintenance Fund, the Self-insurance Fundis a restricted fund in which the moneys are held intrust by the Authority. The Authority has withdrawnmoneys from this fund four times since its creation in1996. The first withdrawal, in fiscal year 1997 for $32million, was for damages caused by HurricaneHortense. The second withdrawal for $30 million infiscal year 1999 was for damages caused by HurricaneGeorges. Then in fiscal year 2005 for damages causedby Tropical Storm Jeanne $18.3 million was with-drawn. It should be noted that these amounts wereused to supplement insurance payments and reim-

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bursements from FEMA. They represented only afraction of the moneys required to restore theAuthority’s facilities.

In fiscal year 2007, at the request of the Authority, theConsulting Engineers authorized the withdrawal ofmoneys from the Self-insurance Fund to cover unin-sured losses associated with the Palo Seco SteamPlant fires. During fiscal year 2008 the Authoritywithdrew $25.4 million from this fund for the unin-sured losses associated with the Palo Seco SteamPlant fires. Also during fiscal year 2008 the Authoritydeposited $5.0 million to this fund. The Authoritydeposited to the fund $10 million per year in fiscalyears 2009, 2010 and 2011 and $5 million in fiscalyear 2012 in accordance with the ConsultingEngineers recommendations.

In August 2011 Hurricane Irene (later Tropical StormIrene as it traveled northward) passed by the northcoast of Puerto Rico. While the storm caused windand flood damages and power outages to more thanone million clients, its impact was significantly lessthan the events described above which required with-drawals from the Self-insurance Fund. During fiscalyear 2012 the Authority submitted claims to FEMAfor $15.9 million. At the end of the past fiscal year theAuthority had not yet received any payments, but didnot plan to use the Self-insurance Fund for this event.

During fiscal year 2014 the Consulting Engineers rec-ommends the Authority need not deposit any moneysinto the Self-insurance Fund.

CAPITAL IMPROVEMENT FUNDSection 507 (h) of the 1974 Agreement reads in part:

to the credit of the Capital Improvement Fund suchamount, if any, of any balance remaining aftermaking the deposits under clauses (a), (b), (c), (d),(e), (f), and (g) above, as the Consulting Engineersshall recommend as provided by Section 706 of thisAgreement; provided, however, that if the amount sodeposited to the credit of said Fund during any fis-cal year of the Authority shall be less than theamount recommended by the Consulting Engineers,the requirement therefore shall nevertheless becumulative and the amount of any such deficiencyin any such fiscal year shall be added to the amountotherwise required to be deposited in each fiscalyear thereafter until such time as such deficiencyshall have been made up, unless such requirementshall have been modified by the ConsultingEngineers in writing, a signed copy of such modifi-cation to be filed with the Authority.

Section 512B of the 1974 Agreement reads in part:

Moneys held for the credit of the CapitalImprovement Fund shall be disbursed…only forpaying the cost of anticipated extensions andImprovements of the System the cost of which hasnot otherwise been provided for from the proceedsof bonds issued under the provisions of thisAgreement.

The Consulting Engineers approves annually theAuthority’s budget for the ensuing fiscal year; thebudget includes amounts for the first year of the five-year Capital Improvement Program (CIP). (for furtherdiscussion, refer to the Annual Budget in the Financialsection) The budget for fiscal year 2013 projected thatthe CIP expenditures would be $300.0 million, ofwhich $27.0 million of the Capital Improvement Fundwould be generated internally. The actual CIP expen-ditures for fiscal year 2013, however, totaled $327.7million, of which $17.0 million, or 5.2%, was financedinternally through the Capital Improvement Fund. Inthe five fiscal years from 2009 through 2013 the aver-age level of internal funding for the CIP was 5.9%; thislow average would have been even lower except forthe contributions made in 2010. The levels of depositsto the Capital Improvement Fund reflect the sensitiv-ity of this funding to the Authority’s compliance withoperating budgets and its obligations of Contributionsin Lieu of Taxes.

For fiscal year 2014 the Capital Improvement Programbudget is $300.0 million, of which $22.7 million, or7.6%, is projected to come from internal funds. Theinternally generated funds portions of the CIP for fis-cal years 2015 through 2018 are projected to be10.4%, 4.3%, 4.0% and 4.0%, respectively. The fore-casted amount of internal funds will average 6.0% ofthe CIP over the five years ending in fiscal year 2018.

The following table shows the Authority’s actualdeposits to the Capital Improvement Fund for themost recent five fiscal years compared with thatwhich was budgeted.

CAPITAL IMPROVEMENT FUND

Fiscal Year Amount Amount DifferenceBudgeted Deposited

2013 $27.0 17.0 ($ 10.0)

2012 $77.3 15.1 ($ 62.2)

2011 $69.1 17.2 ($ 51.9)

2010 $0.0 63.4 $ 63.4

2009 $0.0 4.7 $ 4.7

The Capital Improvement Fund also serves as anadditional reserve for the payment of the principal of

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2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Internally Generated Funds Portion of Financing SourcesFiscal Years 2009-2018

18%

16%

14%

12%

10%

8%

6%

4%

2%

0%

y

ForecastedActual

1%

16%

4% 4% 5%

10%

4% 4% 4%

8%

and the interest on the Power Revenue Bonds andmeeting the amortization requirements to the extentthat moneys in the 1974 Sinking Fund, including the1974 Reserve Account, in the Reserve MaintenanceFund, and in the Self-insurance Fund are insufficientfor such purpose.

The chart presents the annual portions of internallygenerated funds for the total financing sources of cap-ital expenditures since 2009 and those forecastedthrough 2018.

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HUMAN CAPITALHUMAN RESOURCESOn June 30, 2013, the Authority had a workforce of8,465 employees: 8,025 permanent employees, and390 temporary or probationary employees who hadbeen employed by the Authority for less than 12months. The total number of employees on June 30,2013 reflects a net decrease of 161 employees fromthe previous year. This decrease includes oneemployee who was classified as an emergencyemployee in fiscal year 2012. During the past fiscalyear the number of permanent employees declined by263, while the number of temporary employeesincreased by 103. Approximately 90% of those leav-ing the Authority in the past fiscal year retired; in thesame year the Authority hired 200 new employees.The Authority anticipates that the recent rate ofdecline in the number of permanent employees willcontinue through fiscal year 2014. At the end of fiscalyear 2012 the Authority had 8,626 employees; ofwhich 8,338 were permanent and 287 were tempo-rary.

The Authority is comprised of eight directorates andthe Governing Board. The directorates are theExecutive Directorate, the Generation Directorate,the Transmission & Distribution Directorate, the LawDirectorate, the Planning and Environmental ControlDirectorate, the Finance Directorate, the ClientServices Directorate, and the Human Resource andLabor Affairs Directorate. Ninety–three percent of theAuthority’s permanent employees were employed inone of the following four directorates: 3,309 workedin the Transmission & Distribution Directorate for atotal of approximately 40% of the Authority’s employ-ees; 1,951 employees worked in the GenerationDirectorate for a total of 24% of the Authority’semployees; the Client Services Directorate employed1,441 persons or 18% of the Authority’s workforce;and 808 employees worked in the ExecutiveDirectorate, constituting approximately 10% of theAuthority’s workforce. An additional 589 personswere employed in one of the four other directoratesor by the Governing Board.

In an effort to achieve long term cost savings, inSeptember of 2009 the Authority implemented amajor change in the manner in which medical insur-ance would be provided for retirees and their spouses.Before September 1, 2009 an employee retiring with25 years of service received medical care insurancefor themselves and their spouse. After September 30,2009 an employee retiring with less than 30 years of

service was not eligible for a lifetime benefit of med-ical insurance for themselves or their spouse. Anemployee retiring after that date with more than 30years of service received a lifetime benefit of medicalinsurance but received no medical insurance cover-age for their spouse. The Authority put in place a planwhereby former employees with 30 years of servicecan purchase coverage for their spouse. TheAuthority has negotiated an extension of the firmfixed price for the provision of medical care forretirees and eligible spouses through December of2013.

The Authority prepares its employees for their jobassignments by providing a wide range of trainingprograms and refresher training programs. TheHuman Resources Directorate provides theAuthority’s employees with training in the areas ofsafety, health, and computer usage. The training pro-grams offering job specific, technical knowledge ofthe type needed by the employee to effectively per-form their assigned work are provided by the direc-torate within which they are employed. Bargainingand non-bargaining unit employees, supervisors andmanagers participate in these programs.

LABOR AFFAIRS The following paragraphs provide an overview of thebargaining units within the Authority and of the sta-tus of the labor agreements applicable to these bar-gaining units.

During fiscal year 2013 four different unions repre-sented 70% of the Authority’s 8,465 permanent andtemporary employees. The largest union is theElectric Industry and Irrigation Workers Union,known by its Spanish acronym (UTIER). At the endof the past fiscal year UTIER represented 4,717employees engaged in operations and maintenance.The other three unions are the Insular Union ofIndustrial Workers and Electrical Construction, Inc.(UITICE), with 839 construction workers; theIndependent Professional Employees Union (UEPI),with 360 professional employees, and the Puerto RicoElectric Power Authority Pilots Union (UPAEE), withsix pilots. The other 2,592 employees are members ofthe executive, managerial, and administrative staff:the terms of employment for these employees are notestablished by a collective bargaining agreement. Thefigures for fiscal year 2012 were similarly propor-tional; 6,006 employees represented by unions, (70%of the workforce), and 2,620 in executive, manage-rial, and administrative positions.

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The following paragraphs describe the status of therenegotiations of the Authority’s four collective bar-gaining agreements. During these negotiations theAuthority has proposed language that reaffirms certainmanagement rights, clarifies job descriptions, andmodifies the code of conduct in a manner that willfacilitate the management of its operations. TheAuthority is attempting to negotiate a reduction inaccident leave benefits to bring them more in line withthe private sector and to reduce certain sick leave ben-efits for new employees. The Authority has stressedthat the current economy makes concessions on thepart of the unions a prerequisite of a monetary offer.Nevertheless, during the collective bargaining processthe Authority strives to negotiate reasonable and equi-table terms for the Authority and its employees.

Labor agreements establishing wages, hours, and con-ditions of employment for three of the Authority’sfour unions terminated during fiscal 2011; theseexpirations were agreements with the Pilots(UPAEE), the Independent Professional EmployeesUnion (UEPI), and Insular Union of Industrial andElectrical Construction Workers (UTICE). The agree-ment with Electric Industry and Irrigation WorkersUnion (UTIER), the largest union, expired in earlyfiscal year 2013. All renegotiations continued withoutsettlement during fiscal year 2013.

The Authority and representatives of UTIER beganthe renegotiation of their collective bargaining agree-ment during fiscal year 2011 approximately eighteenmonths prior to the agreement’s expiration in fiscalyear 2013. During fiscal year 2013 employees repre-sented by UTIER held sporadic one day or partial daystrikes, plus a two week work action beginning inOctober 2012.

The Authority began the renegotiation the collectivebargaining agreement with the Pilots (UPAEE) inJune 2010. The four-year agreement, which estab-lished wages, hours, and conditions of employmentfor the Authority’s six pilots, terminated in July 2010.At the end of fiscal year 2013 the parties were still innegotiations.

Negotiations for a new collective bargaining agree-ment between the Authority and UEPI, which repre-sented 360 of the Authority’s employees, werecontinuing at the end of fiscal year 2013. TheAuthority is seeking a three year agreement to replacethe agreement that expired in December 2010.

The labor agreement with the construction workersin UTICE terminated in January 2011. UTICE repre-sented 10% of the Authority’s employees on June 30,

2013. Negotiations were continuing at the end of fis-cal year 2013.

EMPLOYEE SAFETYEach of the Authority’s directors is responsible to theExecutive Director for the safety and health of theemployees working within their respective direc-torate. Subordinate managers, supervisors, and ulti-mately the workers themselves share thisresponsibility. The Occupational Safety Divisionassigns the safety and health professionals and certainof the other resources needed to assist the directors intheir efforts to prevent accidents and job-related ill-nesses. The Occupational Safety Division ensures thatthe Authority’s workplace safety and health programscomply with relevant Federal and Commonwealthstatutes and are consistent with the objectives of theAuthority.

The Division’s staff of 28, comprised largely of safetyand health professionals, provides assistance to man-agers and supervisors in the day-to-day implementa-tion of safety and health programs. Fifteen of the 28are assigned to other electric generating facilities andregional offices. The following is a sampling of thedistribution of safety and health professionals acrossthe island. There are eight Safety and IndustrialHygiene Officers, of these one is assigned to each offive generating stations, Central Aguirre Steam,Aguirre Combined Cycle, Central Costa Sur, CentralPalo Seco, and Central San Juan. Two Safety andIndustrial Hygiene Officers are based in Santurce.From these office locations they provide consultingservices to the Cambalache Power Plant, gas turbinesites, the hydroelectric stations as well as to the otherdirectorates. A Health and Safety Officer is assigned ineach of the seven regional Transmission andDistribution offices in Arecibo, Carolina, Ponce, SanJuan, Bayamon, Caguas, and Mayagüez. One Healthand Safety Officer is assigned to the Line andSubstation Construction Subdivision. The Authorityhas a single Safety Consultant based at the Costa SurSteam Plant who is responsible for the developmentand implementation of safety programs for theAuthority’s construction sites. The HazardCommunication Section provides initial and refreshertraining in hazardous waste operations and emer-gency response (HAZWOPER) to employees assignedthroughout the Authority. The training covers hazardrecognition, hazard communication, and the use ofpersonal protective equipment. Additional resourcesinclude an attorney who assists the Authority inresponding to Puerto Rico OSHA (PR OSHA) cita-tions, provides guidance with respect to safety laws,

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and who chairs the Central Health and SafetyCommittee with UTIER.

The Division has a performance recognition programfor units and Directorates whose employees work in ahigh risk environment and a second recognition pro-gram for those working in office environments wherethere is less risk of a work related injury or illness.

During the past year the Authority conducted 511training sessions for 6,637 employees in 32 differentsubject areas. The Authority’s supervisory trainingfocused on the importance of conducting and record-ing job briefings to ensure that subordinates fullyunderstood the exposures they might encounter inthe performance of their tasks, the personal protec-tive equipment and actions necessary to safely com-plete the assigned task. In addition the supervisorytraining programs increased the awareness of thedirect and indirect costs of accidents and illnesses andtheir effect on the Authority’s cost of doing business.

In calendar year 2013, the Authority reported to PROSHA that its employees worked a total of14,465,221 hours and sustained 1,355 incidents ofwork related injury or illness that were recordable inaccordance with OSHA’s requirements. There weretwenty five serious accidents during the year. Since2004 the Authority and other Puerto Rican publiccorporations have been subject to financial penalties,in the same manner as private corporations, for viola-tions of OSHA regulations. The Authority’s managersand supervisors are routinely briefed annually on thechange in the OSHA penalty provisions. In calendaryear 2013, the Authority was cited sixteen times forviolating OSHA regulations. PR OSHA proposed finestotaling $41,975 for eight of the citations; theAuthority paid $8,500 in settlement of these citations.The proposed fines associated with the eight remain-ing citations from fiscal year 2013 total more than$65,000 and are being contested by the Authority.

The employees of the Occupational Health Division,within the Human Resources and Labor AffairsDirectorate, are responsible for providing first aid,medical treatment, training, and administrative serv-ices to employees from the reported onset of a workrelated injury or illness until the employee returns towork, is reassigned, or reclassified. They provide arange of health related activities and training pro-grams. An employee’s initial contact with this divisionis frequently at one of the eight dispensaries that arestaffed with registered nurses. The dispensaries arelocated at the Authority’s main office in Santurce, inregional offices in Monacillos, Caguas, and Ponce andat the steam electric plants in Aguirre, Costa Sur, Palo

Seco, and San Juan. In most cases, however, the firstaid and treatment provided by the Authority’s regis-tered nurses were for a condition that was classified asnon-occupational.

Following a work related injury or illness almost allemployees are referred from the Authority’s dispen-sary or a first aid facility to one of theCommonwealth’s treatment clinics, which are a partof the Corporación del Fondo del Seguro del Estado(CFSE) or Fondo for short. The physicians and med-ical staff employed by Fondo provide the medical carerequired for the Authority’s employees following awork related injury or illness and determine when theemployee is capable of returning to work. A long-term goal of the Authority has been to obtain thecooperation of Fondo’s representatives to expedite thecare being provided to their injured or ill employees.

Since 1995 the Authority has had a random drug-test-ing program, which has been implemented in steps.The random drug testing program applies to employ-ees in safety sensitive positions, which constitutesmore than 60% of its workforce. During the past yearapproximately 25% of these employees were ran-domly tested. Employees who test positive and arereferred to a three month long treatment program,where they received treatment and counseling.Repeat violators are also referred to treatment, how-ever, the Authority’s policy is an employee who testspositive for drugs three times may be terminated. TheAuthority also administers drug tests to all candidatesfor employment.

LEGAL AFFAIRSThe thirty attorneys of the Legal AffairsDirectorate’s are responsible for a wide range ofcontract and litigation related activities. The follow-ing discussion summarizes the status of a numberof the issues that the Authority litigated during fis-cal year 2013.

During the past fiscal year the breach of contract lit-igation between Abengoa, Puerto Rico, S.E. and theAuthority continued in discovery in SuperiorCourt, Court of First Instance in Puerto Rico. Thesuit dates to an action in May 2000 when Abengoa,the prime contractor for the construction of twocombined cycle units at San Juan Steam Plant, ter-minated their contract and left the constructionjobsite; Abengoa alleges $18 million in losses andclaimed as one basis that the Authority had notobtained the required permits from the EPA thatwere necessary for the construction to proceed. TheAuthority filed a counter claim for breach of con-

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tract and subsequently completed construction ofthe units with another firm. The units went intocommercial operation in October 2008. TheAuthority in 2011 estimated their losses as a resultof Abengoa’s alleged breach of contract to beapproximately $250 million. In October 2007 thelawsuit was certified as complex litigation by theSuperior Court of San Juan and a speciallyappointed arbitrator was named to assist both par-ties in reaching a settlement. Subsequent failure ofthe arbitration process moved the litigation to trialwhere the case will be adjudicated in two phases:liability, and wrongful termination and damages. AStatus hearing was scheduled to be held in July2013; it is anticipated that both parties will submita Joint Pretrial Report in November 2013.

As part of the settlement in 2007 of the litigationover the Contributions in Lieu of Taxes, CILT, theAuthority agreed to perform certain infrastructureprojects for the municipalities involved in the liti-gation. Work was continuing during the past fiscalyear.

The Authority filed suit in Puerto Rican Courtseven years ago against the Brazilian manufacturerand the manufacturer’s Puerto Rico agent over thefailure of the more than 6,000 batteries in theSabana Llana Battery Energy Storage System, BESS.The Authority claimed damages of more than $18million against the co-defendants, the manufacturerand their Puerto Rican partner. During fiscal year2010 the Brazilian battery manufacturer declaredbankruptcy. The Authority continued to litigate thiscase against the Puerto Rican partner. The bondingcompany standing behind the Brazilian manufac-turer and the Puerto Rican partner subsequentlyfailed during 2011. The Authority has been advisedthat recovery of more than $500,000 from thebonding company is unlikely. The Authorityexpects to settle this litigation during fiscal year2014 and dispose of the batteries for salvage value.

The Authority has increased its efforts to eliminatethe theft of electricity. Electricity theft is occurringacross client classes, throughout theCommonwealth and has been identified as having amaterial impact on the Authority’s operations.During fiscal year 2013 the Authority increased itsfocus on smart grid technology to identify and dis-courage the theft of electricity. Continued imple-mentation of upgraded meters and new smart datatechnology systems will allow the Authority toidentify usage patterns and system disturbancesconsistent with electric energy theft. The upgraded

meters can remotely disconnect service, whenappropriate. The Authority plans to install approxi-mately 60,000 upgraded meters in fiscal 2014bringing the total to 230,000. Larger Commercialand Industrial theft will be investigated and adjudi-cated by the Puerto Rico Department of Justice,reducing the need and expense of administrativelaw judges in the recovery process. During fiscalyear 2013 the Authority identified $19.1 million intheft related lost revenue, of which, approximately$5.0 million was recovered. The Authority’s finan-cials shows an annual recovery of $30 million intheft related lost revenues for each of the fiscalyears 2014 through 2018.

On August 23, 2007 Power Technologies Corp filedsuit against the Authority over the Authority’s deci-sion not to proceed with a project to construct anelectric generating plant in the Mayagüez area.Power Technologies Corp alleges that the projectwas cancelled without justification; they are seek-ing recovery of damages of more than $51 million.The case was withdrawn by Power Technologieswhen both parties agreed to negotiate.

The Caribbean Petroleum Corporation’s(CAPECO), fuel storage depot in Bayamon caughtfire in October 2009. The Authority had residualfuel oil and distillate stored at the depot. The firewas extensive; it shut down the depot and causedsome amount of air and water contamination to theadjacent area. The Authority and numerous otherparties have been named in suits filed againstCAPECO. Early in fiscal year 2011 CAPECO filedfor bankruptcy protection, staying the suits againstit. In December 2010 CAPECO sold its assets toPuma Energy Caribe who commenced the recon-struction of the damaged facility and environmentalremediation. At the end of fiscal year 2013 the suitagainst the Authority and others continued in thediscovery stage of what could be a lengthy processbut one not material to the Authority.

Following a heavy rainstorm in 2009 there was amudslide that destroyed and damaged a number ofhomes built by squatters on steep hillsides in thePonce area. The mudslide occurred in an area wherethere were Authority, PRASA, and other utilitystructures. Six plaintiffs filed suit against theAuthority and the other utilities, claiming $19.5million in damages. Those bringing suit allege thattheir losses were the result of soil instability thatresulted from the installation of utilities, such astower foundations, underground services, utilitypoles and towers. The Authority alleges that the

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utility installations predated the construction of thehomes. The case was stayed by the court followingbankruptcy proceedings for PRASA’s insurer afterwhich the Authority will continue with its defense.This suit is not likely to be resolved in fiscal year2014.

In 2005 fifty-five former workers, all of whom havea condition that can be associated with asbestosexposure and who were employed by the Authorityfrom 1960 to 2000, filed suit against the Authority.They former workers claim they were exposed toasbestos during their employ and that the Authoritydid not provide adequate protection as required byfederal and local laws. The plaintiffs are calming$320 million damages for health related illnesses.The Authority has filed a motion for dismissalclaiming immunity from suit since those bringingthe suit were former employees and were coveredby workman’s compensation. Discovery is sched-uled to end in fiscal year 2014.

SUPPLEMENTARYINFORMATION

EXECUTIVE DIRECTOR CHANGESIn January 2013 Ing Josué A. Colón Ortiz resignedfrom the Authority after serving as the ActingExecutive Director since June 2012. Prior to hisappointment Ing Colón was the Director ofGeneration; his career with the Authority spanned 24years, from design and maintenance engineering tomanagement of production plant operations.

Following Ing Colón’s resignation, Ing Juan AliceaFlores was appointed Executive Director later thatmonth. Ing Alicea has 30 years experience with theAuthority. During his tenure with the Authority hehas held numerous senior management positionsincluding Acting Executive Director, Director ofPlanning & Environmental Protection, GeneralPower Plant Manager at the Palo Seco Steam PowerPlant, Maintenance Department Head and OperationsDepartment Head of the Aguirre Power Plant andSenior Shift Engineer. Ing Alicea graduated with adegree in Mechanical Engineering from the MayaguezCampus of the University of Puerto Rico.

In February 2013 the Authority’s Governing Boardappointed Ing Roberto Garay González to the newlyreopened the post of Vice Executive Director. IngGaray has 25 years of experience at the Authorityduring which he has held senior positions such asTransmission and Distribution Technical OperationsDirector, and Transmission and DistributionEngineer. Ing Garay is an electrical engineer and hasa Master Degree in Engineering Management.

PREPA SUBSIDIARIESThe Authority’ organization includes two componentunits—Puerto Rico Irrigation Systems and PREPAHoldings LLC. Both were active at the end of fiscalyear 2013.

The Puerto Rico Irrigation System operates variouslegacy portions of irrigation systems throughout theisland. The condensed financial statement forIrrigation Systems as of June 30, 2013 showed $28.0million in total assets and the annual revenue loss of$4.6 million, based on operating revenues of $6.9million and operating expenses of $11.5 million. Inaddition, the Puerto Rico Irrigation System trans-ferred $6.0 million to the Commonwealth govern-ment.

PREPA Holdings, LLC is a subsidiary of the Authoritythat was created as the holding company for the

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Authority’s four other subsidiaries: PREPA Networks,LLC (merged from and PREPA.NET); InterAmericanEnergy Sources, LLC; PREPA Utilities, LLC; andPREPA Oil & Gas, LLC. The latter two were not oper-ating in fiscal year 2013.

Based on the independent consolidated financialstatements prepared for PREPA Holdings, LLC, at theend of fiscal year 2013 the total consolidated assets ofPREPA Holdings were $46.5 million and its consoli-dated liabilities were $29.6 million. PREPA Holdings’operating revenues were $14.5 million and its operat-ing expenses were $8.2 million; this resulted in anoperating income of $4.1 million after interest andthe transfer to the Commonwealth government of$2.0 million. The consolidated operating revenues infiscal year 2013 were up $0.9 million over the previ-ous year primarily from the amounts received fromthe local telecommunications company for the jointpole attachments in the three prior fiscal yearsthrough 2012.

In 2000 the Authority began the acquisition of a fiberoptic cable system to modernize the Authority’s inter-nal communication systems and thereby providefaster and more secure data transmission for opera-tions, load management, system protection, and secu-rity. In order to meet its optical fiber cablerequirements, the Authority entered into a long-termagreement with Puerto Rico Information Networks,Inc. (PRIN) a private, independent, non-profit corpo-ration incorporated in Puerto Rico. Under the agree-ment, PRIN designed and built a fiber optic cablesystem that was installed on the Authority’s rights-of-way (mainly its transmission lines). The fiber-opticcable is an integral part of the overhead ground wireswhich protect transmission lines from lightningstrikes. When completed in August 2002, title to thesystem was transferred to the Authority.

The Authority financed its acquisition of the fiberoptic system from PRIN by selling $43.7 million ofSubordinate Obligations in October 2002. In June2005 the Authority created PREPA Networks, LLC(PREPA.Net) to replace PRIN and market the excesscommunication capacity of the fiber optic network.PREPA.Net owns, operates and maintains the fiberop-tic network that offers next generation telecommuni-cations (NGT) service to carriers, internet serviceproviders (ISPs), and large enterprises. PREPA.net’snetwork has optical technology that is used by serv-ice providers to communicate with submarine cablelanding stations, wireless network towers and islandwide locations.

During fiscal year 2008 PREPA.net acquiredUltracom, one of three submarine cable firms on theisland, to obtain international fiber optic cable capac-ity and satellite teleport facilities. The acquisition wasfinanced with a term loan of $10.1 million due inFebruary 2023. The balance of the loan as of the endof fiscal year 2013 was $8.1 million.

In November 2011 PREPA.NET entered into a 10year Indefeasible Right to Use purchase agreementwith PRASA in the amount of $13.7 million. Theagreement allows PRASA an Indefeasible Right to Use(IRU) for the fiber optic communication network.

Also in fiscal year 2012 PREPA.net acquired propertyin Isla Verde for the development of a facility to sup-port its telecommunications business; the facility isscheduled for completion in fiscal year 2014.

On March 12, 2012 PREPA Networks, Corporationand PREPA .NET merged to form PREPA Holdings,LLC.

Also in March 2012, PREPA holdings entered into an18 year IRU sale agreement with Cable and Wirelessof Panama, S.A. (CWP) for the amount of $2.3 mil-lion. The agreement grants PREPA Holdings an IRUfor the fiber optic communication network owned byCWP.

During fiscal year 2013 the following subsidiarieswere not in operation:

PREPA Utilities was formed to financially participatein, develop, construct and operate industrial projectsand other related infrastructure to improve the elec-tric infrastructure of the Authority.

PREPA Oil & Gas was established to provide a mech-anism for the Authority to participate in a wide rangeof financial, commercial and operational projects forfuel supply and infrastructure.

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APPENDICES

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13

4,45

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3)

2018

2017

2014

2016

2013

2015

Act

ual

Fore

cast

No. CEPR-AP-2015-0001

I 000117

APP

EN

DIX

IIIN

CO

ME

ST

AT

EM

EN

T

Act

ual1

2013

2014

2015

2016

2017

2018

RE

VE

NU

ES

Rev

enue

s fro

m A

ppen

dix

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A

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Bal

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Bal

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559,

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Con

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Bal

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-$

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1. A

udite

d2.

Prin

cipa

l and

Inte

rest

requ

irem

ents

are

net

of c

apita

lized

inte

rest

from

pre

viou

s bon

d is

sues

.

Fore

cast

No. CEPR-AP-2015-0001

I 000118

APP

EN

DIX

III

DE

TA

IL O

F O

PER

AT

ING

and

MA

INT

EN

AN

CE

EX

PEN

SES

Act

ual1

Fore

cast

2013

2014

2015

2016

2017

2018

OPE

RA

TIO

N

Ther

mal

and

Gas

Pro

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ges

No. CEPR-AP-2015-0001

I 000119

APPENDIX IVANNUAL NET GENERATION, FUEL CONSUMPTION, FUEL and PURCHASED POWER COSTS

Page 1 of 2

Actual2013 2014 2015 2016 2017 2018

AGUIRRE STEAM PLANTNet MWh-Generated 4,226,411 4,353,000 4,439,000 5,078,000 4,823,000 4,989,000 Barrels of Fuel Oil Used 7,087,884 6,954,000 7,209,000 8,757,000 8,288,000 8,589,000 MBTUx1000 44,654 43,810 44,870 51,030 48,292 50,046 kWh Per Barrel 596 626 616 580 582 581 Cost of Fuel 800,803,249$ 671,600,000$ 669,920,000$ 678,072,934$ 633,956,000$ 630,726,567$ Cost of Fuel Per Barrel 112.98$ 96.58$ 92.93$ 77.43$ 76.49$ 73.43$ $/Mbtu 17.93$ 15.33$ 14.93$ 13.29$ 13.13$ 12.60$

COSTA SUR STEAM PLANTNet MWh-Generated 3,120,018 4,752,000 4,778,000 3,839,000 3,571,000 3,226,000 Barrels of Fuel Oil Used or Equivlent 5,528,530 8,459,000 8,534,000 6,908,000 6,420,000 5,801,000 MBTUx1000 34,830 50,285 50,756 41,142 38,191 34,480 kWh Per Barrel 564 562 560 556 556 556 Cost of Fuel 521,197,048$ 676,126,000$ 691,105,000$ 567,905,000$ 525,286,000$ 465,395,000$ Cost of Fuel Per Barrel 94.27$ 79.93$ 80.98$ 82.21$ 81.82$ 80.23$ $/Mbtu 14.96$ 13.45$ 13.62$ 13.80$ 13.75$ 13.50$

PALO SECO STEAM PLANTNet MWh-Generated 2,689,532 2,016,000 1,785,000 1,992,000 2,089,000 2,028,000 Barrels of Fuel Oil Used or Equivlent 4,575,037 3,324,000 2,943,000 3,286,000 3,511,000 3,617,000 MBTUx1000 28,823 20,936 18,540 20,698 21,702 21,075 kWh Per Barrel 588 606 607 606 595 561 Cost of Fuel 511,036,274$ 319,444,000$ 284,424,000$ 318,402,000$ 335,828,000$ 316,710,984$ Cost of Fuel Per Barrel 111.70$ 96.10$ 96.64$ 96.90$ 95.65$ 87.56$ $/Mbtu 17.73$ 15.26$ 15.34$ 15.38$ 15.47$ 15.03$

SAN JUAN STEAM PLANTNet MWh-Generated 2,002,269 998,000 640,000 716,000 778,000 627,000 Barrels of Fuel Oil Used or Equivlent 3,616,511 1,808,000 1,161,000 1,301,000 1,436,000 1,195,000 MBTUx1000 22,784 11,393 7,316 8,199 8,904 7,177 kWh Per Barrel 554 552 551 550 542 525 Cost of Fuel 404,852,726$ 174,765,000$ 110,134,000$ 125,714,000$ 138,864,000$ 110,041,000$ Cost of Fuel Per Barrel 111.95$ 96.66$ 94.86$ 96.63$ 96.70$ 92.08$ $/Mbtu 17.77$ 15.34$ 15.05$ 15.33$ 15.60$ 15.33$

AGUIRRE COMBINED-CYCLE UNITSNet MWh-Generated 309,354 226,000 220,000 618,000 922,000 700,000 Barrels of Fuel Oil or Equivalent 595,728 397,000 387,000 1,063,000 1,580,000 1,206,000 MBTUx1000 3,753 2,305 2,248 6,195 9,208 7,030 kWh Per Barrel (or equivalent) 519 569 568 581 584 580 Cost of Fuel 82,931,254$ 56,069,000$ 46,037,000$ 81,118,376$ 119,958,059$ 88,873,042$ Cost of Fuel Per Barrel 139.21$ 141.23$ 118.96$ 76.31$ 75.92$ 73.69$ $/Mbtu 22.10$ 24.32$ 20.48$ 13.09$ 13.03$ 12.64$

COMBUSTION-TURBINES & DIESELSNet MWh-Generated 11,439 1,000 1,000 1,000 1,000 1,000 Barrels of Fuel Oil Used 31,862 1,588 1,494 2,045 2,217 2,037 MBTUx1000 201 9 9 12 13 12 kWh Per Barrel 359 630 669 489 451 491 Cost of Fuel 4,424,965$ 222,565$ 210,428$ 295,774$ 331,558$ 314,000$ Cost of Fuel Per Barrel 138.88$ 140.15$ 140.85$ 144.63$ 149.55$ 154.15$ $/Mbtu 22.04$ 24.73$ 23.38$ 24.65$ 25.50$ 26.17$

