karen m. snyder national fuel gas distribution … · direct testimony of karen m. snyder...

TESTIMONY OF KAREN M. SNYDER

IN BEHALF OF

PGC Statement No. 5

NATIONAL FUEL GAS DISTRIBUTION CORPORATION

PENNSYLVANIA PUBLIC UTILITY COMMISSION v.

NATIONAL FUEL GAS DISTRIBUTION CORPORATION (PURCHASED GAS COSTS -- 66 PA.C.S. SECTION 1307(1)),

DOCKET NO. R-2013-2341534

DIRECT TESTIMONY OF KAREN M. SNYDER R-2013-2341534

1 Q. Please state your name and business address.

2 A. My name is Karen M. Snyder and my business address

3 is 6363 Main Street, Williamsville, New York 14221.

4 Q. By whom are you employed and in what capacity?

5 A. I am employed by National Fuel Gas Distribution

6 Corporation ("Distribution") as a Rate Analyst in the Rates and

7 Regulatory Affairs Department.

8 Q. Will you state briefly your educational background and

9 experience?

10 A. I graduated from Niagara University, in May 1994, with a

11 Bachelor of Business Administration degree in Accounting.

12 Prior to joining Distribution, I worked in public accounting for five

13 years and earned my CPA license in NYS in 1998. I gained an

14 additional four years of industry based financial analysis

15 experience before joining Distribution in 2003.

16 In July 2003, I was employed by Distribution in the Financial

17 Accounting Department. In May 2006, I transferred into the

18 Rates and Regulatory Affairs Department. I was promoted to

19 my present position of Rate Analyst IV in March 2009.

20 Q. Please summarize your responsibilities in this position relative

21 to this proceeding.

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A. My responsibilities include preparation of filings relating to recovery of

2 gas costs. Therefore, I am familiar with the Pennsylvania Public Utility

3 Commission's ("Commission") procedures for gas cost recovery.

4 Q. What is the purpose of your testimony?

5 A. I am testifying in support of PGC Exhibit Nos. 17 and 23 and PGC

6 Exhibit Nos. 1, 2, 3, 21, 21-A, 21-8 and 21-C.

7 Q. Please explain PGC Exhibit No. 17.

8 A. PGC Exhibit No. 17 compares Distribution's average transportation

9 and storage costs from its affiliates to those from others upstream of

10 the affiliates for the twelve months ended November 30, 2012.

11 Q. Does PGC Exhibit No. 17 address any other matters?

12 A. Yes, it addresses any purchases of gas Distribution may have made

13 from its affiliates. As detailed in PGC Exhibit No. 17, and explained

14 further in PGC Exhibit No. 19, pursuant to its tariff, Distribution made

15 purchases of monthly imbalance gas totaling 112,642 Mcf at a unit

16 cost of $2.5496/Mcf from an affiliate during the twelve months ended

17 November 30, 2012.

18 Q. How does the Pennsylvania Division's affiliated average cost of

19 transportation services compare with others?

20 A. As shown in PGC Exhibit No. 17, Page 2, Distribution's average

21 transportation costs from National Fuel Gas Supply Corporation

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1 ("Supply") compare favorably with costs of transportation from

2 Columbia Gas Transmission LLC, Tennessee Gas Pipeline Company

3 and Texas Eastern Transmission LP. It is imperative to emphasize,

4 however, that transportation services by the interstate pipelines

5 upstream of Supply are not interchangeable with transportation service

6 provided by Supply. Specifically, Supply provides the benefit of a

7 multiple point system that distributes the gas from the applicable

8 upstream pipeline receipt points to Distribution's many local distribution

9 systems that in turn deliver gas to end-user customers.

1 o Q. What is the benefit of using Supply's storage service?

11 A. Supply provides the no-notice storage service that is critical for

12 meeting Distribution's temperature sensitive demand. It also allows for

13 overrun service from time to time and offers a more flexible

14 injection/withdrawal operation than the storage services provided by

15 other upstream pipelines.

