eei 2008 financial review - business strategies

EEI 2008 FINANCIAL REVIEW 39

Business StrategiesBusiness Segmentation

Revenues grew in each of the indus-try’s five primary business lines in 2008 and declined in the Other category. As-sets grew across every category except Competitive Energy. Regulated Electric, which grew to a 61.2% share of the in-dustry’s assets and 57.2% of revenues, provided most of the industry’s growth in these areas during 2008. Competitive Energy declined 1.3% from year-end

2007. These developments illustrate the overall industry trend toward a more regulated asset base.

2008 Revenues by Segment

Regulated Electric segment rev-enue rose by $18.7 billion, or 7.7%, to $259.9 billion in 2008 from $241.2 billion in 2007.The segment’s share of total industry revenue edged up to 57.2% in 2008 from 56.7% in 2007, well above the 52.1% of 2005.

Natural Gas Distribution revenue increased by $3.9 billion, or 7.4%, during 2008. About one-fourth of the increase, $923 million, was driven by the Integrys merger (in which WPS Resources acquired Peoples Energy and its gas distribution operations). If this is removed for comparative purposes, Natural Gas Distribution revenue rose by $3.0 billion, or 5.9%.

Total regulated revenue—the sum of the Regulated Electric and Natural

Business Segmentation — RevenuesU.S. SHAREHOLDER-OWNED ELECTRIC UTILITIES

($ Millions) 2008 2007r Difference

Regulated Electric Competitive EnergyNatural Gas Distribution Natural Gas PipelineNatural Gas and Oil Exploration & ProcessingOther

Eliminations/Reconciling Items

Total Revenues

% Change

r = revised

Note: Difference and Percent Change columns may reflect rounding. Totals may reflect rounding.

Source: Based on segment reporting from SEC filings of 69 U.S. Shareholder-Owned Electric Utilities

259,883 241,219 18,664 7.7% 113,190 106,799 6,390 6.0% 56,377 52,496 3,881 7.4% 5,342 5,115 228 4.4% 1,993 1,530 463 30.3% 17,441 18,616 (1,174) -6.3% (20,418) (20,398) (20) 0.1%

433,808 405,376 28,432 7.0%

40 EEI 2008 FINANCIAL REVIEW

BuSineSS StRategieS

Gas Distribution segments—increased by $22.5 billion, or 7.7%, to $316.3 billion during 2008. In comparison, total regulated revenues increased by $14.4 billion, or 5.2%, in 2007 rela-tive to 2006. Regulated operations accounted for nearly 70% of total in-dustry revenue in 2008, just above the 69.0% and 68.9% levels in 2007 and 2006 respectively, up from 65.3% in 2005. The chart Business Segmenta-tion–Revenues presents the industry’s revenue breakdown by business seg-ment. Eliminations and reconciling items were added back to total rev-enues to arrive at the denominator for the segment percentage calculations shown in the charts Revenue Break-down 2008 and 2007r.

2008 assets by Segment

Regulated Electric assets increased from 59.4% of total industry assets at December 31, 2007 to 61.2% at De-cember 31, 2008, as Regulated Electric assets grew by $82.2 billion, or 12.7%,

over the year-end 2007 level. All other categories, except for Competitive En-ergy, had solid asset growth but mini-mal change in their share of total as-sets. Competitive Energy assets fell by $2.6 billion, or 1.3%.

Total regulated assets (Regulated Electric plus Natural Gas Distribu-tion) accounted for 69.5% of total industry assets at year-end 2008, up from 67.9% on December 31, 2007. This aggregate measure has steadily grown from 61.6% at the end of 2002, underscoring the significant rate base growth in recent years and the fact that several companies sold off non-core businesses during the period, often us-ing proceeds to pay down debt.

Regulated electric

Regulated Electric segment opera-tions include the generation, transmis-sion and distribution of regulated elec-tricity to residential, commercial and industrial customers. The Regulated

Electric segment’s 7.7% revenue increase was spread throughout 2008, with sig-nificant year-to-year growth occurring in both the first and second halves of the year. A 5% year-to-year increase in heating degree days helped counteract weakening demand from the economic recession that developed during the year. Although cooling degree days were down 10% given 2007’s very hot summer months, 2008’s cooling degree days were 5% above the norm.

In addition to weather, there were several other drivers that affected Regulated Electric revenues in 2007. Improved pricing, the impact of rate relief over the past year, and rate base growth resulting from system upgrades and expansions more than offset the year’s 0.9% decline in output (which includes all power placed on the grid by electric utilities, IPPs and public power authorities).

During 2007, 72% of the com-panies increased regulated assets as a

Business Segmentation — AssetsU.S. SHAREHOLDER-OWNED ELECTRIC UTILITIES

($ Millions)

Regulated Electric Competitive EnergyNatural Gas Distribution Natural Gas Pipeline

Natural Gas and Oil Exploration & Processing Other Eliminations/Reconciling Items

Total Assets

r = revised

Note: Difference and Percent Change columns may reflect rounding. Totals may reflect rounding.

Source: Based on segment reporting from SEC filings of 69 U.S. Shareholder-Owned Electric Utilities

12/31/08 12/31/2007r Difference % Change

730,555 648,393 82,162 12.7% 203,348 205,960 (2,611) -1.3% 98,775 92,546 6,229 6.7% 23,853 20,438 3,415 16.7%

5,435 4,745 690 14.5%

130,813 119,332 11,481 9.6% (74,788) (65,345) (9,443) 14.5%

1,117,991 1,026,068 91,923 9.0%


BuSineSS StRategieS

Revenue Breakdown 2008U.S. SHAREHOLDER-OWNED ELECTRIC UTILITIES

Revenue Breakdown 2007rU.S. SHAREHOLDER-OWNED ELECTRIC UTILITIES

r = revised

Source: EEI Finance Department and company annual reports

Regulated Electric 57.2%

Natural Gas Distribution

12.4%

Natural Gas Pipeline

1.2%

24.9%

Competitive Energy

Natural Gas and Oil Exploration & Processing

0.4%

Other 3.9%




12.3%Natural Gas Pipeline

1.2%

25.1%

Competitive Energy

0.4%Other 4.4%

percent of total assets (or maintained a 100% regulated structure). Black Hills increased this ratio from 33.6% at the end of 2007 to 65.6% at the close of 2008. The gain is mostly due to the company’s completed asset pur-chase and merger with Aquila in July 2008. Aquila’s natural gas and electric utilities in Colorado, Iowa, Kansas and Nebraska were acquired by Black Hills. Aquila’s Missouri electric utili-ties, stock and other corporate assets were acquired by Great Plains Energy.

Sempra Energy’s regulated mix rose to 62% at year-end 2008 from 49% at year-end 2007. The increase is largely the result of Sempra’s com-pleted joint venture with Royal Bank of Scotland in April 2008, form-ing the commodities joint venture of RBS Sempra Commodities and greatly reducing the Commodities assets that appear as a separate busi-ness segment for Sempra Energy.

Competitive energy

Competitive Energy segment rev-enues rose by 6.0% in 2008, increas-ing by $6.4 billion to $113.2 billion from $106.8 billion in 2007. Com-petitive Energy covers the generation and/or re-sale of electricity in competi-tive markets, including both wholesale and retail transactions. Wholesale buy-ers are typically electric utilities seek-ing to supplement generation capacity, along with regional power pools and large industrial customers. Competi-tive Energy also includes the trading and marketing of natural gas. Of the 42 companies with Competitive assets at the beginning of 2008, 20 showed a year-to-year decline.

Energy Future Holdings (EFH), formerly TXU, had the industry’s larg-est amount of Competitive Energy as-sets, $43.1 billion, at year-end 2008. EFH’s competitive segment engages in electricity generation, construction

of new generation facilities, wholesale energy sales and purchases, commod-ity risk management and trading, and retail electricity sales to residential and business customers, all largely in Texas.

natural gas Distribution

Natural Gas Distribution revenue rose by $3.9 billion, or 7.4%, in 2008, due primarily to colder weather during the heating months and partially to the merger that formed Integrys Energy (formerly WPS Resources). Heating degree days rose by 5% in 2008, but were 1.0% below normal. The months of March and October provided the biggest impact in terms of additional heating degree days in 2008 relative to 2007. Integrys was created when WPS acquired Peoples Energy on February 21, 2007. Integrys increased its Natu-ral Gas Distribution revenues by $923 million, or 44%, from $2.1 billion in 2007 to $3.0 billion in 2008. Over-


BuSineSS StRategieS

all, 31 of the 35 companies (89%) that report Natural Gas Distribution revenues showed year-to-year revenue gains in 2008.

Natural Gas Distribution includes the delivery of natural gas to homes, businesses and industrial customers throughout the United States, while the Natural Gas Pipeline business concentrates on the transmission and storage of natural gas for local dis-tribution companies, marketers and traders, electric power generators and natural gas producers. Added togeth-er, Natural Gas Distribution, Natu-ral Gas Pipeline, and Exploration & Processing (E&P) activities produced $63.7 billion of the industry’s rev-enues in 2008, up from $59.1 billion in the year-ago period. In percent-age terms, the revenue contribution from natural gas activities remained relatively unchanged, rising from 13.9% in 2007 to 14.0% in 2008.

Natural Gas E&P showed the highest revenue growth, at 30.3%, in 2008. Of the five companies in our electric utility universe with operations in this segment, Oklahoma City’s OGE En-ergy was the largest contributor, with 2008 revenue growth of $254 million, or 32%.

2007 Year-end List of Companies By Category

Early each calendar year, we create a new list of shareholder-owned electric utility holding companies by business category based on year-end business segmentation data presented in 10Ks and supplemented by discussions with parent companies. Our category defi-nitions are as follows: Regulated (80% of holding company assets are regulat-ed); Mostly Regulated (50%-79% of holding company assets are regulated); Diversified (less than 50% of holding company assets are regulated).

We use assets rather than revenue for determining categories because we think assets provide a clearer picture of strate-gic trends. In recent years, soaring natu-ral gas prices impacted revenue so greatly that some companies’ strategic approach to business segmentation was distorted by reliance on revenue data alone.

Comparing the list of companies from year to year reveals company migrations between categories and indicates the general trend in indus-try business models. We also base our quarterly category financial data dur-ing the year on this list at the previous year end.

The Regulated and Mostly Regu-lated groups totaled 44 and 19 com-panies, respectively, at year-end 2008, the same as at year-end 2007. The Di-versified group totaled six companies, down from seven at year-end 2007, nine at year-end 2006 and 11 at year-end 2005.

Asset Breakdown As of December 31, 2008

U.S. SHAREHOLDER-OWNED ELECTRIC UTILITIES



8.3%


2.0%

17.0%

Competitive Energy


0.5%

r = revised

Source: EEI Finance Department and company annual reports

Asset Breakdown As of December 31, 2007r


Other 11.0%



8.5%


1.9%

18.9%

Competitive Energy


0.4%

Other 10.9%


BuSineSS StRategieS

Companies that moved into the Regulated category included Alliant Energy and DTE Energy. Aquila was removed from the Regulated group due to its completed acquisition by Great Plains Energy and Black Hills. Companies that moved to the Mostly Regulated category were Black Hills and Sempra Energy from the Diversi-fied group and MGE Energy from the Regulated Group. The Diversified cat-egory lost two companies and gained PPL from the Mostly Regulated Cate-gory. The movement of companies was due to strategic business transactions and the fact that some straddled the 50% and 80% regulated asset cut-off points between categories, where small percentage changes create category jumps. Two notable moves that were caused by strategic transactions were Black Hills acquisition of Aquila and Sempra Energy’s joint venture with Royal Bank of Scotland related to its Commodities business.

Mergers and acquisitions

The pace of utility M&A activity, when defined as mergers or acquisi-tions of whole operating companies, appeared to quicken in 2008 with six announced deals. Four of these were completed during the year and two were withdrawn. But the seemingly robust numbers mask more impor-tant trends. The deals were generally tiny—all but one was valued at under $500 million. And the largest, Mid-American’s bid for Constellation En-ergy Group (subsequently rejected as too low), was the product of severe li-quidity crisis at Constellation resulting from its exposure to bankrupt Lehman Brothers and the lack of financing alternatives in what were essentially shut-down credit markets.

Indeed, the primary driving force on the M&A front in 2008 was the larger global financial crisis. And what did not occur was more indicative of changing trends than what did. There were no big strategic blockbuster deals given sharply lower stock prices and significantly impaired access to debt financing. There were no additional bids for regulated utilities by private equity or infrastructure investors, who were seen in 2007 as a potential new source of capital for utilities fac-ing large capital spending programs. Depressed stock prices made strategic buyers reluctant to bid with what ap-peared to be undervalued shares and also made targets reluctant to accept what seemed to be undervalued bids. And while beaten down stocks made financial deals all the more attractive, the inability to raise financing closed off these possibilities too. In fact, a

Macquarie representative was quoted in the energy press in October 2008 as acknowledging that financing for its acquisition of Puget Energy could not have been arranged at that point due to credit market stress following Lehman Brothers’ September bankruptcy.