CAMBALACHE Net MWh-Generated 62,236 5,000 6,000 3,000 5,000 3,000 Barrels of Fuel Oil or Equivalent 128,558 11,587 12,876 6,375 11,205 5,921 MBTUx1000 810 67 75 37 65 34 kWh Per Barrel 484 432 466 456 446 507 Cost of Fuel3 18,387,724$ 1,611,000$ 1,784,000$ 905,000$ 1,668,000$ 900,000$ Cost of Fuel Per Barrel 143.03$ 139.04$ 138.55$ 141.96$ 148.86$ 152.00$ $/Mbtu 22.70$ 24.04$ 23.79$ 24.46$ 25.66$ 26.47$

MAYAGUEZ TURBINESNet MWh-Generated 110,179 104,000 56,000 20,000 25,000 22,000 Barrels of Fuel Oil or Equivalent 201,497 173,752 94,811 33,483 41,790 36,453 MBTUx1000 1,269 174 95 33 42 36 kWh Per Barrel 547 599 591 597 598 604 Cost of Fuel 28,238,082$ 25,129,000$ 13,633,000$ 4,912,000 6,384,000 5,740,000 Cost of Fuel Per Barrel 140.14$ 144.63$ 143.79$ 146.70$ 152.76$ 157.46$ $/Mbtu 22.24$ 144.42$ 143.51$ 148.85$ 152.00$ 159.44$

REPOWERED SAN JUAN UNITS. 5 & 6Net MWh-Generated 1,159,293 1,017,000 1,305,000 1,170,000 1,518,000 2,529,000 Barrels of Fuel Oil or Equivalent 1,654,843 1,469,000 1,910,000 1,731,000 2,166,000 3,459,000 MBTUx1000 10,426 8,522 11,083 10,046 12,596 20,158 kWh Per Barrel 701 692 683 676 701 731 Cost of Fuel 231,705,894$ 212,439,000$ 274,401,000$ 255,881,000 269,704,000 301,769,774 Cost of Fuel Per Barrel 140.02$ 144.61$ 143.67$ 147.82$ 124.52$ 87.24$ $/Mbtu 22.22$ 24.93$ 24.76$ 25.47$ 21.41$ 14.97$

Forecast

No. CEPR-AP-2015-0001

I 000120

APPENDIX IVANNUAL NET GENERATION, FUEL CONSUMPTION, FUEL and PURCHASED POWER COSTS

Page 2 of 2

Actual2013 2014 2015 2016 2017 2018

Forecast

Continued from previous page

TOTAL THERMAL 2014 MBTUNet MWh-Generated 13,690,731 13,472,000 13,229,000 13,437,000 13,732,000 14,125,000 Barrels of Fuel Oil 23,420,450 22,597,927 22,253,181 23,087,903 23,456,212 23,911,411 MBTUx1000 147,550 137,501 134,992 137,392 139,013 140,048 kWh Per Barrel 585 596 594 582 585 591 Fuel Cost 2,603,577,216$ 2,137,405,565$ 2,091,649,428$ 2,033,205,084$ 2,031,980,617$ 1,920,471,367$ Fuel Financing Credit Line Interest 16,611,020$ 15,000,000$ 15,000,000$ 15,000,000$ 15,000,000$ 15,000,000$ Fuel Cost incl Credit Line Interest 2,620,188,236$ 2,152,405,565$ 2,106,649,428$ 2,048,205,084$ 2,046,980,617$ 1,935,471,367$ Cost of Fuel Per Barrel 111.17$ 95.25$ 94.67$ 88.71$ 87.27$ 80.94$

$/Mbtu 17.65$ 15.54$ 15.49$ 14.80$ 14.62$ 13.71$ PURCHASED POWER-ECOELECTRICA

Net MWh-Generated 3,570,315 3,724,000 3,675,000 3,698,000 3,744,000 3,741,000

Cost 407,552,844$ 358,010,577$ 381,442,274$ 400,162,000$ 421,410,500$ 443,200,215$

$/MWH 114.15$ 96.14$ 103.79$ 108.21$ 112.56$ 118.47$ PURCHASED POWER-AES

Net MWh-Generated 3,513,485 3,362,521 3,362,522 3,372,499 3,362,522 3,362,522

Cost 327,509,327$ 344,813,719$ 351,050,291$ 359,631,000$ 367,774,199$ 374,660,460$

$/MWH 93.21$ 102.55$ 104.40$ 106.64$ 109.37$ 111.42$

PURCHASED POWERNet MWh-Generated 7,083,800 7,086,521 7,037,522 7,070,499 7,106,522 7,103,522 Cost 735,062,171$ 702,824,296$ 732,492,565$ 759,793,000$ 789,184,699$ 817,860,675$ $/MWH 103.77$ 99.18$ 104.08$ 107.46$ 111.05$ 115.13$

RENEWABLE ENERGY SOURCESTotal Renewable Sources

Net MWh-Generated 143,580 621,769 994,960 997,671 994,964 994,959 Cost 20,623,661$ 102,589,786$ 170,714,558 172,983,000 174,538,737 177,694,649 $/MWH 143.64$ 165.00$ 171.58$ 173.39$ 175.42$ 178.59$

HYDROELECTRICNet MWh-Generated 90,860 126,170 126,170 126,170 126,170 126,170

TOTAL (Including Hydro & PP)Net MWh-Generated 21,008,971 21,306,460 21,387,652 21,631,340 21,959,656 22,349,651 Cost 3,359,263,048$ 2,942,819,647$ 2,994,856,551$ 2,965,981,084$ 2,995,704,053$ 2,916,026,691$

Forecast based on ABC '13 projectionsCost of fuel includes shipping and handling charges.

No. CEPR-AP-2015-0001

I 000121

APP

EN

DIX

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No. CEPR-AP-2015-0001

I 000122

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ries R

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ted

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5,00

0 Se

ries I

I iss

ue.

No. CEPR-AP-2015-0001

I 000123

APP

EN

DIX

VI

CA

PIT

AL

EX

PEN

DIT

UR

ES

Act

ual1

Fore

cast

2013

2014

2015

2016

2017

2018

Prod

uctio

n Pl

ant

107,

810,

000

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96

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,000

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11

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1. A

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s are

net

of a

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om p

revi

ous y

ears

.

No. CEPR-AP-2015-0001

I 000124

APP

EN

DIX

VII

SOU

RC

ES

OF

FUN

DS

FOR

CA

PIT

AL

EX

PEN

DIT

UR

ES

Act

ual1

Fore

cast

2013

2014

2015

2016

2017

2018

FUN

DS

FRO

M B

ON

D IS

SUES

AN

D N

OTE

S

REV

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.

No. CEPR-AP-2015-0001

I 000125

APP

EN

DIX

VII

ISY

STE

M C

APA

BIL

ITY

MW

OF

GE

NE

RA

TIN

G C

APA

CIT

Y A

T T

HE

EN

D O

F T

HE

FIS

CA

L Y

EA

R

Act

ual

Fore

cast

2013

2014

2015

2016

2017

2018

STEA

M-E

LEC

TRIC

UN

ITS

Agu

irre

900

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U G

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1En

ergy

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wab

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roje

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re re

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sour

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non

e of

the

proj

ects

, how

ever

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t the

crit

eria

for f

irm a

nd re

liabl

e ca

paci

ty.

No. CEPR-AP-2015-0001

I 000126

APP

EN

DIX

IXD

EPR

EC

IAT

ION

EX

PEN

SE

Act

ual1

Fore

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1. A

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No. CEPR-AP-2015-0001

I 000127

APP

EN

DIX

XD

ET

AIL

S O

F C

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NT

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ber

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2015

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2017

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PRO

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I 000129

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I 000130

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No. CEPR-AP-2015-0001

I 000131


No. CEPR-AP-2015-0001

I 000132

1501-1384337

F I N A N C I A L S T A T E M E N T S , R E Q U I R E D S U P P L E M E N T A R Y I N F O R M A T I O N A N D S U P P L E M E N T A L S C H E D U L E S Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico) Years Ended June 30, 2014 and 2013 With Report of Independent Auditors

No. CEPR-AP-2015-0001

I 000133

1501-1384337

Puerto Rico Electric Power Authority (A Component Unit of the Commonwealth of Puerto Rico)

Financial Statements, Required Supplementary Information and Supplemental Schedules

Years Ended June 30, 2014 and 2013

Contents

Financial Section Report of Independent Auditors................................................................................................... 1 Management’s Discussion and Analysis ..................................................................................... 4 Audited Financial Statements Statements of Net Position ........................................................................................................... 27 Statements of Revenues, Expenses and Changes in Net Position ............................................... 29 Statements of Cash Flows ............................................................................................................ 30 Notes to Audited Financial Statements ........................................................................................ 32 Required Supplementary Information Schedule I – Supplementary Schedule of Funding Progress .......................................................128 Report on Internal Control Report of Independent Auditors on Internal Control Over Financial Reporting and on Compliance and Other Matters Based on an Audit of Financial Statements Performed in Accordance with Government Auditing Standards .............................................129 Supplemental Schedules Notes to Schedules II-VI – Information Required by the 1974 Agreement ................................131 Schedule II – Supplemental Schedule of Sources and Disposition of Net Revenues under the Provisions of the 1974 Agreement ....................................................132 Schedule III – Supplemental Schedule of Sources and Disposition of Net Revenues under the Provisions of the 1974 Agreement ....................................................133 Schedule IV – Supplemental Schedule of Funds under the Provisions of the 1974 Agreement..............................................................................................................134 Schedule V – Supplemental Schedule of Changes in Cash and Investments by Funds – June 30, 2014 .....................................................................................135 Schedule V – Supplemental Schedule of Changes in Cash and Investments by Funds – June 30, 2013 .....................................................................................136 Schedule VI – Supplemental Schedule of Changes in Long-Term Debt and Current Portion of Long-Term Debt .........................................................................137

No. CEPR-AP-2015-0001

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1501-1384337

Financial Section

No. CEPR-AP-2015-0001

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1501-1384337 1

A member firm of Ernst & Young Global Limited

Report of Independent Auditors To the Governing Board of the Puerto Rico Electric Power Authority Report on the Financial Statements We have audited the accompanying financial statements of Puerto Rico Electric Power Authority (the “Authority” or “PREPA”), a component unit of the Commonwealth of Puerto Rico as of and for the years ended June 30, 2014 and 2013, and the related notes to the financial statements, which collectively comprise the basic financial statements listed in the table of contents. Management’s Responsibility for the Financial Statements Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error. Auditor’s Responsibility Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of PREPA Holdings LLC (a blended component unit), which financial statements reflect total assets constituting approximately .64% and .46% of total assets as of June 30, 2014 and 2013, and revenues constituting .65% of total revenues for the years then ended. Those financial statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for PREPA Holdings, is based solely on the reports of the other auditors. We conducted our audits in accordance with auditing standards generally accepted in the United States, and the standards applicable to financial audits contained in Government Auditing Standards, issued by the Comptroller General of the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

Ernst & Young LLP Plaza 273, 10th Floor 273 Ponce de León Avenue San Juan, PR 00917-1951

Tel: +1 787 759 8212 Fax: +1 787 753 0808 ey.com

No. CEPR-AP-2015-0001

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1501-1384337 2


We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion. Opinion In our opinion, based on our audits and the reports of the other auditors, the financial statements referred to above present fairly, in all material respects, the financial position of the Puerto Rico Electric Power Authority as of June 30, 2014 and 2013, and the changes in its financial position and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles. The Authority’s Ability to Continue as a Going Concern The accompanying financial statements have been prepared assuming that the Authority will continue as a going concern. As discussed in Note 19 to the financial statements, the Authority does not have sufficient funds available to fully repay its various obligations as they come due and has entered a process to restructure its long-term debt. The financial difficulties experienced by the Authority, including the uncertainty as to its ability to fully satisfy its obligations, raises substantial doubt about its ability to continue as a going concern. Management’s plans in regard to these matters are also described in Notes 19 and 20. The financial statements do not include any adjustments that might result from the outcome of this uncertainty. Our opinion is not modified with respect to this matter. Adoption of GASB Statement No. 65, Items Previously Reported as Assets and Liabilities As discussed in Notes 2 and 18 to the financial statements, the Authority changed its method for accounting for bond issue costs and deferred losses related to bond refunding as a result of the adoption of GASB Statement No. 65, Items Previously Reported as Assets and Liabilities, effective for periods beginning after July 1, 2012. Our opinion is not modified with respect to this matter. Required Supplementary Information U.S. generally accepted accounting principles require that management’s discussion and the supplementary schedule of funding progress on pages 4 through 26 and 128, respectively, be presented to supplement the basic financial statements. Such information, although not a part of the basic financial statements, is required by the Governmental Accounting Standards Board which considers it to be an essential part of financial reporting for placing the basic financial statements in an appropriate operational, economic or historical context. We have applied certain limited procedures to the required supplementary information in accordance with auditing standards generally accepted in the United States, which consisted of inquiries of management about the methods of preparing the information and comparing the information for consistency with management’s responses to our inquiries, the basic financial statements, and other knowledge we obtained during our audit of the basic financial statements. We do not express an opinion or provide any assurance on the information because the limited procedures do not provide us with sufficient evidence to express an opinion or provide any assurance.

No. CEPR-AP-2015-0001

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Supplementary Information Our audit was conducted for the purpose of forming an opinion on the financial statements that collectively comprise the Puerto Rico Electric Power Authority’s basic financial statements. The supplemental schedules listed in the table of contents are presented for purposes of additional analysis and are not a required part of the financial statements. Such information is the responsibility of management and was derived from and relates directly to the underlying accounting and other records used to prepare the basic financial statements. The information has been subjected to the auditing procedures applied in the audit of the basic financial statements and certain additional procedures, including comparing and reconciling such information directly to the underlying accounting and other records used to prepare the basic financial statements or to the basic financial statements themselves, and other additional procedures in accordance with auditing standards generally accepted in the United States. In our opinion, the information is fairly stated in all material respects in relation to the basic financial statements as a whole. Other Reporting Required by Government Auditing Standards In accordance with Government Auditing Standards, we have also issued our report, dated January 28, 2016, on our consideration of the Authority’s internal control over financial reporting and on our tests of its compliance with certain provisions of laws, regulations, contracts, and grant agreements and other matters. The purpose of that report is to describe the scope of our testing of internal control over financial reporting and compliance and the results of that testing, and not to provide an opinion on the internal control over financial reporting or on compliance. That report is an integral part of an audit performed in accordance with Government Auditing Standards and should be considered in assessing the results of our audits.

EY January 28, 2016 Stamp No. E201502 affixed to original of this report.

No. CEPR-AP-2015-0001

I 000138


Management´s Discussion and Analysis

Year Ended June 30, 2014

1501-1384337 4

This section of the financial report of the Puerto Rico Electric Power Authority (the Authority) presents the analysis of the Authority’s financial performance during the fiscal years ended June 30, 2014, 2013 and 2012. As management of the Authority, we offer readers of the financial statements this narrative overview and analysis of the financial activities. We recommend readers to consider the information herein presented in conjunction with the financial statements that follow this section. Financial Highlights Operating income for fiscal year ended June 30, 2014 was $223.0 million representing a

decrease of 37.0 percent from the fiscal year ended June 30, 2013. For the fiscal year ended June 30, 2013 operating income was $354.0 million representing an increase of 37.7 percent from the fiscal year ended June 30, 2012. For the fiscal year ended June 30, 2012 operating income was $257.0 million representing a decrease of 21.4 percent from the fiscal year ended June 30, 2011.

Operating expenses decreased by $243.1 million or 5.4 percent for the fiscal year ended

June 30, 2014; decreased by $300.5 million or 6.3 percent for the fiscal year ended June 30, 2013, and increased by $693.4 million or 16.9 percent for the fiscal year ended June 30, 2012.

The Authority’s Net Utility Plant for the fiscal year ended June 30, 2014 increased by

$8.9 million or 0.1 percent. For the fiscal year ended June 30, 2013 net utility plant increased by $39.4 million or 0.6 percent. For the fiscal year ended June 30, 2012 the net utility plant decreased by $13.4 million or 0.2 percent.

Total assets and deferred outflows increased by $285.4 million, decreased by $108.0

million and increased by $323.0 million, or 2.8 percent increase, 1.0 percent decrease and 3.3 percent increase, respectively, for the fiscal years ended June 30, 2014, 2013 and 2012.

For the fiscal year ended June 30, 2014, as compared to the fiscal year ended June 30,

2013 and fiscal year ended June 30, 2012, accounts receivable net increased by 7.2 percent from $1,511.9 million to $1,620.6 million, increased by 10.8 percent from $1,364.6 million to $1,511.9 million, and increased by 6.8 percent from $1,277.9 million to $1,364.6 million, respectively. The increases in fiscal year 2014 and 2013 were mainly due to government sector accounts.

No. CEPR-AP-2015-0001

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Management´s Discussion and Analysis (continued)

1501-1384337 5

Financial Highlights (continued) Accounts receivable from the governmental sector increased 30.1 percent from $617.6

million on June 30, 2013 to $803.7 million on June 30, 2014, and increased 43.9 percent from $429.3 million on June 30, 2012 to $617.6 million on June 30, 2013, and decreased 75 percent from $464.1 million on June 30, 2011 to $429.3 million on June 30, 2012.

The Authority’s net position decreased by $419.9 million (49.6 percent) and $272.1

million (47.3 percent) and $344.7 million (149.6 percent) as a result of operations during fiscal years ended June 30, 2014, 2013 and 2012, respectively. The Authority has been in a net deficit position since June 30, 2011.

Ratios of fuel and purchased power adjustment revenues to total operating revenues were

78.9 percent, 76.5 percent and 78.3 percent for years ended June 30, 2014, 2013 and 2012, respectively.

Ratios of fuel oil and purchased power expense to total operating expense (excluding depreciation expense) were 80.3 percent, 81.1 percent and 82.0 percent for fiscal years ended June 30, 2014, 2013 and 2012, respectively.

The decrease in the fuel adjustment revenues and fuel expense for fiscal year 2014 as

compared to 2013 of $228.7 million and $258.6 million, respectively, was mainly due to a decrease in the average fuel oil price per barrel of $4.46 (4.2%) and a decrease of 1.4 million barrels of fuel consumption. The decrease in the fuel adjustment revenues and fuel expense for fiscal year 2013 as compared to 2012 of $323.1 million and $298.2 million, respectively, was mainly due to a decrease in the average fuel oil price per barrel of $7.22 (6.1%). The increase in the fuel adjustment revenues and fuel expense for fiscal year 2012 as compared to 2011 of $606.2 million and $610.5 million, respectively, was mainly due to an increase in the average fuel oil price per barrel of $22.48 (23.4%).

No. CEPR-AP-2015-0001

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1501-1384337 6

Financial Highlights (continued) The increase in the purchased power adjustment revenue and expense of $58.7 million

and $51.9 million, respectively, was due to an increase of price per kWh of purchased power by 1 cent (or 9.1%) for fiscal year 2014 when compared to fiscal year 2013. The increase in the purchased power adjustment revenue and expense of $78.8 million and $71.5 million, respectively, was due to an increase of 593,183 MWh (or 8.9 percent) in amount of purchase power for fiscal year 2013 when compared to fiscal year 2012. The increase in the purchased power adjustment revenue and expense of $26.3 million and $23.3 million, respectively, was due to an increase in the average cost per kWh of (10.6%) purchase power from 9 cents for fiscal 2011 to 10 cents for fiscal 2012.

Financial Condition and Liquidity The Authority does not currently have sufficient funds available to fully repay its various obligations as they come due, and is working on extending the due date of the obligations and obtaining other concessions from its creditors, including pursuant to an exchange offer that would reduce the principal amount of some of its debts, obtaining more favorable covenants and other terms under its Trust Agreement via a consent solicitation, and obtaining new financing to provide relief and/or funds to repay the existing amounts of principal and interest or bring the outstanding balances current at the various due dates as well as to continue to operate and to finance capital improvement projects. The Commonwealth and its instrumentalities are also experiencing significant financial difficulties and may be unable to continue to repay amounts due to the Authority or to extend, refinance or otherwise provide the necessary liquidity to the Authority as and when needed. The Authority has receivables of over $803.7 million payable by the Commonwealth and related entities and is subject to significant uncertainty with regard to its ability to collect on such receivables. As a consequence, the Authority may not be able to avoid future defaults on its obligations. Management has plans to address the Authority’s liquidity situation and continue providing services and believes the Authority will be able to repay or refinance its obligations, as described in Note 19 and Note 20. However, there can be no assurance that the affiliated or unaffiliated creditors will be able and willing to refinance or modify the terms of the Authority’s obligations, that management’s current plans to repay or refinance the obligations or extend their terms will be achieved or that certain services will not have to be terminated, curtailed or modified.

No. CEPR-AP-2015-0001

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1501-1384337 7

Plans to Address the Authority’s Challenges The Authority faces a number of business challenges that have been exacerbated by the Commonwealth’s economic recession and financial difficulties. Its principal challenges, some of which are interrelated, include: (i) addressing its relatively high cost of the type of fuel it uses compared to other energy sources and aging generation fleet; (ii) compliance with applicable environmental regulations; (iii) declining electric energy sales; (iv) addressing government accounts receivables; (v) improving liquidity; and (vi) taking steps to ensure the Authority’s long-term fiscal sustainability, including its ability to satisfy its financial obligations. In July 2014, the Authority began discussions with its financial stakeholders in an effort to stabilize the Authority’s liquidity situation and address its financial position. The Authority subsequently engaged legal, financial and operational advisors, including a chief restructuring officer, to assist it in those efforts. In the period since July 2014, the Authority has entered into various agreements with certain of its financial stakeholders as discussed below. Forbearance Agreements On August 14, 2014, the Authority entered into forbearance agreements (the “Forbearance Agreements”) with certain insurers of the Authority’s Power Revenue Bonds (“Bonds”) and beneficial owners of the Bonds controlling, collectively, more than 60% of the principal amount of the Bonds then outstanding (comprising the Ad Hoc Group (as defined below)) and the monoline insurers providing credit support for certain of the Authority’s Bonds not owned by the Ad Hoc Group (the “monoline bond insurers” and together with the Ad Hoc Group, the “Forbearing Bondholders”), banks that provide revolving lines of credit used to pay for purchased power, fuel and other expenses (together, with their transferees, as applicable, the “Forbearing Lenders”) and Government Development Bank for Puerto Rico (“GDB,” and together with the Forbearing Bondholders and the Forbearing Lenders, the “Forbearing Creditors”). Under the Forbearance Agreements, the Forbearing Creditors agreed to forbear from the exercise of certain rights and remedies under their applicable debt instruments. The Forbearance Agreements were originally scheduled to terminate on March 31, 2015, but were extended by certain of the Forbearing Creditors on numerous occasions, most recently through November 5, 2015. The Forbearance Agreements expired on November 5, 2015, but the agreement of the Forbearing Creditors to refrain from exercising of certain rights and remedies was extended under the RSA (as defined below).

No. CEPR-AP-2015-0001

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1501-1384337 8

Forbearance Agreements (continued) Under the Forbearance Agreements with the Forbearing Bondholders, the Authority’s obligations to pay any and all principal and interest payments on the Bonds were required to continue; however, the Forbearing Bondholders agreed that the Authority was not required to make transfers to the Revenue Fund or the Sinking Fund pursuant to sections 506 and 507 of the Trust Agreement while that agreement remained in effect. The Authority has not made monthly cash deposits into the Sinking Fund since July 2014. This agreement was extended and continued under the RSA. Since entry into the Forbearance Agreements, the Authority has paid all principal and interest payments due on the Bonds. Under the Forbearance Agreements with the Forbearing Lenders, the Authority was permitted until November 5, 2015 to delay certain payments that became due to the Forbearing Lenders in July and August 2014. Under the RSA, the Authority was permitted to delay such payments further until June 30, 2016; however, the Authority has continued to pay interest to the Forbearing Lenders while those agreements remain in effect. In connection with the Forbearance Agreements and in order to address the Authority’s liquidity challenges, on August 27, 2014, the Trust Agreement was amended to permit the Authority to use approximately $280 million held in its construction fund for payment of current expenses in addition to capital improvements. The amendment also provided for an increase in the thresholds required for the exercise of remedies under the Trust Agreement. Those amendments expired on March 31, 2015. In connection with an extension of the Forbearance Agreements executed on June 30, 2015 and the Authority’s agreement to pay approximately $415.8 million of principal and interest due on July 1, 2015 on the Bonds, the Trust Agreement was again amended to increase the thresholds for the exercise of remedies under the Trust Agreement and to allow for the issuance of $130.7 million in Bonds to the monoline bond insurers (the “2015A Bonds”) that matured on January 1, 2016. Those amendments expired on September 1, 2015. On December 15, 2015, the Authority defeased the outstanding principal and interest requirements on the 2015A Bonds, and the 2015A Bonds were paid in full on the first business day of January 2016 (January 4, 2016) in accordance with their terms.

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1501-1384337 9

Bond Payments On July 1, 2014, the Authority paid $413.7 million to satisfy the principal and interest payments on its Bonds due on that date. This payment was funded with moneys in the 1974 Sinking Fund, including reserves. On January 2, 2015, the Authority paid $204.4 million to satisfy the interest payments on its Bonds due on that date. This payment was funded with moneys in the 1974 Sinking Fund, including reserves. On July 1, 2015, the Authority paid $415.8 million, to satisfy the principal and interest payments on its Bonds due on that date. This payment was funded with moneys in the 1974 Sinking Fund, including reserves, and a $153.0 million transfer from the General Fund. On July 31, 2015, pursuant to the Trust Agreement and as agreed with Forbearing Creditors, the Authority issued Power Revenue Bonds Series 2015A, in a par amount of $130.7 million (the Series 2015 A Bonds), to replenish the Authority’s working capital. The Series 2015 A Bonds were bought in their entirety by the monoline bond insurers, and the maturity date of this issue was January 1, 2016. The Authority paid $6.1 million, $5.9 million, $5.8 million, $5.8 million and $6.4 million for the first five months that ended on November 1, 2015 to redeem a portion of the Series 2015 A Bonds. On December 15, 2015, the Authority deposited $103.5 million in escrow to satisfy the remaining principal and interest requirements on the Series 2015 A Bonds, which deposit was funded by $100.9 million from Self-insurance Fund and $2.6 million from General Fund. These amounts were paid to holders of the 2015 A Bonds on January 4, 2016 in accordance with their terms. On January 4, 2016, the Authority paid $198.0 million, to satisfy the interest payments on its other Bonds due on that date. This payment was funded with moneys in the 1974 Sinking Fund, and a $171.0 million transfer from the General Fund.

No. CEPR-AP-2015-0001

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1501-1384337 10

Agreements with Certain Forbearing Creditors Agreement in Principle with Ad Hoc Group On September 2, 2015, PREPA announced an agreement in principle regarding the economic terms of a restructuring with an ad hoc group of bondholders that were Forbearing Bondholders (the “Ad Hoc Group Agreement”) and which group held, at that time, approximately 35% in principal amount of the outstanding Bonds (the “Ad Hoc Group”). Under that agreement, the Ad Hoc Group will have the option to receive securitization bonds that will pay cash interest at a per annum rate of 4.0% - 4.75% (depending on the rating obtained) (“Option A Bonds”) or convertible capital appreciation securitization bonds that will accrete interest at a per annum rate of 4.5% - 5.5% for the first five years and pay current interest in cash thereafter at those per annum rates (“Option B Bonds”). Option A Bonds will not pay principal for the first five years (interest only), and Option B Bonds will accrete interest but not receive any cash interest or principal during the first five years. All of PREPA’s uninsured bondholders will have an opportunity to participate in the exchange. Both Option A and Option B Bonds would be issued at an exchange ratio of 85% (i.e., with a 15% reduction in principal amount of current holdings of outstanding Bonds). Under the extension to the Forbearance Agreement with the Ad Hoc Group executed on September 1, 2015, PREPA agreed to work collaboratively and in good faith with the Ad Hoc Group to reach agreement on a recovery plan incorporating these terms. The Ad Hoc Group Agreement was included in the RSA. Agreement in Principle with Forbearing Lenders of Notes Payables On September 22, 2015, PREPA announced an agreement in principle regarding economic terms with its Forbearing Lenders (the “Fuel Line Agreement”). Under that Agreement, the Forbearing Lenders, which hold all of the approximately $696 million of matured debt (Notes Payable), will have the option to either (1) convert their existing credit agreements into term loans, with a fixed interest rate of 5.75% per annum, to be repaid over six years in accordance with an agreed amortization schedule or (2) exchange all or part of principal due under their existing credit agreements for new securitization bonds to be issued on the same terms as the Ad Hoc Group.

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Agreement in Principle with Forbearing Lenders of Notes Payables (continued) Under the extensions to the Forbearance Agreements with the Forbearing Lenders executed on September 22, 2015, PREPA agreed to work collaboratively and in good faith with the Forbearing Lenders to reach agreement on a recovery plan incorporating these terms. The Fuel Line Agreement was included in the RSA. Terms and Status of Restructuring Support Agreement On November 5, 2015, PREPA announced its entry into a restructuring support agreement (the “Initial RSA”) with both the Ad Hoc Group (representing at that time approximately 40% in principal amount of the outstanding Bonds) and the Forbearing Lenders setting forth the agreed-upon terms of PREPA’s recovery plan which terms were amended to extend the milestone dates therein on numerous occasions. The economic terms set forth in the Initial RSA are consistent with the Ad Hoc Group Agreement and the Fuel Line Agreement. In addition, pursuant to the Initial RSA, GDB would receive substantially the same treatment on $35.9 million owed by PREPA to it as the Forbearing Lenders will receive. The monoline bond insurers were not party to the Initial RSA. On December 23, 2015, certain of the monoline bond insurers along with the Ad Hoc Group (representing together at that time approximately 66% in principal amount of the outstanding Bonds), the Forbearing Lenders and GDB, all signed an amended and restated restructuring support agreement (the “A&R RSA” and together with the Initial RSA and the Revised RSA (as defined below), the “RSA” and the Ad Hoc Group, the monoline bond insurers, the Forbearing Lenders and the GDB, together the “Supporting Creditors”) with terms and conditions substantially similar to those in the Initial RSA outlined above (including the agreement to exchange Bonds held by the Ad Hoc Group for new securitization bonds at an 85% exchange ratio with a 5-year principal holiday and fixed interest rates). Significant uncertainty remains as to the potential consummation of the transactions set forth in the RSA, which is subject to a number of material conditions, including without limitation, (1) obtaining legislative authority for the assessment of a special, transition charge on the Authority’s customers and other terms to facilitate the issuance of the securitization bonds as well as organizational reforms at the Authority; (2) receipt of an investment grade rating on the new securitization bonds from any credit rating agency that will rate the securitization bonds; (3) obtaining an agreed upon level of participation from holders of the Authority’s uninsured Bonds in the exchange offer described above such that no more than $700 million in principal amount of uninsured Bonds shall remain outstanding following the exchange offer, or such higher

No. CEPR-AP-2015-0001

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1501-1384337 12

Terms and Status of Restructuring Support Agreement (continued) amount determined by the Authority after consulting with the Authority’s advisors; (4) amending the Trust Agreement to increase to at least a majority the percentage of Bondholders required to direct the Trustee to take certain actions under the Trust Agreement, including upon a default by the Authority and continue the waiver of the Authority’s obligation to make monthly Sinking Fund deposits, among other things; and (5) obtaining approval and reaching agreement with all Supporting Creditors regarding the definitive documentation of the various restructuring transactions. The RSA contains a number of termination or withdrawal events in favor of the Supporting Creditors, including if there is a material amendment to certain terms of the recovery plan, if the Authority commences any proceeding under bankruptcy or insolvency law or the Recovery Act (except to implement the recovery plan in accordance with the RSA), as well as the failure to achieve certain milestones by specific dates, including the enactment of legislation containing substantive provisions to implement the recovery plan contemplated by the RSA, among other events, which would result in termination of the RSA or withdrawal from the RSA by individual Supporting Creditors. On January 23, 2016, the RSA terminated when the PREPA Revitalization Act was not enacted into law and the Ad Hoc Group did not agree to the Authority’s request to extend the related RSA milestone. PREPA continued to engage in discussions with the Ad Hoc Group and the other Supporting Creditors regarding a potential extension of the RSA and the transactions contemplated therein and described below. Under the RSA, certain of the Supporting Creditors had agreed to purchase approximately $115 million in Bonds to refund a portion of the interest payments on the Bonds made on January 4, 2016, subject to certain conditions including enactment of the PREPA Revitalization Act in acceptable form. This agreement was formalized in a Bond Purchase Agreement (the “Initial Bond Purchase Agreement”) executed on December 29, 2015. The Initial Bond Purchase Agreement also terminated on January 23, 2016 when the A&R RSA terminated. PREPA continued to engage in discussions with the Supporting Creditors regarding the transactions contemplated by the Initial Bond Purchase Agreement. On January 23, 2016, certain of the Forbearing Lenders agreed to enter into a short form forbearance agreement by which they agreed to forbear from exercising enforcement rights against the Authority under the applicable Fuel Line Agreements through February 12, 2016.