16 Q. Does the cost comparison in PGC Exhibit No. 17, Page 3 represent all

17 the costs associated with storage services?

18 A. No. The comparison does not represent all the costs incurred when

19 Distribution contracts for storage capacity with upstream pipelines. In

20 reality, most storage agreements require Distribution to sign up

21 specific transportation service to move gas into and from the storage

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1 field. This additional storage transportation cost is incremental and

2 should be factored in the storage cost comparison. In contrast,

3 Supply's storage service is more economical because Distribution

4 contracts with Supply only for sufficient transportation service to meet

5 customers' peak day and seasonal requirements. No additional

6 transportation capacity is required to use Supply's storage.

7 Q. Please briefly explain PGC Exhibit No. 23.

8 A. PGC Exhibit No. 23 has three schedules, which contain Distribution's

9 projected purchased gas cost portfolio. The schedules are:

1 o • Schedule 1:

11 o Projected upstream transportation volumes at Distribution -

12 PAD's citygate (pages 1-2).

13 o Upstream transportation service tariff rates (pages 3-4)

14 o Storage and purchased gas costs (pages 5-6).

15 o Storage volumes (pages 7 -8).

16 o Summary of storage unit costs (pages 9-10).

17 o Storage costs (pages 11-12).

18 o Storage unit costs (pages 13-14).

19 • Schedule 2: Distribution- PAD's Appalachian and local production

20 gas cost calculation.

21 • Schedule 3: Upstream pipeline contracted capacity and rates.

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1 Q. How is the projected purchased gas portfolio generated?

2 A. The projected purchased gas portfolio, in terms of receipt and

3 delivered volumes, is generated from the SENDOUT™ model.

4 Q. Please briefly describe the SENDOUT™ model.

5 A. The SENDOUT™ model is a linear programming computer model that

6 is used by the Gas Supply Administration Department. In essence, the

7 model identifies the optimal suppliers to use each month and how to

8 schedule purchases from such suppliers. It also determines, for the

9 Pennsylvania Division, storage injections, withdrawals and resulting

10 levels of inventory to meet the system demand on a least cost basis.

11 The optimization process considers numerous factors which include,

12 but are not limited to, daily flow constraints, storage injection and

13 withdrawal flows, daily and seasonal pipeline flow constraints, storage

14 inventory limits and ending targets, gas supply costs, transportation

15 costs and shrinkage, the time interval to be optimized and the market

16 requirements.

17 Q. How is the gas cost in PGC Exhibit No. 23, Schedule 1, Pages 5 and 6

18 calculated?

19 A. With a few exceptions, the gas cost is calculated by multiplying the

20 receipt volume in PGC Exhibit No. 23, Schedule 1, Pages 1 and 2 by

21 the projected wellhead price in PGC Exhibit No. 25. The forecasted

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basis is also applied to the receipt volume and the basis applied is

2 dependent upon the receipt and delivery points. The exceptions are,

3 as discussed in PGC Exhibit No. 8, Distribution's contracts for some

4 gas supplies with fixed prices or limited price escalations to be

5 delivered during the period December 2012 through March 2013.

6 These gas supplies are individually priced in accordance with their

7 negotiated agreements. The gas costs presented on PGC Exhibit No.

8 23 reflect these exceptions.

9 Q. What are the sources of the upstream pipeline rates in PGC Exhibit

1 o No. 23, Schedule 1, Pages 3, 4, 9 and 1 0?

11 A. The rates are derived from the latest tariff filings. The specifics of

12 each pipeline are discussed below:

13 • Columbia: The current rates, which were taken from Docket RP12-

14 605-000 Operational Transactions Rate Adjustment Filing, Docket

15 RP12-000 Annual Retainage Adjustment Mechanism Filing and

16 Docket Nos. RP95-408 and RP12-261-000 Annual Environmental

17 Rate Adjustment Filing, are assumed to remain in effect throughout

18 the projection period.