While frozen credit markets froze much deal activity, the structural forces in the utility industry that have driven M&A in recent years remained very much in place, according to industry analysts. Even though near-term capex budgets at many utilities were cut late in 2008 due to the credit crisis, the industry’s long-term capital spending needs will likely pressure the balance sheets of smaller utilities and lead to strategic combinations with larger firms once markets recover. Financially strong European utilities remained in-terested in the U.S. market and have few M&A options at home due to

List of Companies by Category at December 31, 2008

AlleteAlliant EnergyAmeren American Electric PowerAvista Central Vermont Public ServiceCH Energy GroupCleco CMS EnergyConsolidated EdisonDPL DTE EnergyDuquesne Light Holdings El Paso ElectricEmpire District ElectricEnergy East

Great Plains EnergyGreen Mountain Power IDACORP IPALCO EnterprisesKentucky Utilities KeySpan Louisville G&EMaine and Maritimes Niagara Mohawk Power Northeast UtilitiesNorthWestern EnergyNSTARNV EnergyPG&EPinnacle West CapitalPNM Resources

Portland General Electric Progress EnergyPuget EnergySouthernTECO EnergyUIL HoldingsUniSourceUnitil VectrenWestar EnergyWisconsin EnergyXcel Energy

Black HillsCenterPoint EnergyDominion ResourcesDuke EnergyEdison InternationalEntergyExelon

FirstEnergyFPL GroupIntegrys Energy Group MGE EnergyMidAmerican Energy Holdings NiSourceOGE Energy

Otter Tail PowerPepco HoldingsPublic Service Enterprise GroupSCANASempra Energy

Allegheny EnergyConstellation EnergyEnergy Future Holdings

Hawaiian ElectricMDU ResourcesPPL

Regulated (44)

Mostly Regulated (19)

Diversified (6)


BuSineSS StRategieS

consolidation there. And it remains easier for many utilities that need new generation to buy assets rather than build them, given the regulatory and political challenges that often come with building new generation, unless it is renewable generation. State renew-able mandates are also a potential spur to M&A for companies facing renew-able portfolio standards and uncer-tain means of achieving them. Duke’s September 2008 acquisition of wind energy developer Catamount Energy is one example of a deal driven by the desire to boost the renewable portfo-lio. The potential for more stringent environmental regulations and a car-bon regime under the new Obama ad-ministration throw another wild card into the mix of potential M&A driv-ers, depending on the eventual shape of regulations.

Despite the absence of large deal announcements, 2008 did see the completion of several of the promi-

nent mergers announced in 2007. On July 14, Black Hills and Great Plains Energy closed on their February 2007 buyouts of Aquila’s assets. On Sep-tember 16, Spanish utility Iberdrola completed its June 2007 announced acquisition of Energy East, defying predictions that the deal would fail. And, while not technically a 2008 clo-sure, Macquarie successfully navigated state regulatory politics in 2008 and closed its acquisition of Puget Energy on February 6, 2009.

a Year of Small Deals

Five deals valued at under $500 mil-lion were announced in 2008 and four of these were completed during the year.

The year’s first proposed deal was the only of the five to be withdrawn. On January 12, PNM Resources an-nounced the intention to sell its nat-ural gas operations to a subsidiary of Continental Energy Systems for $620 million and to acquire Continental’s

Cap Rock Energy (an electric distribu-tion and transmission company serv-ing approximately 36,000 customers in 28 counties in north, west and cen-tral Texas) for $202.5 million. PNM said it would use the net proceeds to retire debt, fund future electric capital expenditures and for other corporate purposes. The company added that the planned sale of the gas utility is one of several moves to strengthen its financial position during an era of ris-ing costs, growing power demand and significant capital investment needs. Continental terminated the deal on July 22, 2008 and agreed to pay PNM a $15 million termination fee. The sale of PNM’s gas operations proceeded and closed in January 2009 for $640 million. PNM also said the sale allows it to focus on generation and delivery of electricity and on obtaining better regulatory treatment for its Texas and New Mexico electric utilities.

On December 1, Unitil completed the purchase of Northern Utilities and Granite State Gas Transmission from NiSource, announced on Febru-ary 19, 2008, after gaining approvals from state regulators in Maine, New Hampshire and Massachusetts. The acquisition added 52,000 natural gas distribution customers to the Unitil system, about a 40% increase. The purchase price was $160 million, plus $41.6 million for working capital, in-cluding approximately $33.9 million of natural gas storage inventory. There was no acquisition premium. Unitil’s New Hampshire electric distribution operations share many customers and communities with Northern and Unit-il described Northern Utilities as a nat-ural fit. The acquisition underscored Unitil’s commitment to the region, ac-cording to the company.

Status of Mergers & Acquisitions

1993–2008

Source: EEI Finance Department


0

5

10

15

20

25

30

1993 1994 1995 1996 1997 1998 1999 2000 2001

Completed (91 total)

Announced (117 total)

Withdrawn (28 total)

(Number of Mergers & Acquisitions)

20062002 2003 2004 2005 2007 2008


BuSineSS StRategieS

Duke Energy on June 25 an-nounced its intent to acquire Cata-mount Energy, a transaction designed to significantly increase Duke’s wind energy operations and advance its carbon emissions reduction plans. Catamount develops wind projects in the U.S. and United Kingdom and has approximately 300 megawatts of renewable energy in operation, in-cluding an interest in the Sweetwater project in Nolan County, Texas, one of the largest wind projects in the world. Catamount had approximately 1,750 megawatts of development interests in several states and the U.K. at the time the deal was announced. The transac-tion, which included a $240 million purchase price plus $80 million of as-sumed debt, closed on September 15.

Two natural gas focused acquisitions were announced in July and each closed on October 1. On July 1, MDU Re-sources Group announced it entered into

an agreement to acquire Intermountain Gas Company, a wholly-owned subsid-iary of privately held Intermountain In-dustries, Inc. The transaction was valued at approximately $328 million including debt. Intermoun-tain Gas, headquartered in Boise, Idaho, serves more than 300,000 customers in 74 communities in Idaho. MDU called Intermoun-tain’s service territory and culture a great long-term strategic fit. MDU’s regu-lated operations territory stretches from Minnesota to the Pacific Northwest while Intermountain operates in a high-growth area with recent customer growth of approximately 4.5 per-cent annually. MDU said the acquisition advances its long-term objective of

growing its regulated utility. The deal closed on October 1.

On July 15, Sempra Energy an-nounced the intent to acquire Mobile, Ala.-based EnergySouth for $510 mil-lion in cash. Central to the transaction was Sempra’s interest in the assets of EnergySouth’s subsidiary, EnergySouth Midstream, which included majority ownership in two large, high-cycle un-derground natural gas storage facilities. When fully developed, these will offer 57 billion cubic feet (Bcf ) of capacity in the nation’s fastest-growing natural gas markets. Sempra Energy also ac-quired Mobile Gas Service Corp., an Alabama natural gas distribution util-ity owned by EnergySouth. Mobile Gas serves approximately 93,000 cus-tomers in southwest Alabama, a region that stands to benefit from strong eco-nomic development within its service territory. Sempra said the acquisition supports its natural gas strategy by expanding its Gulf Coast operations to key markets where gas demand

Status of Announced Mergers & Acquisitions1993–2008


Year

1993199419951996199719981999200020012002200320042005200620072008

Totals

2121

139

102365111367

91

Completed

358

13111026952233746

117

Announced

10433––2143110212

28

Withdrawn


Merger Impacts 1995–2008U.S. SHAREHOLDER-OWNED ELECTRIC UTILITIES

Number of Companies Declined by 40% since Dec.’95


Note: Based on completed mergers in the EEI Index groupof electric utilities.

Date No. of Utilities Change

12/31/95 98 N/A12/31/97 96 (2.04%)12/31/99 83 (13.54%)12/31/00 71 (14.46%)12/31/01 69 (2.82%)12/31/02 65 (5.80%)12/31/03 65 – 12/31/04 65 – 12/31/05 65 – 12/31/06 64 (1.54%)12/31/07 61 (4.69%)12/31/08 59 (3.28%)

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BuSineSS StRategieS

outpaces the national average. The transaction was expected to be slightly accretive to earnings in 2009 and con-tribute up to $0.30 per share in 2012. Sempra Energy funded the transaction from operating cash flow and debt.

2007 Vintage Deals get Perfect Score

Five transactions were announced in 2007. The largest of these, TXU’s buy-out by private equity investors, was com-pleted in October 2007. The four oth-ers were navigating regulatory approval as 2008 began and all were successfully completed in 2008 or early in 2009.

On July 14 Black Hills and Great Plains Energy completed their acqui-sitions of Aquila’s assets, a deal an-nounced in February 2007. In the two-part transaction, Black Hills acquired Aquila’s electric utility in Colorado and Aquila’s four natural gas utilities in Colorado, Iowa, Kansas and Nebraska. Great Plains Energy acquired Aquila’s outstanding shares along with its Mis-souri electric utility assets. Black Hills cited the broadening of its regional presence and retail utility base as driv-ers of its interest in the deal. Great Plains cited improved operational and scale efficiencies resulting from the companies’ adjacent service territories, reduced overhead expenses, more ef-ficient procurement and investments in infrastructure and energy efficiency. The Great Plains side of the transac-tion encountered some resistance from shareholders and the Missouri Public Service Commission Staff, who recom-mended that the PSC reject the deal due to concerns that it would hurt the company’s credit rating and not ben-efit rate payers. Great Plains modified deal terms in February 2008 to include earlier savings to customers and miti-

gation of future rate increases along with reduced recovery of transaction costs, which led to the deal’s approval by the Missouri commission in a two to one vote on July 1.

Iberdrola and Energy East also navi-gated at-times turbulent regulatory politics to gain New York regulatory ap-proval on September 3, 2008 for their proposed transaction, which was com-pleted on September 16. FERC and regulators from Connecticut, Maine and New Hampshire approved the deal but New York regulators were concerned about vertical market power in the state and recommended the transaction be rejected. The merger, however, received support from prominent New York poli-ticians including Governor David Patter-son, U.S. Senator Charles Schumer and State Senator Joseph Bruno, who were pleased with Iberdrola’s goal publicized in June to invest $2 billion in renewable energy in New York State over the next five years if regulators approve the deal. The New York PSC conditionally ap-proved the merger on September 3, but only with a long list of provisions that it said were designed to enhance ratepayer financial benefits, mitigate vertical mar-ket power, protect the utilities’ finan-cial condition, improve transmission and distribution system reliability, and strengthen service quality. The merger’s approval process highlighted a trend that appears to be gaining impetus in merger negotiations—the citing of environ-mental-related benefits as a deal driver, similar to the cancellation of TXU’s coal plant construction plans that led to Texas’ approval of the TXU buyout by private equity investors in 2007.

Australia-based global infrastruc-ture investor Macquarie Group on February 6, 2009 completed its $7.4 billion merger transaction with Puget

Energy and its wholly-owned utility subsidiary Puget Sound Energy, for $30 a share. The deal, announced in October 2007, encountered some re-sistance from intervenors, including the Washington State Attorney Gen-eral’s office, who expressed concern that high leverage posed too much risk for rate payers and questioned whether Macquarie’s ownership would deliver lower financing costs than the utility could get on its own. Puget stock fell $2 on June 19 as word of the testimony spread. Washington State regulators, however, approved the deal in a two to one vote on December 31, 2008 and said the merger offered clear benefits to ratepayers and to the region. Indeed, on January 16, after both Macquarie and Puget Sound Energy accepted the Washington Utilities and Transporta-tion Commission merger approval or-der, Standard & Poor’s increased PSE’s corporate credit rating to BBB from BBB- and its secured bond rating to A- from BBB+. The ratings upgrade pro-duced savings for PSE customers due to reduced borrowing costs. Puget said the transaction will enable it to contin-ue to make significant investments in renewable resources to meet evolving green energy requirements and in its natural gas and electricity distribution system. And at a time of tremendous strain in credit markets, the merger enabled PSE to enter into new credit facilities with five-year terms. Macqua-rie also offers the utility access to up to $1 billion a year in new capital for the next five years.

Credit Crisis Hits Constellation energy

The year’s only proposed deal that envisioned the acquisition of a large, stand-alone utility holding company—MidAmerican’s $4.7 billion or $26.50


BuSineSS StRategieS

per share offer on September 17 for Constellation Energy—was a direct result of the credit crisis and not, like blockbuster deals of previous years, motivated primarily by a strategic vi-sion of scope, scale and synergies lead-ing to increased operating efficiencies and a larger footprint in nationwide energy markets. Constellation’s stock had been driven from near $60/share down to $24 in a matter of days fol-lowing the September bankruptcy of Lehman Brothers due to concerns about Constellation’s exposure to Lehman and general fears about li-quidity at Constellation’s energy trad-ing business. Constellation viewed Warren Buffet’s MidAmerican as an ideal suitor who could offer the capi-tal strength necessary for immediate financial stability and a track record of successful M&A, evidenced most recently in MidAmerican’s 2006 acqui-sition of PacifiCorp. The withdrawal of Constellation’s planned merger with FPL Group in March 2006 after a diffi-cult year-long navigation of Maryland regulatory politics underscored the ap-peal of PacifiCorp’s successful M&A record. The proposed merger ran into immediate resistance from sharehold-ers who thought the price underval-ued Constellation’s generation assets and prompted a $35 per share offer on September 19 by French nuclear giant EDF Group (owner of 9.5% of Constellation’s stock) along with pri-vate equity investors Kohlberg, Kra-vis, Roberts & Co. and TPG Group. Negotiations continued through the fall and resulted in a December 17 announcement by Constellation that it would cancel the planned merger with MidAmerican, remain an inde-pendent company and sell 49.99% of its nuclear-generation operations to EDF for $4.5 billion. EDF made an

immediate $1 billion cash investment in Constellation, to be credited against the purchase price, and entered into an agreement to allow Constellation to sell EDF up to $2 billion in non-nu-clear generation assets over a two-year period as an insurance against further liquidity pressures.

exelon Bids for nRg

Finally, in another proposed deal, Exelon on October 19 offered to ac-quire independent power producer NRG in an all-stock transaction valued at $26.43 for each NRG common share (a 37% premium to NRG’s October 17 closing price), representing a total equity value of approximately $6.2 bil-lion based on Exelon’s $54.50 closing price on October 17. Exelon said the combination would geographically di-versify its generation portfolio and cre-ate immediate earnings and cash flow accretion. The proposal, made possible in part by the decline in NRG’s share price from near $40 in late August to the mid-teens by mid-October fol-lowing Lehman’s bankruptcy and the freezing of credit markets, offered a number of benefits to the combined companies, according to Exelon. These included enhanced scope and scale (the combination would create the largest power company in the U.S.), increased generation efficiency with combined nuclear operations, fuel diversifica-tion for both companies, substantial operating synergies, and Exelon’s fi-nancial strength in support of NRG’s more leveraged balance sheet. NRG rejected the proposal, asserting that it undervalued the company given its depressed stock price, although NRG acknowledged the logic of a strategic fit between the two companies. Exelon brought its exchange offer directly to NRG shareholders on November 12,

2008, and by late February 2009 NRG shareholders had tendered over 51% of the outstanding shares of NRG com-mon stock. Exelon subsequently ex-tended its offer until June 26, giving it time to seek regulatory approval for the transaction and solicitation of proxies for the election of NRG directors at the NRG annual meeting, likely in May.