No. CEPR-AP-2015-0001

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Terms and Status of Restructuring Support Agreement (continued) On January 27, 2016, PREPA and the Supporting Creditors executed a revised RSA (“Revised RSA”) and a revised Bond Purchase Agreement (the “Revised Bond Purchase Agreement”). The Revised RSA is substantially the same as the A&R RSA, with minor adjustments to address delays in legislative consideration of the PREPA Revitalization Act. The milestone date for legislative approval of the PREPA Revitalization Act was extended to February 16, 2016, and other related milestones were also adjusted accordingly. The Revised Bond Purchase Agreement is substantially the same as the Initial Bond Purchase Agreement, except for certain changes to the timing, conditions and total amount of the contemplated Bond purchase. Under the Revised Bond Purchase Agreement, 50% of the total purchased Bonds will be purchased upon a determination by the applicable Supporting Creditors that the PREPA Revitalization Act satisfies the standards set forth in the RSA and 50% of the total purchased Bonds will be purchased upon the filing of a petition with the Energy Commission seeking approval of a securitization charge that satisfies the standards under the RSA. Under the Revised Bond Purchase Agreement, the total amount of purchased Bonds is approximately $111 million. There can be no assurance, however, that the transactions contemplated by the Revised Bond Purchase Agreement will be consummated. Under the RSA, the Ad Hoc Group has agreed to exchange 100% of its uninsured Bonds for securitization bonds at an 85% exchange ratio. The monoline bond insurers agreed to provide up to $462 million of reserve surety bonds at the time the transaction closes and forward commitments for additional surety capacity to be provided at a later time during the term of the transaction, as credit support for the securitization bonds, that would be available to be drawn upon in the event certain cash reserves and transition payments from PREPA’s customers are insufficient to pay current debt service on the securitization bonds. In return for this, (1) the SPV (defined below – see PREPA Revitalization Act) would issue $2.086 billion additional securitization bonds, which amount is subject to adjustment in accordance with the RSA, as credit support for outstanding Authority’s insured Bonds to be held in escrow for the benefit of holders of the Authority’s insured Bonds and (2) PREPA and the SPV would attempt to refinance certain outstanding Bonds insured by such insurers with securitization bonds during a 6-month period starting 3 years after the date the above exchange closes. The surety bonds provided by the monoline bond insurers would be replaced by SPV cash (derived from transition payments) beginning in FY2019 over a period of nine years, subject to earlier replacement in accordance with certain conditions set forth in the RSA. Among the primary purposes for this transaction are to refinance at a lower cost a portion of the Authority’s outstanding Bonds and to improve the Authority’s liquidity position during the first five years after issuance. There can be no assurance, however, that the transactions contemplated by the RSA will be consummated.

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Terms and Status of Restructuring Support Agreement (continued) It should be noted that Bondholders holding beneficially approximately $2.73 billion in principal amount of outstanding Bonds representing approximately 34% in principal amount of the outstanding Bonds, have not agreed to the terms of the RSA, and without access to a statutory restructuring regime the terms of their Bonds also cannot be amended until an agreement with such Bondholders has been reached. As discussed below, the Authority is currently not in compliance with certain terms of its Trust Agreement and such Bondholders, who are not covered by the agreements described above, could direct the trustee to take certain actions, or otherwise exercise enforcement actions, against the Authority, each in accordance with the Trust Agreement, which actions could result in a default being declared. Trust Agreement Covenants As a result of the Authority’s non-compliance with certain covenants existing under the Trust Agreement, Bondholders not covered by the agreements described above could direct the trustee to take certain actions, or otherwise exercise enforcement actions, against the Authority, including declaring an event of default as a result of covenant violations, each in accordance with the terms of the Trust Agreement. Under the Trust Agreement, upon a covenant violation, no remedies may be exercised by the trustee on behalf the Bondholders until the trustee notifies the Authority of the particular violation and the Authority does not cure the violation within 30 days after receipt of such notice. The Authority has not received any such notice from the trustee. PREPA Revitalization Act On November 4, 2015, the Governor submitted the PREPA Revitalization Act to the Legislative Assembly to facilitate the Authority’s ongoing transformation and recovery plan. The PREPA Revitalization Act sets forth a framework for PREPA to execute on the agreements with creditors reached to date. Among other things, the PREPA Revitalization Act would (1) enhance PREPA’s governance processes; (2) adjust PREPA’s practices for hiring and managing management personnel; (3) change PREPA’s processes for collecting outstanding bills from public and private entities; (4) improve the transparency of PREPA’s billing practices; (5) implement a competitive bidding process for soliciting third party investment in PREPA’s infrastructure; (6) authorize the refinancing of outstanding Bonds through a securitization that would reduce PREPA’s indebtedness and cost of borrowing; and (7) set forth an expedited process for the Energy Commission to approve or reject PREPA’s proposal for a new rate structure that is consistent

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PREPA Revitalization Act (continued) with its recovery plan. The Legislative Assembly is currently considering various amendments to the PREPA Revitalization Act. There can be no assurance, however, that the PREPA Revitalization Act will be enacted into law or that it will contain provisions that are acceptable to the Authority’s various creditors. As described above, if enacted the PREPA Revitalization Act would provide a legal framework to reduce the Authority’s cost of borrowing and its passage in the form contemplated by the RSA is one of the conditions to the execution of the restructuring transactions contemplated by the RSA and described above. The legislation would authorize creation of a bankruptcy-remote, special purpose public corporation (the “SPV”), entirely separate from the Authority, with the power to issue securitization bonds for limited purposes related to the Authority’s recovery plan, and to impose non-by passable, transition charges on the Authority’s customers. The assessment and periodic automatic adjustments of the transition changes on the Authority’s customers would serve as the source of repayment for the securitization bonds. U.S. Congress Consideration of Bankruptcy Amendment Commonwealth officials have been urging the U.S. Congress to amend the federal bankruptcy code to eliminate an exclusion that currently bars any municipality or other instrumentality of the Puerto Rico government from restructuring under the federal bankruptcy code. U.S. legislative discussions on this are expected to continue in January 2016 and beyond. Operational Improvements The Authority has also made significant investments in evaluating and implementing various operational improvements and strategies in an effort to address its ongoing financial challenges. In an effort to diversify its fuel supply, the Authority has entered into agreements necessary for the construction of an offshore gas port terminal to receive natural gas off the southern part of the island for use in the Aguirre Power Complex. The permitting process for the project is ongoing, and construction has not yet begun. Once operational, the gas port will provide a method to utilize liquefied natural gas at Aguirre. The Authority reduced its number of employees through a combination of attrition from voluntary retirement and the elimination of temporary and vacant positions. In addition, the Authority continues to enforce the new employee hiring freeze implemented in January 2009.

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Operational Improvements (continued) On September 4, 2014, the Authority appointed a chief restructuring officer whose mandate includes providing overall leadership to the Authority’s restructuring process, developing a business plan, implementing revenue improvement and cost reduction plans, overseeing and implementing cash and liquidity management activities, improving the Authority’s ability to analyze, track and collect accounts receivable, improving the Authority’s capital expenditure plan, and developing plans to improve the Authority’s generation, transmission, distribution and other operations. Overview of Financial Report Management’s Discussion and Analysis (MD&A) of operating results serves as an introduction to the basic financial statements and supplementary information. Summary financial statement data, key financial and operational indicators used in the Authority’s strategic plan, projected capital improvement program, operational budget and other management tools were used for this analysis. Required Financial Statements The financial statements report the financial position and operations of Puerto Rico Electric Power Authority and its blended component units, Puerto Rico Irrigation Systems and PREPA Holdings LLC as of and for the year ended June 30, 2014, which include a Statement of Net Position, Statement of Revenues, Expenses and Changes in Net Position, Statement of Cash Flows and the notes to financial statements. PREPA Networks, LLC issued a separate financial report that includes audited financial statements. That report may be obtained by writing to PREPA Networks, Corp. City View Plaza Suite 803, Guaynabo, Puerto Rico 00968. The Statement of Net Position presents the financial position of the Authority and provides information about the nature and amount of resources and obligations at year-end.

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Required Financial Statements (continued) The Statement of Revenues, Expenses and Changes in Net Position present the results of the business activities over the course of the fiscal year and information as to how the net assets changed during the fiscal year. The Statement of Cash Flows shows changes in cash and cash equivalents, resulting from operating, non-capital and capital financing, and investing activities, which include cash receipts and cash disbursement information, without consideration of the depreciation of capital assets. The notes to the financial statements provide information required and necessary to the understanding of material information of the Authority’s financial statements. These notes present information about the Authority’s significant accounting policies, significant account balances and activities, risk management, obligations, commitments and contingencies, and subsequent events. The financial statements were prepared by the Authority’s management from detailed accounting books and records. Financial Analysis The Authority’s net position decreased by $419.8 million, $272.1 million and $344.7 million for the fiscal years ended June 30, 2014, 2013 and 2012, respectively. Our analysis below focuses on the Authority’s net position and changes in net position during the year.

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Financial Analysis (continued)

2014 2013 2012(as restated) (as restated)

Current, non-current and other assets 3,504,903$ $ 3,177,881 3,283,933$ Deferred outflows 126,812 177,283 218,648 Capital assets 6,847,456 6,838,558 6,799,176 Total assets and deferred outflows 10,479,171$ $ 10,193,722 10,301,757$

Long-term debt outstanding 9,413,195$ $ 8,987,971 9,042,843$ Other liabilities 2,332,981 2,052,946 1,834,036 Total liabilities 11,746,176$ $ 11,040,917 10,876,879$

Net position (deficit):Net investments in utility plant (253,448)$ $ (32,432) (21,314)$ Restricted – – 18,299 Unrestricted (1,013,557) (814,763) (572,107)

Total net position (deficit) (1,267,005)$ $ (847,195) (575,122)$

Authority’s Net Position(In thousands )

Year Ended June 30

A portion of the Authority’s net position reflects its net investment in utility plant, which decreased from $23.4 million to $3.6 million as of June 30, 2013 and 2014, respectively.

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Financial Analysis (continued) Changes in the Authority’s net position can be determined by reviewing the following condensed Statements of Revenues, Expenses and Changes in Net Position.

2014 2013 2012(as restated) (as restated)

Operating revenues 4,468,922$ 4,843,016$ 5,046,494$ Other income 21,157 26,329 24,344

Total revenues 4,490,079 4,869,345 5,070,838 Operating expenses 4,245,892 4,488,979 4,789,469

Interest expense, net 431,180 386,867 380,424 Total expenses 4,677,072 4,875,846 5,169,893

Loss before contribution in lieu of taxes (186,993) (6,501) (99,055) and other and contributed capitalContribution in lieu of taxes and other (277,776) (297,551) (283,111) Loss before contributed capital (464,769) (304,052) (382,166)

Contributed capital 44,959 31,979 37,494 Change in net position (419,810) (272,073) (344,672)

Net position at beginning of year (847,195) (575,122) (230,450) Net position at end of year (1,267,005)$ (847,195)$ (575,122)$

Year Ended June 30

Authority’s Changes in Net Position(In thousands)

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Financial Analysis (continued) For fiscal year ended June 30, 2014, as compared to June 30, 2013, net position decreased by $419.8 million, a $147.7 million decrease when compared to the decrease for fiscal year ended June 30, 2013. The reduction in net position was mainly due to a combination of factors that included, among others, a decrease in operating revenues of $374.1 million, mainly due to a decrease in energy sales per kWh from 18.2 million in 2013 to 17.6 million in 2014 (3.3%), representing a $16.8 million basic revenue decrease, and an increase in the reserve for uncollectible accounts of $191.5 million during the fiscal year 2014, due to a change in the assumptions related to collections, as a result of the recent economic situation facing Puerto Rico, net of a decrease in operating expenses of $243.1 million, mainly as a result of a decrease in fuel prices. For fiscal year ended June 30, 2013, as compared to June 30, 2012, net position decreased by $272.1 million. The reduction in net position was mainly due to a combination of factors that included, among others, a decrease in operating revenues of $203.5 million and operating expenses of $300.5 million, resulting in a net decrease in operating income of $97.0 million. Decreases in fuel oil prices, a decrease in depreciation expense of $69.9 million due to the implementation of a new depreciation study, offset by increases in interest expense, and contributions in lieu of taxes contributed to the reduction in operating income. In addition, the Authority’s net revenues were reduced by $53.2 million in fuel adjustment revenues not billed to customers, which reduction was financed by the revenue stabilization fund. For fiscal year ended June 30, 2012, as compared to June 30, 2011, net position decreased by $344.7 million. The reduction in net position was mainly due to a combination of factors that included, among others, an increase in operating revenue of $623.5 million and operating expenses of $693.4 million, resulting in a net decrease in operating income of $69.9 million. Increases in fuel oil prices and an increase in depreciation expense of $63.9 million, as well as increases in interest expense, and contributions in lieu of taxes contributed to the reduction in operating income. In addition, the Authority’s net revenues were reduced by $79.4 million in fuel adjustment revenues not billed to customers, which was financed by the revenue stabilization fund and $37.2 million of costs related to the abandoned Vía Verde Project (Natural Gas Pipeline Project), which were registered as operating expenses.

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Capital Assets and Debt Administration Net Investment in Utility Plant Net investment in utility plant in fiscal years as of June 30, 2014, 2013 and 2012, amounted to approximately $6,847 million, $6,839 million, and $6,799 million (net of accumulated depreciation), respectively. This net investment in utility plant includes land, generation, transmission and distribution systems, buildings, fixed equipment, furniture, fixtures and equipment. The Authority’s net investment in utility plant increased by 0.1 percent, increased by 0.6 percent and decreased by 0.2 percent for years ended June 30, 2014, 2013 and 2012, respectively. A substantial portion of the capital expenditures for production plant in fiscal years ended June 30, 2014, 2013 and 2012, was spent on the rehabilitation and life extension of generating plants in order to maintain availability, reliability and efficiency. Major capital assets projects undertaken by Authority during fiscal years 2014 and 2013 included the following: Conversion of units 5 and 6 at the Costa Sur Power Plant to dual fuel, representing

approximately 820 MW of generating capacity. Improvements to boiler’s internal components to burn 100% of natural gas have been completed for unit 6 as well as for unit 5. These capital improvement projects were completed during summer 2013.

Regular scheduled comprehensive maintenance of its steam unit fleet, combined-cycle units

and combustion turbine peaking units. Boilers and turbine-generators are included in this comprehensive maintenance program.

Projects for the supply of water for industrial processes and generation. The new

demineralized water plant at Costa Sur Power Plant, is an example of a key capital improvements focused on reliability and natural resources protection.

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Capital Assets and Debt Administration (continued) Water infrastructure projects in order to comply with the current and future NPDES

Discharge permits at San Juan Power Plant and Aguirre Power Complex. The integration of advanced water treatment technologies for reusing process wastewater will benefit the surrounding environment and reduce the process water - with the exception of the non-contact cooling water discharge – will be achieved with this project. In addition, the Aguirre Water Supply Project will substitute the underground water extraction from Southern Aquifer – which is currently experiencing salt infiltration – to superficial water supply from the Patillas Irrigation Channel and will supply a fresh water supply to a deteriorated black mangrove area in Jobos Bay for restoration. The expected date to complete the Aguirre Water Supply Project is July 2017. The San Juan Power Plant Project will reuse the process wastewater of two main outfalls. Phase I – reuse of the feed water heater condensations – the expected in service date is December 2015. Phase IV, which includes the integration of microfiltration and reverse Osmosis treatment technologies, is under a bid adjudication process. The San Juan Power Plant Project expected in service date is at end of 2017.

New RO (Reverse Osmosis) and EDI (Electrode ionization) System installed at South Coast

Power Plant is currently commissioned and will provide high reliability and water quality assurance to PREPA’s only natural gas burning power plant.

The Authority is constructing a 230 kV transmission line (38 mile long) between the South

Coast Steam Plant and Cambalache Gas Turbines Plant’s switchyard. The first stage of this project consists of the reconstruction and conversion to 230 kV of an existing 115 kV circuit line between the South Coast Steam Plant and Dos Bocas Hydroelectric Power Plant. The second stage of the project consists of the construction of a new 230 kV line from Dos Bocas to the Cambalache facilities. The expected service date is December 2015. The estimated cost of this project is $50 million. Once in operation, this major infrastructure project will significantly enhance the reliability and security margins of the transmission system, and permit the increase of power transfers from the South of Puerto Rico to the Northern and Western regions.

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Capital Assets and Debt Administration (continued) Reconstruction and rehabilitation of 115 and 38 kV circuit lines throughout the whole island.

It includes the reconstruction of a 42 miles of 115 kV transmission line interconnecting the Bayamon Transmission Center (TC), Cana 115 kV switchyard, Barrio Piñas 115 kV switchyard, Dos Bocas Hydroelectric Plant as well as important substations in the municipalities of Bayamon, Toa Baja, Toa Alta, Corozal, Morovis and Ciales. This project consists of seven phases. The first is the reconstruction of 3.7 miles of 115 kV transmission line with a 556.6 MCM conductor from Piñas Switchyard to the Monterrey Substation, completed in April 2014. The second is the reconstruction of 3.7 miles of 115 kV transmission line with a 556.6 MCM conductor from Monterrey Substation to the Unibon Substation, in service since October 2015. The third is the reconstruction of 4.7 miles of 115 kV transmission line with a 556.6 MCM conductor from Unibon Substation to the Morovis Substation, expected in service date is December 2017. The fourth is the reconstruction of 6.5 miles of 115 kV transmission line with a 1,119.5 MCM conductor from Bayamon TC to the Cana TC, expected in service date is February 2016. The Fifth is the reconstruction of 3 miles of 115 kV transmission line with a 1,119.5 MCM conductor from Cana TC to the Piñas Switchyard, expected in service date is October 2016. The Sixth is the reconstruction of 3.9 miles of 115 kV transmission line with a 556.6 MCM conductor from Morovis to the Ciales Substation, expected in service date is December 2017. The Seventh is the reconstruction of 17 miles of 115 kV transmission line with a 556.6 MCM conductor from Ciales Substation to the Dos Bocas Hydroelectric Plant, expected in service date is fiscal year 2024. The reconstruction and rehabilitation of four 115 kV transmission line interconnecting the Palo Seco power plant with relevant 115/38 kV transmission centers located in the metropolitan area are also included, expected in service date is the fiscal year 2022. Sub-transmission circuits interconnecting substations in the municipalities of Orocovis, Barranquitas, Maricao, Las Marías and Mayaguez, located in the central and west regions of the island, are part of this major reconstruction and rehabilitation plan.

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Capital Assets and Debt Administration (continued) Program to improve the 38 kV sub-transmission systems continues, including the

construction of underground 38 kV line in Medical Center of Puerto Rico, eliminating the tap on line 8900 and integrating a new circuit in Centro Medico Sectionalizer. This project consists of the interconnection of the 38 kV sectionalizer to the critical loads of University Hospital, Cardiovascular Center and the Medical Sciences hospitals, expected in service date is 2017. In addition, major reconstruction project of aerial 38 kV lines in the central and western part of the Island will significantly improve the reliability of the sub-transmission system. The 38 kV line required increasing the capacity to meet load on Barranquitas and provide the interconnection to Toro Negro Hydroelectric Plant, Comerío Transmission Center and the new transmission center in Barranquitas, expected in service date is the fiscal year 2016. In addition, the 38 kV 1500 and 2000 Line increase reliability by line improvement due to structural, line hardware deterioration, expected in service date is the fiscal year 2017.

New air insulated 115/38 kV transmission center in the municipality of Barranquitas, which

improves the reliability and efficiency of the System while increasing its power transfer capability and improving voltage regulation of the sub-transmission system under normal conditions and contingency situations was completed in June 2015.

Construction of two additional insulated 115/38 kV switchyards in the municipalities of San

Juan and Caguas expected to be completed in August 2016. The Buen Pastor Transmission Center will contribute to improve the reliability of the commercial and industrial loads in Río Piedras under certain contingency situations in the southern metropolitan area. The Bairoa Transmission Center will significantly improve the reliability at Caguas and nearby municipalities, by providing backup to 115/38 kV transformer contingencies located at the Caguas Transmission Center. Additional projects are planned to increase the power transfer capability from the 115 kV transmission systems to the subtransmission system by adding transformation capacity in existing switchyards such as San Juan Steam Plant, Bayamón TC and Monacillo TC.

San Juan GIS 38 kV and 115 kV switchgears expected to enter into service in fiscal year

2017. This will be one of the Authority’s major gas insulated 115/38 kV switchyards with direct interconnection through the existing air insulated 115 kV bus to approximately more than 850 MW of generating capability.

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Capital Assets and Debt Administration (continued) These projects were funded from cash reserves, excess-operating revenues (when available), grants, and debt issued for such purposes. Long-Term Debt At the end of the fiscal years 2014, 2013 and 2012, the Authority had total debt outstanding of $9,413.2 million, $8,987.9 million, and $8,935.5 million, respectively, comprised of revenue bonds and notes payable.

Authority’s Outstanding Debt (In thousands)

2014 2013 2012

Power revenue bonds, net $ 8,668,425 $ 8,218,912 $ 8,419,030

Notes payable 744,770 769,059 623,813

Current portion 9,413,195 8,987,971 9,042,843

(1,166,189) (1,175,311) (1,000,255)

Long-term debt, excluding current portion $ 8,247,006 $ 7,812,660 $ 8,042,588

During fiscal year 2014, power revenue bonds increased mainly as a result of the issuance of Series 2013A, with a principal amount of $675.1 million, net of related debt payments of principal and interest. Notes payable decreased $24.3 million mainly as a result of paying down revolving lines of credit to finance working capital. The Authority’s bond ratings were downgraded to “Caa3” by Moody’s, “CC” by S&P and “CC” by Fitch. Additional information on the Authority’s long-term debt can be found in Notes 8 and 11 to the financial statements.

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Economic Factors and Next Year’s Budgets and Rates In the last five years, Puerto Rico’s economy has shown different behavior compared with the U.S economy in terms of the annual Gross Domestic Product (GDP). As published by the U.S Department of Commerce, the real GDP adjusted for price changes increased at an annual rate of 2.5% in the fourth quarter of 2014, according to the advance estimate released by the Bureau of Economic Analysis (BEA) in January 30, 2015. In the third quarter of 2014, real GDP figures increased 2.9%. Real GDP increased 2.4% in 2014, compared with an increase of 1.5% in 2013. According to IHS Global Insight (GI), the U.S economy will grow 3.5% in the period from January to March and 3.4% between October and December 2015. Projections for the years 2014 and 2015 estimate increases of 2.7% in 2014 and 3.3% in 2015. By law, the Puerto Rico Planning Board (PRPB) is the local government agency that gathers and studies the official economic data. In Puerto Rico, the economy is measured by the Gross National Product (GNP). Puerto Rico's economy in fiscal year 2013 reached a real growth of 0.3%, compared to fiscal year 2012. The Authority adopted the 2015 fiscal year budget on October 9, 2014. The total revenues for fiscal year 2014-2015 are projected to be approximately $4,630.7 million. In addition, the Capital Improvement Program amounted to approximately $244.7 million. The 2015 consolidated budget increased by $166.5 million (3.7 percent) when compared to the consolidated budget approved for fiscal year 2013-2014, mainly due to an increase in projected fuel oil prices per barrel from $94.96 for 2013-2014 to $108.48 for 2014-2015, representing a 14.2 percent increase. Request for Information This financial report is designed to provide a general overview of the Authority’s finances. Questions concerning any of the information provided in this report or requests for additional financial information should be addressed to the Authority’s Chief Financial Officer. The executive offices of the Authority are located at 1110 Ponce de León Avenue, San Juan, Puerto Rico 00907.

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2014 2013Assets (as restated)Current assets:

Cash and cash equivalents 147,236$ 122,130$ Receivables, net 1,500,545 1,394,199 Fuel oil, at average cost 194,073 323,730 Materials and supplies, at average cost 196,887 197,786 Prepayments and other assets 463 5,082

Total current assets 2,039,204 2,042,927

Other non-current receivables, net 120,045 117,653

Restricted assets:Cash and cash equivalents held by trustee for

payment of principal and interest on bonds 328,532 369,381 Investments held by trustee 674,395 553,602 Construction fund and other special funds 325,924 83,420

Total restricted assets 1,328,851 1,006,403

Utility plant:Plant in service 12,281,158 11,937,375 Accumulated depreciation (6,422,226) (6,098,403)

5,858,932 5,838,972 Construction in progress 988,524 999,586 Total utility plant, net 6,847,456 6,838,558

Deferred expenses 16,803 10,898 Total assets 10,352,359 10,016,439

Deferred outflows of resourcesAccumulated decrease in fair value of hedging

derivatives 48,864 85,004 Deferred loss resulting from debt refunding 77,948 92,279 Total deferred outflows of resources 126,812 177,283 Total assets and deferred outflows 10,479,171$ 10,193,722$

(Continued)

June 30

Puerto Rico Electric Power Authority

Statements of Net Position

(A Component Unit of the Commonwealth of Puerto Rico)

(In thousands)

27 1501-1384337

No. CEPR-AP-2015-0001

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2014 2013Liabilities and net position (as restated)Current liabilities: Notes payable 733,908$ 755,665$ Accounts payable and accrued liabilities 1,586,390 1,301,028 Customers' deposits 15,726 14,532 Total current liabilities 2,336,024 2,071,225

Current liabilities payable form restricted assets: Current portion of long-term debt 432,281 413,546 Notes payable from restricted assets – 6,100 Accrued interest 218,839 187,432 Other current liabilities payable from restricted assets 60,614 39,594 Total current liabilities payable from restricted assets 711,734 646,672

Noncurrent liabilities: Long-term debt, excluding current portion 8,247,006 7,812,660 Fair value of derivative instruments - interest, basis and

commodity swaps 48,864 85,004 Customers' deposits (excluding current portion) 168,855 166,950 Sick leave benefits to be liquidated after one year 114,518 122,356 Accrued unfunded other post-employment benefits liability 119,175 136,050 Total noncurrent liabilities 8,698,418 8,323,020 Total liabilities 11,746,176 11,040,917

Net position (deficit): Invested in utility plant, net of related debt (253,448) (32,432) Restricted for capital and debt service – – Unrestricted (1,013,557) (814,763) Total net position (deficit) (1,267,005) (847,195) Total liabilities and net position 10,479,171$ 10,193,722$

See accompanying notes.


Statements of Net Position (continued)

June 30


(In thousands)

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2014 2013(as restated)

Operating revenues 4,468,922$ 4,843,016$

Operating expenses: Operations: Fuel 2,345,000 2,603,577 Purchased power 807,620 755,686 Other production 70,557 72,384 Transmission and distribution 175,754 175,461 Customer accounting and collection 111,475 116,605 Administrative and general 192,031 201,663 Maintenance 201,944 218,950 Depreciation 341,511 344,653 Total operating expenses 4,245,892 4,488,979 Operating income 223,030 354,037

Interest income and other 21,157 26,329 Income before interest charges, contribution in lieu of taxes and contributed capital 244,187 380,366 Interest charges: Interest on bonds 431,021 399,641 Interest on notes payable and other long-term debt 7,181 741 Amortization of debt discount, issuance costs and refunding loss 2,737 550 Allowance for funds used during construction (9,759) (14,065) Total interest charges, net 431,180 386,867 Loss before contribution in lieu of taxes and contributed capital (186,993) (6,501)

Contribution in lieu of taxes and other (277,776) (297,551) Loss before contributed capital (464,769) (304,052)

Contributed capital 44,959 31,979 Change in net position (419,810) (272,073)

Net position (deficit), beginning balance, as restated (847,195) (575,122) Net position (deficit), ending balance (1,267,005)$ (847,195)$



Statements of Revenues, Expenses and Changes in Net Position

Year Ended June 30


(In thousands)

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No. CEPR-AP-2015-0001

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Cash flows from operating activitiesCash received from customers 4,176,780$ 4,665,529$ Cash paid to suppliers and employees (3,549,714) (4,272,003) Net cash flows provided by operating activities 627,066 393,526

Cash flows from noncapital financing activitiesProceeds from notes payable 116,527 32,921 Principal paid on notes payable (92,454) (92,053) Interest paid on notes payable (1,163) (566) Principal paid on fuel line of credit (1,630,600) (1,264,351) Proceeds from fuel line of credit 1,582,238 1,468,736 Interest paid on fuel line of credit (27,197) (16,611) Net cash flows (used in) provided by noncapital financing activities (52,649) 128,076

Cash flows from capital and related financing activitiesConstruction expenditures (288,746) (315,764) Proceeds received from contributed capital 4,358 10,898 Power revenue bonds:

Proceeds from issuance of bonds, net of original discount 658,336 – Principal paid on revenue bonds maturities (194,920) (185,605) Interest paid on revenue bonds (409,847) (397,700)

Swap termination fees paid (37,873) – Net cash flows used in capital and related financing activities (268,692) (888,171)

Cash flows from investing activitiesPurchases of investment securities (3,131,639) (4,085,709) Proceeds from sale and maturities of investment securities 3,012,296 4,165,974 Interest on investments 41,828 24,531 Net cash flows (used in) provided by investing activities (77,515) 104,796 Net increase (decrease) in cash and cash equivalents 228,210 (261,773)

Cash and cash equivalents at beginning of year 553,251 815,024 Cash and cash equivalents at end of year 781,461$ 553,251$

(Continued)

Puerto Rico Electric Power Authority(A Component Unit of the Commonwealth of Puerto Rico)

Statements of Cash Flows(In thousands)

Year Ended June 30

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Cash and cash equivalentsUnrestricted 147,236$ 122,130$ Restricted:

Cash and cash equivalents held by trustee for payment of principal and interest on bonds 328,532 369,381 Cash and cash equivalents within construction and other special funds 305,693 61,740

781,461$ 553,251$

Reconciliation of operating income to net cash provided by operating activities

Operating income 223,030$ 354,037$ Adjustments to reconcile operating income to net cash

provided by operating activities:Depreciation 341,511 344,653 Provision for uncollectible accounts and other 191,523 15,740 Changes in assets and liabilities:

Receivables (334,556) (342,632) Fuel oil 156,854 (78,438) Materials and supplies 899 580 Prepayments and other assets 4,619 (5,027) Other deferred debits (6,649) (6,881) Noncurrent liabilities, excluding revenue bonds

and notes payable (24,713) (12,210) Accounts payable and accrued liabilities 71,448 118,370 Customer's deposits 3,100 5,334

Total adjustments 404,036 39,489 Net cash flows provided by operating activities 627,066$ 393,526$

Supplemental cash flows informationNoncash transactions:

Capital contributions 40,601$ 21,081$ Change in fair value of derivative instruments 36,140$ 26,303$ Changes in deferred loss resulting from debt refunding (14,331)$ (15,062)$



Statements of Cash Flows (continued)(In thousands)

Year Ended June 30

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Notes to Audited Financial Statements

June 30, 2014 and 2013

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1. Reporting Entity Puerto Rico Electric Power Authority (the Authority) is a public corporation and governmental instrumentality of the Commonwealth of Puerto Rico (the Commonwealth) created on May 2, 1941, pursuant to Act No. 83, as amended, re-enacted, and supplemented, of the Legislature of Puerto Rico (the Act) for the purpose of conserving, developing and utilizing the water, and power resources of Puerto Rico in order to promote the general welfare of the Commonwealth. Under the entity concept, the Authority is a component unit of the Commonwealth. The Authority transmits and distributes, substantially, all of the electric power consumed and produces a majority of the electricity generated in Puerto Rico. The Authority has broad powers including, among others, to issue bonds for any of its corporate purposes subject to the limitations set forth in a Trust Agreement dated as of January 1, 1974, as amended (the 1974 Agreement). The Authority is required, under the terms of the 1974 Agreement and the Act, to determine and collect reasonable rates for electric service in order to produce revenues sufficient to cover all operating and financial obligations, as defined. On August 18, 2003, the Commonwealth approved Act No. 189, which authorizes the Authority to create, acquire and maintain corporations, partnerships or subsidiary corporations, for profit or non-profit entities. On May 27, 2014, the Commonwealth approved Act No. 57, which authorizes the Puerto Rico Energy Commission to approve electric rates proposed by the Authority among other matters. Basis of Presentation – Blended Component Units The financial statements of the Authority as of the fiscal years ending June 30, 2014 and 2013, include the financial position and operations of the Puerto Rico Irrigation Systems (Irrigation Systems) and PREPA Holdings LLC (PREPA Holdings). The Irrigation Systems operate pursuant to the provisions of the Act, and Acts Nos. 83 and 84, approved on June 20, 1955, regarding the Puerto Rico Irrigation Service, South Coast, and Isabela Irrigation Service, respectively, and the Lajas Valley Public Irrigation Law, approved on June 10, 1953, as amended. PREPA Holdings, a wholly owned subsidiary of the Authority, was created for the sole purpose of acting as a holding company and has no current operations. PREPA Holdings is the direct parent of the following entities: PREPA Networks, LLC (PREPA.Net), Inter American Energy Sources, LLC, and Consolidated Telecom of Puerto Rico, LLC.

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Notes to Audited Financial Statements (continued)

1501-1384337 33

1. Reporting Entity (continued) Basis of Presentation – Blended Component Units (continued) The Irrigations Systems and PREPA Holdings conform to the requirements of Governmental Accounting Standards Board (GASB) No. 61, The Financial Reporting Entity: Omnibus-an amendment of GASB Statements No. 14 and No. 34, and No. 39, Determining Whether Certain Organizations are Component Units, on its stand-alone financial statements. GASB No. 39 establishes standards for defining and reporting on the financial reporting entity. It also establishes standards for reporting participation in joint ventures. It applies to financial reporting by primary governments, and other stand-alone governments; and it applies to the separately issued financial statements of governmental component units. In addition, this Statement should be applied to governmental and non-governmental component units when they are included in a governmental financial reporting entity.