19 • Tennessee: The current rates, which were taken from Docket Nos.

20 RP11-1566, RP11-2066 and RP12-450, are assumed to be in

21 effect throughout the projection period.

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1 • Supply: The current rates, which were taken from Docket No.

2 RP12-88-000, are assumed to be in effect throughout the projection

3 period.

4 • Texas Eastern: The current rates, which were taken from Docket

5 RP-13-237 -000 Annual ASA and Interruptible Revenue

6 Reconciliation Report are assumed to be in effect throughout the

7 projection period.

8 Q. Please describe Distribution's FY2013 and FY2014 storage rate

9 derivation in PGC Exhibit No. 23, Schedule 1, Pages 13 and 14.

1 o A. Distribution's Pennsylvania Division's storage rate derivation mirrors

11 the calculation actually performed at the ,end of each fiscal year. The

12 annual gas costs inclusive of commodity and demand purchased gas

13 costs, upstream transportation costs and storage rental costs are

14 totaled. The cost of gas purchased for off-system sales is excluded

15 from the storage rate calculation. The net cost is then divided by the

16 annual gas delivery volume at Distribution's Pennsylvania Division

17 citygate.

18 Q. Please explain PGC Exhibit No. 23, Schedule 2.

19 A. PGC Exhibit No. 23, Schedule 2 is Pennsylvania's Appalachian

20 Production ("~P") and Local Production ("LP") volume and cost

21 summaries. AP is production received directly by Supply and

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1 transported by Supply to Distribution whereas LP is production

2 received directly by Distribution without the use of Supply's facilities.

3 Effective in this 1307(f) filing, Distribution has two AP Production

4 Rates. AP Production Rate 1 is priced at the forecasted wellhead rate

5 plus a monthly adjustment. The monthly adjustment is a composite

6 rate that reflects that approximately 33% of the AP is purchased

7 pursuant to spot contracts that are priced at 80% of the Appalachian

8 Index and 67o/o is purchased pursuant to dedicated (Life-of-Reserves)

9 contracts that are priced at 1 OOo/o of the Appalachian Index. AP

1 o Production Rate 2 represents a one-winter contract that Distribution

11 entered into effective November 1, 2012. The contract is for 9,936

12 Dth/day of firm gas supply that is delivered into its Supply EFT

13 capacity. The price is the projected wellhead forecast plus the receipt

14 point differential at Columbia Appalachia less a $.03/Dth commodity

15 premium. Distribution also has one LP Production Rate this season.

16 LP Production Rate 1 is priced at the forecasted wellhead rate plus a

17 monthly adjustment. The monthly adjustment is a composite rate that

18 reflects that approximately 11 °/o of the LP is purchased pursuant to

19 spot contracts that are priced at 80°/o of the Appalachian Index and

20 89% is purchased pursuant to dedicated (Life-of-Reserves) contracts

21 that are priced at 100% of the Appalachian Index.

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Q. Please explain PGC Exhibit No. 23, Schedule 3.

2 A. PGC Exhibit No. 23, Schedule 3 summarizes Distribution's contracted

3 capacity and rates by pipeline for the period December 2012 through

4 November 2014.

5 Q. Please describe PGC Exhibit 1.

6 A. PGC Exhibit 1 details, by month, for the twelve months

7 ended November 30, 2012, volumes and costs of gas

8 purchased from upstream suppliers, local production and

9 Peoples TWP, LLC ("T.W. Phillips"). The data shown in PGC

1 o Exhibit 1 represent historical information from Distribution's

11 books and records.

12 The category entitled "Upstream Purchases" on PGC

13 Exhibit 1, Schedule 1, Sheet 1 reflects Distribution's cost of

14 purchasing gas from various upstream producers, whose gas is

15 transported by long-line interstate pipeline companies to

16 National Fuel Gas Supply Corporation ('Supply"), which in turn

17 delivers the gas supplies to Distribution. A monthly breakdown

18 of Distribution's commodity and demand costs from upstream

19 suppliers is provided in PGC Exhibit 1, Schedule 1, Sheet 2.