Construction

generation

New Capacity Online

After two years of declining capac-ity additions, shareholder-owned elec-tric utilities brought 8,852 MW of new capacity into operation in 2008, 70% more than in 2007. New plants accounted for 3,263 MW and expan-sions 5,590 MW. The U.S. power in-dustry as a whole increased total capac-ity by only 17% in 2008.

Even more than 2007, 2008 was the year of new wind farms. Wind capacity additions broke a new record and, for the first time, the entire power sector added as much wind capacity as natural gas ca-pacity. Wind accounted for 68% of total megawatts from new plants placed into operation by shareholder-owned electrics and 60% of new plants brought online by the broader industry—surpassing, in both cases, the relative contribution from all other fuel types. The prolifera-tion of state renewable energy standards (RES) and wind’s lack of fuel cost have helped make it an increasingly popular generation choice in windy parts of the country.

FPL Group remained the leader in new wind investment nationwide. FPL was responsible for a third of total wind additions by the U.S. power sec-


BuSineSS StRategieS

tor in 2008 and almost 60% of the to-tal added by shareholder-owned elec-trics. Texas continues to lead all states in wind capacity, with over 7,500 MW (7% of the U.S. total) in place and another 17,500 MW in the proposal stage. Iowa has become the state with the largest percentage of wind in its en-ergy mix, at 18% of installed capacity.

Cancellations

At just under 5,000 MW, cancella-tions by the shareholder-owned utili-ties in 2008 were one-third the level in 2007. Unlike 2007, when a large number of coal-fired projects were can-celled, shareholder-owned electrics did not cancel any major projects last year. The coal-fired capacity that was can-celled came largely from three projects —postponements by Pinnacle (1,200 MW in Arizona) and AEP (630 MW in Ohio) and one cancellation by PNM (630 MW in Texas). FPL’s postponed Tesla natural gas project in California accounted for almost all gas-fired ca-pacity cancelled or postponed during the year. The broad industry also fol-lowed a similar pattern by cancelling only about half as much as in 2007.

The financial crisis that worsened during 2008’s fourth quarter did not appear to have an immediate effect on additions or cancellations. Some pre-liminary evidence, however, suggested that smaller renewable development was being constrained by unavailable or more expensive financing. And the delays that have affected an increasing number of big renewable and fossil-fueled projects seemed driven by re-ductions in expected electricity de-mand growth in addition to a higher cost of capital.

announcements

The entire electric industry announced over 113,000 MW of new capacity during 2008. Not only was this the highest level since 2001, but 87,000 MW were renew-able projects (of which 32 GW were hydro and 44 GW were wind projects), reflecting the rising prominence of renewable gen-eration. Shareholder-owned electrics, how-ever, were responsible for only 13% of the total 113,000 MW, and announced 40% less new capacity in 2008 than in 2007. Af-ter 2007’s wave of coal cancellations, share-holder-owned utilities announced only one coal project in 2008 (the expansion of an existing AES plant in Oklahoma) which was cancelled in February 2009. In fact, new capacity announcements fell dramati-cally as the year progressed, from almost

8,000 MW in Q2 to 1,700 in Q3 to 1,300 MW in Q4. All fuel sources except wind showed declines.

Shareholder-owned utilities have traditionally been the nation’s core suppliers of baseload power and they built most of the country’s coal-fired, combined cycle and nuclear plants. The pattern seen since late-summer 2008, however, shows an almost ex-clusive interest in renewable energy by all segments of the industry. It is too early to tell if this will be a long-term trend that impacts the way the power sector ensures reliability for a growing demand base.

Shareholder-owned utilities have over 90,000 MW of projects in the pipeline, of which 80,000 MW are

New Capacity Online (MW) 2004-2008

Note: Totals may reflect rounding. Historical data subject to revision.

Source: Ventyx, Inc., The Velocity Suite and EEI Finance Department

U.S. Shareholder- Owned Electric Entire2008p Utilities Industry New plant 3,263 11,005Plant expansions 5,590 8,619Total 8,852 19,624 2007r New plant 2,003 11,517Plant expansions 3,201 5,290Total 5,204 16,807 2006 New plant 2,642 6,901Plant expansions 3,049 6,274Total 5,691 13,175 2005 New plant 3,976 9,396Plant expansions 6,309 11,131Total 10,284 20,526 2004 New plant 6,305 18,986Plant expansions 2,136 7,885Total 8,441 26,871


BuSineSS StRategieS

fueled by coal, gas or uranium. In rela-tion to the broader industry, the share-holder-owned segment accounts for 26% of total projects in the pipeline and 45% of the coal, gas and nuclear capacity expected online before 2020. This sector has naturally a lesser per-centage of renewables in their con-struction plans than the broader indus-try, as they tend to enter into LPs and

PPAs with smaller renewable develop-ers to buy their electricity production.

Despite the recession-induced slow-down in demand growth likely over the short to medium term, additional baseload generation will still be needed in many power markets over the long-term. In light of the resistance facing many announced coal plants, several utilities have turned to nuclear power,

although new nuclear reactors will not be immune to controversy and face a different set of financial and regulatory hurdles. In 2008, shareholder-owned utilities submitted Construction and Operating License (COL) applications to the Nuclear Regulatory Commis-sion (NRC) for an additional 19 nu-clear reactors, which brought the total number of reactors pending approval

Shareholder- Entire Shareholder- Entire Shareholder- Entire Shareholder- Entire Shareholder- Entire Owned Industry Owned Industry Owned Industry Owned Industry Owned Industry 2004 2004 2005 2005 2006 2006 2007 2007 2008p 2008p

(MW)

New Capacity Online by Fuel Type 2004-2008

Note: Other = diesel, fuel oil, landfill gas, pet coke, solar/PV, waste heat, water, wood, biomass, and fuel cells.Entire Industry includes all new capacity placed on the grid by shareholder-owned electric utilities, independent power producers, municipals,co-ops, government authorities and corporations. Data includes expansions and new plants.

p = preliminary


0

5,000

10,000

15,000

20,000

25,000

30,000

Coal

Natural Gas

Nuclear

Wind

Other

U.S. Shareholder-Owned Elecric Utilities Entire IndustryFuel Type Online Online Online Online Online Online Online Online Online Online 2004 2005 2006 2007 2008p 2004 2005 2006 2007r 2008p

Coal — — 110 479 790 670 329 534 2,091 1,390

Natural Gas 8,054 9,255 4,126 3,483 4,687 25,057 17,774 9,459 7,506 8,946

Nuclear 79 247 350 — 422 79 247 350 1,199 434

Wind 306 781 1,051 1,240 2,857 484 1,924 2,405 5,022 8,319

Other 3 2 54 2 96 581 252 427 989 536

Total 8,441 10,284 5,691 5,204 8,852 26,871 20,526 13,175 16,807 19,624


BuSineSS StRategieS

projects will be the next challenge. The majority of companies already have in-dicated that without federal incentives, building a new nuclear plant will not be economically feasible.

at year-end to 24 out of a proposed 29. The NRC did not approve any Early Site Permits (ESPs) in 2008, but Southern Company’s Vogtle project in Georgia is expected to be approved in 2009. Despite the increasing number of ESP and COL application submis-sions, approvals do not guarantee that plants will be built. Lining up financ-ing to build these capital-intensive

transmission

Transmission and Distribution Survey Results

The 2008 EEI Annual Property & Plant Capital Investment Survey indi-cated that shareholder-owned electric utilities and stand-alone transmission companies invested a record $7.8 bil-lion in the nation’s transmission grid in

New Capacity Online by Region 2004-2008

Note: Data includes new plants and expansions of existing plants, including nuclear uprates. Totals may reflect rounding. ReliabilityFirst Corporation (RFC) began operations on 1/1/06 and includes ECAR, MAAC, and MAIN.



2004 2005 2006 2007 2008 Region Online Cancelled Online Cancelled Online Cancelled Online Cancelled Online CancelledECAR 1,934 2,054 — 1,736 — — — — — —ERCOT — 500 324 1,100 381 500 551 6,575 1,095 729FRCC 1,118 — 2,874 2,493 — 188 2,040 2,977 — —MAAC 1,369 — 750 1,161 — — — — — —MAIN 621 3,098 1,329 1,627 — — — — — —MRO 780 — 681 1,049 199 175 561 1,050 2,531 300NPCC 284 2,885 1,211 635 259 80 — 690 92 —RFC 1,330 1,403 — — 775 867SERC 1,762 2,440 1,691 5,104 — 3,940 84 2,217 1,134 —SPP — 2,000 107 650 141 640 776 874 670 150WECC 575 2,420 1,318 4,654 3,380 3,387 1,192 2,194 2,556 2,910Total 8,441 15,397 10,284 20,209 5,691 10,313 5,204 16,577 8,852 4,956

0

5,000

10,000

15,000

20,000

25,000

30,000

2007r 2008

(MW)

ENTIRE INDUSTRY

2004


2005

Competitive

Regulated

New Capacity Online – Regulated vs. Competetive

2004 2005 2006 2007r 2008

Total Competitive 16,655 7,419 7,205 7,864 12,177

Total Regulated 10,216 13,108 5,970 8,943 7,447

Total 26,871 20,526 13,175 16,807 19,624

2006


BuSineSS StRategieS

2007, 12% more than the $7 billion in 2006. After a slow decline from 1978 to 1998, the industry’ investment in the nation’s transmission grid experi-enced uninterrupted growth during the last 8-10 years. Since 2000, the industry and transmission companies have invested more than $40 billion in the nation’s transmission system. Also in 2007, shareholder-owned electric utility investment in the distribution system reached $17.6 billion, a 2.4% increase over the previous year’s level and a 20% increase over the amount spent in 2000. The industry has in-vested well over $100 billion in the na-tion’s distribution system since 2000.

national Corridor Designations

At the end of 2007, the Department of Energy (DOE) announced the desig-nation of two National Interest Electric Transmission Corridors (in the mid-Atlantic and the Southwest) where the DOE determined that significant con-gestion adversely impacts customers. The designations require the Federal En-ergy Regulatory Commission (FERC) to consider proposals to site interstate transmission lines within these corridors,

provided that either an affected state does not have the authority to grant ap-proval for a new line or a state involved in the proceeding has withheld approval for one year following submission of a siting application. In addition, FERC will only consider permits for projects that substantially reduce congestion. The designations raised strong opposition by environmental groups and several state regulatory commissions in both regions. In March 2008, however, the U.S. De-partment of Energy (DOE) announced that it would not reconsider any aspect of the corridor designations.

Several interstate transmission lines are currently proposed within these corridors, and most of the proposed lines are now being reviewed by state authorities. Many, like Allegheny’s TrAIL project, continue to face op-position, and are still awaiting state approval. After the Arizona Commis-sion denied an application submitted by Southern California Edison for its Palo Verde to Devers 2 project last year, the company asked FERC to use its backstop siting authority. In May, Southern California Edison requested that FERC start a prefiling process.

The process, as well as the controversy, are still ongoing.

In an attempt to facilitate planning and construction of new transmission lines, several states and Regional Trans-mission Organizations (RTOs) released reports in 2008 that outlined the need for and the challenges facing new trans-mission in their regions. And over the course of the year, the increased aware-ness of the need for transmission to support renewable energy development eclipsed congestion concerns.

transmission in Support Of Renewables

State renewable portfolio standards and a rising ecological consciousness among the public, politicians and state commissions are driving an increased focus on improving transmission ac-cess to prime wind and other renew-ables areas, which are typically far-re-moved from load centers. Connecting these resources to the transmission network is potentially costly due to the remote locations. Yet, the need to ex-pand the nation’s transmission grid to accommodate increasingly large shares of renewable energy became even more apparent during 2008.

New vs. Cancelled Capacity by Fuel Type (MW)

Note: Totals may reflect rounding. Data includes new plants and expansions of existing plants, including nuclear uprates. Other = diesel, fuel oil, landfill gas, pet coke, solar/PV, waste heat, water, wood, biomass, and fuel cells.



Fuel Type Online Cancelled Online Cancelled Online Cancelled Online Cancelled Online Cancelled 2004 2004 2005 2005 2006 2006 2007 2007 2008 2008Coal –– 750 –– 4,585 110 2,575 479 13,880 790 2,759Natural Gas 8,054 14,527 9,255 15,054 4,126 7,584 3,483 2,177 4,687 1,810Nuclear 79 –– 247 –– 350 –– –– –– 422 ––

Solar/Photovoltaics –– –– 1 5 1 3 –– –– –– ––

Wind 306 120 781 408 1,051 110 1,240 390 2,857 262Other 3 –– 1 157 53 41 2 130 96 125Total 8,441 15,397 10,284 20,209 5,691 10,313 5,204 16,577 8,852 4,956


BuSineSS StRategieS

During the first half of the year, concerns that some companies may not be able to comply with their state’s renewable energy standard (RES) due to transmission constraints encouraged the Western Governors’ Association to

make renewables a focus of western corridors and the Western Renew-able Energy Zones project was initi-ated to encourage construction of new transmission projects. Subsequently, the governors of five Great Plains states

(Iowa, Minnesota, North Dakota, South Dakota and Wisconsin) formed a joint planning group (the Upper Midwest Transmission Development Initiative) to examine issues relating to transmission for wind power. The Midwest ISO and the New England and New York ISO also conducted studies on these topics.