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1. Reporting Entity (continued) Basis of Presentation – Blended Component Units (continued) Condensed financial information as of June 30, 2014 and 2013 and for the fiscal years then ended for the Irrigation Systems is as follows: 2014 2013 (In thousands) Statements of net position:

Assets: Receivables, net $ 6,062 $ 7,383 Prepayments and other assets 240 240 Utility Plant, net of depreciation 20,556 20,408

Total assets $ 26,858 $ 28,031

Liabilities: Accounts payable, net $ 1,066 $ 1,066

Statements of revenues, expenditures and changes in net

position: Operating revenues $ 6,284 $ 6,875 Operating expenses (7,457) (11,523)

(1,173) (4,648) Transfer to primary government – (5,999) Net position, beginning balance 26,965 37,612 Net position, ending balance $ 25,792 $ 26,965

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1. Reporting Entity (continued) Basis of Presentation – Blended Component Units (continued) Pursuant to the Act, the Authority is authorized to create subsidiaries in order to, among other things, delegate or transfer any of its rights, powers, functions or duties. The Authority currently has four principal subsidiaries organized in a holding company structure. PREPA Holdings, a wholly owned subsidiary of the Authority, was organized on October 26, 2009 as a Delaware limited liability company for the sole purpose of acting as a holding company and has no current operations. PREPA Holdings is the direct parent of the following entities: PREPA.Net, InterAmerican Energy Sources, LLC and Consolidated Telecom of Puerto Rico, LLC. PREPA.Net, a subsidiary of the Company, was formed for the purpose of merging two local not-for-profit entities – PREPA Networks, Corp, and PREPA.Net International Wholesale Transport, Inc. PREPA.Net markets the excess communication capacity of the Authority’s fiber optic cable system. PREPA.Net currently offers next generation telecommunications services to carriers, internet service providers, and large commercial enterprises. These services include data transmission via Synchronous Optical Network (SONET), metro and long haul Ethernet transport services, wireless last mile, and internet protocol services optimized for voice over internet protocol. PREPA.Net also offers international fiber optic cable capacity and satellite teleport facilities through the submarine fiber optic cable capacity acquired in 2008. InterAmerican Energy Sources, LLC was created on May 25, 2007, as a Delaware limited liability company, for the purpose of investing, developing, financing, constructing and operating renewable energy projects and other infrastructure related to the optimization of the Authority’s electric infrastructure. InterAmerican Energy Sources, LLC is currently not operating. Consolidated Telecom of Puerto Rico, LLC was created on October 27, 2009, as a Delaware limited liability company, for the purpose of developing, financing, constructing and operating a telecommunications business within or outside of the Commonwealth, directly or indirectly, in relation to the operations of the Authority.

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1. Reporting Entity (continued) Basis of Presentation – Blended Component Units (continued) Condensed financial information for PREPA Holdings, LLC as of June 30, 2014 and 2013 and for the year then ended is as follows:

Statement of net position:Assets:

Cash and cash equivalentsCertificates of depositReceivables, netPrepayments and other assetsUtility plant, net of depreciationOther receivables

Total assets

Liabilities:Accounts payable, netNotes payable

Total liabilities

Statements of revenues, expenditures and changes in net position:

Operating revenuesOperating expenses

Net position, beginning balanceNet position, ending balance

2014 2013(In thousands)

$ 8,297 $ 7,871

2,258 5,481 72 62

1,638 1,635

10,862 7,294

29,356 16,869 11,086 14,623 $ 52,707 $ 46,541

$ 21,423 $ 22,350

$ 32,285 $ 29,644

$ 18,029 $ 14,550 (14,504) (10,438) 3,525 4,112

16,897 12,785 $ 20,422 $ 16,897

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1. Reporting Entity (continued) Basis of Presentation – Blended Component Units (continued)

Statement of cash flows:Cash flows from operating activitiesCash flows from noncapital financing activitiesCash flows from capital and related financing activitiesCash flows from investing activities

Net increase in cash

Cash at beginning of yearCash at end of year

12 1,604 426 (3,950)

4,428

$ 8,297 $ 7,871 7,871 11,821

(1,125)

(14,567) (11,136)

2014 2013(In thousands)

$ 10,553 $ 6,707

2. Summary of Significant Accounting Policies The following is a summary of the most significant accounting policies followed by the Authority in preparing its financial statements: Basis of Accounting The accounting and reporting policies of the Authority conform to the accounting rules prescribed by the Governmental Accounting Standards Board (GASB). As such, it functions as an enterprise fund. The Authority maintains its accounting records on the accrual basis of accounting in conformity with U.S. generally accepted accounting principles. Although the Authority is not subject to all Federal Energy Regulatory Commission (FERC) regulations, the Authority has adopted the uniform system of accounts prescribed by FERC. The accounting and reporting policies of the Authority conform to the accounting rules prescribed by the Governmental Accounting Standards Board (GASB).

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2. Summary of Significant Accounting Policies (continued) Basis of Accounting (continued) The Authority accounts for its operations and financings in a manner similar to private business enterprises; the intent is that costs of providing goods or services to the general public on a continuing basis be financed or recovered primarily through user charges. Such accounts and these financial statements have been prepared on the basis that the Authority will continue as a going concern. Additional disclosures within the Notes to these financial statements, particularly in Notes 8, 11, 19 and 20, should be read in connection with consideration of the future ability of the Authority to continue as such. Cash and Cash Equivalents The Authority considers all highly liquid debt instruments with maturities of three months or less when purchased to be cash equivalents. Cash and cash equivalents included in the restricted funds are considered cash equivalents for purposes of the statements of cash flows. Receivables Receivables are stated net of estimated allowances for uncollectible accounts, which are determined, based upon past collection experience and current economic conditions, among other factors. The Authority establishes a general or specific reserve for each group of customers (i.e., residential, commercial, industrial, and governmental). The Authority has significant amounts receivable from the Commonwealth’s and its instrumentalities. There is significant uncertainty in regards to the collection of such receivables due to the financial challenges these entities are facing. The Authority has considered this in its estimate of the specific governmental reserve for uncollectible accounts. Because of uncertainties inherent in the estimation process, management’s estimate of credit losses inherent in the existing accounts receivable and related allowance may change in the future. Materials, Supplies and Fuel Oil Materials, supplies and fuel oil inventories are carried at average cost and are stated at the lower of cost or market.

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2. Summary of Significant Accounting Policies (continued) Investments The Authority follows the provisions of GASB Statement No. 31, Accounting and Financial Reporting for Certain Investments and for External Investment Pools, which require the reporting of investments at fair value in the statement of net position and recording changes in fair value in the statements of revenues, expenses and changes in net position. The fair value is based on quoted market prices and recognized pricing services for certain fixed income securities. The funds under the 1974 Agreement may be invested in: Government obligations, which are direct obligations of, or obligations whose principal

and interest is guaranteed by the U.S. Government, or obligations of certain of its agencies or instrumentalities.

Investment obligations of any of the states or territories of the United States or political subdivisions thereof (other than obligations rated lower than the three highest grades by a nationally recognized rating agency) and repurchase agreements with commercial banks fully secured by U.S. Government obligations.

Time deposits with Government Development Bank for Puerto Rico (GDB) or the Authority’s Trustee under the 1974 Agreement or any bank or trust company member of the Federal Deposit Insurance Corporation having a combined capital and surplus of not less than $100 million.

Effective April 1999, the 1974 Agreement was amended to provide that permitted investments of moneys to the credit of the Self-insurance Fund be expanded (subject to the Authority’s adoption of an investment policy with the consent of GDB) to coincide with the investments permitted for the pension fund for employees of the Commonwealth of Puerto Rico and its instrumentalities. Such investments include various debt instruments, such as mortgage loans and leases, common and preferred stock, real property and various other financial instruments.

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2. Summary of Significant Accounting Policies (continued) Utility Plant Utility plant is carried at cost, which includes labor, materials, overhead, and an allowance for the cost of funds used during construction (AFUDC). AFUDC represents the cost of borrowed funds used to finance construction work in progress. AFUDC is capitalized as an additional cost of property and as a reduction of interest expense. Capitalized interest expense is reduced by interest income earned on related investments acquired with proceeds of tax-exempt borrowings. Such costs are recovered from customers as a cost of service through depreciation charges in future periods. Capitalized interest during the years ended June 30, 2014 and 2013 amounted to $9.8 million and $14.1 million, respectively. These amounts are net of interest income earned on investments amounting to $4.0 million and $1.0 million, respectively. Capital expenditures of $1,200 or more are capitalized at cost at the date of acquisition. Maintenance, repairs, and the cost of renewals of minor items of property units are charged to operating expenses. Replacements of major items of property are charged to the plant accounts. The cost of retired property, together with removal cost less salvage, is charged to accumulated depreciation with no gain or loss recognized. The Authority follows the provisions of GASB Statement No. 42, Accounting and Financial Reporting for Impairment of Capital Assets and for Insurance Recoveries. This statement establishes guidance for accounting and reporting for the impairment of capital assets and for insurance recoveries. Depreciation Depreciation is computed on the straight-line method at rates considered adequate to allocate the cost of the various classes of property over their estimated service lives. The annual composite rate of depreciation, determined by the Authority’s consulting engineers, was approximately 3.58% for 2014 and 2013. Unamortized Debt Issuance Expense Debt issuance costs are presented as expense during the year they are incurred. Premium and discounts incurred in the issuance of bonds are deferred and amortized using the straight-line method, which approximates the interest method, over the term of the related debt.

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2. Summary of Significant Accounting Policies (continued) Unamortized Debt Issuance Expense (continued) For debt refunding debt, the excess of reacquisition cost over the carrying value of long-term debt is deferred and amortized to operating expenses using the straight-line method over the remaining life of the original debt or the life of the new debt, whichever is shorter. Bonds payable are reported net of applicable bond premium or discount. For fiscal year 2013 and 2014, as a result of the adoption of GASB Statement No. 65, the deferred loss from debt refunding is reported as deferred outflows of resources in the accompanying statements of net position. Pension Plan and Other Postemployment Benefits Pension and other postemployment benefits (OPEB) expenses are equal to the statutory required contribution to the employees’ retirement system. A pension liability or asset is reported equal to the cumulative difference between annual required contributions and actual contributions. Accounting for Compensated Absences Employees earn annual vacation leave at the rate of 30 days per year up to a maximum permissible accumulation of 60 days for union employees and management personnel. Employees accumulate sick leave at the rate of 19 days per year. Sick leave is only payable if the regular employee resigns and has more than 10 years of employment, or retires and takes a pension. Maximum permissible accumulation for sick leave is 90 days for all employee and the excess shall be lost if an employee does not use such excess from January to June of the next year. The Authority records as a liability and as an expense the vested accumulated vacation and sick leave as benefits accrue to employees. The cost of vacation and sick leave expected to be paid in the next twelve months is classified as current and accrued liabilities while amounts expected to be paid after twelve months are classified as noncurrent liabilities.

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2. Summary of Significant Accounting Policies (continued) Revenue Recognition, Fuel Costs and Purchased Power Clients are billed monthly. Revenues are recorded based on services rendered during each accounting period, including an estimate for unbilled services. Revenues include amounts resulting from a fuel and purchased power cost recovery clause (Fuel Adjustment Clause), which is designed to permit full recovery through customer billings of fuel costs and purchased power. Fuel costs and purchased power are reflected in operating expenses as the fuel and purchased power are consumed. Contributions in Lieu of Taxes and Governmental Subsidies The Act exempts the Authority from all taxes that otherwise would be levied on its properties and revenues by the Commonwealth and its Municipalities, except to the extent net revenues, as defined, are available, wherein the Authority is required under the Act to make a contribution in lieu of taxes of 11% to the Commonwealth and the Municipalities of gross electric sales as follows: Municipalities The Authority is required under the Act to make a contribution in lieu of taxes to municipalities of the greater of:

a) Twenty percent of the Authority’s Adjusted Net Revenues (Net Revenues, as defined in the 1974 Agreement, less the cost of the Commonwealth rate subsidies);

b) The cost collectively of the actual electric power consumption of the municipalities; or c) The prior five-year moving average of the contributions in lieu of taxes paid to the

municipalities collectively. If the Authority does not have sufficient funds available in any year to pay the contribution in lieu of taxes, the difference is accrued and carried forward for a maximum of three years. The contribution in lieu of taxes to Municipalities can be used to offset accounts receivable balance owed by the Municipalities to the Authority as permitted by law.

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2. Summary of Significant Accounting Policies (continued) Contributions in Lieu of Taxes and Governmental Subsidies (continued) Commonwealth of Puerto Rico To the extent net revenues are available, the Authority is also required under the Act to set aside the remainder of contribution in lieu of taxes of gross electric sales for the purpose of (i) financing capital improvements, (ii) offsetting other subsidies (other than cost of fuel adjustments to certain residential clients) of the Commonwealth, and (iii) any other lawful corporate purpose. Amounts assigned to (ii) above, are classified as a contribution in lieu of taxes in the accompanying statements of revenues, expenses and changes in net position and reduce the related accounts receivable in the statements of net position. Contributed Capital The Authority records contributed capital as income in the year earned. The Authority receives contributed capital in the form of cash and property from residential projects developed by third parties during recent years and local and federal agencies. During the years ended June 30, 2014 and 2013, the Authority received non-cash contributed capital in the amount of $40,601 and $21,081, respectively. Risk Management The Authority purchases commercial insurance covering casualty, theft, tort claims, natural disaster and other claims covering all risk property (excluding transmission and distribution lines), boiler and machinery, boiler, machinery and public liability. In addition, the Authority has a self-insured fund to pay the cost of repairing, replacing or reconstructing any property damaged or destroyed from, or extraordinary expenses incurred as a result of a cause, which is not covered by insurance required under 1974 agreement.

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2. Summary of Significant Accounting Policies (continued) Estimates The preparation of the basic financial statements in conformity with U.S. generally accepted accounting principles (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets (including related allowances for uncollectible accounts) and liabilities and disclosure of contingent assets and liabilities at the date of the basic financial statements and the reported amounts of revenue and expenses during the reporting period. Actual results could differ from those estimates. Interest-Rate Swap Agreements The Authority follows the provisions of GASB Statement No. 53, Accounting and Financial Reporting for Derivative Instruments. This statement establishes guidance for the recognition, measurement, and disclosure of information regarding derivative instruments. The interest-rate swaps are used in the area of debt management to take advantage of favorable market interest rates and to limit interest rate risk associated with variable rate debt exposure. Under the interest-rate swap programs, the Authority pays fixed and variable rates of interest based on various indices for the term of the variable interest rate Power Revenue Bonds and receives a variable rate of interest, which is also based on various indices. These indices are affected by changes in the market. The net amount received or paid under the swap agreements is recorded as an adjustment to interest expense on the statements of revenues, expenses and changes in net position. The interest rate swaps are reported at fair value in the Statement of Net Positions. The changes in fair value for effective hedges are recorded as deferred inflows or outflows of resources in the Statement of Net Positions. The changes in fair value for ineffective hedges are reported in investment income. The Authority accounts for its derivative instruments at fair value. The changes in fair values of the effective hedging derivative instruments are reported as either deferred inflows or deferred outflows of resources. The changes in fair value of investment derivative instruments (which include ineffective hedging derivative instruments) are reported as part of investment income in the current reporting period.

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2. Summary of Significant Accounting Policies (continued) Restricted Assets Funds set aside for construction, debt service payments or other specific purposes are classified as restricted assets since their use is limited for these purposes by the applicable agreements. When both restricted and unrestricted resources are available for a specific use, it is the Authority’s policy to use restricted resources first, then unrestricted resources as they are needed. Claims and Judgment The estimated amount of the liability for claims and judgments is recorded on the accompanying statement of net position based on the Authority’s evaluation of the probability of an unfavorable outcome in the litigation of such claims and judgments. The Authority consults with legal counsel upon determining whether an unfavorable outcome is expected. Because of uncertainties inherent in the estimation process, management’s estimate of the liability for claims and judgments may change in the future. 3. Cash and Cash Equivalents The 1974 Agreement established the General Fund, the Revenue Fund, and certain other funds (see Note 5). All revenues (other than income from investments and construction funds obtained from financing) are deposited in these funds. The moneys held in these funds are presented as unrestricted cash and cash equivalents in the statement of net position.

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3. Cash and Cash Equivalents (continued) At June 30, 2014 and 2013, the carrying amount and bank balance of cash deposits held by the Authority and restricted cash deposits held by the Trustee under the 1974 Agreement are as follows (in thousands): 2014 2013 Carrying Bank Carrying Bank Amount Balance Amount Balance Unrestricted $147,236 $158,517 $122,130 $49,499 Restricted:

Held by the Trustee 328,532 328,532 369,381 369,381 Held by the Authority 305,693 305,693 61,740 61,740

$781,461 $792,742 $553,251 $480,620 Custodial Credit Risk - Deposits Custodial credit risk is the risk that in the event of a bank failure, the Bank’s deposits may not be returned. The Commonwealth requires that public funds deposited in commercial banks in Puerto Rico must be fully collateralized. Deposits maintained in GDB or the Economic Development Bank (EDB) are exempt from the collateral requirements established by the Commonwealth and thus represents custodial credit risk because in the event of GDB’s or EDB’s failure the Authority may not be able to recover the deposits. The Authority’s policy is to deposit funds with either institution which provides insurance or securities as collateral. Such collateral is held by the Department of the Treasury of the Commonwealth. All moneys deposited with the Trustee or any other Depository hereunder in excess of the amount guaranteed by the Federal Deposit Insurance Corporation or other federal agency are continuously secured by lodging with a bank or trust company approved by the Authority and by the Trustee as custodian, or, if then permitted by law, by setting aside under control of the trust department of the bank holding such deposit, as collateral security, Government Obligations or other marketable securities.

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4. Accounts Receivable At June 30, receivables consist of (in thousands): 2014 2013

Current: Electric and related services:

Government agencies and municipalities $ 638,637 $ 499,996 Residential, industrial, and commercial 928,277 884,776 Recoveries under fuel adjustment clause under billed 67,766 10,144 Unbilled services 220,104 195,278 Miscellaneous accounts and others 9,334 14,611 1,864,118 1,604,805 Allowance for uncollectible accounts - current (397,705) (251,283) 1,466,413 1,353,522 Receivable from insurance companies and other 29,818 37,819 Accrued interest on investments 4,314 2,858

$1,500,545 $1,394,199 Noncurrent:

Electric and related services: Government agencies and municipalities $ 165,090 $ 117,653 Allowance for uncollectible accounts – noncurrent (45,045) –

$ 120,045 $ 117,653 The Authority has other subsidies and reimbursable costs receivable from the Commonwealth, which are reduced by means of charges (accounted for as a contribution in lieu of taxes and to the extent net revenues, as defined, are available) against a portion of the 11% of gross electric sales, after the contribution in lieu of taxes to municipalities, it is required to set aside under the Act. The Authority has the right to offset amounts receivable from municipalities amounting to $555 million and $321 million as of June 30, 2014 and 2013, respectively with contribution in lieu of taxes payable to such municipalities. The portion of accounts receivable and other governmental receivables not expected to be collected during the next fiscal year are reflected in the accompanying statement of net position as other noncurrent receivables. Further, the Authority has recorded an allowance for uncollectible accounts estimated at $68 million and $12 million, for 2014 and 2013, respectively, in consideration of the financial difficulty being experienced by the Commonwealth and related entities and the risk receivables (both current and long term) from such entities are uncollectible.

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5. Restricted Assets At June 30, 2014 and 2013, certain investments and cash deposits of the Authority were restricted to comply with long-term principal and interest debt service requirements (sinking funds) as well as for self-insurance. These restricted assets are held by the Trustee under the 1974 Agreement (see Note 3) in the following funds:

1974 Reserve Account – Reserve for payment of principal of and interest on Power Revenue Bonds in the event moneys in Bond Service Account or Redemption Account are insufficient for such purpose. During fiscal year 2013-2014, the Authority deposited $46.4 million into 1974 Reserve Account from the proceeds of Power Revenue Bonds Series 2013 A.

1974 Self-Insurance Fund – Fund to pay the cost of repairing, replacing or reconstructing any property damaged or destroyed from, or extraordinary expenses incurred as a result of a cause, which is not covered by insurance required under the 1974 Agreement. The 1974 Self-Insurance Fund also serves as an additional reserve for the payment of the principal of and interest on the Power Revenue Bonds, and meeting the amortization requirements to the extent that moneys in the Bond Service Account, the Redemption Account and the 1974 Reserve Account are insufficient for such purpose. The Authority did not make any deposits into the 1974 Self Insurance Fund during fiscal years 2012-2013 and 2013-2014.

Bond Service Account and Redemption Account (1974 Sinking Fund) – Current year requirements for principal of and interest on Power Revenue Bonds. The Authority did not make required deposits into 1974 Sinking Fund Principal and Interest for May 2014.

Please see further discussion regarding the forbearance agreements in Note 20.

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5. Restricted Assets (continued) At June 30, cash, cash equivalents and investments held by the Trustee consist of (in thousands): 2014 2013 Cash and Cash Cash and Cash Equivalents Investments Equivalents Investments 1974 Sinking Fund - Principal $188,508 $ – $194,920 $ 569 1974 Sinking Fund – Interest

and Capitalized Interest 140,024 124,992 174,461 62,344 1974 Reserve Account – 453,323 – 398,472 1974 Self-Insurance Fund – 96,080 – 92,217 $328,532 $674,395 $369,381 $553,602 Investments held by Trustee under the 1974 Agreement are invested exclusively in securities of the U.S. Government and its agencies. The Authority also has cash and investment securities held by the trust department of a commercial bank restricted for the following purposes: 1974 Construction Fund – Special fund created by the 1974 Agreement. The proceeds of any Power Revenue Bonds issued for the purpose of paying the cost of acquiring or constructing improvements, together with the money received from any other source for such purpose, except proceeds which are (i) applied to the repayment of advances, (ii) deposited in the 1974 Reserve Account, (iii) deposited in the Bond Service Account as capitalized interest or (iv) used for the payment of financing expenses, shall be deposited in the 1974 Construction Fund and held by the Authority in trust. During fiscal year 2013-2014, the Authority deposited $500 million into 1974 Construction Fund from the proceeds of Power Revenue bonds Series 2013 A. Reserve Maintenance Fund – Fund to pay the cost of unusual or extraordinary maintenance or repairs, not recurring annually, and renewals and replacements, including major items of equipment. The Reserve Maintenance Fund also serves as an additional reserve for the payment of principal and interest on the Power Revenue Bonds and meeting the amortization requirements to the extent that moneys in the 1974 Sinking Fund, including money in the 1974 Reserve Account, are insufficient for such purpose. The Authority did not make any deposits into the 1974 Reserve Maintenance Fund during fiscal years 2014 and 2013.

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5. Restricted Assets (continued) At June 30, 2014 and 2013, the 1974 Construction Fund, Reserve Maintenance Fund and other restricted funds consist of (in thousands): 2014 2013 Cash and Cash Cash and Cash Equivalents Investments Equivalents Investments

1974 Construction Fund $303,793 $ 1,105 $49,370 $ 1,103 Reserve Maintenance Fund – 15,949 – 15,818 Other Restricted Funds 1,900 – 12,370 – PREPA Client Fund – 3,177 – 4,759 $305,693 $20,231 $61,740 $21,680 Following is the composition of the investments in the 1974 Construction Fund and other special funds (in thousands):

2014 2013

U.S. Government obligations $ 1,105 $ 1,103 Certificate of deposit 19,126 20,577 $20,231 $21,680

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5. Restricted Assets (continued) Investments The following table provides a summary of the Authority’s investments by type at June 30, 2014 (in thousands):

June 30, 2014

% of

Maturity Total

Coupon Rate Dates Face Value Fair Value Portfolio

1974 Reserve Maintenance Fund

Federal Home Loan Bank 0.87% 05/12/17 $ 5,000 $ 5,011 31.4%

Federal Home Loan Mortgage Corp. 1.00% 06/26/17 5,000 5,007 31.4%

Certificate of Deposits Various 08/29/14 5,931 5,931 37.2%

Total Portfolio 15,949

1974 Self Insurance Fund

Federal Home Loan Mortgage Corp. .90 to 6.50% 12/2017 to 11/2028 8,443 8,791 9.1%

Federal Home Loan Bank .87 to 1.625% 03/2017 to 04/2017 30,675 30,642 31.9%

Federal National Mortgage Association .50 to 6.00% 05/2016 to 03/2030 12,436 13,152 13.7%

Federal Farm Credit Bank 0.87% May-17 15,000 15,034 15.6%

Corporate Issues .03 to 5.75% 07/2014 to 05/2024 3,057 3,258 3.4%

U.S. Bank Money Market 0.30% Aug-14 387 387 0.4%

U.S. Treasury Note 2.00 to 4.75% 08/2017 to 02/2022 6,710 6,821 7.1%

U.S. Treasury Bonds 1.75 to 8.13% 08/2021 to 05/2022 4,185 4,206 4.4%

Domestic Common Stocks Various Various 9,316 12,252 12.8%

Certificate of Deposit Various Aug-13 1,538 1,537 1.6%

1974 Reserve Account Total Portfolio 96,080

Federal Home Loan Mortgage Corporation .90 to 5.00% 02/2016 to 12/2017 48,980 48,856 10.8%



Federal Farm Credit Bank .082 to 2.28% 02/2017 to 04/2019 37,000 36,947 8.1%

U.S. Bank Money Market .03 to .04% Various 2,354 2,354 0.5%

U.S. Treasury Note .50 to 4.625% 08/2016 to 02/2018 50,145 50,817 11.2%


Certificates of Deposits .20 to 1.00% Various 230,390 230,390 50.8%


Sinking Fund - Capitalized Interest

Federal Home Loan Mortgage Corporation .625 to .75% 11/2014 to 12/2014 1,800 1,804 1.4%


U.S. Bank Money Market 0.300% Various 35,022 35,022 28.0%

Certificates of Deposits 1.20 to 1.90% 12/2014 to 12/2015 69,658 69,658 55.7%

Municipal Issues .515to 5.50% 07/2014 to 12/2023 14,410 14,489 11.6%


1974 PREPA Client

Certificates of Deposits 3,177 3,177 100.0%


1974 Construction Fund

Other - Rural Electrification Administration (REA) 1,105 1,105 100.0%


$ 694,626

No. CEPR-AP-2015-0001

I 000186



1501-1384337 52

5. Restricted Assets (continued) Investments (continued) The following table provides a summary of the Authority’s investments by type at June 30, 2013 (in thousands):

June 30, 2013

% of

Maturity Total

Coupon Rate Dates Face Value Fair Value Portfolio

1974 Reserve Maintenance Fund

Federal National Mortgage Association 0.52% 16-Feb $ 5,000 $ 4,972 31.4%

Federal Farm Credit Bank 0.44% 15-Oct 5,000 4,983 31.5%

Certificate of Deposits 0.15% 13-Sep 5,863 5,863 37.1%


1974 Self Insurance Fund

Federal Home Loan Mortgage Corp. 5.00 to 6.50% 08/2021 to 11/2028 4,294 4,642 5.0%


Federal Farm Credit Bank .42 to .45% 10/2015 to 05/2016 45,000 44,724 48.5%

Corporate Issues 3.45 to 8.50% 12/2017 to 02/2023 8,770 9,387 10.2%

U.S. Bank Money Market 0.10% 13-Aug 754 754 0.8%

U.S. Treasury Note 8.13% 21-Aug 290 429 0.5%

Domestic Common Stocks Various Various 8,549 9,787 10.6%

Certificate of Deposit 0.140% 13-Aug 1,309 1,308 1.4%


1974 Reserve Account

Federal Home Loan Mortgage Corporation .90 to 5.00% 02/2016 to 12/2017 48,195 47,688 12.0%



Federal Farm Credit Bank .235 to 1.08% 05/2013 to 02/2018 25,700 25,193 6.3%

U.S. Bank Money Market .04 to .10% Various 4,421 4,421 1.1%

U.S. Treasury Note .25 to 4.625% 03/2014 to 02/2018 122,915 122,874 30.9%


Certificates of Deposits .25 to .45% 13-Jul 17,794 17,794 4.5%


1974 Sinking Fund – Principal

U.S. Bank Money Market 0.040% 13-Jul 569 569 100.0%

Total Portfolio 569

Sinking Fund - Capitalized Interest

Federal Home Loan Mortgage Corporation .625 to .75% 11/2014 to 20/2014 1,800 1,808 3.9%


U.S. Bank Money Market 0.100% 08/2013 to 09/2013 2,268 2,268 4.9%

Municipal Issues .30 to 6.875% 07/2013 to 01/2015 49,750 50,182 108.2%

Corporate Issues 0.438% 13-Nov 500 500 1.1%


1974 PREPA Client

Certificates of Deposits 4,759 100.0%


1974 Construction Fund

Other - Rural Electrification Administration (REA) 1,103 100.0%


$ 575,282

No. CEPR-AP-2015-0001

I 000187



1501-1384337 53

5. Restricted Assets (continued) Credit Risk Credit risk is the risk that an issuer of an investment will not fulfill its obligation to the holder of the investment. This is measured by the assignment of a rating by a nationally recognized statistical rating organization. The 1974 Trust Agreement limits investments in: Government obligations, which are direct obligations of or obligations whose principal and

interest is guaranteed by the U.S. Government, or obligation of certain of its agencies or instrumentalities.

Investment obligation of any of the states or territories of the United States or political subdivisions therefore (other than obligations rated lower than the three highest grades by a nationally recognized rating agency) and repurchase agreements with commercial banks fully secured by U.S. Government Obligations.

Time deposits with GDB or the Authority’s Trustee under the 1974 Agreement or any bank or trust company member of the Federal Deposit Insurance Corporation having a combined capital and surplus of not less than $100 million.

Self-insurance fund (sinking fund) and PREPA client fund are allowed to invest in corporate issues, with certain restrictions (40% of the total fixed income portfolio).

As of June 30, 2014, the Authority’s investments in Federal Home Loan Mortgage, Federal Home Loan Bank, Federal National Mortgage Association and Federal Farm Credit Bank and Freddie Mac were rated AA+ by Standard & Poor’s (S&P) and Aaa by Moody’s Investors Service. Concentration Credit Risk Concentration of credit risk is the risk of loss attributable to the magnitude of investment in a single issuer by five percent or more of total investment. The Authority’s investment policy does not contain a limitation to invest in the securities of single issuer. As of June 30, 2014, more than 5% of the Authority’s total investments are in Federal Home Loan Mortgage, Federal Home Loan Bank, Federal National Mortgage Association, Federal Farm Credit Bank, and Certificate of Deposits.

No. CEPR-AP-2015-0001

I 000188



1501-1384337 54

5. Restricted Assets (continued) Interest Rate Risk Interest rate risk is the risk that changes in interest rates will adversely affect the fair value of an investment. Generally, the longer the maturity of an investment, the greater the sensitivity of its fair value to changes in market interest rates. Information about the sensitivity of the fair values of the Authority’s investment to market interest fluctuations is provided by the following tables that show the distribution of the investments by maturity as of June 30, 2014 and 2013 (in thousands):

Investment Type Fair Value Less than 1 year 1-5 years More than 5 years Total

Federal Home Loan Mortgage Corporation $ 64,458 $ 1,804 $ 58,360 $ 4,294 $ 64,458 Federal Home Loan Bank 50,546 – 50,546 – 50,546 Federal National Mortgage Association 70,715 4,019 45,510 21,186 70,715 Federal Farm Credit Bank 51,981 – 46,211 5,770 51,981 Certificate of Deposits 310,694 310,694 – – 310,694 Other-REA Investment 1,105 – 1,105 – 1,105 US Treasury Note 57,638 – 57,638 – 57,638 US Treasury Bonds 4,206 4,206 – 4,206 US Bank Money Market 37,763 37,763 – – 37,763 Municipal Issues 14,489 14,184 305 – 14,489 Domestic Common Stocks 12,252 – 12,252 – 12,252 Corporate Issues 18,779 14,871 3,908 – 18,779

Total Investments $ 694,626

June 30, 2014Investment Maturities

No. CEPR-AP-2015-0001

I 000189



1501-1384337 55

6. Utility Plant As of June 30, utility plant consists of: 2014 2013 (In thousands) Distribution $ 3,996,392 $ 3,770,419 Transmission 2,242,637 2,168,381 Production 2,830,980 2,764,986 Other production 1,534,943 1,472,402 Hydroelectric 139,266 136,182 General 1,465,866 1,563,236 Irrigation systems 34,824 34,324 Fiber Network 36,250 27,445 12,281,158 11,937,375 Less accumulated depreciation (6,422,226) (6,098,403) 5,858,932 5,838,972 Construction in progress 988,524 999,586 $ 6,847,456 $ 6,838,558

No. CEPR-AP-2015-0001

I 000190



1501-1384337 56

6. Utility Plant (continued) Utility plant activity for the fiscal years ended June 30, 2014 and 2013 was as follows (in thousands):

2013 2014Beginning

Balance Increases Decreases TransfersEnding Balance

Utility plant $ 11,937,375 $ – $ (17,688) $ 361,471 $ 12,281,158 Construction work in progress 999,586 350,409 – (361,471) 988,524 Total utility plant, as restated 12,936,961 350,409 (17,688) – 13,269,682

Less:Accumulated depreciation (6,098,403) (341,511) 17,688 – (6,422,226)

Total utility plant, net as restated $ 6,838,558 $ 8,898 $ – $ – $ 6,847,456

2012 2013Beginning

Balance Increases Decreases TransfersEnding Balance

Utility plant $ 11,703,301 $ – $ (14,345) $ 248,419 $ 11,937,375 Construction work in progress 863,970 384,035 – (248,419) 999,586 Total utility plant 12,567,271 384,035 (14,345) – 12,936,961

Less:Accumulated depreciation (5,768,095) (344,653) 14,345 – (6,098,403)

Total utility plant, net $ 6,799,176 $ 39,382 $ – $ – $ 6,838,558

Construction work in progress at June 30, 2014 and 2013 consists principally of expansions and upgrades to the electric generation, distribution and transmission systems.