20 Further detail of Distribution's costs from upstream suppliers is

21 provided in PGC Exhibit 1, Schedule 2, Sheet 1.

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DIRECT TESTIMONY OF KAREN M. SNYDER R-20 13-2341534

1 The category entitled "Storage" on PGC Exhibit 1,

2 Schedule 1, Sheet 1 reflects Distribution's charges from storage

3 providers for space required within their facilities and the cost of

4 gas purchased for storage. A monthly breakdown of

5 Distribution's rental and storage gas cost is provided in PGC

6 Exhibit 1, Schedule 2, Sheet 2.

7 The category entitled "Transportation" on PGC Exhibit 1,

8 Schedule 1, Sheet 1 reflects charges for transportation of gas

9 purchased from suppliers. A monthly breakdown of

1 o Distribution's costs for transportation of upstream gas is

11 provided in PGC Exhibit 1, Schedule 4.

12 The Demand cost of gas is split between Demand-

13 Natural Gas Supply ("Demand-NGS") and Demand-Distribution

14 Charge ("Demand-DC"). Demand-DC includes the cost of

15 pipeline capacity and storage needed to provide peak

16 delivery/temperature swing requirements for Distribution's sales

17 and SATC customers. These are costs that Distribution would

18 incur even if all customers converted to transportation service.

19 A certain amount of capacity would have to be maintained to

20 serve these peaking requirements. PGC Exhibit 1, Schedule 5

21 provides a detailed calculation of the Demand-DC costs.

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Demand-NGS includes the remaining demand costs incurred to

2 provide sales service. The Demand-NGS costs represent total

3 demand costs less Demand-DC costs.

4 Distribution shares Capacity Release Revenues on a

5 75%/25% basis. The transportation amount includes the

6 adjustment necessary to flow through 75% of these revenues to

7 ratepayers.

8 The category entitled "Transportation Credit" on PGC

9 Exhibit 1, Schedule 1, Sheet 1 reflects the costs recovered from

1 o transportation customers. A monthly breakdown of

11 Distribution's transportation credits is provided in PGC Exhibit 1,

12 Schedule 1, Sheet 4.

13 The category entitled "Local Production" on PGC Exhibit

14 1, Schedule 1, Sheet 1 reflects Distribution's cost of gas

15 purchased from local producers. A monthly breakdown of

16 Distribution's cost of gas purchased from local producers is

17 provided in PGC Exhibit 1, Schedule 1, Sheet 3.

18 The category entitled "T.W. Phillips" on PGC Exhibit 1,

19 Schedule 1, Sheet 1 reflects Distribution's cost of purchasing a

20 small volume of gas from T.W. Phillips under its Rate Schedule

21 SWS - Small Wholesale Service. A monthly breakdown of

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1 Distribution's cost from T.W. Phillips is provided in PGC Exhibit

2 1, Schedule 3. T.W. Phillips is the only physical source of

3 supply for a small portion of Distribution's system. In order to

4 obtain other supplies Distribution would have to make a

5 substantial investment for the construction of new facilities to

6 physically connect a few existing customers to Distribution's

7 other sources of supply. The customers referenced are located

8 in Butler County, at the extremity of Distribution's system.

9 The category entitled "Exchange Gas" on PGC Exhibit 1,

10 Schedule 1, Sheet 1 reflects the recognition of gas costs related

11 to any monthly imbalances associated with tWo Exchange

12 Agreements as discussed in PGC Exhibit No. 8 and further

13 explained in PGC Exhibit No. 4. The monthly breakdown of

14 Distribution's costs associated with Exchange Gas is provided

15 in PGC Exhibit 1, Schedule 1, Sheet 6.