In addition to these regional ef-forts, a number of states undertook initiatives to assess the need for new transmission and to facilitate its con-struction. The California ISO released a “Report on Preliminary Renewable Transmission Plans” in July which ac-knowledged that the state will not meet its RES target of 20% by 2010 for lack of transmission capacity and outlined a plan to add 9,550 MW of transmis-sion capacity at a cost of $6.5 billion. Shortly after, Texas began the process set up by its “Competitive Renewable Energy Zone” (CREZ) rules and the Public Utility Commission of Texas (PUCT) approved a plan to build over 2,300 miles of new transmission lines to integrate about 18,500 MW of wind capacity at a cost of about $5 bil-lion. Following the Texas model, Utah, Colorado and Nevada adopted the CREZ model to facilitate development of transmission for renewables. During the summer, Utah’s Renewable Energy Zone Task Force began to study ways to support and facilitate the develop-ment of renewable energy and the nec-essary accompanying transmission. In Nevada, the PUC approved $3.5 mil-lion for NV Energy to spend on new renewable transmission system studies.

Spurring and supporting these ini-tiatives were a number of influential studies that highlighted the need to strengthen the nation’s transmission

2008 New Capacity Announcements by Fuel Type


Note: Other includes biomass, diesel/fuel oil, fuel cells, landfill gas, pet coke, solar/PV, waste heat, water, wood. Totals may reflect rounding.


Other499 MW

Natural Gas3,868 MW

Coal68 MW

Wind4,914 MW

Nuclear1,793 MW

Hydro2,409 MW


New Capacity Announcements by Fuel Type (MW)2004-2008

Note: Other includes biomass, diesel/fuel oil, fuel cells, landfill gas, pet coke, solar/PV, waste heat, water, wood. Totals may reflect rounding.


2004 2005 2006 2007 2008Coal 5,050 7,170 17,242 2,462 68Natural Gas 6,923 2,174 7,929 5,988 3,868Nuclear — 5,180 10,217 11,277 1,793Wind 869 898 1,773 4,900 4,914Hydro — — — — 2,409Other 5 669 1,146 322 499Total 12,847 16,091 38,307 24,949 13,551

continued on page 58


BuSineSS StRategieS

(MW)U.S. SHAREHOLDER-OWNED ELECTRIC UTILITIES

Actual and Projected Capacity Additions 2004-2020

Notes: Data includes new plants and expansions of existing plants, including nuclear uprates. Other includes biomass, diesel/fuel oil, fuel cells, landfill gas, pet coke, solar/PV, waste heat, water, wood.

Totals may reflect rounding. 2004-2008 is actual plants brought online. 2009-2020 is projected based on projects announced as of 12/31/08.

Source: Ventyx, Inc., The Velocity Suite, and EEI Finance Department

Actual Projected

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Coal

Natural Gas

Nuclear

Wind

Other

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Coal — — 110 479 790 3,833 3,132 1,350 4,065 2,014 — 1,680 750 — 500 — 1,000

Natural Gas 8,054 9,255 4,126 3,483 4,687 6,259 3,151 6,950 6,776 3,158 1,579 — — — — — —Nuclear 79 247 350 — 422 256 200 21 868 — — 6,210 4,959 7,042 4,380 2,617 7,800

Wind 306 780 1,051 1,240 2,857 2,366 1,867 1,352 558 651 349 100 — — — — —Other 3 2 54 2 96 659 18 317 257 117 1,250 1,185 — — — — —Total 8,442 10,284 5,691 5,204 8,852 13,373 8,367 9,990 12,524 5,940 3,178 9,175 5,709 7,042 4,880 2,617 8,800

2018 2019 2020

Stage of Projected Capacity Additions

Note: Data as of 12/31/08. Other includes biomass, diesel/fuel oil, fuel cells, landfill gas, pet coke, solar/PV, waste heat, water, wood. Totals may reflect rounding. Data is for the years 2009-2020.


U.S. SHAREHOLDER-OWNED ELECTRIC UTILITIESby MW Fuel Proposed Feasibility Application Pending Permitted Site Prep Under Construction Testing TotalCoal 1,010 500 4,860 784 600 10,570 — 18,324Natural Gas 2,306 140 8,823 6,777 1,060 8,406 362 27,873Nuclear 451 0 33,100 803 — — — 34,353Wind 5,063 60 885 150 — 847 238 7,243Other 694 2,405 383 142 — 179 — 3,803Total 9,524 3,105 48,051 8,655 1,660 20,001 600 91,596


BuSineSS StRategieS

Proposed New High Voltage Transmission Projects Located in Draft NIETC Designated Corridors

Source: Edison Electric Institute and SNL Financial


Project Company Voltage Location Distance Estimated Expected Cost Year In ServiceMid-Atlantic Trans-Allegheny Allegheny Energy & Dominion Resources 500 kV PA-WV 240 mi $1.1 B 2011 Interstate Line (TrAIL) Potomac-Appalachian Transmission American Electric Power & Allegheny Energy 765/500 kV WV-MD 290 mi $1.8 B 2013 Highline (PATH) AEP Interstate Project (I-765) American Electric Power 765 kV WV-NJ 550 mi $3.0 B 2015Maine Power Reliability Program Central Maine Power & Maine Public Service Co. 345 kV ME-NH 484 mi $1.4 B 2012Maine Power Connection Central Maine Power & Maine Public Service Co. 345 kV ME 200 mi $625 M 2012 (Limestone to Detroit) New England East-West National Grid USA & Northeast Utilities 345 kV CT-MD $2.1 B 2012-2013 Solution (NEEWS) Interstate Reliability Project $250 M Greater Springfield Reliability Project Central Connecticut Reliability Project 36 mi $313 M Rhode Island Reliability Project $250 M North East Energy Link National Grid USA Can-MA 200 mi Greater Springfield Reliability Project Northeast Utilities 345 kV MA-CT 100 mi $714 M 2013Mid-Atlantic Power Pathway Pepco Holdings 500 kV VA-NJ 230 mi $1.4 B 2013Susquehanna-Roseland Line PPL Corp. & PSEG 500 kV PA-NJ 130 mi $930 M 2012 Southwest Tehachapi Renewable Edison International (Southern Cal. Edison) 500 kV CA 306 mi $2.0 B 2009-13 Transmission Project Palo Verde - Devers 2 Edison International (Southern Cal. Edison) 500 kV AZ-CA 225 mi $680 M 2011Palo Verde - Yuma Pinnacle West (Arizona Public Service Co.) 500 kV AZ-CO 115 mi $300 M 2012Palo Verde - Pinnacle Peak Pinnacle West (Arizona Public Service Co.) 500 kV AZ 110 mi $700 M 2010-2012Sunrise Powerlink Sempra Energy (San Diego Gas & Electric) 500 kV CA 91 mi $1.9 B 2012

Company Site Early Site Permit Design Expected Construction & (State) (ESP) (# of Units) Operating License SubmittalAmeren Callaway (MO) –– EPR (1) July 2008DTE Energy Co. Fermi (MI) TBD ESBWR (1) September 2008Dominion Resources Inc. North Anna (VA) Approved November 2007. ESBWR (1) November 2007Duke Energy Corp. Davie County (NC) Under consideration TBD TBDDuke Energy Corp. Oconee (SC) Under consideration TBD TBDDuke Energy Corp. William States Lee (SC) –– AP1000 (2) December 2007Entergy Corp. River Bend (LA) –– ESBWR (1) September 2008Exelon Corp. Clinton (IL) Approved March 2007. TBD TBDExelon Corp. Victoria County (TX) –– ESBWR (2) September 2008Florida Power & Light Turkey Point (FL) –– AP1000 (2) 2009NuStart (Consortium) - TVA Site Bellefonte (AL) –– AP1000 (2) October 2007NuStart (Consortium) -Entergy Site Grand Gulf (MS) Approved April 2007. ESBWR (1) February 2008PPL Corp. / UniStar Susquehanna, PA –– EPR (1) October 2008Progress Energy Shearon Harris (NC) –– AP1000 (2) February 2008Progress Energy Levy County (FL) –– AP1000 (2) July 2008SCANA Corp. V.C. Summer (SC) –– AP1000 (2) March 2008Southern Co. Vogtle (GA) Approval expected in 2009. AP1000 (2) March 2008Energy Future Holdings Inc. (Luminant) Comanche Peak (TX) –– APWR (2) September 2008UniStar (Constellation & Areva) Calvert Cliffs (MD) –– EPR (1) July 2007 & March 2008UniStar (Constellation & Areva) Nine Mile Point (NY) TBD EPR (1) September 2008

Note: As of 12/31/2008

Proposed New Nuclear PlantsU.S. SHAREHOLDER-OWNED ELECTRIC UTILITIES

Source: Nuclear Energy Institute, Nuclear Regulatory Commission and EEI Finance Department

Legend: TBD: To Be Determined AP1000: Reactor designed by WestinghouseAPWR: Advanced Pressurized Water Reactor

EPR: Pressurized Water Reactor designed by FramatomeESBWR: Economic Simplified Boiling Water ReactorThose in italics represent COL applications that have been approved so far.


BuSineSS StRategieS

Selected Renewable High Voltage Transmission Projects


Project Company Voltage Location Distance Estimated Expected Status Cost Year In Service Southwest Wyoming-Colorado Intertie Project (TOT-3) AES & Western Area Power Admin. 345 kV WY-CO 250 mi $325 M 2013 AnnouncedPalo Verde-Yuma Arizona Public Service Co. 500 kV AZ-CO 115 mi $300 M 2012 AnnouncedGreen Path (North Gila to Hassayampa) Arizona Public Service Co & others 500 kV CA 117 mi 2012 Advanced developmentPalo Verde - Devers 2 Edison International (SCE) 500 kV AZ-CA 225 mi $680 M 2011 Approved by ISO and PUCTehachapi Renewable Transmission Project Edison International (SCE) 500 kV CA 306 mi $2 B 2009-13 BC to NorCal PG&E 500 kV BC-CA 2017 AnnouncedCentral California Clean Energy PG&E 500 kV CA 150 mi 2013 AnnouncedSunrise Powerlink Sempra Energy (San Diego Gas & Electric) 500 kV CA 91 mi $1.9 B 2012 SunZia Southwest Transmission Project SunZia Southwest (UniSource Energy) 500 kV AZ-NM 500 mi 2013 AnnouncedSunrise Tap project NV Energy 500 kV NV 2011 AnnouncedEastern Nevada Transmission Intertie ( EN-Ti ) NV Energy 500 kV NV 250 mi 2012 Advanced developmentPawnee-Smoky Hill transmission project PSC of CO 345 kV CO 96 mi $120 M 2013 Announced Northwest Southwest Intertie Project (SWIP) Dynegy & LS Power Group 500 kV ID-NV 500 mi 2011 Advanced developmentBoardman-Hemingway Idaho Power 500 kV ID-OR 300 mi $600 M 2012 AnnouncedGateway West Transmission Project Idaho Power & PacifiCorp 500 kV WY-ID 650 mi 2013 AnnouncedMountain States Transmission Intertie NorthWestern 500 kV MT-ID 400 mi $800 M 2013 AnnouncedColstrip Transmission System (upgrade) NorthWestern, Puget, PacifiCorp, and others 500 kV MT 2012 AnnouncedSalt Lake City to Downey PacifiCorp 345 kV UT-ID 136 mi $750 M 2010 UC - ID PUC approved 10/08Sigurd-Red Butte-Crystal PacifiCorp 345 kV UT-NV 2012 AnnouncedEnergy Gateway Transmission Project PacifiCorp 500 kV 2,000 mi $6 B Hemingway - Captain Jack ID-OR 230 mi 2013 Announced Wyoming -Jim Bridger WY-ID 600 mi 2014 Announced Wyoming -Mona substation WY-UT 600 mi 2014 AnnouncedSouthern Crossing Project Portland General Electric 500 kV OR 225 mi 2013 Announced Plains Electric Transmission Texas Electric Transmission America* 765 kV TX 1,000 mi $3.2 B 2015 AnnouncedTransWest Express Anschutz (former owners: Pinnacle, National Grid) 500 kV WY-AZ 1000 mi $3 B 2014 Spearville-Axtell ITC Great Plains 345 kV KS-NE 210 mi $186 M 2012 Advanced developmentSpearville-Wichita ITC Great Plains 345 kV KS 180 mi $82 M 2012 Advanced developmentBig Stone-Granite Falls MDU Resources & Otter Tail 345 kV SD-MN 53 mi 2013 Advanced developmentHorizon Transmission OG&E, Electric Transmission America* 765 kV OK 170 mi $500 M 2013 AnnouncedWoodward - Ok City OG&E, Electric Transmission America* 345 kV OK 115 mi $211 M 2010 Approved 9/08Prairie Wind Transmission Electric Transmission America* 765 kV KS-OK 230 mi $600 M 2013 AnnouncedV-Plan Westar Energy & ITC Great Plains 345 kV KS 180 mi 2012 Applied to build project 4/08Wichita-OK Westar Energy & OG&E 345 kV KS-OK 95 mi $260 M 2011 AnnouncedSouthwest Minnesota Wind Expansion Project Xcel 345 kV MN-SD 87 mi 2008 Construction begunHigh Plains Express (HPX) PSC of CO, PSC of NM, & others 500 kV WY-CO- NM-AZ 1,300 mi $5.1 B 2017 AnnouncedCapX 2020 Xcel & others 345 kV $1.5-1.7 B Brookings, SD- Southeast Twin Cities Xcel, Otter Tail, & others MN-SD 230 mi $665 M 2014 Announced Southeast Twin Cities - Rochester - La Crosse Xcel, Wisconsin Public Power, & others MN-WI 150 mi $360 M 2014 Announced Fargo, ND - St Cloud/Monticello Xcel, Otter Tail, Allete, & others ND-MN 250 mi $490 M 2014 Announced Northeast Potomac-Appalachian Transm. Highline (PATH) AEP & Allegheny 765 kV/500 kV WV-MD 290 mi $1.8 B 2013 Advanced developmentMaine Power Connection (Limestone to Detroit) Central Maine Power & Maine Public Service Co. 345 kV ME 200 mi $625 M 2012 AnnouncedCarson-Suffolk Dominion Resources Inc. 500 kV VA 60 mi $250 M 2011 Advanced developmentGreen Line Project New England ITC 500 kV ME-MA 140 mi 2013 AnnouncedMid-Atlantic Power Pathway Pepco Holdings 500 kV VA-NJ 230 mi $1.4 B 2013 Susquehanna-Roseland Line PPL & PSEG 500 kV PA-NJ 130 mi $930 M 2012 North East Energy Link National Grid CANADA-MA 200 mi Announced Midwest Donald C. Cook Transmission line AEP & ITC 765 kV OH-MI 700 mi $2.6 B 2015 AnnouncedChicago- Hartland (North Dakota) AEP 765 kV ND-IL 1,000 mi $5-10 B AnnouncedPioneer Transmission AEP & Duke 765 kV IN 240 mi $1 B 2015 Announced * Electric Transmission America: American Electric Power and MidAmerican