No. CEPR-AP-2015-0001

I 000191



1501-1384337 57

7. Defeasance of Debt In prior years, the Authority has refunded in advance certain Power Revenue Bonds and other obligations by placing the proceeds of new debt in an irrevocable trust to provide for future debt service payments on such bonds. Accordingly, the trust accounts, assets, and liabilities for the defeased bonds are not included in the Authority’s financial statements. At June 30, 2014, $3.7 million of Power Revenue Bonds which remain outstanding were considered defeased. 8. Notes Payable The following is a summary of notes payable as of June 30, 2014 (in thousands):

June 30, 2014 Effective Current Long-Term

Maturity Date Interest Rate Liabilities Debt Total

Notes payable, unrestricted:

Revolving line of credit of $250 million to finance

working capital Jan-15 7.25% $ 146,042 $ – $ 146,042

Revolving line of credit of $500 million to finance

working capital Aug-14 7.25% 549,976 – 549,976

Line of credit of $25 million to finance improvements (F)

to Isabela Irrigation System Jun-18 7.00% 743 – 743

Revolving line of credit of $100 million to fund (F)

swap's collateral posting Dec-14 6.00% 35,136 – 35,136

P.R. (ULTRACOM) Feb-23 3.25% (V) 842 6,452 7,294

PREPA Holdings (IT Solution) May-17 3.50% (F) 1,169 4,410 5,579

Total notes payable $ 733,908 $ 10,862 $ 744,770

_______________ (V) – variable interest rate (F) – fixed interest rate

No. CEPR-AP-2015-0001

I 000192



1501-1384337 58

8. Notes Payable (continued) The following is a summary of notes payable as of June 30, 2013 (in thousands): June 30, 2013

Effective Current Long-Term

Maturity Date Interest Rate Liabilities Debt Total

Notes payable, unrestricted:

Line of credit of $64.2 million to fund payments required Jun-14 .70%+LIBOR (V) $ 9,700 $ – $ 9,700

under a settlement agreement with municipalities

Revolving line of credit of $250 million to finance working Oct-14 2.80%+LIBOR (V)

249,138

–

249,138

Capital

Revolving line of credit of $500 million to finance working Aug-14 2.25%+LIBOR (V)

495,242

–

495,242

Capital

Line of credit of $25 million to finance improvements to Jun-18 7.00% (V)

743

–

743

Isabela Irrigation System

P.R. (ULTRACOM) Feb-23 3.25% (F) 842 7,294 8,136

755,665 7,294 762,959

Notes payable, restricted:

Revolving line of credit of $100 million to fund

swap’s collateral posting 6,100 – 6,100

Total notes payable $ 761,765 $ 7,294 $ 769,059

_______________ (V) – variable interest rate (F) – fixed interest rate Short-term debt activity for the years ended June 30, 2014 and 2013 was as follows: 2014 2013 (In thousands)

Balance at beginning of year $ 761,765 $ 605,219 Proceeds and transfers from long-term debt 734,029 1,512,950 Payment of short-term debt (761,886) (1,356,404)

Balance at end of year $ 733,908 $ 761,765

Notes payable – short-term: $ 733,908

Unrestricted $ 755,665 Restricted – 6,100

Total of notes payable $ 733,908 $ 761,765

No. CEPR-AP-2015-0001

I 000193



1501-1384337 59

9. Accounts Payable and Accrued Liabilities Accounts payable and accrued liabilities at June 30, 2014 and 2013 were as follows: 2014 2013 (In thousands) Accounts payable, accruals, and withholdings in process of payment $ 836,640 $ 791,680 Additional accruals and withholdings:

Injuries and damages and other 5,305 20,400 Accrued vacation and payroll benefits 57,301 56,179 Accrued sick leave and payroll benefits - exclusive of

benefits to be liquidated after one year of approximately $114.5 million in 2014 and $122.4 million in 2013 30,628 31,576

Accrued compensation 9,484 26,432 Accrued pension plan contribution and withholding

from employees: Employees’ Retirement System 19,096 18,054 Employees health plan 27,831 6,275

Contribution in lieu of taxes 572,385 323,622 Other accrued liabilities 27,720 26,810

$1,586,390 $ 1,301,028 10. Other Current Liabilities Payable from Restricted Assets 2014 2013 (In thousands) Contract retainage $ 6,165 $ 7,173 Other liabilities 54,449 32,421 $ 60,614 $ 39,594

No. CEPR-AP-2015-0001

I 000194



1501-1384337 60

11. Long-Term Debt At June 30, 2014 and 2013, long-term debt consists of: 2014 2013 (In thousands) Power Revenue Bonds payable:

Publicly offered at various dates from 2002 to 2013, interest rates ranging from 2.5 to 7.25%, maturing to 2043 $8,526,710 $8,048,485

Plus unamortized premium/discount, net 141,715 170,427 Revenue bonds payable, net 8,668,425 8,218,912 Notes payable and bond anticipation notes 744,770 769,059 9,413,195 8,987,971 Less current portion of long-term debt:

Notes payable from unrestricted assets 733,908 755,665 Notes payable from restricted assets – 6,100 Power revenue bonds 432,281 413,546

Total current portion of long-term debt 1,166,189 1,175,311 $8,247,006 $7,812,660

No. CEPR-AP-2015-0001

I 000195



1501-1384337 61

11. Long-Term Debt (continued) Long-term debt activity for the years ended June 30, 2014 and 2013 was as follows: 2014 2013 (In thousands) Long-term debt excluding current portion at beginning of

year $ 8,987,971 $ 9,042,843 New issues:

Power revenue bonds 673,145 – Debt discount on new bond issues, net (14,806) – Notes payable 1,709,900 1,501,656 11,356,210 10,544,499

Payments: Power revenue bond – July 1 (194,920) (185,605) Notes payable (1,734,188) (1,356,411)

Total payments (1,929,108) (1,542,016) Amortization of debt discount (13,907) (14,512) Balance at end of year $ 9,413,195 $ 8,987,971 Current portion of notes payable $ 733,908 $ 761,765 Current portion of power revenue bonds 432,281 413,546 Total current portion of long-term debt $ 1,166,189 $ 1,175,311

No. CEPR-AP-2015-0001

I 000196



1501-1384337 62

11. Long-Term Debt (continued) Power Revenue Bonds Payable During fiscal year 2014, the Authority issued its Power Revenue Bonds, Series 2013A. A summary of the net proceeds of the Power Revenue Bonds, Series 2013A and the application of the proceeds follows (in thousands):

Sources: Principal amount of the bonds $ 673,145

Net original issue discount (10,502) Total sources $ 662,643 Application of net proceeds:

Deposit to 1974 Construction Fund $ 500,000 Deposit to 1974 Reserve Account 46,439 Payment of line of credit and accrued interest 109,647

Underwriting discount and estimated legal, printing and other financing expenses 6,557

Total application of proceeds $ 662,643 Maturities of the Power Revenue Bonds Series 2013A, issued during fiscal year 2014 range July 1, 2030 to July 1, 2043. The Series 2013A bear fixed interest rates ranging from 6.75% to 7.25%. Interest on the Series 2013A is payable on the first day of each July and January. The Authority has issued Power Revenue Bonds pursuant to the 1974 Agreement principally for the purpose of financing the cost of improvements; as such term is defined in the 1974 Agreement, and subject to the conditions and limitations set forth therein. In the 1974 Agreement, the Authority covenants to fix, charge, and collect rates so that revenues will be sufficient to pay current expenses and to provide the greater of (i) the required deposits or transfers under the Sinking Fund, the 1974 Self-insurance Fund and the Reserve Maintenance Fund or (ii) 120% of the aggregate principal and interest requirements for the next fiscal year on account of all outstanding Power Revenue Bonds. See further discussion in Note 20.

No. CEPR-AP-2015-0001

I 000197



1501-1384337 63

11. Long-Term Debt (continued) Power Revenue Bonds Payable (continued) Gross revenues, exclusive of income on certain investments, less current expenses as defined in the 1974 Agreement have been pledged to repay Power Revenue Bonds principal and interest. Bond Anticipation Notes Bond anticipation notes (BANs) are used primarily to provide interim construction financing and are usually retired with the proceeds of long-term debt. Swap Agreements To protect against the potential of rising interest rates, the Authority entered into quarterly separate pay-fixed, receive-variable interest-rate, basis and commodity swap agreements at a cost anticipated to be less than what the Authority would have paid to issue fixed-rate debt. On June 30, 2014, the Authority had the following derivative instruments outstanding (in thousands):

Item Type Objective Terms

A Pay-Fixed Interest Rate Swap

Hedge of changes in cash flows on the Series UU Bonds 5/3/2007 7/1/2029 Pay 4.08%; receive 67%

3M LIBOR + 0.52% Aa3/A+ $ 169,532

B Pay-Fixed Interest Rate Swap

Hedge of changes in cash flows on the Series UU Bonds 5/3/2007 7/1/2029 Pay 4.08%; receive 67%

3M LIBOR + 0.52% Aa3/A+ 83,343

$ 252,875

Notional Amount

Effective Date

Maturity Date

Counterparty Credit Rating

No. CEPR-AP-2015-0001

I 000198



1501-1384337 64

11. Long-Term Debt (continued) Swap Agreements (continued) On June 30, 2013, the Authority had the following derivative instruments outstanding (in thousands):

Item Type O bjective Terms

A Pay-Fixed Interest Rate Swap

Hedge of changes in cash flows on the Series UU Bonds

5/3/2007 7/1/2017 Pay 4.014%; receive 5Y SIFMA

Aa3/A+ $ 25,525

B Pay-Fixed Interest Rate Swap



Aa3/A+ 17,000

C Pay-Fixed Interest Rate Swap



Aa3/A+ 29,055

D Pay-Fixed Interest Rate Swap


5/3/2007 7/1/2025 Pay 4.232%; receive 67% 3M LIBOR + 0.68%

Aa3/A+ 14,570

E Pay-Fixed Interest Rate Swap



Aa3/A+ 169,532

F Pay-Fixed Interest Rate Swap



Aa3/A+ 72,800

G Pay-Fixed Interest Rate Swap



A2/A 83,343

H Basis Swap Goldman Sachs

Hedges tax risk on underlying fixed rate bonds (various) and provides expected positive cash flow accrual

7/1/2008 7/1/2037 Pay SIFMA; receive 62% 3M LIBOR + 0.29% + 0.4669%

A2/A 500,000

I Basis Swap Deutsche Bank



A2/A 200,000

J Basis Swap Royal Bank of Canada



Aa3/AA- 300,000

K Commodity Swap JP Morgan

Hedge Fuel Cost 10/1/2012 10/1/2013 N.Y. Harbor No. 6 1% Cargo

Aa3/A+ 1,675

L Commodity Swap Macquire Bank


A2/A 120

M Commodity Swap Morgan Stanley


Baa2/A- 225

N Commodity Swap Scotiabank


Aa2/A+ 175

$ 1,414,020

Notional Amount

Effective Date

Maturity Date

Counterparty Credit Rating

No. CEPR-AP-2015-0001

I 000199



1501-1384337 65

11. Long-Term Debt (continued) Swap Agreements (continued) Derivative instruments A and B hedge changes in cash flows of the underlying bonds – floating rate notes with coupons based on 5-year SIFMA or 67% of 3-month LIBOR index, and maturities equal to the maturities of the corresponding swaps. As such they are considered hedging derivative instruments. The total fair value of these instruments as of June 30, 2014 is negative $48.9 million. The following tables include summary information for the Authority’s effective hedges related to the outstanding swap agreements for fiscal years 2014 and 2013.

Instrument Type Classification Amount Classification Amount Notional

Interest Rate Swap Deferred Outflows 22,106$ Fair value of derivative instruments (48,864)$ 252,875$ Basis Swap Investment income 7,612 Fair value of derivative instruments – – Commodity Swap Investment income 6,422 Fair value of derivative instruments – –

Total 36,140$ (48,864)$ 252,875$

Instrument Type Classification Amount Classification Amount Notional

Interest Rate Swap Deferred Outflows 37,468$ Fair value of derivative instruments (70,970)$ 411,825$ Basis Swap Deferred Outflows (4,743) Fair value of derivative instruments (7,612) 1,000,000 Commodity Swap Deferred Outflows (6,422) Fair value of derivative instruments (6,422) 2,195

Total 26,303$ (85,004)$ 1,414,020$

Changes in Fair Value Fair Value at June 30, 2013

Changes in Fair Value Fair Value at June 30, 2014

As of June 30, 2014 and 2013, negative fair values of the derivative instruments are $48.9 million and $85.0 million, respectively.

No. CEPR-AP-2015-0001

I 000200



1501-1384337 66

11. Long-Term Debt (continued) Swap Agreements (continued) Interest-Rate Swap Agreements The terms, fair values and credit ratings of the outstanding interest-rate swaps as of June 30, 2014 and 2013, were as follows (in thousands):

Fair Value

Associated Power

EffectiveMaturity Date

Fixed

Revenue Bonds 6/30/2014 Date Rate

2014

2013

Libor Bonds, Series UU $ 169,532 3-May-07 1-Jul-29 4.08% $ (32,835) $ (31,846)

Libor Bonds, Series UU 83,343 3-May-07 1-Jul-29 4.08% (16,029) (15,621)

Libor Bonds, Series UU – 3-May-07 1-Jul-25 4.23% – (2,441)

Libor Bonds, Series UU – 3-May-07 1-Jul-31 4.29% – (14,529)

Muni-BMS Bonds, Series UU – 3-May-07 3-Jul-17 4.01% – (2,071)



Total $ 252,875 $ (48,864) $ (70,970)

The notional amounts of the swaps match the principal amounts of the associated Power Revenue Bonds. During fiscal years 2014 and 2013, the payments of fixed rate interest from the Authority exceeded the amount received as variable interest rate from swap counterparties by $15.7 million and $16.9 million, respectively. Using rates as of June 30, 2014, debt service requirements of the variable-rate debt and net swap payments, assuming current interest rates remain the same for their term. These debt service requirements are included in the scheduled maturities of long-term debt disclosed further in this note. As rates vary, variable-rate bond interest payments and net swap payments will vary.

No. CEPR-AP-2015-0001

I 000201



1501-1384337 67

11. Long-Term Debt (continued) Swap Agreements (continued) Interest-Rate Swap Agreements (continued)

Fiscal Year Interest-Rate Ending June 30 Principal Interest Swap, Net Total

(In thousands)

2015 $ – $ 2,108 $ 8,209 $ 10,3172016 – 2,108 8,209 10,3172017 – 2,108 8,209 10,3172018 – 2,108 8,209 10,3172019 – 2,108 8,209 10,317

2020-2029 252,875 21,081 82,092 356,048Total $ 252,875 $ 31,621 $ 123,137 $ 407,633

On June 4, 2014, the Authority terminated $158.9 million in notional amounts with J.P. Morgan. Pursuant to the agreement the Authority paid $21.3 million in order to partially terminate the interest rate swap. As of June 30, 2014, the current outstanding notional amount of this swap is $252.9 million. As of June 30, 2014 and 2013, the swaps had a negative fair value of approximately $48.9 million and $70.9 million, respectively. The negative fair value of the swaps may be countered by a reduction in future net interest payments required on the variable-rate Power Revenue Bonds, creating higher synthetic rates. As of June 30, 2014 and 2013, the Authority was not exposed to credit risk because the swaps had a negative fair value. However, should interest rates change and the fair value of the swap become positive, the Authority would be exposed to credit risk in the amount of the derivative’s fair value. The swaps counterparties were rated A2 and Aa3 as issued by Moody’s Investor Services (Moody’s), AA- and A+ by Standard & Poors (S&P), and A and A+ by Fitch Ratings.

No. CEPR-AP-2015-0001

I 000202



1501-1384337 68

11. Long-Term Debt (continued) Swap Agreements (continued) Interest-Rate Swap Agreements (continued) The derivative contract uses the International Swaps and Derivatives Association, Inc. Master Swap Agreement, which includes standard termination events, such as failure to pay and bankruptcy. The Authority or the counterparties may terminate the swaps if the other party fails to perform under the terms of the contracts. Also, the swaps may be terminated by the Authority if the counterparties’ credit quality rating falls below Baa1 as determined by Moody’s or BBB+ as determined by S&P. If at the time of termination the swap has a negative fair value, the Authority would be liable to the counterparty for a payment equal to the swap’s fair value. Basis Swap Agreement In March 2008 (with effective date of July 1, 2008), the Authority entered into a basis swap agreement in the notional amount of $1,375 million with an amortization schedule matching certain maturities of the Authority’s outstanding power revenue and revenue refunding bonds issued in various years from 2027 to 2037 (the 2008 basis swap). Under the terms of the Master Swap Agreement, the Authority receives from its counterparty (Goldman Sachs Capital Markets, L.P., an affiliate of Goldman, Sachs & Co.) quarterly, commencing on October 1, 2008, a floating amount applied to said notional amount at a rate equal to 62% of the taxable London Inter-Bank Offering Rate (LIBOR) index reset each week plus 29 basis points (hundredths of a percent) and a fixed rate payment of 0.4669% per annum (the “basis annuity”), quarterly for the term of swap in return for quarterly payments by the Authority, commencing also on October 1, 2008, on such notional amount at a rate based on the Securities Industry and Financial Markets Association (SIFMA) municipal swap index. During the last quarter of fiscal year 2014, the Authority terminated the basis swap with a $1.0 billion notional amount that was outstanding. As agreed upon, the Authority paid $16.5 million to the counter party in order to terminate the basis swap. The basis swap hedges the portion of the fair value of the underlying liabilities attributable to the relative value/basis risk between tax-exempt and taxable rates. Because of the tax-exemption, tax-exempt bonds trade at yields lower than taxable yields. The percent at which tax-exempt yields trade relative to taxable yields (UST or LIBOR) is referred to as MMD ratios or muni-bond ratios.

No. CEPR-AP-2015-0001

I 000203



1501-1384337 69

11. Long-Term Debt (continued) Swap Agreements (continued) Basis Swap Agreement (continued) In order to assess effectiveness of the basis swap as a hedge, the Authority ran a regression of SIFMA ratios (as an independent variable) and MMD ratios (as dependent variable), adjusting to the specific circumstances. The result showed a high correlation. The method used can be qualified as Other Quantitative Method. Because the MMD ratios and SIFMA ratios reflected respectively the change in the relationship of tax-exempt rates to taxable rates in the bond market and the SIFMA swap market, the Authority concluded that the regression showed that the SIFMA swap could effectively hedge the basis risk between tax-exempt and taxable rates and, therefore, the basis swap was considered an effective hedge instrument under GASB 53. By using derivative financial instruments to hedge the exposure to changes in interest rates, the Authority exposes itself to credit risk, market-access risk and basis risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Authority, which creates a credit risk for the Authority. When the fair value of the derivative contract is negative, the Authority owes to the counterparty and, therefore, does not pose credit risk to the Authority. The Authority minimizes the credit risk in derivative instruments by entering into transactions with high-quality counterparties whose credit rating is acceptable under the investment policies of the Authority and of GDB, its fiscal agent. Market risk is the adverse effect on the value of a financial instrument that results from a change in interest rates. The market risk associated with an interest rate swap contract is managed by establishing and monitoring parameters that limit the types and degree of market risk that may be undertaken. The Authority assesses market risk by continually identifying and monitoring changes in interest rate exposures that may adversely affect expected interest rate swap contract cash flows and evaluating other hedging opportunities. The Authority and GDB maintain risk management control systems to monitor interest rate cash flow risk attributable to both the Authority’s outstanding or forecasted debt obligations as well as the Authority’s offsetting hedge positions.

No. CEPR-AP-2015-0001

I 000204



1501-1384337 70

11. Long-Term Debt (continued) Swap Agreements (continued) Basis Swap Agreement (continued) Basis risk arises when different indices are used in connection with a derivative instrument such as an interest rate swap contract. The 2008 basis swap exposes the Authority to basis risk should the relationship between LIBOR and the SIFMA municipal swap index converge. If a change occurs that results in the relationship moving to convergence, the expected financial benefits may not be realized. The Authority assesses basis risk by following the aforementioned market risks control system. During fiscal years 2014 and 2013, the Authority received from its counterparty $4.7 million and $9.1 million, respectively. The following table shows the cash flow benefit of the basis annuity in exchange for the Authority taking tax and other basis risks tied to the change in the relationship between LIBOR and the SIFMA municipal swap index.

2014 2013 (In thousands)

Basis annuity received $ 1,167 $ 2,510 LIBOR index amounts received 3,869 8,188 SIFMA index amounts paid (300) (1,589) Net amount received $ 4,736 $ 9,109

According to the Credit Support Annex of the Master Swap Agreement, the Authority shall post eligible collateral on the next business day upon notification from its counterparty, if the fair value of the 2008 basis swap is negative and exceeds the threshold amount. This amount is determined by the Authority’s credit ratings with Moody’s Investors Service and Standard & Poor’s. Based on the Authority’s ratings, the collateral posting threshold is zero. The Authority and GDB entered into an agreement for a $100 million revolving line of credit to meet collateral posting requirements from the 2008 basis and interest rate swaps. As of June 30, 2014, there was a $35.1 million outstanding balance in this line of credit. This balance is mainly related to the amounts paid under the termination agreements of the swap.

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11. Long-Term Debt (continued) Swap Agreements (continued) Commodity Swap Agreement During fiscal year 2012, the Authority entered into a 2012 Commodity Swap Agreement that provided it with protection against increases in the price of fuel of oil No. 6 covering contracts for 10.2 million barrels from June 2012 through October 2013. The notional amount of the swaps matches the barrel of fuel. The premium amount established for this swap was $29.2 million, which was amortized from June 2012 to October 2013. The Authority paid to its counterparties $6.4 million and $21.9 million for fiscal years 2014 and 2013, respectively. This derivative instrument expired in October 2013, as a result it had no outstanding balance as of June 30, 2014, and a negative fair value of $6.4 million as of June 30, 2013.

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11. Long-Term Debt (continued) Scheduled Maturities of Long-Term Debt The scheduled maturities of long-term debt with interest thereon as of June 30, 2014, are as follows:

Fiscal Year Ending June 30, Principal Interest Total

2015 $ 1,152,623 $ 426,505 $ 1,579,128 2016 229,287 415,395 644,682 2017 238,207 403,730 641,937 2018 250,377 391,530 641,907 2019 262,355 378,923 641,278 2020-2024 1,525,286 1,682,360 3,207,646 2025-2029 1,895,140 1,268,457 3,163,597 2030-2034 1,458,545 829,573 2,288,118 2035-2039 1,381,460 446,711 1,828,171 2040-2043 878,200 107,127 985,327 Total 9,271,480 6,350,311 15,621,791 Less:

Unamortized premium/discount, net 141,715 – 141,715 Interest – (6,350,311) (6,350,311)

Total long-term debt 9,413,195 – 9,413,195

Current portion, net of discount (432,281) – (432,281)Current portion of notes payable (733,908) – (733,908)Total current portion (1,166,189) – (1,166,189)Long-term debt, excluding current portion $ 8,247,006 $ – $ 8,247,006

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12. Employees’ Retirement Benefits Pension Plan Plan Description All of the Authority’s permanent full-time employees are eligible to participate in the Authority’s Pension Plan, a single employer defined benefit pension plan (the Plan) administered by the Employees’ Retirement System of the Puerto Rico Electric Power Authority (the System). The System issues a publicly available financial report that includes financial statements and required supplementary information for the Plan. That report may be obtained by writing to the Retirement System of the Puerto Rico Electric Power Authority, PO Box 13978, San Juan, Puerto Rico 00908-3978. Benefits include maximum retirement benefits of 75% of average basic salary (based on the three highest annual basic salaries) for employees with 30 years of service; with reduced benefits available upon early retirement. The Plan was amended on February 9, 1993 to provide revised benefits to new employees limiting the maximum retirement basic salary to $50,000. The plan was further amended in January 1, 2000 to provide improved retirement benefits to employees with 25 years or more of credited service. Disability and death benefits are also provided. Separation benefits fully vest upon reaching 10 years of credited service. If a member’s employment is terminated before he becomes eligible for any other benefits under this Plan, he shall receive a refund of his member contribution plus interest compounded annually. The Plan is not subject to the requirements of the Employees Retirement Income Security Act of 1974 (ERISA). Funding Policy and Annual Pension Cost The contribution requirements of plan members and the Authority are established and may be amended by the Authority. The Annual Pension Cost (APC) and the Annual Required Contribution (ARC) were computed as part of an actuarial valuation performed as of June 30, 2013 and projected to June 30, 2014, based on current year demographic data.

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12. Employees’ Retirement Benefits (continued) Funding Policy and Annual Pension Cost (continued) The contribution requirements to the System of plan members and the Authority are established and may be amended by the Authority. The Authority’s annual pension cost to the System for the fiscal years ended June 30, 2014 and 2013 is as follows:

Fiscal Year Ending June 30 2014 2013

Annual required contribution $ 99,971,184 $ 89,405,009 Interest on net pension obligation 1,276,170 1,249,465 Adjustment to annual required contribution (972,705) (935,293)Annual Pension Cost 100,274,649 89,719,181

Contributions made and accruals (99,971,184) (89,405,009)Increase (decrease) on net pension obligation 303,465 314,172

Net pension obligation, beginning of year 15,013,760 14,699,588 Net pension obligation, end of year $ 15,317,225 $ 15,013,760

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12. Employees’ Retirement Benefits (continued) The Authority’s annual pension cost for the year ended June 30, 2014 and related information for the Plan and supplemental benefits follows:

Contribution rates: Pension Plan

Authority 29.29%

Average Plan members 10.44%

Annual pension cost (thousands) $100,275

Contributions made and accruals (thousands) $99,971

Actuarial valuation date 6/30/2012

Actuarial cost method Individual: Entry Age Normal

Amortization method Level percentage of pay, closed

(4% payroll increases per year)

Remaining amortization period 28 years

Asset valuation method 5-year smoothed market

Actuarial assumptions:

Investment rate of return (net of

administrative expenses)* 8.5%

Projected salary increases* 4.10% – 5.40% depending on age

*Includes inflation at 3.0%

Cost-of-living adjustments 8% per year for yearly pension up

to $3,600 and 4% per year for

yearly pension between $3,600

and $7,200, 2% per year for

yearly pension in excess of

$7,200. The minimum

adjustment is $300 per year. The

maximum is $600 per year.

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12. Employees’ Retirement Benefits (continued) Supplemental Benefits not Funded Through the System Trend Information (In millions) Annual Percentage Pension of APC Net Pension

Fiscal Year Ended Cost (APC) Contributed Obligation

Pension Plan: 06/30/12 84.6 99.6% 14.7 06/30/13 89.7 99.7% 15.0 06/30/14 100.3 99.7% 15.3

The annual required contribution amounted to $100.0 million and $89.4 million in 2014 and 2013, respectively. The net pension obligation is included in accounts payable and accrued liabilities in the Statements of Net Position. Supplemental benefits were unfunded and such benefits were reimbursed to the System when paid as of December 31, 1999. Effective January 1, 2000, the Board of Trustees of the System approved the transfer of the obligation for supplemental benefits provided by the Authority and not funded through the System (supplemental pension obligations exchanged for forfeited sick leave benefits and the supplemental spousal survivor benefits) to the Retirement System. Also, the Board of Trustees of the System accepted an amortization period for the Plan of 40 years, which commenced on June 30, 1996.

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12. Employees’ Retirement Benefits (continued) Supplemental Benefits not Funded Through the System (continued) Supplemental Pension Obligations Exchanged for Forfeited Sick Leave Benefits The Authority’s employees with over 20 years of service are entitled to exchange accrued sick leave for supplemental pension benefits just to complete merit annuity (30 years of service) and/or be paid in cash the value of such sick leave upon separation from employment. Other Post-Employment Benefits (OPEB) Postemployment Health Plan Plan Description – PREPA Retired Employees Healthcare Plan (Health Plan) is a single-employer defined benefit healthcare plan administered by the Authority. During fiscal year 2010, the Authority adopted a resolution to change the Health Plan. The Health Plan for all retirees will be capped at $300 per member per month for retirees and spouses under age 65 and $200 per member per month for retirees and spouses age 65 and over. Membership – During fiscal year 2010, the Health Plan changed to require all new retired employees on or after September 1, 2009, to have 30 year of services to receive health benefits. Certain retired employees on or after September 1, 2009, all retired employees before September 1, 2009, are eligible to participate in the Postretirement Health Plan. To remain eligible for participation, Medicare eligible retired participants and their spouses must enroll in Medicare Part B at age 65, or whenever eligible, at their own expenses. The benefit provisions to retired employees are established and may be amended by the Authority.

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12. Employees’ Retirement Benefits (continued) Other Post-Employment Benefits (OPEB) (continued) Funding Policy and Annual OPEB Cost – The required contribution is based on projected pay-as-you-go financing requirements. The contribution requirements of plan members and the Authority are established and may be amended by the Authority. The Annual OPEB Cost is calculated based on the Annual Required Contribution (ARC) of the employer, an amount actuarially determined in accordance with the provisions of GASB Statement No. 45. The ARC represents a level of funding that, if paid on ongoing basis, is projected to cover normal cost each year and amortize any unfunded actuarial liabilities over a period not to exceed thirty years. The following table shows the components of the Authority’s annual OPEB cost for fiscal years 2014 and 2013 (in thousands): 2014 2013 Annual OPEB cost $ 19,553 $ 20,464 Actuarial Accrued Liability (AAL) $378,444 $408,419 Unfunded AAL $378,444 $408,419 Funded Ratio 0% 0% Annual Covered Payroll $364,982 $357,405

The net OPEB obligation change is as follows (in thousands): 2014 2013 Change in net OPEB obligation:

Net OPEB obligation, beginning balance $119,826 $122,627 Total annual required contribution (ARC), July 1–

June 30 18,754 19,647 Interest on Net OPEB obligation 4,793 4,905 Adjustments to annual required contribution (3,994) (4,088) Actual benefit payments, July 1–June 30 (20,204) (23,265)

Net OPEB obligation, ending balance $119,175 $119,826 For the fiscal years ended June 30, 2014 and 2013, the Authority’s annual OPEB expense was $19.6 million and $20.5 million, respectively. This expense is included in Administrative and General Expenses.

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12. Employees’ Retirement Benefits (continued) Other Post-Employment Benefits (OPEB) (continued) Postemployment Health Plan (continued) The OPEB expense is not equal to the Annual Required Contribution, which is considered in operating expenses in the Authority’s Statement of Revenues, Expenses and Changes in Net Position. For the fiscal year ended June 30, 2014, the Authority’s annual OPEB expense of $19.6 million, which is included in Administrative and General Expenses. The OPEB expense is considered in operating expenses in the Authority’s Statement of Revenues, Expenses and Changes in Net Position. The payment to the health plan for retirees and their beneficiaries totaled $20.2 million for fiscal year 2014. The Authority’s annual OPEB cost, and the net OPEB obligation for 2014 and the two preceding years were as follows: Trend Information (In millions) Annual Percentage of Annual OPEB OPEB Net OPEB

Fiscal Year Ended Cost Cost Contributed Obligation06/30/12 $ 20.5 75% $ 122.606/30/13 $ 20.5 113% $ 119.8 06/30/14 $ 19.6 103% $ 119.2

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12. Employees’ Retirement Benefits (continued) Other Post-Employment Benefits (OPEB) (continued) Postemployment Health Plan (continued) OPEB Actuarial Valuation – The Authority’s other Post-Employment Benefits Program actuarial valuation was conducted by Cavanaugh Macdonald Consulting, LLC. Cavanaugh Macdonald Consulting, LLC is a member of the American Academy of Actuaries. The valuation was performed in accordance with GASB Statement No. 45 requirements. Actuarial Methods and Assumptions:

Actuarial Valuation Date July 1, 2012 Actuarial Cost Method Projected Unit Credit Amortization method Level Percent of Pay, Open Remaining Amortization Period 30 years Actuarial Assets Valuation Method Market Value of Assets Investment Rate of Return 4% (includes inflation rate) Inflation Rate:

Medical Prescription drug Dental

3% Not applicable Not applicable Not applicable

Projected Salary Increases 4% The required schedule of funding progress included supplementary information (Schedule I) that presents multiyear trend information about whether the actuarial value of plan assets is increasing or decreasing over time relative to the actuarial accrued liability for benefits. The actuarial calculations reflect a long-term perspective. Consistent with that perspective, actuarial methods and assumptions used include techniques that are designed to reduce short-term volatility in actuarial accrued liabilities and the actuarial value of assets.

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13. Revenues from Major Clients and Related Parties Electric operating revenues from major clients and related parties are as follows: 2014 2013 (In thousands) Governmental sector, principally instrumentalities, agencies

and corporations of the Commonwealth of Puerto Rico $ 566,379 $ 639,849 Municipalities of the Commonwealth of Puerto Rico 249,310 260,839 $ 815,689 $ 900,688 14. Net Position As of June 30, 2014, the Authority is in a net deficit position. The Authority faces a number of business challenges that have been exacerbated by the Commonwealth’s economic recession, the volatility in oil prices, and the fact that the Authority has not increased rates to its customers at sufficient levels to offset the effects of its rising costs. Its principal challenges, some of which are interrelated, are: (i) addressing the decline in electric energy sales; (ii) addressing the volatility of oil costs; (iii) addressing high customer electric power rates; (iv) reducing government accounts receivables; and (v) improving its liquidity. In June 2014, the Authority entered into discussions with its financial with its financial stockholders in an effort to stabilize the Authority’s liquidity situation and address its financial position. See further discussion in Notes 19 and 20. 15. Contribution in Lieu of Taxes 2014 2013 (In thousands) Municipalities $ 249,310 $260,839 Commonwealth:

Hotels 8,685 8,869 Fuel adjustment subsidy 19,781 27,843

$ 277,776 $297,551

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16. Commitments and Contingencies Environmental Matters Facilities and operations of the Authority are subject to regulation under numerous Federal and Commonwealth environmental laws, including the Clean Air Act, Clean Water Act, Oil Pollution Act (OPA), Resource Conservation Recovery Act (RCRA), Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) and Underground Storage Tanks, among others. In February 1992, the Environmental Protection Agency (EPA) conducted a multimedia inspection of the Authority’s facilities and identified several alleged instances of non-compliance related to the Authority’s air, water and oil spill prevention control and countermeasures compliance programs. The Authority and the EPA negotiated to resolve the issues regarding the deficiencies observed during the inspection and to ensure future compliance with all applicable laws and regulations. As a result of the negotiations, the Authority and the EPA reached an agreement that resulted in a consent decree (the Consent Decree) approved by the United States federal court in March 1999. Under the terms and conditions of the Consent Decree, the Authority paid a civil penalty of $1.5 million, and implemented additional compliance measures amounting $4.5 million. In addition, the Consent Decree requires that the Authority improve and implement compliance programs and operations in order to assure compliance with environmental laws and regulations. In 2004, the United States federal court approved a modification to the Consent Decree agreed by the Authority and the EPA under which the Authority reduced, in two steps, the sulfur content in the No. 6 fuel oil used in certain generating units of its Costa Sur and Aguirre power plants (to 0.75% or less by March 1, 2005 and to 0.5% or less by March 1, 2007), and used No. 6 fuel oil with sulfur content of not more than 0.5% through July 18, 2009 at its Palo Seco and San Juan power plants. Additionally, the Authority has completed a nitrogen oxide emissions reduction program and modified the optimal operating ranges for all its units under the Consent Decree. The Authority also paid a $300,000 civil fine and reserved $200,000 to fund certain supplemental environmental projects and programs under the Consent Decree.