16 The category entitled "Off-System Sales" on PGC Exhibit

17 1, Schedule 1, Sheet 1 reflects costs of gas purchased for sale

18 to customers that are not part of Distribution's retail system.

19 Such purchases are removed from gas costs to properly reflect

20 gas purchased to serve Distribution's retail customers. The

21 monthly breakdown of Distribution's gas costs associated with

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Off-System Sales is provided in PGC Exhibit 1, Schedule 1,

Sheet 7.

As stated in PGC Exhibit No. 8, and approved under

previous settlements of Distribution's 1307(f) proceedings,

Distribution retains 25% of the net revenues from off-system

sales. The remaining 75% of the net revenues are flowed

through to ratepayers. The category entitled "Off-System Sales

Refund" on PGC Exhibit 1, Schedule 1, Sheet 1 reflects this

75% flow through of the net revenues. The monthly breakdown

of Off-System Sales Refunds is provided in PGC Exhibit 1,

Schedule 1, SheetS.

The category entitled "Credit- Line Hits" on PGC Exhibit

1, Schedule 1, Sheet 1 reflects payments received by

Distribution as compensation for gas lost as a result of damage

to Distribution's facilities. Generally such payments are

received from construction contractors that cause damage to

Distribution's facilities, typically during excavation projects. A

monthly breakdown of these amounts is provided in PGC

Exhibit 1, Schedule 1, Sheet 5.

Please explain PGC Exhibit 2 and PGC Exhibit 3.

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1 A.


PGC Exhibit 2 and PGC Exhibit 3 contain data pertaining

2 to projected volumes and costs of gas to be purchased by

3 Distribution. PGC Exhibit 2 contains projected data, by month,

4 for gas to be purchased from suppliers during the period

5 December 1, 2012 through July 31, 2013. PGC Exhibit 3

6 contains projected data, by month, for gas to be purchased from

7 suppliers during the twelve month period ending July 31, 2014.

8 Q. Please summarize how the projected data, contained in PGC

9 Exhibit 2 and PGC Exhibit 3, were prepared.

10 A. Based upon forecasted sales of gas explained by Ms.

11 Zablonski, Distribution determined the total volume of gas that

12 Distribution would be required to purchase in order to make the

13 projected level of sales to its customers. Volumes of gas that

14 Distribution would be able to obtain from local producers and

15 the small volume of gas to be purchased from T. W. Phillips

16 were projected. The remainder of gas supplies was projected

17 to be purchased from upstream suppliers.

18 Under FERC Order 636, Distribution is responsible for

19 the purchasing function previously provided by Supply. Supply

20 and upstream pipelines will transport this gas. PGC Exhibit 2,

21 Schedule 1 and PGC Exhibit 3, Schedule 1 summarize the

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1 projections of costs by cost category. PGC Exhibit 2, Schedule

2 1 summarizes projections for the eight month period ending July

3 31, 2013. PGC Exhibit 3, Schedule 1 summarizes projections

4 for the twelve month period ending July 31, 2014.

5 The category entitled "Transportation Credit" on PGC

6 Exhibit 2, Schedule 1 reflects revenues for recovery of

7 purchased gas costs of transportation and storage expected

8 from transportation customers. The "Transportation Credit"

9 reflected on Exhibit 3, Schedule 1 is based upon the rate that is

10 discussed in Ms. Suarez's testimony. PGC Exhibit 2, Schedule

11 1 summarizes such data for the eight month period ending July

12 31, 2013. PGC Exhibit 3, Schedule 1 summarizes data for the

13 twelve month period ending July 31, 2014.

14 PGC Exhibit 2, Schedule 2 and PGC Exhibit 3, Schedule

15 2 provide detailed calculations of projected costs for upstream

16 purchases and storage. PGC Exhibit 2, Schedule 2 provides

17 data for the eight month period ending July 31, 2013. PGC

18 Exhibit 3, Schedule 2 provides data for the twelve month period

19 ending July 31, 2014. The projections of upstream supplier

20 costs were explained previously in this testimony and the

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1 wellhead price projection will be explained in Ms. Cruz's

2 testimony.