Source: SNL Financial and EEI Finance Department


BuSineSS StRategieS

infrastructure to support the growth of renewable generation. Perhaps the most influential was NERC’s 2008 Long Term Reliability Assessment (LTRA) covering the 2008-2017 timeframe. NERC reiterated the need for ongoing investment in transmis-sion to maintain grid reliability and to integrate rapidly growing renew-able generation, which it expects will significantly outpace new transmis-sion development. Other organiza-tions, such as the Pacific NorthWest Economic Region (comprising states in the northwest United States and some Canadian provinces) and WIRES also released reports stressing the need for new transmission in some regions and examining the many financial and reg-

ulatory obstacles that thwart increased investment in renewable energy in-frastructure. In February 2009, EEI released a report entitled “Transmis-sion Projects: Supporting Renewable Resources” that illustrates the recent and ongoing efforts of EEI members to develop transmission to support renewable resource integration.

Encouraged by existing renewable developments as well as regional trans-mission organization (RTO) planning guidelines, numerous projects were an-nounced in 2008. The table Selected Renewable High Voltage Transmission Projects shows a sample of transmission projects announced by shareholder-owned utilities to support develop-ment of renewable resources. Some

of these cross numerous state lines, such as PacifiCorp’s Energy Gateway (2,000 miles through Idaho, Oregon, Utah and Wyoming), AEPs Chicago-to-Hartland (1,000 miles from North Dakota to Illinois), PG&E’s BC-to-NorCal (expected to bring renewable resources from British Columbia to California), as well as the High Plains Express project owned by the PSC of Colorado and PSC of New Mexico (running 1,000 miles through Wyo-ming, Colorado, New Mexico and Ar-izona). Building these projects, how-ever, may be difficult. Split authority over siting and permitting, public op-position in some cases, rising cost of capital, and cost allocation and cost recovery challenges all represent sig-nificant barriers for the expansion of transmission infrastructure.

Fuel Sources

Record high fossil fuel commodity prices during much of 2008 and a 1% year-to-year decline in electricity de-mand deeply affected the use of fuels for power generation and contributed to a reduction in coal, gas and oil-fired generation. The only generation technologies that saw increased output were nuclear (0.32%), hydropower (0.92%) and non-hydro renewables (17.57%). Coal remained the primary fuel source for U.S. electric generation but its share of the total continued its decline, from 52.8% in 1997 to 48.5% in 2008. Breaking with recent trends, the percentage of U.S. electric output generated by natural gas fell in 2008, to 21.3%, consistent with the 2.2% decline in gas-fired generation. Renewable resources continued to grow in importance, producing 9.1% of total U.S. electric output in 2008.

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

2001 2002 2003 2004 2005

($ Millions [Real $2007])

2007 2008 2009

Planned*Actual

Actual and Planned Transmission Investment 2000-2010

20062000

Note: The Handy-Whitman Index of Public Utility Construction Costs used to adjust actual investment for inflation from year to year. The GDP Deflator used to adjust planned investment for inflation from year to year.Data represent both shareholder-owned utilities and stand-alone transmission companies.

*Planned total industry expenditures are estimated from 85% response rate to EEI’s Electric Transmission Capital Budget & Forecast Survey. Actual expenditures from EEI’s Annual Property & Plant Capital Investment Survey & FERC Form 1s.

Source: Edison Electric Institute, Business Information Group

5,0734,948

6,8157,551 7,769

9,463

10,388

11,050

5,6525,198

5,746

2010


BuSineSS StRategieS

Fuel Sources for Electric Generation 1999–2008

U.S. ELECTRIC UTILITY AND NON-UTILITY

1999 2000 2001 2007r2002 2003

p = preliminaryr = revised

U.S. Electric Utility: Owns and/or operates facilities within the United States, its territories, or Puerto Rico for the generation, transmission, distribution, or sale of electric energy primarily for use by the public. This includes shareholder-owned utilities, public power, and cooperatives.

Non-Utility Power Producer: Non-utility power producers include qualifying cogenerators, qualifying small power producers, and other non-utility generators (including independent power producers) without a designated franchised service area.

Source: Energy Information Administration

2004 20050

10%

20%

30%

40%

50%

60%

Coal

2006

Nuclear

Natural Gas

Oil

Conventional Hydro

Other Renewables

2008p

Fuel Sources for Net Electric Generation U.S. ELECTRIC UTILITY AND NON-UTILITY

p = preliminaryr = revised

Note: Totals may not equal 100.0% due to rounding.



Source: Energy Information Administration

2008p 2007r

Coal 48.5% 48.5%

Natural Gas 21.3% 21.6%

Nuclear 19.7% 19.4%

Hydro conventional 6.1% 6.0%

Oil 1.1% 1.6%

Other 0.4% 0.5%

Other renewables 3.0% 2.5%

Biomass 1.4% 1.3%

Geothermal 0.4% 0.4%

Solar 0.02% 0.0%

Wind 1.3% 0.8%

Total 100% 100%


BuSineSS StRategieS

Non-hydro renewable energy ac-counted for 3% of total U.S. electric generation in 2008, up from to 2.5% in 2007, as it continued to grow strongly on an absolute basis. As in 2007, wind and solar power were the year’s fastest growing sources of electricity; wind generation increased by 51% year-to-year and solar generation grew by 36%.

Coal

Although coal remained the prima-ry fuel used to generate electricity in the U.S. in 2008, its share of the fuel mix has steadily declined for the last

ten years. Coal accounted for 48.5% of 2008’s total electric output versus 52.8% a decade earlier. The trend is primarily attributable to the growth in natural gas-fired generation. Up until 2008, despite coal’s relative ero-sion of market share, rising nationwide electricity demand drove up total coal consumption by the power sector. Last year, however, a 1% reduction in over-all electricity demand, coupled with rising coal prices, pushed coal genera-tion down by 1.1% compared to 2007.

Despite coal’s declining relative contribution, it is expected to remain

the nation’s primary generation fuel for the foreseeable future due to its cost advantage over natural gas and the abundant domestic supply of coal reserves. The recent evolution in U.S. natural gas markets (higher than ex-pected supply and lower prices) implies that coal’s cost-advantage over natural gas might be reduced in the future if increasingly large amounts of domestic gas supply enter the market. Factoring in that possibility, the Energy Informa-tion Administration’s (EIA) 2009 An-nual Energy Outlook estimated that coal-fired generation will represent 45% of total electric output in 2025 and 46.6% in 2030. This is the first time the Outlook forecasts coal’s share at under 50% throughout the 2009-2030 period.

However, the increasing likelihood that Congress will impose a national cap on carbon emissions makes it diffi-cult to confidently predict that far into the future. Coal usage will be shaped by market fundamentals, state and fed-eral greenhouse gas (GHG) emissions policies, and the availability of cost-effective technologies that capture and sequester GHG emissions from coal-fired facilities.

Despite much lower prices for sul-fur dioxide (SO

2) emission allowances

(SO2 emissions allowances closed the

year at around $200/ton, well below the levels of 2006 and 2005) due to the District of Columbia Court of Appeals decision to strike down the Clean Air Interstate Rule, the average cost to produce electricity1 from coal (based on preliminary, modeled data) was $26.99/MWh in 2008, a 9% in-crease over 2007. However, the fuel cost component of the total rose by

Average Cost of Fossil Fuels 1999-2008

(Cents/MMBtu)

U.S. ELECTRIC UTILITIES

0

200

400

600

800

1000

1200

1400

1600

1800

The years 2002 and beyond include data for electric utilities, independent power producers, and commercial and industrial combined heat and power producers. The years prior to 2002 include data for electric utilities only.


Source: U.S. Department of Energy, Energy Information Administration (EIA)

2008p1999 2000 2001 2002 2003 2004 2005 2006 2007

OILCOAL GAS

1 Production costs for each fuel only include fixed and variable operating costs. they do not include capital or construction costs.


BuSineSS StRategieS

15%. The rapid growth of coal prices that began at the end of 2007 due to increased international demand con-tinued until the third quarter of 2008, when the global economic slowdown brought most energy and commodity prices down. At year-end, coal prices from most basins had gone down sig-nificantly from their record peaks dur-ing the summer but remained well above the level observed at the end of 2007. Northern Appalachian coal spot prices, for example, closed the year at about $101/ton, a 32% reduction from the September price of $150/ton

but still 84% higher than the $55/ton level of December 2007.

natural gas

The combined effects of high nat-ural gas prices during the first half of 2008 and slightly reduced energy demand for the year contributed to a more than 2% decrease in natural gas generation. The fuel’s share of the nation’s total electric output also de-creased for the first time since 2003, to 21.3% from 21.6% in 2007.

As was the case with coal and other energy commodity prices, 2008 saw

record high natural gas prices. The price trend reversal after the summer was not enough to bring yearly costs down. The preliminary average cost to produce electricity from natural gas was $84.35/MWh in 2008 compared to $64.63/MWh in 2007 and $75.67/MWh in 2005 (the previous high).

Natural gas prices followed the rise in crude oil prices during the first half of the year, reversing the trend of price moderation seen in 2006 and 2007. Henry Hub spot prices jumped from a near-term low of about $6 per mil-lion British thermal units (mmBtu) in October 2007 to more than $8 per mmBtu by mid-January and up to $13.32 per mmBtu by early July—the highest level for the year. Rising natu-ral gas spot prices appeared to be the result of several factors, including ris-ing crude oil prices, increased demand from most economic sectors and low inventories. However, after the rise in domestic supply from unconventional sources, slowing demand and a conse-quent increase in inventories, natural gas prices began a slow descent in July. By the end of December, the Henry Hub natural gas price was below $6 per mmBtu.

U.S. natural gas production has been slowly increasing since 2005. In 2008, it grew 8% over the 2007 level, and total production, at 21.2 quadril-lion Btu, reached the highest level since 1975. Increased onshore production in the lower 48 states and higher produc-tion from unconventional sources were responsible for this increase.

Rising domestic production cou-pled with reduced overall electricity demand cut imported LNG volume in half—from 2007’s record 771 Bcf to 355 Bcf in 2008. Many analysts expect LNG imports to grow again in

0

20

40

60

80

100

120

140

160

180

200

Average Cost to Produce Electricity

2003-2008



* 2008 results are preliminary and based on modeled data from Ventyx, Inc., The Velocity Suite

Source: Ventyx, Inc., The Velocity Suite

Coal

Nat

ural

Gas Oi

lN

ucle

ar

Hyd

ro

Cost of Fuel Non-Fuel O&M

($/MWh)

U.S. ELECTRIC UTILITY AND NON-UTILITY

2008*2003 2004 2005 2006

Coal

Nat

ural

Gas Oi

lN

ucle

ar

Hyd

ro

Coal

Nat

ural

Gas Oi

lN

ucle

ar

Hyd

ro

Coal

Nat

ural

Gas Oi

lN

ucle

ar

Hyd

ro

Coal

Nat

ural

Gas Oi

lN

ucle

ar

Hyd

ro

Coal

Nat

ural

Gas Oi

lN

ucle

ar

Hyd

ro2007


BuSineSS StRategieS

2009 as global demand stays depressed and cargo tankers are attracted to the U.S. market and its vast storage capa-bilities. Over the longer-term, demand for natural gas will probably return to a growth trend and (despite increased domestic production) LNG supply will be an important factor in meet-ing that demand. An adequate LNG import, storage and pipeline infra-structure in the U.S. will be crucial for meeting the nation’s energy needs. Fu-ture federal carbon legislation will also likely increase the electric industry’s re-liance on natural gas-fired generation, accentuating the critical importance of a dependable natural gas supply chain. Cognizant of this, FERC and MARAD/Coast Guard are approving more LNG import terminals. At the end of 2008, there were 8 LNG import terminals in the U.S., 4 new terminals

and 2 expansions under construction, and 16 projects in the approval stage.

nuclear

There are 104 electricity-generating nuclear reactors in the U.S. Nuclear pow-er continues to account for the largest percentage of electric generation in Ver-mont, South Carolina, New Jersey, Illi-nois, Connecticut and New Hampshire. Nuclear energy accounted for 19.7% of total U.S. electric generation in 2008, up from 19.4% in 2007. Whereas coal and gas-fired generation were lower in 2008 than in 2007, nuclear generation edged up 0.32% year-to-year, highlighting its essential role as a low-cost, reliable source of baseload power.