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16. Commitments and Contingencies (continued) Environmental Matters (continued) PREPA has audited several instances for compliance with the Consent Decree programs, and understands that a considerable number of them can be closed since their requirements have been completed. PREPA has formally requested to meet with EPA on August 20, 2010; February 25, 2011; May 23, 2012 and June 15, 2012 to begin the process conducive to the partial termination of certain provisions of the Consent Decree and its Modification. On July 22, 2014, representatives from PREPA, EPA and United States Department of Justice (DOJ) met to begin the discussion towards the termination of some of the programs. As a result, the EPA and the DOJ requested PREPA to submit information regarding PREPA’s compliance with the Programs for their review and evaluation. On September 25, 2014, PREPA met again with EPA and DOJ representatives and submitted the information requested, along with a letter formally requesting the EPA to review and approve the termination of those programs/provisions of the Consent Decree and its Modification of 2004 presented, as well as begin the process toward jointly filing in the Court a stipulation for Partial Termination of such programs. To accomplish this goal, PREPA suggested appointing a task force composed of EPA and PREPA representatives to schedule and meet to address the details agreed upon with EPA. On May 27 and 28, 2015, PREPA, EPA and DOJ legal representatives met to begin discussions about PREPA’s termination claims, as well as define any additional documentation requested to support and demonstrate PREPA’s determination of compliance with the different programs obligations. Additional information has been exchanged between all parties, and a follow-up meeting was held on October 1, 2015. EPA, PREPA and DOJ representatives continue with the thorough evaluation and discussion process of the information submitted by PREPA. Since September 2004, there has been no legal action in the United States federal court or any administrative proceeding against the Authority regarding the Consent Decree or its modification. The Consent Decree includes stipulated penalties for certain events of non-compliance. Non-compliance events must be disclosed to EPA in the corresponding report. Ordinarily, when a covered non-compliance event occurs, the Authority pays the stipulated penalty in advance in order to benefit from a 50% discount of the applicable stipulated penalty.

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16. Commitments and Contingencies (continued) Environmental Matters (continued) Other Proceedings In 1997, as a result of an inspection carried out by the EPA and the Puerto Rico Environmental Quality Board (the EQB) at the Authority’s Palo Seco power plant, the EPA issued an Administrative Order for the investigation and possible remediation of seven areas identified by the EPA at the Palo Seco power plant and the Palo Seco General Warehouse (Depot). The Administrative Order required the Authority to carry out a Remedial Investigation/Feasibility Study (RI/FS). The RI/FS required under the order was designed to: (1) determine the nature and extent of contamination and any threat to the public health, welfare or environmental caused by any release or threatened release of hazardous substances, pollutants, or contaminants at or from the site; and (2) determine and evaluate alternatives for the remediation or control of the release or threatened release of hazardous substances, pollutants, or contaminants at or from the site. The RI was completed and a final report was submitted to EPA for evaluation. The information gathered under the RI reflected the presence of free product (Separate Phase Hydrocarbons) in several monitoring wells. The analysis of this product also reflected a low concentration of polychlorinated biphenyls (PCBs). PREPA and EPA entered into an Administrative Order on Consent (AOC) (CERCLA-02-2008-2022) requiring the Authority to complete a removal plan that consisted of determining if the underground water had been impacted by PCBs, the extent of the contamination and the implementation of a work plan for free product removal. Analytical data collected during this activity reflected that underground water had not been impacted by PCBs. Nevertheless, water/oil mix was found in seven monitoring wells (MWs). PCBs concentrations between 1.36-2.36 parts per million were detected in the oil found in 3 of the 7 MWs. Multiphase extraction (MPE) activities in the MWs where water/oil phases were found, has been performed on a weekly basis. After several MPE, this activity was discontinued under the USEPA’s recommendations. On April 19, 2012, PREPA submitted for EPA’s review and approval the final report letter for the AOC. On August 13, 2012, EPA notified PREPA by certified mail, that the final report was reviewed and determined that the work required pursuant the AOC has been fully carried out in accordance with its terms. Also the letter indicated that the notification shall not affect any continuing obligation of respondents, including but not limited to the reimbursement of EPA response costs, as specified in the AOC.

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16. Commitments and Contingencies (continued) Environmental Matters (continued) Other Proceedings (continued) Based on the findings of the RI, the Human Health Risk Assessment, the Screening Level Ecological Risk Assessment and the AOC, NO ACTION recommendation under CERCLA for the PREPA, The Palo Seco site is believed to be protective of human health and environment. The risk assessments indicate that the levels of residual contaminants present at the site fall within EPA’s acceptable risk range. This non-action remedy complies with the federal and commonwealth requirements. “Both Orders” with Both AOC’s established a Reimbursement of Costs condition in which the Authority agreed to reimburse EPA for all costs incurred by EPA in connection to the site. The Authority has not been charged for these costs to date and therefore there is no amount recorded in the financial statements for these cost reimbursements. In 2002, the Authority received a “Special Notice Concerning Remedial Investigation/Feasibility Study for Soil at the Vega Baja Solid Waste Disposal Superfund Site. The EPA has identified the Authority and six other entities as “potentially responsible parties”, as defined in the CERCLA. In 2003, the Authority agreed to join the other potentially responsible parties in an Administrative Order on Consent (AOC) for an RI/FS, with the understanding that such agreement did not constitute an acceptance of responsibility. Under the AOC, the Authority committed up to $250,000 as its contribution to partially fund the RI/FS. At this time, RI/FS has been completed. The work proceeded in accordance with the schedule established by the Authority and the other designated potentially responsible parties. On July 2010, a proposed Plan was issued identifying the Preferred Alternative to address soil contamination at the Vega Baja Solid Waste Disposal Site. EPA held a public hearing on August 3, 2010 to discuss the alternatives to address soil contamination.

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16. Commitments and Contingencies (continued) Environmental Matters (continued) Other Proceedings (continued) The Record of Decision (ROD) was published as scheduled by EPA on September 30, 2011. Alternative No. 2, Removal with On-Site Consolidation and Cover in the Non-Residential Area, was selected. From this point on, EPA resumed negotiations with the Potential Responsible Parties (PRP’s), both private and public, towards signing a Consent Decree through which the PRP’s would contribute enough funds to cover the costs of the remedial action and the maintenance of the site. PREPA has already approved a contribution of $1,000,000 through Resolution 3804, April 1, 2011. Notwithstanding, through further negotiations an additional contribution of $300,000 was required by EPA. This additional contribution was approved by PREPA’s Governing Board. On December 4, 2012, the Federal Department of Justice lodged with the Court the Consent Decree (CD) Civil Action No. 3:12-cv-01988, which requires that PREPA shall pay to EPA for the Past Response Costs of the agency the amounts of $300,000 within 30 days of the effective date; $300,000 not later than August 15, 2013 and $300,000 not later than August 15, 2014. In accordance with the definition of “effective date” in the CD, is the day the decree is entered on the court’s docket controls. The Federal Court signed the CD on April 19, 2013 and entered the CD on the Docket on April 25, 2013. PREPA has complied with the Past Response Cost payment provided in the CD. To this date, PREPA has fulfilled all the Payments obligations in relation to this requirement. On April 10, 2013, an Environmental Escrow Agreement (EEA) was entered into by and among the Government Development Bank for the Puerto Rico, as the escrow agent, the Puerto Rico Land Authority, the Puerto Rico Housing Department and PREPA; and the United States of America on behalf of the Environmental Protection Agency. This agreement became effective on April 25, 2013. The EEA (Account No. 251-0395-2) was created to serve as financial assurance for the performance of the obligation under the CD. On June 24, 2013, PREPA deposited $400,000 into the escrow as provided in the CD.

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16. Commitments and Contingencies (continued) Environmental Matters (continued) Other Proceedings (continued) As agreed by the parties, this CD can be terminated upon motion by any party, provided that all public Defendants have satisfied their obligations of payments of Response Cost and Stipulated Penalties. Termination of this Consent Decree shall not affect the Covenants Not to Sue (Sections XX and XXI of the CD) including all reservations pertaining to those covenants and shall not affect any continuing obligation of the Settling Defendants under sections IX, X, XVI, XXIII and XXIV of the CD. Compliance Programs The Authority continues to develop and implement a comprehensive program to improve environmental compliance in all applicable environmental media. This program has been and continues to be updated to conform to new regulatory requirements. Air Quality Compliance The Authority is consistently maintaining a 99% or better level of compliance with in stack opacity requirements. The Authority continues to use No. 6 fuel oil with sulfur content of 0.5% or better in its San Juan, Palo Seco and Aguirre Power Plants. In the case of the South Coast power plant, Units 5 and 6 have been converted to use natural gas, and are currently operating on a dual-fuel scenario. Units 3 and 4 operate minimally, and use Bunker C as fuel oil. Mercury and Air Toxics Standards The Mercury and Air Toxics Standard (MATS) was published by the Environmental Protection Agency (EPA), pursuant to Section 112 of the Clean Air Act (CAA), to establish national emission standards for hazardous air pollutants (NESHAP) limits and work practice standards for pollutants emitted from coal and oil fired electric utility steam generating units (EGU). It became effective on April 16, 2012, sixty days after it was published as a Final Rule in the Federal Register, Vol. 77, No. 32 on February 16, 2012.

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16. Commitments and Contingencies (continued) Compliance Programs (continued) Mercury and Air Toxics Standards (continued) The requirements established by the MATS are found in the Code of Federal Regulations, Title 40, Part 63, Subpart UUUUU, National Emission Standards for Hazardous Air Pollutants from Coal and Oil Fired Electric Utility Steam Generating Units. The terms and definitions used in this regulation are included in 40 CFR 63.10042, Subpart UUUUU. The MATS applies to new, reconstructed or existing coal- and oil-fired EGUs in continental and non- continental areas (from industry, federal government, state and tribal government). In the case of Puerto Rico, there are fourteen (14) oil-fired EGUs affected by the regulation, which are operated and maintained by the PREPA, and two (2) coal-fired EGUs which are operated and maintained by AES-Puerto Rico, LLP. The new rule requires that the affected units comply with the new standard requirements by April 16, 2015. According to MATS, owners/operators of units that cannot comply by the initial compliance date of April 16, 2015 can request an additional year (1st year) from the local environmental regulatory agency. In Puerto Rico, according with section 112(i)(3), of the CAA, the EQB has the delegated authority to approve such extension. Owners and operators can also request a second year (2nd year) extension to the EPA for those units that are determined to be critical to the reliability of the electrical system. This is based on the EPA’s Enforcement Policy for Use of Clean Air Act Section 113(a) Administrative Orders in Relation to Electric Reliability and the Mercury and Air Toxics Standard of December 16, 2011. In order to obtain the second year extension, an early notice of compliance plans must be filed with the local Planning Authority (The Puerto Rico Planning Board) by April 16, 2013, a year after the effective date of the rule.

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16. Commitments and Contingencies (continued) Compliance Programs (continued) MATS Compliance Strategy Pursuant to Section 112(1)(3) of the Clean Air Act, PREPA initiated the process for requesting an Administrative Order for some of the EGUs affected by the MATS and to obtain from the EPA a 2nd year extension to the MATS initial compliance date for such units determined to be critical for the reliability of Puerto Rico’s electrical system. On April 16, 2013, PREPA submitted an Early Notice of Compliance Plan to the Puerto Rico Planning Board. On May 14, 2013, the Governor of Puerto Rico issued an Executive Order (No. 2013-040) to create an Electrical Reliability Council, whose main goal is to evaluate the impact of the MATS implementation strategies and the integration of renewable energy source projects on the Puerto Rico’s electrical system’s operation and reliability. The Council creation became necessary because Puerto Rico is not subject to NERC or FERC jurisdiction. This Council would also serve as the Technical Advisor to the Puerto Rico Planning Board regarding PREPA’s claim of the critical reliability impact of the EGUs included in the Early Notice of Compliance Plan. PREPA has developed and commenced the implementation of this compliance plan for the new MATS emission limit requirements, as well as to address compliance with future air compliance regulations. Continuous compliance of some of the existing applicable units with MATS and future air compliance regulations requires the construction and development of a natural gas supply infrastructure in the Island of Puerto Rico. Unlike the Continental United States, this infrastructure is currently extremely limited to one port in the south side of the Island with no transmission and distribution pipelines. If natural gas is to be a viable option, infrastructure needs to be developed to supply some of PREPA’s existing EGUs and any new future generation units. The development and construction of such infrastructure will result in the delay of the installation of controls (conversion projects) at some of the selected PREPA’s existing EGUs, some of which require the EQB to grant a 1st year extension of the MATS initial compliance date of April 16, 2015. Such delays also affect other existing EGUs that are critical to the Puerto Rico’s isolated electrical grid reliability.

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16. Commitments and Contingencies (continued) Compliance Programs (continued) MATS Compliance Strategy (continued) In the case of Costa Sur Units 5 and 6, the EGUs were converted to have the capacity to use natural gas and bunker C in a dual -fuel scenario 2011. Under MATS classification, they have been designated as Non-Continental Liquid Oil-Fired EGUs. The infrastructure to supply natural gas to these EGUs is located in the EcoEléctrica’s Liquefied Natural Gas terminal located in Peñuelas. Units 3 and 4 will be designated as Limited-Use Liquid Oil-Fired EGUs, which entails limiting each unit’s operation to less than 8% in a 24 months block period of their respective nameplate heat input capacity, effective on April 16, 2015. For the Aguirre Power Complex Units 1 and 2, they will be designated as Natural Gas-Fired EGUs upon completion of their respective conversion projects to provide them with the capacity to use natural gas as the primary fuel. Under this category, these EGUs will not be subject to MATS. To supply natural gas to the units, PREPA is committed to contract the development of the AOGP with Excelerate Energy, LLC, which is the contractor chosen to develop, construct and operate this gas port. The gas port will be located approximately 3 miles offshore the Jobos Bay in the municipality of Salinas, within the southern shore of the Commonwealth of Puerto Rico’s territorial waters. The floating LNG terminal comprises an LNG transfer platform, a floating storage and regasification unit (FSRU), and a 4.1 mile long submarine natural gas pipeline. LNG will be received through LNG carriers that will dock in the terminal’s platform. This project is currently in the process of obtaining the required regulatory certifications, endorsements, approvals, and permits from the agencies with jurisdiction (EQB, FERC and OGPe, among others) prior to commencing its construction. The AOGP construction is expected to end after the MATS initial compliance date, for which PREPA requested the EQB for a one year extension from the initial compliance date. Such extension was granted by EQB on March 28, 2014, allowing PREPA until April 16, 2016 to complete the conversion projects and demonstrate compliance with MATS.

No. CEPR-AP-2015-0001

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16. Commitments and Contingencies (continued) Compliance Programs (continued) MATS Compliance Strategy (continued) On the Early Notice of Compliance Plan presented to the Puerto Rico Planning Board and EPA, PREPA presented the conversion of the San Juan Units 9 and 10 and Palo Seco Units 3 and 4 as the compliance strategy to follow. As explained before, the key condition for achieving this goal is the existence of a feasible natural gas managing infrastructure in the north coast of the Island to supply these EGUs. Following the Plan, in July 2013, PREPA began the process of requesting information from different natural gas companies and suppliers. Over thirty (30) companies provided presentations and information to PREPA regarding different proposals and alternatives to satisfy the project requirements. On August 2013, PREPA initiated a process with the Puerto Rico Public-Private Partnerships Authority (PPPA) process for the determination of the best technology and cost-effective alternative for the project, as well as the selection of the proposal and company that best fits such determination. On November 2013, the PPPA and PREPA selected KMPG as the financial advisor company that will be responsible for the evaluation of the financial investment alternatives, generation of the required request for proposals (RFP’s) and the final selection of the companies that comply with the established requirements. Galway Group, LP was also selected as technical advisor for the project. They will be responsible for the generation of a Desirability and Convenience Study, the first draft report for this study was submitted in June 2015. Also, PREPA contracted Siemens Power Technologies International to perform a feasibility study to determine the impacts on the security of PREPA’s electrical system upon the possible suspension of power generation from Aguirre Units 1 and 2, San Juan Units 9 and 10, and Palo Seco Units 3 and 4 these units due the application of the Mercury and Air Toxic Standards (MATS). The study was concluded and the results presented to PREPA on September 12, 2014. The study concluded that these units are considered critical to maintain the Puerto Rico’s electrical system reliability.

No. CEPR-AP-2015-0001

I 000226



1501-1384337 92

16. Commitments and Contingencies (continued) Compliance Programs (continued) MATS Compliance Strategy (continued) Another factor that has affected the Plan’s implementation for these units is that PREPA is currently under the Forbearance Agreement with its creditors. Such agreement requires to Alix Partners, acting as Chief Restructuring Officer, to develop a Business Plan, which includes the development of an Integrated Resource Plan (IRP). The first phase of the IRP was completed and presented to PREPA on November 13, 2014. The alternatives presented by the study consider the replacement of these units by new and more efficient technologies, such as high efficiency combined cycles. In March 2015, PREPA contracted Siemens to complete the second phase of the IRP, which is currently underway and is expected to be completed before by June 2015. On December 3, 2014, PREPA requested the EQB a one-year extension to the MATS initial compliance date for each of these EGUs. The EQB requested PREPA additional information, which could not be supplied in the time provided since compliance alternatives implementation schedules are subject to the completion of the second phase of the IRP and the restructuring process results. In the case that compliance with MATS cannot be achieved for these units in the time allowed, including the extensions granted, PREPA considers reaching a settlement agreement with EPA to agree on a Consent Decree (or modify the existing one) to cover the period required to convert the existing EGUs to natural gas or replace them by a new and more efficient technology, and comply with the MATS requirements. For the rest of the applicable EGUs (San Juan Units 7 and 8, and Palo Seco Units 3 and 4), they will be designated as Limited -Use Liquid Oil-Fired EGUs, which entails limiting each unit’s operation to less than 8% in a 24 months block period of their respective nameplate heat input capacity, effective on April 16, 2015. QA/QC Continuous Monitoring Program This program requires quarterly audits to the opacity monitors in PREPA’s power plants to insure compliance with the Consent Decree Clean Air Compliance Program. Also, this program requires annual quality assurance audits to the optimization monitors at our power plants in compliance with the Consent Decree. All these reports have been performed and submitted in compliance with the Consent Decree stipulations.

No. CEPR-AP-2015-0001

I 000227



1501-1384337 93

16. Commitments and Contingencies (continued) Compliance Programs (continued) Relative Accuracy Test Audit (RATA) A Relative Accuracy Test Audit (RATA) is a test to validate and certify for a period of one year the plant’s Continuous Emission Monitoring Systems (CEMS) equipment for purposes of continuous data collection. The requirements to perform this test are found at 40 CFR Part 60 Appendix F and is to insure compliance with the Plants PDS air operation permits. Annually reports have been performed and submitted in compliance with the air operation permits requirements. The Authority was not able to perform the RATA test for 2012 for Unit 3 at Cambalache Power Plant, due to operational problems with the plant. These tests were performed during February 2013. Title V Permitting Program PREPA is still awaiting issuance of a Title V Permit for the Palo Seco Power Plant. The permit application was submitted in November 1996. The Environmental Quality Board continues to request additional information. The last information request was received on January 27, 2012. The information requested was submitted on February 7, 2013. No other information has been requested. The EQB has not issued a final permit. PREPA is also awaiting issuance of a Title V for the San Juan Power Plant. A modification was submitted to include the natural gas scenario for units 5 and 6. EQB has not issued a final permit, but issued a permit shield on November 2, 2009. In September 2011, PREPA submitted a modification of the Costa Sur Power Plant’s Title V permit to include the natural gas scenario for units 5 and 6. The EQB has not issued a final Title V permit. The Title V permit for the Aguirre Power Complex expired on February 24, 2013. A permit renewal application was submitted in February 24, 2012. The Environmental Quality Board deemed the application as complete and, on June 12, 2012 issued a permit shield.

No. CEPR-AP-2015-0001

I 000228



1501-1384337 94

16. Commitments and Contingencies (continued) Compliance Programs (continued) Title V Permitting Program (continued) PREPA had a scheduled meeting with the EQB (April 18, 2013) to discuss, among other things, the status of the Title V permits. Our goal is to have EQB issue all the permits in draft form to allow a comment period from PREPA. After this, the comments are either incorporated in the permit or rejected. Then, a final permit can be issued. Water Quality Compliance As of December 2010, the Authority had achieved and has maintained a level of compliance with the Clean Water Act regulations (NPDES permits, Safe Drinking Water Act, OPA’90 (FRP’s and Operations Manual) and SPCC Regulation) in excess of 99%. The Authority has completed compliance plans for abating water pollution at its four major power plants - Aguirre, San Juan, South Coast, and Palo Seco, as required by the Consent Decree, Section VI, Part I. PREPA prepared and submitted the San Juan Power Plant NDPES Renewal Application on September 30, 2011. In compliance with the regulatory requirement, PREPA submitted it 180 days before the current NDPES Permit expiration date (March 31, 2012). The current NPDES Permit is administratively extended until the EPA grants a renewed permit. PREPA uses drinking water from the Puerto Rico Aqueducts and Sewer Authority (PRASA) as raw water in order to generate electricity at the San Juan Power Plant. In 1994, Puerto Rico experienced a prolonged drought that forced PRASA to implement a water rationing plan, which limited the operation of the San Juan generating units. In addition, this power plant has exceedances related to the NPDES Discharge Permit (National Pollutants Discharge Elimination System) PR0000698. Specifically, with Outfalls 002 and 003 permit limit exceedances. The issuance of a new NPDES permit for SJPP in 2007 and a Water Quality Standards Regulation revision from the EQB in 2003 imposed more restrictive permit limits, which eventually led to the issuance of an Administrative Order (AO) CWA-02-2010-3119 by the EPA. As a control measure, PREPA began the process of developing and implementing the San Juan Waste Water Treatment Plant Improvement project (PREQB Project No. C-72-096-40) to reuse the Outfalls 002 and 003 process wastewater leaving these discharges as stormwater only.

No. CEPR-AP-2015-0001

I 000229



1501-1384337 95

16. Commitments and Contingencies (continued) Compliance Programs (continued) Water Quality Compliance (continued) In December 2015, PREPA expects to complete the Phase I of the San Juan Waste Water Treatment Plant Improvement Project. This phase consists of the reuse of the generating units feedwater heaters condensations. Phase IV that consists of the acquisition and installation of Microfiltration and Reverse Osmosis Systems is in a pre-bid process. PREPA’s power generation, especially steam power plants, requires the high volumes of water. In the case of the Aguirre Power Complex (APC), this water comes from a water well system owned and operated by PREPA. These water wells supply capacity has been reduced throughout the years due to urban expansion in the Salinas Municipality, causing salt water intrusion to the aquifer. Considering this, PREPA determined to develop and construct the necessary infrastructure to supply raw water from the Patillas Irrigation Channel to the APC, keeping the current well water supply as back-up. The raw water will then be treated in the APC using ultrafiltration or microfiltration, reverse osmosis and demineralization methods. Also, the project provides for the reuse of condenser cooling water that is currently discharged thru the APC Outfalls, under the National Pollutant Discharge Elimination System Permit Program (NPDES Permit Program) required by Title 40 of the Code of Federal Regulations, Part 122. PREPA already completed the Phase II (Filtration System Building) in March 2015 of the Water Supply Project from the Patillas Irrigation Channel. Phase III (Retention Ponds Construction) of this project is in the bid adjudication process and Phase I (Pipeline Construction from the Irrigation Channel) is in a pre-bid process. For the financing of the San Juan Waste Water Treatment Plant Improvement (C-72-096 -40) and the Water Supply Project from Patillas Lake Irrigation Channel Projects (C-72-128- 19), PREPA signed two Loan Agreements at 2% interest rate, pursuant to the Commonwealth of Puerto Rico Water Pollution Control State Revolving Fund Program (SRF Program). The first one was signed on September 6, 2012 for the amount of $17,560,028 and the second one on September 27, 2013 for the amount of $9,463,258.00. The September 27, 2013 agreement included a Grant for the amount of $1,536,742. These projects were not included in the PREPA’s Capital Improvement Plan.

No. CEPR-AP-2015-0001

I 000230



1501-1384337 96

16. Commitments and Contingencies (continued) Compliance Programs (continued) Water Quality Compliance (continued) Since 1977, PREPA submitted to EPA an updated request under Section 316(a) of the Clean Water Act that its South Coast power plant be permitted to discharge into the Caribbean Sea heated sea water that was previously used for cooling purposes, as part of the plant’s combustion and generation process, known as “thermal effluent”. EPA denied a 316(a) Thermal Variance Request in December 2000. After several discussions and meetings, EPA and PREPA agreed to perform a Detailed Engineering and Environmental Review (DEER) of alternatives to select a final alternative for the cooling water discharge that meets the water temperature standard or otherwise, qualify for a waiver request under Section 316(a) of the Water Quality Act. While the DEER was in progress EPA issued a draft permit for the power plant, which included a compliance schedule for the DEER selected alternative (Offshore Submerged Discharge – OSD). The selected alternative estimated capital cost is approximately $60 million. EPA issued a final permit in October 1, 2009 with a schedule of compliance for relocation of Outfall 001. PREPA submitted the scoping document, an inventory of the environmental studies already performed and a Joint Permit Application for the Outfall 001 relocation in December 2009. As part of the permit requirements, PREPA prepared a Preliminary Environmental Impact Statement (PEIS) including the discussions of four alternatives for the 001 Outfall by October 2011. The PEIS included an in-cove alternative to reduce the cooling water discharge temperature to a thermal tolerance temperature range based on operations improvements and partial restoration of the historic flow. On January 30, 2013, PREPA submitted a Final Environmental Impact Statement (FEA) at the Puerto Rico Management Permits Office (OGPe) including the in-cove alternative, as the preferred one. PREPA prepared and submitted the South Coast Power Plant NDPES Renewal Application on March 30, 2014. In compliance with the regulatory requirement, PREPA submitted the application 180 days before the current NDPES Permit expiration date (September 30, 2014). The current NPDES Permit is administratively extended until the EPA grants a renewed permit. As part of the NPDES permit renewal, PREPA included OGPe’s determination that the in-cove is the less environmental impact activity according to Section 4(b)(3) of the Environmental Public Policy Act [Act 416 – 2004].

No. CEPR-AP-2015-0001

I 000231



1501-1384337 97

16. Commitments and Contingencies (continued) Compliance Programs (continued) Water Quality Compliance (continued) EPA included, as part of Section 316(a) requirements in the current San Juan Power Plant NPDES Permit, the performance of thermal plume studies and the biological monitoring program. PREPA submitted the thermal plume study plan and the QA/QC Plan for the Biological Monitoring Program in March 13, 2009, and it is waiting for EPA approvals. Also, EPA included, as another compliance requirement, the performance of a Comprehensive Demonstration Study (CDS) under the Section 316(b) of the Clean Water Act. On March 31, 2008, PREPA submitted an Impingement and Entrainment Characterization Study and Current Status Report for EPA evaluation. Also, PREPA submitted a Post-repowering Verification Study Work Plan for 316(b) in June 30, 2008 and it is waiting for EPA approval. PREPA made a reference of all the above mentioned pending work plans approvals and 316(b) reports at the San Juan Power Plant NDPES Renewal Application submitted to EPA on September 30, 2011. EPA has not responded to this petition yet. Proposed Regulation under the CWA Pursuant to a consent decree with environmental organizations, the EPA has issued past rulemaking under Section 316(b) of the CWA in three phases. Existing large electric-generating facilities were addressed in Phase II of the rulemaking which was finalized in February 2004, while the existing small electric-generating and all manufacturing facilities were addressed in Phase III of the rulemaking, which was finalized in June 2006. However, the Phase II rulemaking and a portion of the Phase III rulemaking were subject to legal challenges and, therefore, remanded to EPA for reconsideration. As a result, on April 20, 2011, EPA published a new draft rule pertaining to Section 316(b) of the CWA. Compliance with this rule is established in reference to the date of issuance of the final rule. According to the terms of a settlement agreement with Riverkeeper, EPA was required to issue the final rule by July 27, 2012. The final rule was not issued by EPA at the proposed date, but instead signed an agreement with Riverkeeper (the “Third Amendment”) to finish the rule by November 4, 2013. EPA issued the 316 (b) Final Rule on November 12, 2014.

No. CEPR-AP-2015-0001

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1501-1384337 98

16. Commitments and Contingencies (continued) Compliance Programs (continued) Proposed Regulation under the CWA (continued) This new regulation has three (3) components. First, existing facilities that withdraw at least 25 percent of their water from an adjacent water body, exclusively for cooling purposes, and have a design intake flow of greater than 2 million gallons per day would be subject to an upper limit on the amount of fish allowed to be affected by impingement. To comply with this requirement, each facility is given the option of selecting the technologies that would be best suited to address it or reduce its intake velocity to 0.5 feet per second. Second, existing facilities that withdraw very large amounts of water, at least 125 million gallons per day, would be required to conduct studies to help their permitting authority determine whether and what site-specific controls, if any, would be required to reduce the number of aquatic organisms sucked into cooling water systems, known as entrainment. Third, new units that add electrical generation capacity at an existing facility would be required to add technology that is equivalent to closed-cycle cooling which may be achieved by incorporating a closed-cycle system into the design of the new unit or making other design changes with equivalent results. PREPA has developed and is in the process of implementing an impingement and entrainment control technology (Aquatic Filter Barrier) in its South Coast Power Plant. This technology includes the verification sampling for impingement and entrainment. On June1, 2011, PREPA prepared and submitted to EPA a Plan of Action (“POA”) for the South Coast Power Plant. The POA recommends the steps required to achieve the impingement and entrainment reduction. Based on these steps, PREPA understands that it will be able to comply with the existing NPDES permit conditions. In January 2015, PREPA finished the installation of an Aquatic Barrier at Units 5 and 6 Intake Structure, according with the compliance alternatives included in the EPA’s POA. Also, PREPA received an Hydrolox Traveling Screen in March 2015, to be install in the Unit 5 Intake Area. PREPA received a proposal from his consultant for the verification sampling for impingement and entrainment at Guayanilla Bay.

No. CEPR-AP-2015-0001

I 000233



1501-1384337 99

16. Commitments and Contingencies (continued) Compliance Programs (continued) Underground Injection Control Regulation PREPA has prepared a compliance plan to comply with the EQB’s underground injection control regulations. This plan entails the closing of certain septic systems where sanitary discharges can be connected to the Puerto Rico Aqueduct and Sewer Authority (PRASA) system. As of December 2014, the projects at San Juan, Aguirre, Palo Seco, and South Coast Power Plants for the connection of the sanitary discharges to the PRASA system have been completed. PREPA completed the sampling and analysis of the septic systems at Aguirre, Palo Seco and San Juan. Currently, EQB’s has not issued their evaluation in order to close the underground injection systems at Aguirre, Palo Seco and San Juan Power Plants. Spill Prevention Control and Countermeasures Plan (SPCCP) Under Section 311 of the CWA, EPA has issued regulations setting forth requirements for prevention of, preparedness for, and response to oil discharges at specific non-transportation-related facilities. To prevent oil from reaching navigable waters and adjoining shorelines, and to contain discharges of oil, the regulation requires these facilities to develop and implement SPCC Plans, and establishes procedures, methods and equipment requirements. Pursuant to the terms of the Consent Decree, PREPA was required to implement a Spill Prevention Maintenance and Construction Program (SPMCP). This program included major overhauls to dikes and fuel tanks. As of December 2009, the Authority completed all compliance projects under the SPMCP of the Consent Decree, in accordance with the established scope of work. PREPA has a program to comply with new SPCC requirements, which became effective on November 10, 2011. These requirements addressed the containment of potential leakages from oil containing electrical equipment in its distribution substations. PREPA has already implemented the monitoring and inspection requirements under these new regulations (40 C.F.R. §112.7(k)). Notwithstanding, during fiscal year 2011, PREPA completed the installation of spill response material at all its substations. In addition, it completed the construction of secondary containment at 36 of the 54 substations that are located besides water bodies. PREPA has budgeted $1.5 million for the completion of this program.

No. CEPR-AP-2015-0001

I 000234



1501-1384337 100

16. Commitments and Contingencies (continued) Compliance Programs (continued) Spill Prevention Control and Countermeasures Plan (SPCCP) (continued) During 2015, PREPA updated the SPCC plans for EPA’s Five Year Review for Aguirre, San Juan, Palo Seco, Costa Sur, Cambalache and Mayaguez. Also, PREPA updated the SPCC plans for the substations and Transmission and Distribution offices. Facility Response Plans (FRPs) Some facilities are also required to implement Facility Response Plans (FRP), depending on the fuel storage capacity and risk of harm to navigable waters and extent of risk they present with respect to an oil spill to a body of water. PREPA prepared and submitted the Five Year review FRP’s for Aguirre Power Complex, San Juan Power Plant, Cambalache Turbine Gas Station, Mayaguez Turbine Gas Station and Palo Seco Power Plant to the United Sates Coast Guard for approval. Operation Manual Other PREPA’s facilities are required, by the federal law, to have an Operation Manual implemented for the all the oil transfers operations. The Operation Manuals for San Juan and Palo Seco Power Plants, Aguirre Power Complex and Cambalache and Mayaguez Turbine Gas Stations has been amended and approved by the United States Coast Guard. PCB Program The Authority completed on 2000, a ten-year EPA-mandated program to sample and test its oil-filled transformers and other equipment in order to identify and dispose of PCB equipment. Pursuant to this program, the Authority has completed the removal and disposal of transformers with PCB concentrations of more than 500 ppm. The Authority continues with the removal and disposal of transformers with PCB concentrations between 50 and 499 ppm. According to EPA, the Authority has been the only utility to go so far with a program sample, test, identify, remove, and dispose of PCB or PCB contaminated transformers.

No. CEPR-AP-2015-0001

I 000235



1501-1384337 101

16. Commitments and Contingencies (continued) Compliance Programs (continued) Capital Improvement Program The Authority’s capital improvement program for fiscal year that ended June 30, 2014 includes $10.5 million in order to comply with existing Commonwealth and federal environmental laws and regulations, including the South Coast water related projects in compliance with the Clean Water Act 316(a) and 316(b) sections previously discussed. The Authority keeps taking all the necessary steps to comply with all applicable environmental laws, regulations, and the Consent Decrees requirements. Self-Insurance Health Program Changes in the balances of the health insurance program (self-insurance risk) incurred but not recorded (IBNR) during fiscal years 2014 and 2013 were as follows:

Liability Liability Beginning Ending Balance Expenses Payments Balance (In thousands)

2014 $5,270 $ 89,332 $ 88,870 $5,732

2013 $7,188 $ 100,889 $ 102,807 $5,270 These amounts are included in accounts payable and accrued liabilities in the statement of net position

No. CEPR-AP-2015-0001

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1501-1384337 102

16. Commitments and Contingencies (continued) Contingencies General The Authority is a defendant or codefendant in numerous legal proceedings pertaining to matters incidental to its business and typical for an electrical utility of its size and nature, including claims for damages due to electrified wires, failure to supply power and fluctuations in the power supply. Pursuant to the Act, the Authority is authorized to sue and be sued by individuals or legal entities. Under certain circumstances, as provided in Act No. 9 of November 26, 1975, as amended (Act No. 9), the Commonwealth may provide its officers and employees, including directors, executive directors and employees of public corporations and government instrumentalities and mayors of the municipalities of the Commonwealth, with legal representation, as well as assume the payment of any judgment that may be entered against them. There is no limitation on the amount of the judgment that may be paid under the provisions of Act No. 9 in cases before federal court, but in all other cases the Secretary of Justice of the Commonwealth may determine whether, and to what extent, the Commonwealth will assume payment of such judgment. Although the Authority’s directors, executive director and employees are covered by the provisions of Act No. 9, Article 19 of Act No. 9 requires the Authority to cover the costs associated with judgments, expenses and attorneys’ fees incurred by the Commonwealth in the legal representation of its directors, executive director and employees. To the extent the Authority is unable to cover these costs and expenses, the Authority would be required to reimburse the Commonwealth from future revenues, as provided by the Secretary of the Treasury of the Commonwealth in consultation with the Authority’s board of directors.

No. CEPR-AP-2015-0001

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16. Commitments and Contingencies (continued) Contingencies (continued) Abengoa Litigation In May 2000, Abengoa, Puerto Rico, S.E., the Authority’s original contractor for the construction of the new generating units (Units 5 and 6) at the San Juan power plant, unilaterally declared a termination of the contract and filed a complaint for breach of contract. The Authority filed a counterclaim for breach of contract and for all damages caused to the Authority by the contract termination. On September 21, 2007, the Regional Administrating Judge for the Superior Court of San Juan certified the case as complex civil litigation pursuant to the Authority’s petition. On July 27, 2011, Mr. Angel F. Rossy Garcia, a retired Commonwealth appeals court judge, was named as special master for the case. After his appointment, the special master intervened as a neutral evaluator for purposes of assisting the parties in reaching a potential settlement. The parties filed their respective position papers stating their legal contentions and case theories in August 2011. After reviewing the position papers and meeting separately with each party to discuss the strength and weakness of their respective cases, the parties were unable to reach a settlement agreement. The special master then determined that the contested issues would be resolved at trial and that the case would be bifurcated into two phases: a liability phase that would determine whether the termination was wrongful and a damages phase. The parties in the Litigation are: Abengoa PR, SE (Plaintiff Counterdefendant); PREPA (Defendant Counterplaintiff and Third Party Plaintiff); Abengoa, SA (Third Party Defendant and Counterplaintiff); AIG (Third Party Defendant and Counterplaintiff); UNIPRO (Intervenor) e INDUTECH (Intervenor). In order to mitigate its possible losses, the Authority entered into an agreement with Washington Engineers P.S.C. for the completion of the generating units, having said units entered into service in 2009. Expert reports have been developed assessing potential damages to be recovered from Abengoa, including excess amounts billed to the Authority prior to the wrongful termination.

No. CEPR-AP-2015-0001

I 000238



1501-1384337 104

16. Commitments and Contingencies (continued) Contingencies (continued) Abengoa Litigation (continued) This Complex Litigation was bifurcated into a liability and a damages phase. Trial on the first phase to determine the question of wrongful termination (breach of contract) commenced on January 22, 2015 and was concluded during the course of that same year. Trial on the second phase to determine the questions of damages is scheduled to commence in January 2016. The trial will be heard before designated Special Master Angel F. Rossy at the Superior Court of San Juan. Economic claims have been reserved for the second phase of trial on damages. PREPA is prepared to prove direct damages arising from the wrongful termination by Abengoa (i.e. direct costs to complete Abengoa’s scope of work, equipment refurbishment, etc.) in an amount of at least of $250 million. If recovery of indirect or consequential damages is permitted by the Court, PREPA has claimed in excess of $400 million (including claims for fuel differential costs, los of EPA credits, etc.). The limit of liability under the EPC Contract is 150% of the Contract Price. This represents a range of between $276 million and $310.5 million depending on which value is considered the Contract Price at the time of termination. The Penal Sum of all Performance Bonds issued by the surety in the aggregate is approximately $190 million. PREPA understands that is has significant probabilities of prevailing on the merits or its counterclaim for wrongful termination against Abengoa and its surety American International Insurance Company. The evidence will show that Abengoa chose to terminate the Contract with knowledge of or total disregard of the financial damage that such termination would cause PREPA and the People of Puerto Rico.

No. CEPR-AP-2015-0001

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1501-1384337 105

16. Commitments and Contingencies (continued) Contingencies (continued) Capeco Litigation In 2009, a large fire at a tank farm owned by CAPECO caused major damage to surrounding areas. The Authority stored some of its fuel at this facility. In the aftermath of the fire, numerous claims were filed against CAPECO. Some of the plaintiffs included the Authority as a defendant in these suits, alleging that the Authority failed in its duty (as the owner of fuel stored at the site) to properly monitor CAPECO’s operations in the tank farm. All cases are in the initial stages and the Authority intends to vigorously defend against these claims. On August 12, 2010, CAPECO filed for bankruptcy. As a result thereof, all proceedings against CAPECO have been stayed. Consumer Billing Litigation In 2011, separate lawsuits were filed against the Authority by various consumers claiming damages allegedly caused by incorrect and unlawful billing and invoicing practices. Several separate lawsuits, that were filed in 2011, were finally consolidated in the case of Héctor Carmona Resto, et al. v. Autoridad de Energía Eléctrica, Civil No. K AC2011-1265 (907). The case was also certified as a complex litigation, as requested by the Authority. The consumers are claiming damages in excess of $100 million. The consumers requested that the case be certified as a class action. The Authority filed its Reply to the Master Lawsuit and promptly opposed to the class certification request. The case is in the discovery stage. PREPA hired an expert witness for the case. PREPA will pursue active litigation in order to show that no class action certification is warranted, and that Plaintiffs’ claims have no merit since PREPA’s billing and invoicing is made according to the applicable laws and regulations. PREPA’s Expert witness rendered his report. Defendants declined the idea of retaining the services of an expert. Discovery proceedings regarding the class certification issue are being conducted.

No. CEPR-AP-2015-0001

I 000240



1501-1384337 106

16. Commitments and Contingencies (continued) Contingencies (continued) Consumer Billing Litigation (continued) In the case of Santiago-Ramos, et al. v. AEE, et al., USDC Civil No. 11-CV01987 (JAF), the complaint was filed on October 6, 2011 by Duamel Santiago-Ramos, Marines Rivera Figueroa individually and as Class Representatives, and Caribbean Economic Council, Inc., against PREPA and Marimar Pérez-Riera, Chair, Board of Directors individually and as President of The Board of Directors. The amount claimed is unspecified. The complaint claimed (1): that PREPA’s rate schedules, including subsidies granted to various groups, violate antitrust law, specifically the Robinson-Patman Act; and (2) that PREPA’s rate schedules, including subsidies granted to various groups, violate the First Amendment of the U.S. Constitution, as they “require” customers to associate with religious and political groups they do not agree with by forcing them to subsidize those groups by paying higher energy bills. PREPA does not meet several elements of the Robinson-Patman Act, including the fact that PREPA does not sell electricity outside of Puerto Rico and thus does not meet the interstate commerce requirement. The constitutional claim, in our opinion, is also without merit, first because PREPA is not forcing anyone to associate with anyone else and second because the subsidies that are granted are not granted by PREPA, but instead are mandated by legislation. PREPA moved for dismissal. The court partially granted the dismissal requested by PREPA. It dismissed the antitrust claims, the substantive due process and equal protection claims, and the claims against co-defendant Marimar Pérez Riera. Plaintiff’s First Amendment claim, procedural due process claim and takings claim remained active. Plaintiffs sought class certification, with PREPA’s opposition. PREPA filed a motion for summary judgment requesting dismissal of the remaining claims on the grounds of issue preclusion. The preclusion argument was based on a previous state court case alleging that PREPA’s rates are illegal, in which class certification was sought and denied on the merits. The Court denied PREPA’s motion for summary judgment and held there was no issue preclusion between the prior state case and this one. An evidentiary hearing for certification as a class was held before a Magistrate Judge, who issued a report and recommendation adopted by the Court.

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I 000241



1501-1384337 107

16. Commitments and Contingencies (continued) Contingencies (continued) Consumer Billing Litigation (continued) According to said report and recommendation, the class certification was held in abeyance, pending discovery on the merits of the constitutional claims. The Court indicated it questioned the plaintiff’s First Amendment claims possibility of success in light of the uncontested fact that the subsidies all are ordered by state law. Thus, the Court ordered expedited discovery on the merits of the First Amendment, procedural due process and takings claims. Discovery regarding these issues took place, consisting of both document production and the depositions of several PREPA officials. As ordered, PREPA timely filed a motion for summary judgment, seeking dismissal of all the remaining constitutional claims above mentioned. Plaintiffs filed their opposition thereto, and while adopting all the uncontested material facts proposed by PREPA, attempted at this late stage to dismiss only their First Amendment Claims and amend the complaint to bring a new constitutional claim. PREPA filed its reply, and among other things, opposed Plaintiff’s attempts to change pleadings at such late state. The Judge referred the matter once again to the same Magistrate Judge who had presided the class certification hearing. The parties are waiting for the Magistrate Judge to issue her Report and Recommendation, as to the pending issues in the case. In the case of Román-Rivera, et. al. v. AEE, et al., USDC Civil No. 11-2003 (DRD), the complaint was filed on October 9, 2011 by Dario Román Rivera and 9 other plaintiffs against PREPA, the current Acting Executive Director and two former Executive Directors, and 12 members of the PREPA Governing Board. Federal jurisdiction is based upon federal question jurisdiction, and the federal statute cited is the Racketeer Influenced and Corrupt Organizations Act (RICO). The amount claimed is unspecified.

No. CEPR-AP-2015-0001

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1501-1384337 108

16. Commitments and Contingencies (continued) Contingencies (continued) Consumer Billing Litigation (continued) The Complaint consists of five counts, all of which are pursuant to RICO. Count 1 is against PREPA for unlawful use of an enterprise to launder money generated by a pattern of racketeering activity. Count 2 is against the directors and Board members only, for unlawfully acquiring or maintaining an interest in an enterprise through a pattern of racketeering activity. Count 3 is against the directors and Board members only, for unlawful manipulation of an enterprise for purposes of engaging in, concealing, or benefiting from a pattern of racketeering activity. Count 4 is against PREPA, the directors and Board members, for unlawful conspiracy to violate the RICO Act. Count 5 is against PREPA only, and it alleges that PREPA conspired with the other defendants to advance a money-laundering scheme. The court partially granted the dismissal requested by PREPA. It granted the dismissal of most of the claims, but denied the dismissal of two: conspiracy to advance a money laundering scheme, and conspiracy for acquiring an interest in an enterprise through a pattern of racketeering activity. Plaintiffs seek class certification. PREPA opposed the certification, and filed a motion for summary judgment to that effect on the grounds of preclusion. The preclusion argument is based on a previous state court case in which class certification was sought and denied on the merits. PREPA’s motion for summary judgment was denied. The case proceeded to discovery on the two remaining claims. The parties met and arranged a discovery timetable. PREPA was served an extensive request for production of documents, and served plaintiff a First Set of Interrogatories and Request for Production of Documents. While PREPA has been producing those documents which are not privileged or confidential, plaintiffs have not done likewise, and at present they have yet to answer PREPA’s interrogatories. Depositions are in the process of being scheduled. PREPA believes that the claims that were not dismissed are without merit because the plaintiffs will be unable to prove the necessary elements of those claims. In particular, plaintiffs will not be able to prove that PREPA, as a corporation, conspired through its employees, to violate the RICO ACT, or that its directors or Board members obtained any interest in PREPA (other than their employment).

No. CEPR-AP-2015-0001

I 000243



1501-1384337 109

16. Commitments and Contingencies (continued) Contingencies (continued) Vitol Inc. Litigation In 2009, the Authority filed suit in the Commonwealth of P.R. Court of First Instance (the State Court) against Vitol, Inc. and Vitol S.A. (collectively the Vitols) seeking a declaratory judgment as to the nullity of a $2 billion fuel supply agreement due to the Vitols’ failure to disclose (a) certain corruption criminal charges to which Vitol S.A. pled guilty and (b) various other investigations. The Vitols removed this suit to federal court and presented a counterclaim alleging that the Authority owed Vitol, Inc. approximately $45 million, consisting of $28 million in fuel that was delivered to, and used by, the Authority and approximately $17 million in excise taxes to be reimbursed to Vitol, Inc. by the Authority. On November 28, 2012, the Authority filed a second complaint against the Vitols in State Court seeking essentially the same remedies sought in the first action but as to four other certain contracts, after discovery revealed the date in which Vitol learned of the investigations in the corruption cases. The Vitols also removed this action to the U.S. District Court for the District of P.R. The Authority claims approximately $3.5 billion in the aggregate. Vitol, Inc. has resolved the claim for the $17 million in excise taxes and has stated that it will amend its counterclaim to dismiss that claim. Discovery in the case is closed. The parties have submitted motions for summary judgment against each other and the corresponding oppositions and replies thereto. The motions are pending adjudication by the court. Asbestos Litigation The case of Jorge Martínez, et al. v. AEE, Civil No. K DP2005-1599, which includes fifty-four former and current employees of PREPA, was consolidated with the case of Jose Flores Sanchez v. AEE, Civil No. K DP2010-1708, a retired employee of PREPA. In both cases, plaintiffs claim that they have health problems due to PREPA’s intentional failure to comply with federal and local laws regarding handling and exposure to asbestos materials. In particular, plaintiffs claim that, during the years 1972 to 1988, PREPA failed to comply with its duty to protect the plaintiffs from asbestos exposure pursuant to the requirements of OSHA and its regulation, the Constitution of the Commonwealth of Puerto Rico and local applicable laws and regulations. Plaintiffs claim $320.96 million in damages.

No. CEPR-AP-2015-0001

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1501-1384337 110

16. Commitments and Contingencies (continued) Contingencies (continued) Asbestos Litigation (continued) PREPA alleged employer’s immunity under the Workers’ Compensation Law. An evidentiary hearing on the issue of liability took place. After trial, the Court entered judgment dismissing both complaints in their entirety. The plaintiffs in the case of Jorge Martínez, et al. v. AEE filed an appeal before the Puerto Rico Appeals Court. PREPA filed a motion to dismiss the appeal. The Appeals court denied PREPA’s Motion to Dismiss and PREPA filed its Appellate Brief. The case is pending adjudication by the Court of Appeals. Tropical Solar Farm Litigation On November 21, 2013, Tropical Solar Farms, LLC; New Horizon Solar, LLC; Jonas Solar Energy, LLC and Roberto Torres Torres (collectively the “Plaintiffs”) filed a 58-page suit in the Commonwealth of P.R. Court of First Instance, Ponce Section, against 29 defendants and several John Does. The complaint contains a plethora of claims against multiple defendants arising from an alleged multiplicity of sources of obligations: contractual, in tort, and in breach of fiduciary duties and the law. It encompasses private entities, a public corporation, the Puerto Rico Electric Power Authority (“PREPA”) and former public officers, among others. The complaint claims monetary compensation in excess of $705 million. The complaint alleges that the defendants negotiated several Renewable Power Purchase Agreements to provide up to 40 megawatts to PREPA, all of which were assigned by the plaintiffs to various other defendants. In a nutshell, the Plaintiffs allege that the defendants never intended to comply with their obligations under the agreements, and were only buying time to advance their other renewable energy projects with PREPA. PREPA filed its answer to the complaint on January 7, 2014. As of this date not all the defendants have answered the complaint, and the discovery proceedings are in a very early stage. Although it is anticipated that the litigation may become a protracted one as a result of the plethora of allegations and defendants, it is our professional evaluation at this early stage of the proceedings that PREPA should not be held liable to Plaintiffs.

No. CEPR-AP-2015-0001

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1501-1384337 111

16. Commitments and Contingencies (continued) Construction and Other Commitments As of June 30, 2014, the Authority has commitments of approximately $47.0 million on active construction, maintenance and engineering services contracts. Agreements to Purchase Power The EcoEléctrica plant is a cogeneration facility located in the Municipality of Peñuelas. The facility includes a combined cycle power block, consisting of one steam and two combustion turbine units, and a liquefied natural gas terminal. The Authority began purchasing power from EcoEléctrica in September 1999 during the testing and start-up phase of the facility. Commercial operation began in March 2000. The Authority entered into an agreement with EcoEléctrica to purchase all of the power produced by the facility for a term of 22 years from the date of commencement of commercial operation. The agreement requires EcoEléctrica to provide 507 MW of dependable generating capacity to the Authority. The Authority may purchase any energy produced by the facility in excess of 507 MW, if made available, by paying an energy charge only. No capacity charge would be imposed on the Authority for this "excess" power. EcoEléctrica has entered into a long-term supply agreement to meet its expected needs for natural gas at the facility. The power purchase agreement with EcoEléctrica includes monthly capacity and energy charges to be paid by the Authority for the 507 MW of capacity, which EcoEléctrica is committed to provide. The capacity charge is subject to reduction, progressively to zero, if the facility does not achieve certain availability guarantees determined on a 12-month rolling average basis. The energy charges for power purchases are based on a number of factors including a natural gas related charge on a per kWh of energy basis and inflation indices. The EcoEléctrica purchased power costs incorporate a minimum monthly power or fuel purchase requirement based on an average capacity utilization factor on the part of the Authority. After paying this minimum requirement, the Authority only pays for energy actually received (including energy in excess of the 507 MW guaranteed by EcoEléctrica). This element of the agreement, when combined with the possible reduction in the capacity charge described above, effectively transfers substantially all of the economic risk of operating the facility to EcoEléctrica.

No. CEPR-AP-2015-0001

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1501-1384337 112

16. Commitments and Contingencies (continued) Agreements to Purchase Power (continued) The AES-PR plant is a co-generation facility located in the Municipality of Guayama. Commercial operation began in November 2002. This clean burning coal technology facility consists of two identical fluidized bed boilers and two steam turbines with 454 MW of dependable generating capacity. The Authority entered into an agreement with AES-PR to purchase all of the power produced by this facility for a term of 25 years from the date of commencement of commercial operation. The contract with AES-PR is substantially similar to the EcoEléctrica contract described above, including the compensation structure. Above a certain minimum amount, the Authority is only obligated to purchase energy actually produced by the facility. AES-PR is an affiliate of AES Corporation. The AES-PR and EcoEléctrica projects contribute to the Authority's efforts towards fuel diversification and improved reliability of service. Prior to the commencement of operations of the EcoEléctrica and AES-PR facilities, oil-fired units produced approximately 99% of the Authority's energy. After the incorporation of the EcoEléctrica and AES-PR facilities to the System, approximately 31% of the Authority's annual energy generation is being provided by non-oil-fired generating facilities. Among other benefits, the integration of the EcoEléctrica and AES-PR cogeneration facilities into the Authority's System reduces the impact of changes in energy costs to the Authority's clients resulting from short-term changes in fuel costs due to the manner of calculation of the energy charges under the EcoEléctrica and AES-PR agreements. While the agreements provide that energy charges will change based on different formulas relating to the prior year, each agreement fixes the energy price for each year of the contract at the beginning of such year. Fixing the energy component of the price for the whole year reduces the impact of seasonal or short duration variations in the market price of electricity. Because the energy price is fixed and known for the entire year, the Authority is able to achieve better economic dispatching and scheduling of maintenance outages of all of its generating units. In addition, the year delay in the effect of energy price changes for these two facilities on the Authority's energy costs reduces variations of the fuel and purchased power components in the price of electricity sold by the Authority by postponing the impact of the price changes and bringing these changes out of step with price changes in the other components of the Authority's fuel mix.

No. CEPR-AP-2015-0001

I 000247



1501-1384337 113

16. Commitments and Contingencies (continued) Agreements to Purchase Power (continued) All of the Authority's purchased power costs under the EcoEléctrica and AES-PR power purchase agreements are accounted for as operating expenses on the Authority's financial statements, are treated as a current expense under the Trust Agreement, and are being recovered by the Authority pursuant to the purchased power charge under its current rate structure. 17. Recently Issued Accounting Pronouncements GASB Statement No. 68, Accounting and Financial Reporting for Pension – an amendment of GASB Statement No. 27. The primary objective of this Statement is to improve accounting and financial reporting by state and local governments for pensions. Establish a definition of a pension plan that reflects the primary activities associated with the pension arrangement—determining pensions, accumulating and managing assets dedicated for pensions, and paying benefits to plan members as they come due. This Statement replaces the requirements of GASB Statement No. 27, Accounting for Pensions by State and Local Governmental Employers, as well as the requirements of GASB Statement No. 50, Pension Disclosures, as they relate to pensions that are provided through pension plans administered through trusts or equivalent arrangements that meet certain criteria. The provisions of this Statement are effective for financial statements for periods beginning after June 15, 2014 (The Authority’s 2015 fiscal year). The requirements of GASB Statement No. 68 apply to the financial statements of all state and local governmental employers whose employees (or volunteers that provide services to state and local governments) are provided with pensions through pension plans that are administered through trusts or equivalent arrangements as described above, and to the financial statements of state and local governmental non-employer contributing entities that have a legal obligation to make contributions directly to such pension plans. This Statement establishes standards for measuring and recognizing liabilities, deferred outflows of resources, and deferred inflows of resources, and expense/expenditures related to pensions. Note disclosure and Required Supplementary Information requirements about pensions also are addressed. For defined benefit pensions, this Statement identifies the methods and assumptions that should be used to project benefit payments, discount projected benefit payments to their actuarial present value, and attribute that present value to periods of employee service.

No. CEPR-AP-2015-0001

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1501-1384337 114

17. Recently Issued Accounting Pronouncements (continued) The major fundamental change is switching from the existing “funding-based” accounting model, where currently the Annual Required Contribution (ARC) is compared to the actual payments made and that difference determines the Net Pension Obligation (or Asset); to an “accrual basis” model similar to current Financial Accounting Standards Board (“FASB”) standards, where the Total Pension Obligation (Actuarially determined) is compared to the Net Plan Position (or assets) and the difference represents the Net Pension Liability or Asset. The information to adopt this Statement will be based on the new actuarial report prepared under the new GASB Statement No. 67. The Authority expects the implementation will have a significant impact to its financial statements. GASB Statement No. 69 Government Combinations and Disposals of Government Operations. This Statement establishes accounting and financial reporting standards related to government combinations and disposals of government operations. The term “government combinations” is used to refer to a variety of arrangements including mergers and acquisitions. Mergers include combinations of legally separate entities without the exchange of significant consideration. Government acquisitions are transactions in which a government acquires another entity, or its operations, in exchange for significant consideration. Government combinations also include transfers of operations that do not constitute entire legally separate entities in which no significant consideration is exchanged. Transfers of operations may be present in shared service arrangements, reorganizations, redistricting, annexations, and arrangements in which an operation is transferred to a new government created to provide those services. The provisions of this Statement are effective for financial statements for periods beginning after December 15, 2013. GASB Statement No. 71 Pension Transition for Contributions Made Subsequent to the Measurement Date—an amendment of GASB Statement No. 68. The objective of this Statement is to address an issue regarding application of the transition provisions of Statement No. 68, Accounting and Financial Reporting for Pensions. The issue relates to amounts associated with contributions, if any, made by a state or local government employer or nonemployer contributing entity to a defined benefit pension plan after the measurement date of the government’s beginning net pension liability. This Statement amends GASB Statement No. 68 to require that, at transition, a government recognize a beginning deferred outflow of resources for its pension contributions, if any, made subsequent to the measurement date of the beginning net pension liability. The provisions of this Statement are required to be applied simultaneously with the provisions of Statement 68.

No. CEPR-AP-2015-0001

I 000249



1501-1384337 115

18. Adoption of GASB No. 65 and Prior Period Adjustment During fiscal year ended June 30, 2014, GASB No.65, Items Previously Reported as Asset and Liabilities, became effective, which requires recording the non-insurance portion of deferred debt issuance costs previously presented as Other Assets in the Authority’s balance sheets, as operating expenses, and proper classification of certain items previously reported as assets or liabilities as deferred outflows of resources and deferred inflows of resources. As a result of the implementation of GASB 65, starting with the 2014 fiscal year, all debt issuance costs will be presented as expense during the year they are incurred. In addition, a $55.8 million restatement on beginning net position for 2013 was recorded.

2013 2012 and prior Unamortized Debt Issue Costs, as reported $ 55,810 $ 59,436 Restatement as of June 30, 2012 (59,436) (59,436) Restatement as of June 30, 2013 3,626 – Total restatement (55,810) (59,436) Unamortized Debt Issue Costs, as restated – – GASB 65 restatement (55,810) (59,436) Net position, as previously reported (791,385) (515,686) Net position, as restated $(847,195) $(575,122)

In addition, deferred loss from debt refunding previously reported as of June 30, 2013, as a decrease of long-term debt (current and non-current) was adjusted as follows:

Deferred outflows of resources $ – $ 92,279 $ 92,279 Current portion of long-term debt 399,215 14,331 413,546 Long-term debt, excluding current portion 7,734,712 77,948 7,812,660

2013 Balance as previously

reportedGASB 65

Adjustment2013 Balance as restated

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1501-1384337 116

19. Financial Condition and Liquidity The Authority does not currently have sufficient funds available to fully repay its various obligations as they come due, and is working on extending the due date of the obligations and obtaining other concessions from its creditors, including pursuant to an exchange offer that would reduce the principal amount of some of its debts, obtaining more favorable covenants and other terms under its Trust Agreement via a consent solicitation, and obtaining new financing to provide relief and/or funds to repay the existing amounts of principal and interest or bring the outstanding balances current at the various due dates as well as to continue to operate and to finance capital improvement projects. The Commonwealth and its instrumentalities are also experiencing significant financial difficulties and may be unable to continue to repay amounts due to the Authority or to extend, refinance or otherwise provide the necessary liquidity to the Authority as and when needed. The Authority has receivables of over $803.7 million payable by the Commonwealth and related entities and is subject to significant uncertainty with regard to its ability to collect on such receivables. As a consequence, the Authority may not be able to avoid future defaults on its obligations. Management has plans to address the Authority’s liquidity situation and continue providing services and believes the Authority will be able to repay or refinance its obligations, as described above and Note 20. However, there can be no assurance that the affiliated or unaffiliated creditors will be able and willing to refinance or modify the terms of the Authority’s obligations, that management’s current plans to repay or refinance the obligations or extend their terms will be achieved or that certain services will not have to be terminated, curtailed or modified. See further discussion in Note 20. 20. Subsequent Events Act 57-2014 On May 27, 2014, the Commonwealth of Puerto Rico enacted Act 57 (Act 57-2014), also known as the Transformation and Energy Relief Act of Puerto Rico. The Act provides for, among other things, the creation of the Puerto Rico Energy Commission with regulatory oversight over the Authority’s operations, as well as over any other company providing electric energy services in Puerto Rico. The Energy Commission has since been formed, and given supervisory power over the Authority, and many transactions that affect the electrical system and the electric infrastructure of Puerto Rico, including but not limited to, rate setting approval powers. Act 57 also provides for the Authority to set aside two percent (2%) out of the eleven percent (11%) from the fuel and purchase power adjustment clause revenues for deposit to a Rate Stabilization Account with the purpose of stabilizing the price of energy in Puerto Rico.

No. CEPR-AP-2015-0001

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20. Subsequent Events (continued) Financial Position In July 2014, the Authority began discussions with its financial stakeholders in an effort to stabilize the Authority’s liquidity situation and address its financial position. The Authority subsequently engaged legal, financial and operational advisors, including a chief restructuring officer, to assist it in those efforts. In the period since July 2014, the Authority has entered into various agreements with certain of its financial stakeholders as discussed below. Forbearance Agreements On August 14, 2014, the Authority entered into forbearance agreements (the “Forbearance Agreements”) with certain insurers of the Authority’s Power Revenue Bonds (“Bonds”) and beneficial owners of the Bonds controlling, collectively, more than 60% of the principal amount of the Bonds then outstanding (comprising the Ad Hoc Group (as defined below)) and the monoline insurers providing credit support for certain of the Authority’s Bonds not owned by the Ad Hoc Group (the “monoline bond insurers” and together with the Ad Hoc Group, he “Forbearing Bondholders”), banks that provide revolving lines of credit used to pay for purchased power, fuel and other expenses (together, with their transferees, as applicable, the “Forbearing Lenders”) and Government Development Bank for Puerto Rico (“GDB,” and together with the Forbearing Bondholders and the Forbearing Lenders, the “Forbearing Creditors”). Under the Forbearance Agreements, the Forbearing Creditors agreed to forbear from the exercise of certain rights and remedies under their applicable debt instruments. The Forbearance Agreements were originally scheduled to terminate on March 31, 2015, but were extended by certain of the Forbearing Creditors on numerous occasions, most recently through November 5, 2015. The Forbearance Agreements expired on November 5, 2015, but the agreement of the Forbearing Creditors to refrain from exercising of certain rights and remedies was extended under the RSA (as defined below).

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1501-1384337 118

20. Subsequent Events (continued) Forbearance Agreements (continued) Under the Forbearance Agreements with the Forbearing Bondholders, the Authority’s obligations to pay any and all principal and interest payments on the Bonds were required to continue; however, the Forbearing Bondholders agreed that the Authority was not required to make transfers to the Revenue Fund or the Sinking Fund pursuant to sections 506 and 507 of the Trust Agreement while that agreement remained in effect. The Authority has not made monthly cash deposits into the Sinking Fund since July 2014. This agreement was extended and continued under the RSA. Since entry into the Forbearance Agreements, the Authority has paid all principal and interest payments due on the Bonds. Under the Forbearance Agreements with the Forbearing Lenders, the Authority was permitted until November 5, 2015 to delay certain payments that became due to the Forbearing Lenders in July and August 2014. Under the RSA, the Authority was permitted to delay such payments further until June 30, 2016; however, the Authority has continued to pay interest to the Forbearing Lenders while those agreements remain in effect. In connection with the Forbearance Agreements and in order to address the Authority’s liquidity challenges, on August 27, 2014, the Trust Agreement was amended to permit the Authority to use approximately $280 million held in its construction fund for payment of current expenses in addition to capital improvements. The amendment also provided for an increase in the thresholds required for the exercise of remedies under the Trust Agreement. Those amendments expired on March 31, 2015. In connection with an extension of the Forbearance Agreements executed on June 30, 2015 and the Authority’s agreement to pay approximately $415.8 million of principal and interest due on July 1, 2015 on the Bonds, the Trust Agreement was again amended to increase the thresholds for the exercise of remedies under the Trust Agreement and to allow for the issuance of $130.7 million in Bonds to the monoline bond insurers (the “2015A Bonds”) that matured on January 1, 2016. Those amendments expired on September 1, 2015. On December 15, 2015, the Authority defeased the outstanding principal and interest requirements on the 2015A Bonds, and the 2015A Bonds were paid in full on the first business day of January 2016 (January 4, 2016) in accordance with their terms.

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20. Subsequent Events (continued) Bond Payments On July 1, 2014, the Authority paid $413.7 million to satisfy the principal and interest payments on its Bonds due on that date. This payment was funded with moneys in the 1974 Sinking Fund, including reserves. On January 2, 2015, the Authority paid $204.4 million to satisfy the interest payments on its Bonds due on that date. This payment was funded with moneys in the 1974 Sinking Fund, including reserves. On July 1, 2015, the Authority paid $415.8 million, to satisfy the principal and interest payments on its Bonds due on that date. This payment was funded with moneys in the 1974 Sinking Fund, including reserves, and a $153.0 million transfer from the General Fund. On July 31, 2015, pursuant to the Trust Agreement and as agreed with Forbearing Creditors, the Authority issued Power Revenue Bonds Series 2015A, in a par amount of $130.7 million (the Series 2015 A Bonds), to replenish the Authority’s working capital. The Series 2015 A Bonds were bought in their entirety by the monoline bond insurers, and the maturity date of this issue was January 1, 2016. The Authority paid $6.1 million, $5.9 million, $5.8 million, $5.8 million and $6.4 million for the first five months that ended on November 1, 2015 to redeem a portion of the Series 2015 A Bonds. On December 15, 2015, the Authority deposited $103.5 million in escrow to satisfy the remaining principal and interest requirements on the Series 2015 A Bonds, which deposit was funded by $100.9 million from Self-insurance Fund and $2.6 million from General Fund. These amounts were paid to holders of the 2015 A Bonds on January 4, 2016 in accordance with their terms. On January 4, 2016, the Authority paid $198.0 million, to satisfy the interest payments on its other Bonds due on that date. This payment was funded with moneys in the 1974 Sinking Fund, and a $171.0 million transfer from the General Fund.