Since 2001, when costs associated with coal generation began rising, nuclear power has enjoyed the lowest

production costs of all fuel types. In 2008, the preliminary average cost to produce electricity from nuclear power was $16.66/MWh ($4.64 for fuel and $12.02 for non-fuel O&M) compared to $26.99/MWh for coal, $84.35/MWh for natural gas and $178.06/MWh for oil. Nuclear power’s low generating cost and fuel price stability result from the low frequency of the refueling cycle and the small impact of fuel costs on overall production costs. In 2008, nuclear fuel accounted for only 27.9% of total production costs. The share was 80.8%, 91.2% and 94.1% respectively for coal, oil and natural gas generation.

In 2008, uranium spot prices con-tinued the decline observed since mid-2007. Uranium peaked at $135/lb. in June 2007, ended that year at about $90/lb., and closed 2008 at $52/lb. (a level still elevated in relation to the longer-term price history of the com-modity). Overall, world uranium re-sources are considered adequate, but analysts generally believe that ongoing production and supply constraints, in addition to the uncertainties about whether new production can be devel-oped in time to meet demand growth, will keep spot prices elevated for the foreseeable future.

According to Trade-Tech and the Nuclear Energy Institute (NEI), there are 29 new nuclear plants under con-struction worldwide. In the U.S., 48 nuclear reactors have been granted 20-year license extensions, seven have filed for license renewals and 17 more plants (25 units) are expected to apply. In 2008, shareholder-owned utilities submitted Construction and Operat-ing License (COL) applications to the NRC for an additional 19 reactors, which brought the total number of re-

NYMEX-Henry Hub Natural Gas Close Prices1999-2008

($/MMBtu)

0

2

4

6

8

10

12

14

16

Source: NYMEX & SNL Financial

Jan-08

Jul 08

Jul-99

Jan-00

Jul-00

Jan-01

Jul-01

Jan-02

Jul-02

Jan-03

Jul-03

Jan-04

Jul-04

Jan-05

Jul-05

Jan-06

Jul-06

Jan-07

Jul-07

Jan-99

Dec 08


BuSineSS StRategieS

Existing and Proposed U.S. LNG TerminalsAs of December 31, 2008

* On hold or canceled

Sources: FERC and Ventyx Inc., The Velocity Suite

Constructed:1. Everett, MA: 1.035 Bcfd (DOMAC -SUEZ LNG)2. Cove Point, MD: 1.0 Bcfd (Dominion -Cove Point LNG)3. Cove Point, MD: 0.8 Bcfd (Dominion) - Expansion4. Elba Island, GA: 1.2 Bcfd (El Paso -Southern LNG)5. Lake Charles, LA: 2.1 Bcfd (Southern Union -Trunkline LNG)6. Gulf of Mexico: 0.5 Bcfd (Gulf Gateway Energy Bridge -ExcelerateEnergy)7. Offshore Boston: 0.8 Bcfd (Northeast Gateway -ExcelerateEnergy)8. Freeport, TX: 1.5 Bcfd (Cheniere/Freeport LNG Dev.)9. Sabine, LA: 2.6 Bcfd (Sabine Pass Cheniere LNG)

Under Construction:10. Hackberry, LA: 1.8 Bcfd (Cameron LNG -Sempra Energy)11. Sabine, TX: 2.0 Bcfd (Golden Pass -ExxonMobil)12. Sabine, LA: 1.4 Bcfd (Sabine Pass Cheniere LNG -Expansion)13. Elba Island, GA: 0.9 Bcfd (El Paso -Southern LNG) - Expansion14. Pascagoula, MS: 1.5 Bcfd (Gulf LNG Energy LLC)15. Offshore Boston: 0.4 Bcfd (Neptune LNG -SUEZ LNG)

Approved by FERC:16. Corpus Christi, TX: 1.0 Bcfd (Ingleside Energy -Occidental Energy Ventures)17. Corpus Christi, TX: 2.6 Bcfd (Cheniere LNG)18. Corpus Christi, TX: 1.1 Bcfd (Vista Del Sol –4Gas)19. Fall River, MA: 0.8 Bcfd (Weaver's Cove Energy/Hess LNG)*20. Port Arthur, TX: 3.0 Bcfd (Sempra Energy)21. Logan Township, NJ: 1.2 Bcfd (Crown Landing LNG -BP)*22. Cameron, LA: 3.3 Bcfd (Creole Trail LNG -Cheniere LNG)23. Freeport, TX: 2.5 Bcfd (Cheniere/Freeport LNG Dev.) – Expansion24. Hackberry, LA: 0.85 Bcfd (Cameron LNG -Sempra Energy) – Expansion25. Pascagoula, MS: 1.3 Bcfd (Bayou CasotteEnergy LLC-ChevronTexaco)26. Port Lavaca, TX: 1.0 Bcfd (Calhoun LNG -Gulf Coast LNG Partners)27. LI Sound, NY: 1.0 Bcfd (Broadwater Energy – TransCanada/Shell)28. Bradwood, OR: 1.0 Bcfd (Northern Star LNG – Northern Star Natural Gas LLC)29. Baltimore, MD: 1.5 Bcfd (AES Sparrows Point – AES Corp.)

Approved by MARAD/Coast Guard30. Port Pelican: 1.6 Bcfd (Chevron Texaco)*31. Offshore Louisiana: 1.0 Bcfd (Main Pass McMoRanExp.)

Proposed to FERC32. Robbinston, ME: 0.5 Bcfd (Downseast LNG – Kestrel Energy)*33. Coos Bay, OR: 1.0 Bcfd (Jordan Cove Energy Project)34. Astoria, OR: 1.5 Bcfd (Oregon LNG)35. Calais, ME: 1.5 Bcfd (BP Consulting)*

Proposed to MARAD/Coast Guard36. Offshore California: 1.4 Bcfd (Clearwater Port LLC – NorthernStar NG LLC)37. Gulf of Mexico: 1.4 Bcfd (Bienville Offshore Energy Terminal – TORP)*38. Offshore Florida: 1.9 Bcfd (SUEZ Calypso – SUEZ LNG)39. Offshore California: 1.2 Bcfd (OceanWay – Woodside Natural Gas)*40. Offshore Florida: 1.2 Bcfd (Hoëgh LNG – Port Dolphin Energy)41. Offshore New York: 2.0 Bcfd (Safe Harbor Energy – ASIC, LLC)


BuSineSS StRategieS

actors pending approval to 24 out of the proposed 29.

The low and stable cost of nuclear-fueled generation, the security of ura-nium fuel supply and environmental considerations are all driving a re-newed interest in nuclear energy in the U.S. Yet the development of domes-tic nuclear plants is unlikely to occur quickly. New plant construction must navigate a potentially slow regulatory and licensing process. And despite nuclear power’s generation cost and

environmental advantages, its future will also be shaped by the strategy for long-term storage of spent fuel. Until recently, Yucca Mountain was the cho-sen location for a national repository for spent nuclear fuel. The Obama Administration, however, has rejected this option, and is currently consider-ing new strategies to dispose of radio-active waste.

Renewable energy

Renewable fuel sources (includ-ing hydropower) produced 9.1% of total U.S. electric generation in 2008 compared to 8.5% in 2007. The in-crease was primarily due to the rapid growth of wind and solar generation, which brought the share of non-hydro renewable generation to 3% from 2.5% in 2007. Although small in abso-lute terms, this 0.5% gain represents a

States With Renewable Electricity Standard Programs29 States and the District of Columbia as of April 3, 2009

*Xcel Energy: 30% By 2020 **Increasing 1% per year thereafter, with no stated expiration date

Source: Edison Electric Institute

15%By 2020

15%By 2015 25%

By 2025*

20%By 2015

33%By 2020

15%By 2025

20%By 2020

20%By 2020

5,880 MWBy 2015

10%By

2015

105 MW25%By

2025

18%By 2020

25%By 2013

40%By

2017

VT: =Load Growth2005-2012

20%By 2020 Existing RES Mandate

Statewide Renewable Electricity Goal

MA: 25%By 2030**

RI: 16%By 2019

CT: 27%By 2020

NJ: 22.5%By 2021DE: 20%

By 2019

MD: 20%By 2022

DC: 20%By 2020

NH: 24%By 2025

15%By

2021

25%By 2025

15%By 2025

12.5%By 2021

10%By 2015

20%By 2025

10%By 2015

25%By 2025

10%By

2015

continued on page 72

State Renewable electricity Standard Mandates by State as of March 2009

State implementation Schedule Covered entities eligible Resources Off-ramps(Cost Mitigation/Other)

aZ • Starts at 1.25% of sales in 2006, steps up to 15% in 2025

Set-aside:• Renewable dG = 30% of

RES by 2012

•IoUs•Coops

•Solar thermal/PV•Wind•Geothermal•Landfill gas•Biogas •Qualified biomass•Fuel cells using renewables•Qualified hydro•onsite renewable dG

None

Ca • Start points vary by LSE w/statewide standard of 33% by 2022

•Note: By executive order

•IoUs•CLSEs• Community choice aggregators•Munis to comply w/intent•LAdWP committed to RES•Non-creditworthy LSEs exempt

•Note: Per 2006 law

•Solar thermal/PV•Wind•ocean wave, thermal, tidal•Geothermal•Some biomass•Biodiesel•Fuel cells using renewables•Qualified hydro•Gas from digesters, landfills•MSW-to-fuel using non-burning process


None

CO • IoUs: Starts at 3% in 2007, steps up to 20% by 2020

• Munis w/ > 40K customers & all coops: 1% by 2008, steps up to 10% by 2020

Set-aside:• Solar mandate = 4% of

RES w/half from onsite customer dG

•IoUs•Coops•Munis w/ > 40K customers•Smaller munis may opt in

•Wind•Solar•Geothermal•Qualified biomass•Qualified hydro•Fuel cells using renewables•Gas from landfills, wastewater treatment•Waste heat, w/restrictions

• Covered entities except coops have 2% annual per cus-tomer rate impact limit; no penalty imposed if exceeded

• Coops have 1% rate limit

Ct • Starts at 4% in 2004, steps up to 27% in 2020

•IoUs•CLSEs and aggregators• Munis to promote &

encourage RE but not mandated

Some resources subject to specified tier/class limits•Solar thermal/PV•Wind• Fuel cells using renewable or non-

renewable fuels•Landfill gas•ocean thermal, wave, tidal•Qualified hydro•Qualified biomass•onsite dG using renewables•trash-to-energy•Efficient ChP• Savings from customer-side energy

efficiency/load mgt. C&I waste heat/pressure recovery

None

De • Starts at 1% on 6/1/07, steps up to 20% in 2019

Set-aside:• Solar PV = 2% of RES in

2019

• Retail electric suppliers, including IoUs and CLSEs

• Munis & coops may opt out if offering green tariffs/funding for RE/energy efficiency

• Industrials w/peaks > 1,500 kW exempt

•Solar thermal/PV•Fuel cells using renewables•Wind•ocean•Geothermal•Qualified hydro•Qualified biomass•Gas from biodigesters, landfills•onsite in-state dG

• PSC in 2010, 2011, and 2013 may review schedule and recommend acceleration or deceleration to legislature as necessary

• PSC in 2014 and each year thereafter may itself change schedule given certain mar-ket conditions


BuSineSS StRategieS

State Renewable electricity Standard Mandates by State as of March 2009


aZ • Starts at 1.25% of sales in 2006, steps up to 15% in 2025

Set-aside:• Renewable dG = 30% of

RES by 2012

•IoUs•Coops

•Solar thermal/PV•Wind•Geothermal•Landfill gas•Biogas •Qualified biomass•Fuel cells using renewables•Qualified hydro•onsite renewable dG

None

Ca • Start points vary by LSE w/statewide standard of 33% by 2022

•Note: By executive order

•IoUs•CLSEs• Community choice aggregators•Munis to comply w/intent•LAdWP committed to RES•Non-creditworthy LSEs exempt


•Solar thermal/PV•Wind•ocean wave, thermal, tidal•Geothermal•Some biomass•Biodiesel•Fuel cells using renewables•Qualified hydro•Gas from digesters, landfills•MSW-to-fuel using non-burning process


None

CO • IoUs: Starts at 3% in 2007, steps up to 20% by 2020

• Munis w/ > 40K customers & all coops: 1% by 2008, steps up to 10% by 2020

Set-aside:• Solar mandate = 4% of

RES w/half from onsite customer dG

•IoUs•Coops•Munis w/ > 40K customers•Smaller munis may opt in

•Wind•Solar•Geothermal•Qualified biomass•Qualified hydro•Fuel cells using renewables•Gas from landfills, wastewater treatment•Waste heat, w/restrictions

• Covered entities except coops have 2% annual per cus-tomer rate impact limit; no penalty imposed if exceeded

• Coops have 1% rate limit

Ct • Starts at 4% in 2004, steps up to 27% in 2020

•IoUs•CLSEs and aggregators• Munis to promote &

encourage RE but not mandated

Some resources subject to specified tier/class limits•Solar thermal/PV•Wind• Fuel cells using renewable or non-

renewable fuels•Landfill gas•ocean thermal, wave, tidal•Qualified hydro•Qualified biomass•onsite dG using renewables•trash-to-energy•Efficient ChP• Savings from customer-side energy

efficiency/load mgt. C&I waste heat/pressure recovery

None

De • Starts at 1% on 6/1/07, steps up to 20% in 2019

Set-aside:• Solar PV = 2% of RES in

2019

• Retail electric suppliers, including IoUs and CLSEs

• Munis & coops may opt out if offering green tariffs/funding for RE/energy efficiency

• Industrials w/peaks > 1,500 kW exempt

•Solar thermal/PV•Fuel cells using renewables•Wind•ocean•Geothermal•Qualified hydro•Qualified biomass•Gas from biodigesters, landfills•onsite in-state dG

• PSC in 2010, 2011, and 2013 may review schedule and recommend acceleration or deceleration to legislature as necessary