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20. Subsequent Events (continued) Agreements with Certain Forbearing Creditors Agreement in Principle with Ad Hoc Group On September 2, 2015, PREPA announced an agreement in principle regarding the economic terms of a restructuring with an ad hoc group of bondholders that were Forbearing Bondholders (the “Ad Hoc Group Agreement”) and which group held, at that time, approximately 35% in principal amount of the outstanding Bonds (the “Ad Hoc Group”). Under that agreement, the Ad Hoc Group will have the option to receive securitization bonds that will pay cash interest at a per annum rate of 4.0% - 4.75% (depending on the rating obtained) (“Option A Bonds”) or convertible capital appreciation securitization bonds that will accrete interest at a per annum rate of 4.5% - 5.5% for the first five years and pay current interest in cash thereafter at those per annum rates (“Option B Bonds”). Option A Bonds will not pay principal for the first five years (interest only), and Option B Bonds will accrete interest but not receive any cash interest or principal during the first five years. All of PREPA’s uninsured bondholders will have an opportunity to participate in the exchange. Both Option A and Option B Bonds would be issued at an exchange ratio of 85% (i.e., with a 15% reduction in principal amount of current holdings of outstanding Bonds). Under the extension to the Forbearance Agreement with the Ad Hoc Group executed on September 1, 2015, PREPA agreed to work collaboratively and in good faith with the Ad Hoc Group to reach agreement on a recovery plan incorporating these terms. The Ad Hoc Group Agreement was included in the RSA. Agreement in Principle with Forbearing Lenders of Notes Payables On September 22, 2015, PREPA announced an agreement in principle regarding economic terms with its Forbearing Lenders (the “Fuel Line Agreement”). Under that Agreement, the Forbearing Lenders, which hold all of the approximately $696 million of matured debt (Notes Payable), will have the option to either (1) convert their existing credit agreements into term loans, with a fixed interest rate of 5.75% per annum, to be repaid over six years in accordance with an agreed amortization schedule or (2) exchange all or part of principal due under their existing credit agreements for new securitization bonds to be issued on the same terms as the Ad Hoc Group.

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20. Subsequent Events (continued) Agreements with Certain Forbearing Creditors (continued) Agreement in Principle with Forbearing Lenders of Notes Payables (continued) Under the extensions to the Forbearance Agreements with the Forbearing Lenders executed on September 22, 2015, PREPA agreed to work collaboratively and in good faith with the Forbearing Lenders to reach agreement on a recovery plan incorporating these terms. The Fuel Line Agreement was included in the RSA. Terms and Status of Restructuring Support Agreement On November 5, 2015, PREPA announced its entry into a restructuring support agreement (the “Initial RSA”) with both the Ad Hoc Group (representing at that time approximately 40% in principal amount of the outstanding Bonds) and the Forbearing Lenders setting forth the agreed-upon terms of PREPA’s recovery plan which terms were amended to extend the milestone dates therein on numerous occasions. The economic terms set forth in the Initial RSA are consistent with the Ad Hoc Group Agreement and the Fuel Line Agreement. In addition, pursuant to the Initial RSA, GDB would receive substantially the same treatment on $35.9 million owed by PREPA to it as the Forbearing Lenders will receive. The monoline bond insurers were not party to the Initial RSA. On December 23, 2015, certain of the monoline bond insurers along with the Ad Hoc Group (representing together at that time approximately 66% in principal amount of the outstanding Bonds), the Forbearing Lenders and GDB, all signed an amended and restated restructuring support agreement (the “A&R RSA” and together with the Initial RSA and the Revised RSA (as defined below), the “RSA” and the Ad Hoc Group, the monoline bond insurers, the Forbearing Lenders and the GDB, together the “Supporting Creditors”) with terms and conditions substantially similar to those in the Initial RSA outlined above (including the agreement to exchange Bonds held by the Ad Hoc Group for new securitization bonds at an 85% exchange ratio with a 5-year principal holiday and fixed interest rates).

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20. Subsequent Events (continued) Agreements with Certain Forbearing Creditors (continued) Terms and Status of Restructuring Support Agreement (continued) Significant uncertainty remains as to the potential consummation of the transactions set forth in the RSA, which is subject to a number of material conditions, including without limitation, (1) obtaining legislative authority for the assessment of a special, transition charge on the Authority’s customers and other terms to facilitate the issuance of the securitization bonds as well as organizational reforms at the Authority; (2) receipt of an investment grade rating on the new securitization bonds from any credit rating agency that will rate the securitization bonds; (3) obtaining an agreed upon level of participation from holders of the Authority’s uninsured Bonds in the exchange offer described above such that no more than $700 million in principal amount of uninsured Bonds shall remain outstanding following the exchange offer, or such higher amount determined by the Authority after consulting with the Authority’s advisors; (4) amending the Trust Agreement to increase to at least a majority the percentage of Bondholders required to direct the Trustee to take certain actions under the Trust Agreement, including upon a default by the Authority and continue the waiver of the Authority’s obligation to make monthly Sinking Fund deposits, among other things; and (5) obtaining approval and reaching agreement with all Supporting Creditors regarding the definitive documentation of the various restructuring transactions. The RSA contains a number of termination or withdrawal events in favor of the Supporting Creditors, including if there is a material amendment to certain terms of the recovery plan, if the Authority commences any proceeding under bankruptcy or insolvency law or the Recovery Act (except to implement the recovery plan in accordance with the RSA), as well as the failure to achieve certain milestones by specific dates, including the enactment of legislation containing substantive provisions to implement the recovery plan contemplated by the RSA, among other events, which would result in termination of the RSA or withdrawal from the RSA by individual Supporting Creditors. On January 23, 2016, the RSA terminated when the PREPA Revitalization Act was not enacted into law and the Ad Hoc Group did not agree to the Authority’s request to extend the related RSA milestone. PREPA continued to engage in discussions with the Ad Hoc Group and the other Supporting Creditors regarding a potential extension of the RSA and the transactions contemplated therein and described below.

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20. Subsequent Events (continued) Agreements with Certain Forbearing Creditors (continued) Terms and Status of Restructuring Support Agreement (continued) Under the RSA, certain of the Supporting Creditors had agreed to purchase approximately $115 million in Bonds to refund a portion of the interest payments on the Bonds made on January 4, 2016, subject to certain conditions including enactment of the PREPA Revitalization Act in acceptable form. This agreement was formalized in a Bond Purchase Agreement (the “Initial Bond Purchase Agreement”) executed on December 29, 2015. The Initial Bond Purchase Agreement also terminated on January 23, 2016 when the A&R RSA terminated. PREPA continued to engage in discussions with the Supporting Creditors regarding the transactions contemplated by the Initial Bond Purchase Agreement. On January 23, 2016, certain of the Forbearing Lenders agreed to enter into a short form forbearance agreement by which they agreed to forbear from exercising enforcement rights against the Authority under the applicable Fuel Line Agreements through February 12, 2016. On January 27, 2016, PREPA and the Supporting Creditors executed a revised RSA (“Revised RSA”) and a revised Bond Purchase Agreement (the “Revised Bond Purchase Agreement”). The Revised RSA is substantially the same as the A&R RSA, with minor adjustments to address delays in legislative consideration of the PREPA Revitalization Act. The milestone date for legislative approval of the PREPA Revitalization Act was extended to February 16, 2016, and other related milestones were also adjusted accordingly. The Revised Bond Purchase Agreement is substantially the same as the Initial Bond Purchase Agreement, except for certain changes to the timing, conditions and total amount of the contemplated Bond purchase. Under the Revised Bond Purchase Agreement, 50% of the total purchased Bonds will be purchased upon a determination by the applicable Supporting Creditors that the PREPA Revitalization Act satisfies the standards set forth in the RSA and 50% of the total purchased Bonds will be purchased upon the filing of a petition with the Energy Commission seeking approval of a securitization charge that satisfies the standards under the RSA. Under the Revised Bond Purchase Agreement, the total amount of purchased Bonds is approximately $111 million. There can be no assurance, however, that the transactions contemplated by the Revised Bond Purchase Agreement will be consummated.

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20. Subsequent Events (continued) Agreements with Certain Forbearing Creditors (continued) Terms and Status of Restructuring Support Agreement (continued) Under the RSA, the Ad Hoc Group has agreed to exchange 100% of its uninsured Bonds for securitization bonds at an 85% exchange ratio. The monoline bond insurers agreed to provide up to $462 million of reserve surety bonds at the time the transaction closes and forward commitments for additional surety capacity to be provided at a later time during the term of the transaction, as credit support for the securitization bonds, that would be available to be drawn upon in the event certain cash reserves and transition payments from PREPA’s customers are insufficient to pay current debt service on the securitization bonds. In return for this, (1) the SPV (defined below – see PREPA Revitalization Act) would issue $2.086 billion additional securitization bonds, which amount is subject to adjustment in accordance with the RSA, as credit support for outstanding Authority’s insured Bonds to be held in escrow for the benefit of holders of the Authority’s insured Bonds and (2) PREPA and the SPV would attempt to refinance certain outstanding Bonds insured by such insurers with securitization bonds during a 6-month period starting 3 years after the date the above exchange closes. The surety bonds provided by the monoline bond insurers would be replaced by SPV cash (derived from transition payments) beginning in FY2019 over a period of nine years, subject to earlier replacement in accordance with certain conditions set forth in the RSA. Among the primary purposes for this transaction are to refinance at a lower cost a portion of the Authority’s outstanding Bonds and to improve the Authority’s liquidity position during the first five years after issuance. There can be no assurance, however, that the transactions contemplated by the RSA will be consummated. It should be noted that Bondholders holding beneficially approximately $2.73 billion in principal amount of outstanding Bonds representing approximately 34% in principal amount of the outstanding Bonds, have not agreed to the terms of the RSA, and without access to a statutory restructuring regime the terms of their Bonds also cannot be amended until an agreement with such Bondholders has been reached. As discussed below, the Authority is currently not in compliance with certain terms of its Trust Agreement and such Bondholders, who are not covered by the agreements described above, could direct the trustee to take certain actions, or otherwise exercise enforcement actions, against the Authority, each in accordance with the Trust Agreement, which actions could result in a default being declared.

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20. Subsequent Events (continued) Trust Agreement Covenants As a result of the Authority’s non-compliance with certain covenants existing under the Trust Agreement, Bondholders not covered by the agreements described above could direct the trustee to take certain actions, or otherwise exercise enforcement actions, against the Authority, including declaring an event of default as a result of covenant violations, each in accordance with the terms of the Trust Agreement. Under the Trust Agreement, upon a covenant violation, no remedies may be exercised by the trustee on behalf the Bondholders until the trustee notifies the Authority of the particular violation and the Authority does not cure the violation within 30 days after receipt of such notice. The Authority has not received any such notice from the trustee. PREPA Revitalization Act On November 4, 2015, the Governor submitted the PREPA Revitalization Act to the Legislative Assembly to facilitate the Authority’s ongoing transformation and recovery plan. The PREPA Revitalization Act sets forth a framework for PREPA to execute on the agreements with creditors reached to date. Among other things, the PREPA Revitalization Act would (1) enhance PREPA’s governance processes; (2) adjust PREPA’s practices for hiring and managing management personnel; (3) change PREPA’s processes for collecting outstanding bills from public and private entities; (4) improve the transparency of PREPA’s billing practices; (5) implement a competitive bidding process for soliciting third party investment in PREPA’s infrastructure; (6) authorize the refinancing of outstanding Bonds through a securitization that would reduce PREPA’s indebtedness and cost of borrowing; and (7) set forth an expedited process for the Energy Commission to approve or reject PREPA’s proposal for a new rate structure that is consistent with its recovery plan. The Legislative Assembly is currently considering various amendments to the PREPA Revitalization Act. There can be no assurance, however, that the PREPA Revitalization Act will be enacted into law or that it will contain provisions that are acceptable to the Authority’s various creditors.

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20. Subsequent Events (continued) PREPA Revitalization Act (continued) As described above, if enacted the PREPA Revitalization Act would provide a legal framework to reduce the Authority’s cost of borrowing and its passage in the form contemplated by the RSA is one of the conditions to the execution of the restructuring transactions contemplated by the RSA and described above. The legislation would authorize creation of a bankruptcy-remote, special purpose public corporation (the “SPV”), entirely separate from the Authority, with the power to issue securitization bonds for limited purposes related to the Authority’s recovery plan, and to impose non-by passable, transition charges on the Authority’s customers. The assessment and periodic automatic adjustments of the transition changes on the Authority’s customers would serve as the source of repayment for the securitization bonds. U.S. Congress Consideration of Bankruptcy Amendment Commonwealth officials have been urging the U.S. Congress to amend the federal bankruptcy code to eliminate an exclusion that currently bars any municipality or other instrumentality of the Puerto Rico government from restructuring under the federal bankruptcy code. U.S. legislative discussions on this are expected to continue in January 2016 and beyond. Operational Improvements The Authority has also made significant investments in evaluating and implementing various operational improvements and strategies in an effort to address its ongoing financial challenges. In an effort to diversify its fuel supply, the Authority has entered into agreements necessary for the construction of an offshore gas port terminal to receive natural gas off the southern part of the island for use in the Aguirre Power Complex. The permitting process for the project is ongoing, and construction has not yet begun. Once operational, the gas port will provide a method to utilize liquefied natural gas at Aguirre. The Authority reduced its number of employees through a combination of attrition from voluntary retirement and the elimination of temporary and vacant positions. In addition, the Authority continues to enforce the new employee hiring freeze implemented in January 2009.

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20. Subsequent Events (continued) Operational Improvements (continued) On September 4, 2014, the Authority appointed a chief restructuring officer whose mandate includes providing overall leadership to the Authority’s restructuring process, developing a business plan, implementing revenue improvement and cost reduction plans, overseeing and implementing cash and liquidity management activities, improving the Authority’s ability to analyze, track and collect accounts receivable, improving the Authority’s capital expenditure plan, and developing plans to improve the Authority’s generation, transmission, distribution and other operations.

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Required Supplementary Information

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Schedule I

Actuarial Valuation Date

Actuarial Value of Assets

(a) Note 1

Actuarial Accrued Liability (AAL)

(b)

Unfunded AAL

(UAAL) (b)-(a)

Funded Ratio (a)/(b)

Covered Payroll

(c)

UAAL Percentage of

Covered Payroll

[(b)-(a)]/(c)

Pension Plan6/30/2011 1,363 2,875 1,503 47% 361 419%6/30/2012 1,285 2,986 1,701 43% 365 466%6/30/2013 1,248 3,043 1,795 41% 355 505%

Postemployment Health Plan*7/1/2008 $ – $ 587 $ 587 0% $ 363 162%7/1/2010 – 408 408 0% 357 114%7/1/2012 – 378 378 0% 365 104%

Note 1: The system, as permitted by the GASB, reflects its investments at an average fair market value of the last five years to determine its actuarial funding.

*Postemployment Health Plan valuation performed every two years, as required by the GASB.


Supplementary Schedule of Funding Progress

Years Ended June 30, 2014(In millions)

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Report on Internal Control

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Report of Independent Auditors on Internal Control Over Financial Reporting and on Compliance and Other Matters Based on an Audit of Financial Statements

Performed in Accordance with Government Auditing Standards The Board of Directors Puerto Rico Electric Power Authority We have audited, in accordance with auditing standards generally accepted in the United States and the standards applicable to financial audits contained in Government Auditing Standards issued by the Comptroller General of the United States, the financial statements of the Puerto Rico Electric Power Authority (the Authority), which comprise the statement of financial position as of June 30, 2014, and the related statements of activities, and cash flows for the year then ended, and the related notes to the financial statements, and have issued our report thereon dated January 28, 2016. Our report includes a reference to other auditors who audited the financial statements of PREPA Holdings LLC (a blended component unit) and PREPA.Net as described in our report on the Puerto Rico Electric Power Authority’s financial statements. This report does not include the results of the other auditors’ testing of internal control over financial reporting or compliance and other matters that are reported on separately by those auditors. Internal Control Over Financial Reporting In planning and performing our audit of the financial statements, we considered the Authority’s internal control over financial reporting (internal control) to determine the audit procedures that are appropriate in the circumstances for the purpose of expressing our opinion on the financial statements, but not for the purpose of expressing an opinion on the effectiveness of the Authority’s internal control. Accordingly, we do not express an opinion on the effectiveness of the Authority’s internal control. A deficiency in internal control exists when the design or operation of a control does not allow management or employees, in the normal course of performing their assigned functions, to prevent, or detect and correct misstatements on a timely basis. A material weakness is a deficiency, or combination of deficiencies, in internal control, such that there is a reasonable possibility that a material misstatement of the entity’s financial statements will not be prevented, or detected and corrected on a timely basis. A significant deficiency is a deficiency, or a combination of deficiencies, in internal control that is less severe than a material weakness, yet important enough to merit attention by those charged with governance.

Ernst & Young LLP Plaza 273, 10th Floor 273 Ponce de León Avenue San Juan, PR 00917-1951

Tel: +1 787 759 8212 Fax: +1 787 753 0808 ey.com

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Our consideration of internal control was for the limited purpose described in the first paragraph of this section and was not designed to identify all deficiencies in internal control that might be material weaknesses or significant deficiencies and therefore, material weaknesses or significant deficiencies may exist that were not identified. We consider the deficiencies described in the accompanying Schedule of Findings and Responses as items 2014-001 and 2014-002 to be material weaknesses. Compliance and Other Matters As part of obtaining reasonable assurance about whether the Authority’s financial statements are free of material misstatement, we performed tests of its compliance with certain provisions of laws, regulations, contracts and grant agreements, noncompliance with which could have a direct and material effect on the determination of financial statement amounts. However, providing an opinion on compliance with those provisions was not an objective of our audit, and accordingly, we do not express such an opinion. The results of our tests disclosed no instances of noncompliance or other matters that are required to be reported under Government Auditing Standards. The Authority’s Response to Findings The Authority’s response was not subjected to the auditing procedures applied in the audit of the financial statements and, accordingly, we express no opinion on it. Purpose of this Report The purpose of this report is solely to describe the scope of our testing of internal control and compliance and the result of that testing, and not to provide an opinion on the entity’s internal control or on compliance. This report is an integral part of an audit performed in accordance with Government Auditing Standards in considering the entity’s internal control and compliance. Accordingly, this communication is not suitable for any other purpose.

EY January 28, 2016 Stamp No. E201503 affixed to original of this report.

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Supplemental Schedules

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Note to Schedules II-VI - Information Required by the 1974 Agreement

As of June 30, 2014 and 2013, and for the Years then Ended

Schedules II - VI present certain information which is required by the 1974 Agreement. The Net Revenues data, as defined in the 1974 Agreement (Net Revenues), presented in Schedules II and III differ in some important respects from generally accepted accounting principles (GAAP). Such differences are explained below; Schedule II also presents a reconciliation of Net Revenues with GAAP. The most significant differences between Net Revenues and GAAP are the following: 1) Revenues do not include investment income on investments in the construction fund (see

Note 5 to the financial statements); 2) Depreciation and interest expense on bonds covered by the 1974 Agreement are not included

as deductions in calculating Net Revenues; 3) Amortization of debt discount and issuance costs and the allowance for funds used during

construction are not considered in the computation in calculating Net Revenues; 4) Contribution in lieu of taxes is not considered a deduction for purposes of Net Revenues; 5) Net Revenues do not include revenues or expenses of the Irrigation Systems (see Note 1 to

the financial statements). For further details and information on the definition of Net Revenues, please refer to the 1974 Agreement.

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Schedule II

1974 Statement Reconciliation 1974 Statement ReconciliationTrust of Income of Net Trust of Income of Net

Agreement (GAAP) Income Agreement (GAAP) Income

Reconciliation of components of net income:

Revenues:Operating revenues 4,444,610$ 4,468,922$ 4,821,348$ 4,843,016$ Other operating revenues 32,577 32,577 28,405 28,136 Other (9,986) 22,416 1,064 (2,773) 1974 agreement construction fund investment income

and gain on sale of other properties (4,038) 48,996 – 32,945 4,463,163 4,572,911 109,748$ 4,850,817 4,901,324 50,507$

Current Expenses:As shown 3,886,765 3,904,924 4,125,390 4,138,988

Total as defined 3,886,765 3,904,924 (18,159) 4,125,390 4,138,988 (13,598) Net revenues, as defined 576,398$ 725,427$

Depreciation 341,511 (341,511) 344,653 (344,653)

Other post-employment benefit (OPEB) (543) 543 5,338 (5,338)

Disposition of Revenues: (not classified in order of payment)

Interest on debt 359,556$ 431,021 332,504$ 399,641 Interest on general obligation notes 6,872 45,054 458 741 Amortization of debt discount, financing expenses – (11,593) – (14,511) Amortization of bond defeasance – 14,330 – 15,061 Allowance for funds used during construction – (9,759) – (14,065)

Net interest on long-term debt 366,428 469,053 (102,625) 332,962 386,867 (53,905)

Power revenue bonds:Principal 204,305 – 204,305 194,920 194,920

Appropriation capital improvement fund (2,124) – (2,124) 16,986 16,986 Appropriation reserve account (41,480) – (41,480) – – Contribution in lieu of taxes 49,269 277,776 (228,507) 180,559 297,551 (116,992)

Total expenses (GAAP) 4,992,721 5,173,397

Net revenues, as defined 576,398$ 725,427$

Net income (419,810)$ (419,810)$ (272,073)$ (272,073)$

(In thousands)

2014 2013


Sources and Disposition of Net RevenuesUnder the Provisions of the 1974 Agreement

Statements of Income (GAAP)and Reconciliation of Net Income

Years Ended June 30, 2014 and 2013

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Schedule III

2014 2013Sources of Net Revenues:

Revenues:Electric revenues 4,444,610$ 4,821,348$ Other operating revenues 32,577 28,405 Other (principally interest) (14,024) 1,064

4,463,163 4,850,817

Current Expenses:Operations:

Fuel 2,345,000 2,603,578 Purchased Power 807,620 755,686 Other productions 64,381 71,655 Transmissions and distributions 172,392 172,318 Customer accounting and collection 111,406 116,351 Administrative and general 188,641 191,912 Maintenance 197,325 213,890

3,886,765 4,125,390 Net revenues, as defined 576,398$ 725,427$

Disposition of Net Revenues:

Revenue fund:Power revenue bonds - sinking fund requirements:

Interest 359,556$ 332,504$ Principal 204,305 194,920 Reserve Account (41,480) –

Balance available for capital improvements and other needs (2,124) 16,986 520,257 544,410

General obligation notes:Interest 6,872 458

Contribution in lieu of taxes and other 49,269 180,559 Net revenues, as defined 576,398$ 725,427$


Supplemental Schedule of Sources and Dispositionof Net Revenues under the Provisions of the 1974 Agreement

Years Ended June 30, 2014 and 2013(In thousands)

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No. CEPR-AP-2015-0001

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Schedule IV

Held by Held byAuthority Authority

Other Other Non-Current Other Other Non-CurrentTotal Assets Assets Assets Total Assets Assets Assets

By Account:

1974 Agreement (restricted): Sinking Fund - principal and interest 328,532$ –$ 328,532$ –$ 369,381$ –$ 369,381$ –$ Reserve account 453,323 – – 453,323 398,472 – – 398,472 Self Insurance Fund 96,080 – 96,080 92,217 – 92,217 Sinking Fund - Capitalized Interest 124,992 – – 124,992 62,913 – – 62,913 Reserve Maintenance Fund 15,949 15,949 – – 15,818 15,818 – – Other Restricted Fund 1,900 1,900 – – 12,370 12,370 – – Construction Fund: Rural Utilities Services (RUS) 1,463 1,463 – – 1,103 1,103 – – Other 303,434 303,434 – – 49,370 49,370 – – PREPA Client Fund 3,177 3,177 – – 4,759 4,759 – – General purpose (unrestricted) General (excluding Prepa Net) 136,305 136,305 – – 111,817 111,817 – – Working funds 996 996 – – 807 807 – – Total 1,466,151$ 463,224$ 328,532$ 674,395$ 1,119,027$ 196,044$ 369,381$ 553,602$

By Type of Assets Held:

Working funds 996$ 996$ –$ –$ 807$ 807$ –$ –$ PREPA Client Fund 3,177 3,177 – – 4,759 4,759 – – Cash in bank and time deposits (by depository institutions): Government Development Bank for Puerto Rico 399,301 399,301 – – 2,638 2,638 – – Banco Popular de Puerto Rico 36,936 36,936 – – 31,362 31,362 – – Citibank, N. A. 5,961 5,961 – – 78,001 78,001 – – US Bank 328,597 65 328,532 – 414,630 45,249 369,381 – Banco Bilbao Vizcaya (Chase), Puerto Rico 1,955 1,955 – – 10,807 10,807 – – Banco Bilbao Vizcaya, Mayaguez, Puerto Rico 188 188 – – 179 179 – – Banco Bilbao Vizcaya, Call Center 9,632 9,632 18,548 18,548 FirstBank, San Juan, Puerto Rico 2,663 2,663 – – 748 748 – – Banco Santander, San Juan, Puerto Rico (5,131) (5,131) – – 2,922 2,922 – – RG Premier Bank 7,481 7,481 – – 24 24 – – Western Bank, Mayaguez, P.R. – – – – – – – JP Morgan – – – – – – – – Other Institutions – – – – – – – –

791,756 463,224 328,532 – 565,425 196,044 369,381 –

Investment Securities 674,395 – – 674,395 553,602 – – 553,602 Total 1,466,151$ 463,224$ 328,532$ 674,395$ 1,119,027$ 196,044$ 369,381$ 553,602$

Restricted RestrictedDeposits with Trustee Deposits with Trustee


Supplemental Schedule of Funds Under the Provisions of the1974 Agreement

Years Ended June 30, 2014 and 2013(In thousands)

2014 2013

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Schedule V

Interest Principal Reserve Self Construction Reserve Subordinated OtherGeneral Revenue Working 1974 1974 1974 Insurance 1974 Maintenance Obligation Restricted

2013-2014 Activity Total Fund Fund Fund Agreement Agreement Agreement Fund Agreement Fund Fund Fund

Balances at June 30, 2013, before interfund account 1,119,027$ 427,821$ 770$ 807$ 236,805$ 195,489$ 398,472$ 92,217$ (266,301)$ 15,818$ –$ 17,129$ Operations: – Actual Net revenues – (769,465) 192,450 329,597 187,280 – – 15,392 44,746 Funds provided from internal operations 912,263 912,263 1974 Agreement investment income Acct 4191 – (4,037) 4,037 Investment income and other 12,140 1,878 664 4,989 1,513 3,026 70 Unrealized gain (or loss) on market value of investment 6,849 1,030 3,423 2,335 61 Offset of current year's contribution in lieu – of taxes against certain government accounts – receivable – 152,224 (152,224) Offset of current year's 5% contribution in lieu of – taxes against Commonwealth of Puerto – Rico debt and transfers to General Obligations – 40,226 (40,226) Funds used for construction (255,547) (255,547) Reclassified construction costs for deferred debits – – Proceeds from Federal Agencies and Insurance Companies – Financing: – Proceeds from new bond issues-net of – original discounts 656,086 109,647 46,439 500,000 – Proceeds from Contributed Capital 4,358 4,358 Proceeds from refunding bonds issues-net of – original discounts – Defeased bonds-net of original discounts – Sinking Funds and account transfers – 10,297 1,673 5,000 (16,970) Notes issued for construction – Notes issued to working capital 116,527 116,527 Note issued to finance the acquisition on fuel oil 1,582,238 1,582,238 Payment of notes payable (1,723,054) (1,723,054) Payment of interest (445,080) (28,360) (409,847) (6,873) Swap termination fees paid (37,873) (37,873) Payment of current maturities of long-term debt (194,920) (194,920) Proceeds from Prepa Holding 4,918 4,918 Changes in assets and liabilities: – Working funds – (189) 189

Accounts receivable (includes non-current) (516,699) (516,699) Fuel oil 156,854 156,854 Materials and supplies 899 899 Prepayments and other 4,607 4,607 Deferred debits (3,023) (3,023) Accounts payable and accrued liabilities

(includes non-current) 62,481 41,461 21,020 Customer deposits 3,100 3,100 Adjustment (14,225) 14,225

Interfund transfers, etc. – 8,093 (756) – (5,767) (5) 15 (1,580) – – Total before interfund accounts 1,466,151 397,558 14 996 265,016 188,508 453,323 96,080 43,630 15,949 – 5,077 Add (deduct) Interfund accounts – (261,267) – – – – – – 261,267 – – – Balances at June 30, 2014 1,466,151$ 136,291$ 14$ 996$ 265,016$ 188,508$ 453,323$ 96,080$ 304,897$ 15,949$ –$ 5,077$


Supplemental Schedule of Changes in Cash and Investments by Funds

Year Ended June 30, 2014(In thousands)

General Purposes Funds Sinking Fund Other Funds

135 1501-1384337

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Schedule V

Interest Principal Reserve Self Construction Reserve Subordinated OtherGeneral Revenue Working 1974 1974 1974 Insurance 1974 Maintenance Obligation Restricted

2012-2014 Activity Total Fund Fund Fund Agreement Agreement Agreement Fund Agreement Fund Fund Fund

Balances at June 30, 2012, before interfund accounts 1,455,539$ 449,740$ 14$ 886$ 296,060$ 185,974$ 401,735$ 90,372$ 10,297$ 15,809$ –$ 4,652$ Operations: Net revenues – (725,427) 180,559 – 332,503 194,920 – 16,986 – 459 – Funds provided from internal operations 743,318 743,318 – – – – – – – – – – 1974 Agreement investment income Acct 4191 – (966) – – – – – – 966 – – – Investment income and other 31,870 14,691 – – 10,146 441 3,360 1,296 1,872 57 – 7 Unrealized gain (or loss) on market value of investment (7,339) – – – (1,218) – (6,622) 549 – (48) – – Offset of current year's contribution in lieu of taxes against certain government accounts receivable – 138,198 (138,198) – – – – – – – – – Offset of current year's 5% contribution in lieu of taxes against Commonwealth of Puerto Rico debt and transfers to General Obligations – 42,360 (42,360) – – – – – – – – – Funds used for construction (314,905) – – – – – – – (314,905) – – – Reclassified construction costs for deferred debits – – – – – – – – – – – – Proceeds from Federal Agencies and Insurance Companies 6,981 – – – – – – – 6,981 – – – Financing: Proceeds from new bond issues-net of original discounts – – – – – – – – – – – – Proceeds from Contributed Capital 10,898 – – – – – – – 10,898 – – – Proceeds from refunding bonds issues-net of – original discounts – – – – – – – – – – – – Defeased bonds-net of original discounts – – – – – – – – – – – – Sinking Funds and account transfers – (8,699) – – (1,649) (243) – – 14 – 107 10,470 Notes issued for construction – – – – – – – – – – – – Notes issued to working capital 32,921 32,921 – – – – – – – – – – Note issued to finance the acquisition on fuel oil 1,468,736 1,468,736 – – – – – – – – – – Payment of notes payable (1,355,720) (1,355,720) – – – – – – – – – – Payment of interest (414,877) (16,611) – – (397,700) – – – – – (566) – Payment of current maturities of long-term debt (185,605) – – – – (185,605) – – – – –

Proceeds from Prepa Holding 2,000 – – – – – – – – – – 2,000 Changes in assets and liabilities: – – – – – – – – – – – –

Working funds – 79 – (79) – – – – – – – – Accounts receivable (includes non-current) (376,046) (376,046) – – – – – – – – – – Fuel oil (74,438) (74,438) – – – – – – – – – – Materials and supplies 580 580 – – – – – – – – – – Prepayments and other (5,020) (5,020) – – – – – – – – – – Deferred debits (6,881) (6,881) – – – – – – – – – – Accounts payable and accrued liabilities (includes non-current) 101,681 101,681 – – – – – – – – – – Customer deposits 5,334 5,334 – – – – – – – – – – Interfund transfers, etc. – (9) 755 – (1,337) 2 (1) – 590 – – –

Total before interfund accounts 1,119,027 427,821 770 807 236,805 195,489 398,472 92,217 (266,301) 15,818 – 17,129 Add (deduct) Interfund accounts – (316,774) – – – – – – 316,774 – – – Balances at June 30, 2013 1,119,027$ 111,047$ 770$ 807$ 236,805$ 195,489$ 398,472$ 92,217$ 50,473$ 15,818$ –$ 17,129$


Year Ended June 30, 2013(In thousands)

Other FundsGeneral Purposes Funds Sinking Fund

Supplemental Schedule of Changes in Cash and Investments by Funds (continued)

136 1501-1384337

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Schedule VI


Supplemental Schedule of Changes in Long-TermDebt and Current Portion of Long-Term Debt

Years Ended June 30, 2014 and 2013(In Thousands)

2014 2013Long-term debt, excluding current portion:

Balance at beginning of year 7,812,660$ 8,042,587$ Transfers to current liabilities:

Power revenue bonds (227,561) (218,626) Notes payable 27,856 (156,546)

Payment of general obligation notes:Notes payable (1,734,188) (1,356,411)

Remainder 5,878,767 6,311,004

New Issues:Power revenue bonds 673,145 – Power revenue refunding bonds – – Debt discount on new bond issues - net (14,806) – Defeasance of bonds – – Debt discount on cancelled bonds - net – – Notes payable 1,709,900 1,501,656

Balance at end of year 8,247,006$ 7,812,660$

Current portion of long-term debt:Balance at beginning of year 1,165,311$ 1,000,256$

Transfer from long-term debt 199,705 365,172 Payments to bondholders:

Power revenue- July 1 (194,920) (185,605) Amortization of debt discount (13,907) (14,512)

Balance at end of year 1,156,189$ 1,165,311$

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Discussion topics

16 www.alixpartners.com

‣ Business Plan Process

‣ Business Review

‣ A. Fuel

‣ B. Customer Service

‣ C. Indirect Procurement

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