• PSC in 2014 and each year thereafter may itself change schedule given certain mar-ket conditions


BuSineSS StRategieS


DC • total (two tiers) starts at 4.5% in 2008, steps up to 20% in 2020

Set-aside: • Solar (tier 1) = 0.4% of

RES in 2020

•IoUs•CLSEs

Some resources subject to specified tier/class limits•Wind•Solar thermal/PV•Qualified biomass•Geothermal•All forms of ocean energy•Landfill/wastewater treatment gas•Fuel cells using renewables •Qualified hydro•Some waste-to-energy

None

Hi • Starts at 10% in 2010, steps up to 20% by 12/31/20

•IoUs •Wind•Solar•ocean •Landfill gas•Biomass•Biofuels•Biodiesel•Fuel cells using renewables•Geothermal•Falling water•hydrogen from renewables•Energy efficiency•onsite grid-connected renewable dG•Waste heat from efficient ChP • RE displacement or offset technology,

e.g., solar water heating, seawater AC

• Requires ratemaking structure encouraging cost-effective RE development, but allows for deviation if standards cannot be met cost-effectively due to events beyond utility control

iL • Starts at 2% on 6/1/08, steps up to 25% by 2025

Set-aside:• Wind = 75% of RES in

2025

•IoUs w/ ≥ 100,000 customers• Merchants/wholesale suppli-

ers serving C&I customers

•Solar thermal/PV•Wind•Biodiesel•Biomass •Qualified hydro•In-state landfill gas

• If specified rate impact limits exceeded, compliance delayed

• CC to review cap in 2011 and report to General Assembly if it unduly constrains procure-ment of cost-effective RE resources

• RES impact limits: 2008, 0.5% of kWh cost in baseline yr. ending 5/31/07; 2009, greater of 0.5% of prior yr. costs or 1% of 2007 baseline yr. costs; 2010, greater of 0.5% of prior yr. costs or 1.5% of 2007 baseline yr.; 2011, greater of 0.5% of prior yr. costs or 2% of 2007 baseline yr.; thereafter, greater of 2.015% of 2007 baseline yr. or incremental costs in 2011

ia • 105 MW statewide w/no target date

•IoUs •Qualified hydro•Solar •Wind•MSW•Some biomass

None


Me • Class 2 starts/stays at 30% in 2000; Class 1 starts at 1% in 2008, steps up to 10% in 2017. total: 40% in 2017

•IoUs•CLSEs• All other entities selling at

retail or providing standard offer service

•Fuel cells•tidal•Geothermal•Solar thermal/PV•Wind•Efficient ChP•PURPA small power•Qualified hydro•Biomass•Landfill gas•MSWonline after 9/1/05:• Qualified new/expanded resources

(except wind) from above resources except hydro w/o fish passage, MSW, efficient ChP

•Qualified pumped storage

• PUC may review Class I standard, suspend increases under certain circumstances, and waive penalties if utility deemed to have made good faith effort but could not reasonably satisfy standard due to market conditions

MD • Starts at 3.5% in 2006, steps up to 20% in 2022

Set-aside:•Solar = 2% of RES in 2022

•IoUs•All other retail suppliers• Coops w/PPAs in place on

10/1/04 exempted until PPAs expire

Some resources subject to specified tier/class limits•Solar thermal/PV•Wind•Qualified biomass•Biomass part of co-fired units•Geothermal•ocean wave, tidal, current, thermal• Gas from landfill, digesters,

waste treatment• Fuel cells using fuels from biomass/

biogas•Eligible onsite grid-connected dG•Qualified poultry litter-to-energy•Qualified hydro

• If actual or projected cost of purchasing solar RECs in any year is ≥ 1% of supplier’s total annual electricity sales revenues in state, supplier may ask PSC to delay by 1 year scheduled increase for solar. delay to continue until actual or anticipated cost is < 1% of supplier’s annual sales revenue, at which time supplier is subject to next scheduled increase

• Above procedures & rules apply to non-solar (tier 1) except trigger level is greater of 10% of supplier's total an-nual retail sales or applicable tier 1 percentage require-ment for that year

Ma • Starts at 1% by 12/31/03, steps up to 4% by 12/31/09 and increases 1%/yr. afterward w/no end date, e.g., RES is 25% by 12/31/30

•IoUs •CLSEs• Munis exempt unless opting

into retail choice

Some resources subject to specified tier/class limits•Solar thermal/PV•Wind•ocean thermal, wave, tidal•Fuel cells using renewables•Landfill gas•Qualified hydro•Qualified biomass•Marine/hydrokinetic energy•Qualified dG•Geothermal

None

Mi Credit Portfolio: • 10% by 2015, starts in

2012 w/obligations unique to each supplier based on specified criteria

Capacity Portfolio: • Consumers Energy must

build or purchase 200 MW of new RE by 2013 and 500 MW by 2015

• detroit Edison must build or purchase 300 MW by 2013 and 600 MW by 2015

•IoUs•Munis•Coops•Alternative electric suppliers

•Biomass•Solar thermal/PV•Wind• Kinetic energy of moving water including

waves, tides, currents •Qualified hydro•Geothermal•MSW•Landfill gas• Energy optimization and/or advanced

cleaner energy systems may be applied against targets w/regulatory approval

• Compliance not required to extent PSC determines recovery of incremental cost of compliance to exceed retail rate impact caps as follows: $3/mo for residential; $16.58/mo. for commercial; and $187.50/mo. for lg. C&I

• Upon petition by provider, PSC may for good cause grant two one-year extensions of 2015 deadline; good cause stems from factors related to siting, equipment cost/availability, transmission, reli-ability, labor or government/court orders


BuSineSS StRategieS


Mn Xcel:• Starts at 15% by 12/31/10,

steps up to 30% by 2020Xcel set-aside:• Wind = 25% of RES in

2020Covered entities except Xcel: • Starts at 12% by 12/31/12,

steps up to 25% by 2025

•IoUs•G&t coops• Municipal power agencies

(not munis themselves)

•Solar•Wind•hydro • Biomass including gas from landfills,

anaerobic digesters •MSW•hydrogen

• PUC may modify or delay mandate for cost impacts, adverse impacts on reliability, siting problems, construction or permitting delays, trans-mission constraints, or other statutory limitations

MO • Starts at 2% in 2011, steps up to 15% by 2021

Set-aside:• Solar = 2%; Empire district

Electric excepted

•IoUs •Wind•Solar thermal/PV•Biomass •Landfill/wastewater treatment gas•Qualified hydro•Fuel cells using renewables

• PSC may excuse compliance for events beyond utility con-trol or if cost increases retail rates by > 1%

Mt • Starts at 5% on 1/1/08, steps up to 15% in 2015

•IoUs• Coops & munis must recog-

nize intent of law to encour-age RE and establish own RES

•Wind•Solar• Gas from landfills, farms, wastewater

treatment•Geothermal•Qualified biomass•Fuel cells using renewables•Renewable part of multi-fired facilities•Qualified hydro

• Utilities may seek short-term waivers of full compliance based on factors outside their control, inability to mitigate adverse reliability impacts of integrating resources, or bids exceeding cost caps specified for ea. utility

nV • Starts at 6% on 1/1/05, steps up to 20% on 1/1/15

Set-aside:•Solar = 5% of RES

•IoUs•CLSEs

•Solar thermal/PV•Wind•Geothermal•Qualified biomass•Qualified biogas•Fuel cells using renewables•hydro•Reverse polymerization• Certain energy efficiency, capped @

25% of RES, including savings from customer dG

• PUC must waive RES to extent energy efficiency or RE contracts are not available at just and reasonable cost

nH • Starts at 4% in 2008, steps up to 23.8% in 2025

Set-asides:• Solar = 0.3% of RES in

2025•Biomass & biogas = 6.5% •Qualifying hydro = 1%

•All retail electricity•suppliers

Some resources subject to specified tier/class limits•Wind•Geothermal•Fuel cells using biomass/biogas•ocean thermal, wave, current, tidal•Gas from landfills, biodigesters•Qualified biomass•Qualified biogas•Qualified hydro•Solar•In-state, onsite customer dG

• PUC may accelerate or delay by up to 1 year any incremental increase in Class I (most eligible resources) or II (new solar) for good cause and after notice & hearing

• PUC may modify Class III (biomass) or IV (hydro) as of 1/1/12, such that require-ments must be 85%-95% of reasonably expected potential annual output of available eli-gible sources after taking into account demand from similar programs in other states

• PUC must review RES pro-gram and report findings to legislature in 2011, 2018 and 2025, including any recom-mendations for changes to class requirements or other program aspects


nJ • Starts at 3.5% in 2006, steps up to 22.5% in 2021

Set-aside:• Solar = 2.12% of RES in

2021 mandate

•IoUs•CLSEs

Some resources subject to specified tier/class limits•Wind•Geothermal•ocean wave, tidal•Fuel cells using renewables•Gas from landfills, biodigesters•Qualified biomass•Solar thermal/PV•Qualified hydro•Qualified resource recovery

None

nM •IoUs: • Starts at 5% on 1/1/06,

steps up to 20% in 2020 IoU set-asides (“diversifica-tion targets”) in RES:•Solar = 20% of RES•Wind = 20% • Geothermal & biomass =

10% •Renewable dG = 3% Coops: • Starts at 5% by 1/1/15,


•IoUs•Coops

•Solar thermal/PV•Wind•Qualified hydro•Geothermal•Fuel cells using non-fossil fuels•Qualified biomass•Renewable onsite dG

• Utilities excused from diversi-fication targets but not overall RES if costs raise rates by > 2%, or if targets cannot be reached w/o impairing reliability.

• For C&I loads > 10 million kWh/yr, PRC may reduce RES to keep cost increases at lesser of 1% of annual bill or $49,000 as of 1/1/06, then cap increases at $10,000/yr until fixed at lower of 2% or $99,000. After 1/1/12, cap adjusted by CPI

nY • Starts at existing 19.3% (lg. hydro) in 2006, steps up to 25% by 12/31/13

Set-aside:• output from new re-

sources = 7.71% of RES by 12/31/13

• IoUs collect sales-based sur-charge, used by central pro-curement agency to provide incentives for producers to deliver RE to state wholesale market and for end-users to install RE facilities

Some resources subject to specified tier/class limits•Wind•Gas from landfill, biodigesters•Qualified biomass•Liquid biofuel, biodiesel•Fuel cells•Solar PV•Qualified hydro•ocean tidal, wave, current, thermal•Eligible customer dG

None

nC • IoUs: Starts at 3% in 2012, steps up to 12.5% in 2021

• Coops & munis: Starts at 3% in 2012 then steps up to 10% in 2018

Set-asides:• Solar = 0.20% of overall

RES in 2018•Swine waste same as solar• Poultry waste = 900,000

MWh in 2014

•IoUs•Coops•Munis

•Solar thermal/PV•ocean wave, current•Biomass•Geothermal•Landfill gas•Qualified hydro•Fuel cells & ChP using renewables•Waste heat from onsite renewable dG• Certain energy-efficiency, capped @25%

of RES to 2021, 40% after

• UC may modify or delay RES if in public interest


BuSineSS StRategieS


Mn Xcel:• Starts at 15% by 12/31/10,

steps up to 30% by 2020Xcel set-aside:• Wind = 25% of RES in

2020Covered entities except Xcel: • Starts at 12% by 12/31/12,


•IoUs•G&t coops• Municipal power agencies

(not munis themselves)

•Solar•Wind•hydro • Biomass including gas from landfills,

anaerobic digesters •MSW•hydrogen

• PUC may modify or delay mandate for cost impacts, adverse impacts on reliability, siting problems, construction or permitting delays, trans-mission constraints, or other statutory limitations

MO • Starts at 2% in 2011, steps up to 15% by 2021

Set-aside:• Solar = 2%; Empire district

Electric excepted

•IoUs •Wind•Solar thermal/PV•Biomass •Landfill/wastewater treatment gas•Qualified hydro•Fuel cells using renewables

• PSC may excuse compliance for events beyond utility con-trol or if cost increases retail rates by > 1%

Mt • Starts at 5% on 1/1/08, steps up to 15% in 2015

•IoUs• Coops & munis must recog-

nize intent of law to encour-age RE and establish own RES

•Wind•Solar• Gas from landfills, farms, wastewater

treatment•Geothermal•Qualified biomass•Fuel cells using renewables•Renewable part of multi-fired facilities•Qualified hydro

• Utilities may seek short-term waivers of full compliance based on factors outside their control, inability to mitigate adverse reliability impacts of integrating resources, or bids exceeding cost caps specified for ea. utility

nV • Starts at 6% on 1/1/05, steps up to 20% on 1/1/15

Set-aside:•Solar = 5% of RES

•IoUs•CLSEs

•Solar thermal/PV•Wind•Geothermal•Qualified biomass•Qualified biogas•Fuel cells using renewables•hydro•Reverse polymerization• Certain energy efficiency, capped @

25% of RES, including savings from customer dG

• PUC must waive RES to extent energy efficiency or RE contracts are not available at just and reasonable cost

nH • Starts at 4% in 2008, steps up to 23.8% in 2025

Set-asides:• Solar = 0.3% of RES in

2025•Biomass & biogas = 6.5% •Qualifying hydro = 1%

•All retail electricity•suppliers

Some resources subject to specified tier/class limits•Wind•Geothermal•Fuel cells using biomass/biogas•ocean thermal, wave, current, tidal•Gas from landfills, biodigesters•Qualified biomass•Qualified biogas•Qualified hydro•Solar•In-state, onsite customer dG

• PUC may accelerate or delay by up to 1 year any incremental increase in Class I (most eligible resources) or II (new solar) for good cause and after notice & hearing

• PUC may modify Class III (biomass) or IV (hydro) as of 1/1/12, such that require-ments must be 85%-95% of reasonably expected potential annual output of available eli-gible sources after taking into account demand from similar programs in other states

• PUC must review RES pro-gram and report findings to legislature in 2011, 2018 and 2025, including any recom-mendations for changes to class requirements or other program aspects


nJ • Starts at 3.5% in 2006, steps up to 22.5% in 2021

Set-aside:• Solar = 2.12% of RES in

2021 mandate

•IoUs•CLSEs

Some resources subject to specified tier/class limits•Wind•Geothermal•ocean wave, tidal•Fuel cells using renewables•Gas from landfills, biodigesters•Qualified biomass•Solar thermal/PV•Qualified hydro•Qualified resource recovery

None

nM •IoUs: • Starts at 5% on 1/1/06,

steps up to 20% in 2020 IoU set-asides (“diversifica-tion targets”) in RES:•Solar = 20% of RES•Wind = 20% • Geothermal & biomass =

10% •Renewable dG = 3% Coops: • Starts at 5% by 1/1/15,


•IoUs•Coops

•Solar thermal/PV•Wind•Qualified hydro•Geothermal•Fuel cells using non-fossil fuels•Qualified biomass•Renewable onsite dG

• Utilities excused from diversi-fication targets but not overall RES if costs raise rates by > 2%, or if targets cannot be reached w/o impairing reliability.

• For C&I loads > 10 million kWh/yr, PRC may reduce RES to keep cost increases at lesser of 1% of annual bill or $49,000 as of 1/1/06, then cap increases at $10,000/yr until fixed at lower of 2% or $99,000. After 1/1/12, cap adjusted by CPI

nY • Starts at existing 19.3% (lg. hydro) in 2006, steps up to 25% by 12/31/13

Set-aside:• output from new re-

sources = 7.71% of RES by 12/31/13

• IoUs collect sales-based sur-charge, used by central pro-curement agency to provide incentives for producers to deliver RE to state wholesale market and for end-users to install RE facilities

Some resources subject to specified tier/class limits•Wind•Gas from landfill, biodigesters•Qualified biomass•Liquid biofuel, biodiesel•Fuel cells•Solar PV•Qualified hydro•ocean tidal, wave, current, thermal•Eligible customer dG

None

nC • IoUs: Starts at 3% in 2012, steps up to 12.5% in 2021

• Coops & munis: Starts at 3% in 2012 then steps up to 10% in 2018

Set-asides:• Solar = 0.20% of overall

RES in 2018•Swine waste same as solar• Poultry waste = 900,000

MWh in 2014

•IoUs•Coops•Munis

•Solar thermal/PV•ocean wave, current•Biomass•Geothermal•Landfill gas•Qualified hydro•Fuel cells & ChP using renewables•Waste heat from onsite renewable dG• Certain energy-efficiency, capped @25%

of RES to 2021, 40% after

• UC may modify or delay RES if in public interest


BuSineSS StRategieS


OH • IoUs: Starts at 0.25% in 2009 from each of advanced & renewable resource groups, steps up to 12.5% from ea. group for total 25% by 12/31/24

Set-aside:•Solar = 0.5% by 12/31/24

•IoUs•CLSEs

Renewable resources:•Solar thermal/PV•Wind •Qualified hydro•Geothermal• Solid-waste derived fuel not involving

combustion•Fuel cells generating electricity•Biogas•Qualified biomass• Energy storage increasing use of off-

peak renewable•onsite renewable dG•Qualified hydroAdvanced resources:• Increased conventional output not

increasing Co2•Any onsite dG meeting customer needs•Clean coal•Advanced nuclear•Any fuel cell• Advanced waste conversion reducing

GhGs• Advanced-fueled dG of C&I customers,

w/restrictions•dSM/energy efficiency

• Compliance excused if 3% of costs of otherwise producing/buying requisite electricity is exceeded

• Covered entity may file for force majeure, requiring PUC to determine renewables are reasonably available in ohio and PJM/MISo regions. If resources not available, PUC must modify that year’s obligation. Such modification doesn’t reduce future obliga-tions and PUC may order shortfalls made up later

• PUC to review compliance yearly to identify weather, equipment or resource factors, or events beyond supplier’s control leading to shortfalls

OR • For entities w/load ≥ 3% of state’s retail sales: Starts at 5% in 2011, steps up to 25% in 2025

• Load > 1.5% and < 3% of state’s retail sales: Fixed at 10% in 2025

• Load ≤ 1.5% of state’s retail sales: Fixed at 5% in 2025

•IoUs•PUds•Munis•Coops•CLSEs

•Wind•Solar thermal/PV•ocean wave, tidal, thermal•Geothermal•Qualified biomass • Gas from landfill wastewater, anaerobic

digesters, MSW•hydrogen from renewables•Qualified hydro

• Full compliance excused if utility costs exceed 4% of its annual revenue requirement for compliance year

• Utilities exempt if purchase of electricity from eligible sources would: 1) exceed projected load requirements; 2) require utility to substitute eligible RE for sources other than coal, natural gas or petroleum; 3) require utility to substitute eligible RE from existing large hydro located on the Columbia River; or 4) reduce consumer-owned util-ity's purchase of lowest price electricity from BPA

Pa • Starts at 5.7% on 6/1/06, steps up to 18% on 6/1/20

Set-aside:•Solar PV = 0.5% on 6/1/20

•IoUs•CLSEs• Coops to offer energy ef-

ficiency, dSM to comply

Some resources subject to specified tier/class limits•Wind•Qualified hydro•Fuel cells using renewables•Solar thermal/PV•Geothermal •Biomass•Gas from coal mines, landfills, digesters•Waste coal•Coal gasification•ChP•Qualified dG•hydro w/pumped storage•MSW•Waste heat from industrial onsite dG

• If PUC determines utilities are unable to comply despite good faith efforts, it may alter obligation for given year, but may set higher obliga-tions later to compensate for shortfalls


Ri • Starts at 3% on 1/1/07, steps up to 16% in 2019

•1 IoU•CLSEs

•Solar thermal/PV•Wind•Geothermal•ocean tidal, wave, current, thermal•Qualified hydro •In-state dG•Fuel cells using renewables•Qualified biomass•Landfill gas•Biodiesel•Renewable fuel in co-fired units

• In 2010 and 2014, PUC may delay scheduled annual increases for one year if sup-plies deemed inadequate

• In 2020/each year thereafter, the min. requirement set in 2019 must be maintained unless PUC determines stan-dard no longer necessary

tX • Starts at 2,280 MW on 1/1/07, steps up to 5,880 MW by 1/1/15

Set-aside:• Non-wind resources must

be ≥ 500 MW by 1/1/15

•IoUs in non-restructured areas•CLSEs• Munis and coops offering

customer choice

•Solar thermal/PV•Wind•Geothermal•hydro•Qualified biomass•Landfill gas•ocean wave, tidal, thermal•onsite renewable dG

• PUC may cap price of RECs and suspend RES to protect grid reliability and operation

Vt • Goal that may become mandate: Lesser of 100% of retail sales growth during 2005-12 or 10% of total 2005 statewide sales

•IoUs•Munis•Coops

•Wind•Solar•Geothermal• Gas from landfills, biodigesters, sewage

treatment•Biomass•Biodiesel•Qualified hydro •Fuel cells using renewables•ChP using renewables• Efficient ChP using fossil fuels/qualifying

increases from existing units

• Goal to become manda-tory if PSB makes specified finding by 1/1/13, otherwise RES mandate does not apply. Finding may include whether renewable resources placed in service or certified exceeded 10% of total state-wide retail sales for 2005

Wa • Starts at 3% in 2012, steps up to 15% in 2020

•IoUs•Munis

•Wind•Solar•Geothermal•Gas from landfill, sewage treatment•ocean wave, tidal•Qualified hydro•Qualified biodiesel•Renewable, qualified dG • Zero load growth (not energy efficiency

per se)

• Waiver allowed for listed events beyond utility control or reasonable ability to antici-pate. Impact of RES costs on rates not reason for waiver

Wi Starts at 2% by 12/31/10, steps up to 10% by 12/31/15

IoUsMunisCoops

•Wind•Fuel cells using renewables•Geothermal•Qualified biomass•Landfill gas•ocean tidal, wave•Solar thermal/PV•Qualified hydro

• PSC may delay require-ments due to reliability or rate impacts, siting delays, or transmission constraints


BuSineSS StRategieS

aCROnYM gLOSSaRY

AC – air conditioningBPA – Bonneville Power AdministrationCC – Commerce CommissionC&I – commercial and industrialChP – combined heat & powerCLSE – competitive load serving entitydG – distributed generationdSM – demand-side managementG&t – generation and transmissionGhG – greenhouse gashVAC – heating, ventilation & air conditioningIoU – investor-owned utilitykW – kilowattkWh – kilowatt hourLAdWP – Los Angeles dept. of Water & PowerLSE – load-serving entity MISo – Midwest Independent System operatorMSW – municipal solid waste

MW – megawattMWh – megawatt hourPJM – Pennsylvania-New Jersey-MarylandPPA – power purchase agreementPRC – Public Regulation CommissionPSB – Public Service BoardPSC – Public Service CommissionPUC – Public Utilities Commission or Public Utility CommissionPUd – public utility districtPURPA – Public Utility Regulatory Policies Act of 1978PV – photovoltaicQF – qualifying facilityRE – renewable energyREC – renewable energy creditRES – renewable electricity standard (also called renewable energy standard, renewable portfolio standard, or other, depending on state)UC – Utilities Commission

Sources: Edison Electric Institute from original source material, database of State Incentives for Renewables & Efficiency

significant development. Despite their still small relative contribution to total electric output, renewables produced, again, the fastest growth of all fuel types, including a 36.1% increase in 2008 compared to 2007 for solar and a 51% rise for wind. Wind generation has experienced very rapid growth in recent years and is almost exclusively responsible for the growth of the non-hydro renewables sector. The expan-sion in solar output is also significant given that solar generation had been fairly stable since the late 1990s. In 2008, solar-powered electricity exceed-ed 8.3 GWh compared to 5 GWh only two years earlier.

The above data demonstrate the growing support for renewable energy that has resulted from a number of fac-tors, including the long-term climb in fossil fuel commodity prices; rising costs associated with building base-

load coal plants; the financial, regula-tory and political uncertainties facing new nuclear plant construction; and rising public concern over environ-mental issues.

Government and state policies and incentives, however, have been and continue to be key sources of support for development of renewable gen-eration. The Federal Production Tax Credit (PTC), which provides a 2¢/kWh credit for electricity produced from certain renewable resources, is critical for financing new wind farms and the Investment Tax Credit (ITC) is a major financial support for solar power. After months of uncertainty, Congress passed a short-term exten-sion of federal tax incentives as part of an economic stimulus package in the fall of 2008. In early 2009, the Ameri-can Recovery and Reinvestment Act (ARRA) granted a longer-term exten-

sion of those incentives, allowed devel-opers to apply for the Investment Tax Credit (ITC) instead of the Production Tax Credit (PTC), or a cash grant in-stead of the PTC or the ITC. Given the almost disappearance of the tax equity market and the overarching ef-fects of the credit crisis, the extensions and new tax provisions will undoubt-edly help investment in wind and solar facilities.

State policies have also promoted and supported non-hydro renew-able resources. The continuation and expansion of state renewable energy electricity standards (RES) has been a major driver of renewable energy de-velopment. Like recent years, 2008 was a very active year in the RES arena. Utah and South Dakota enacted legis-lation that set non-mandatory renew-able goals. Maryland and Washington, D.C. increased their RES targets. And


BuSineSS StRategieS

three additional states enacted an RES: Ohio (25% by 2025), Michi-gan (10% by 2015) and Missouri (re-placed a state goal with a15% by 2021 RES mandate).

Given such public sector support, renewable energy’s share of U.S. elec-tricity generation will likely continue to grow. However, growth of renewable generation is critically dependent on a parallel development of transmission infrastructure and on the availability of financing (which became strained in late 2008 by the economic recession and credit crisis).

Oil

Oil accounted for 1.1% of U.S. electric generation in 2008, a 30% re-duction from the 1.6% in 2007. For the third straight year, oil made the smallest contribution to electricity generation of all fuel types, accounting for less than half that made by non-hydro renewables. The 2008 figures contrast with those of 2005, when oil accounted for 3% of electric output and non-hydro renewables 2.2%.

Persistently high oil prices in 2006, 2007 and through most of 2008 were an important contributing factor to the decline in oil use. The prelimi-nary average cost to produce electricity from oil in 2008 was $178.06/MWh, a 71% increase from 2007 and an 82% increase from 2006. Surging global oil prices pushed the already high ratio of fuel cost to total generation cost from 86% in 2007 to 91% in 2008.

While crude oil prices averaged $15 to $25/barrel in the mid-1990s, the price of oil began an upward climb in the beginning of the current decade. West Texas Intermediate crude spot prices started 2007 at around $60/

barrel, peaked at over $145/barrel in mid-July 2008 and closed the year at around $40/barrel.

The international political envi-ronment is often the primary driver of world spot oil prices, yet the highs reached in the winter of 2007 and first half of 2008 were also a reflection of a tight physical market. Strong world demand along with OPEC’s decision to cut back production at the begin-ning of the year, as well as refinery and production outages, led to falling in-ventories in oil importing countries. The upward spiral was reversed in the summer when the combination of sus-tained high oil prices, slowing demand from China, and the first manifesta-tions of the international economic re-cession all led to a reduction of world oil demand and prices. Even OPEC’s decision at the beginning of October 2008 to cut back production by 1.5 million barrels a day and hurricane-related outages were insufficient to sta-bilize crude oil prices.

As has been the case for the last 40 years, crude oil prices in the United States will remain subject to the dynamics of the international oil market and the relative strength of the dollar versus other currencies. As recent developments show, however, oil prices are also inextricably linked to the evolution and international management of the current credit and economic crises.

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