4 3 provide detail of projected volumes and costs of gas to be

5 purchased from T.W. Phillips. PGC Exhibit 2, Schedule 3

6 provides such data for the eight month period ending July 31,

7 2013 and PGC Exhibit 3, Schedule 3 provides such data for the

8 twelve month period ending July 31, 2014. These projections

9 are based on historical amounts for the twelve months ended

10 November 30, 2012.


12 4 provide the amount of credits related to capacity release by

13 month. PGC Exhibit 2, Schedule 4 provides data for the eight

14 month period ending July 31, 2013 and PGC Exhibit 3,

15 Schedule 4 provides data for the twelve month period ending

16 July 31, 2014. The projection of capacity release credits will be

17 explained in Ms. Suarez's testimony.


19 5 provide the temperature swing/peaking capacity cost, which is

20 the Demand-DC cost of gas. PGC Exhibit 2, Schedule 5

21 provides data for the eight month period ending July 31, 2013

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DIRECT TESTIMONY OF KAREN M. SNYDER R~2013-2341534

1 and PGC Exhibit 3, Schedule 5 provides data for the twelve

2 month period ending July 31, 2014.

3 Q. Please explain PGC Exhibit 21.

4 A. PGC Exhibit 21 is a computation of the projected cost of

5 purchased gas that would be included in rates effective August

6 1, 2013. This amount includes projected gas costs through the

7 end of the application period, July 31, 2014 and projected

8 over/under collections through July 31, 2013.

9 As indicated on PGC Exhibit 21, Schedule 1, Sheet 4,

10 the total projected cost of purchased gas per Mcf is $6.5457.

11 Of this amount, $4.6794 per Mcf is the commodity cost

12 (including the "E" factor), and $1.8663 per Mcf is the demand

13 cost (including the "E" factor).

14 The cost of gas has been separated into three categories

15 on PGC Exhibit 21, Schedule 1, Sheet 4: the Natural Gas

16 Supply Charge, the Gas Adjustment Charge and the Distribution

17 Charge.

18 For gas supplied to all classes of retail customers (except

19 those receiving service under load balancing service and

20 natural gas vehicle service rate schedules), the Natural Gas

21 Supply Charge is $6.5490/Mcf. This represents an increase of

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1 $0.4390/Mcf from the Natural Gas Supply Charge of

2 $6.11 00/Mcf included in rates from November 1, 2012 through

3 January 31, 2013.



6 natural gas vehicle service rate schedules), the Gas Adjustment

7 Charge is ($0.2681 )/Mcf. This represents an increase of

8 $0.4852/Mcf compared to the Gas Adjustment Charge of

9 ($0.7533)/Mcf included in rates from November 1, 2012 through

10 January 31, 2013.



13 natural gas vehicle service rate schedules), the Distribution

14 Charge is $0.2648/Mcf. This represents a decrease of

15 $0.0064/Mcf compared to the Distribution Charge of

16 $0.2712/Mcf included in rates from November 1, 2012 through

17 January 31, 2013.

18 In total, for gas supplied to all classes of customers

19 (except those receiving service under load balancing or natural

20 gas vehicle service rate schedules), the projected cost of gas is

21 $6.5457/Mcf. This represents an increase of $0.9178/Mcf from

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DIRECT TESTIMONY OF KAREN M. SNYDER R-20 13-2341534

1 the amount of $5.6279/Mcf included in rates from November 1,

2 2012 through January 31, 2013 for the recovery of purchased

3 gas costs.

4 The increase in rates for the recovery of purchased gas

5 costs results from a number of factors, one of which is an

6 increase in the "E" or experienced factor. The current "E"

7 factor reflected in rates as of November 1, 2012 is an

8 overcollection of $14,382,141 or ($0.7723)/Mcf 1. The projected

9 sales for passback of the "E" factor this period (TME July 2013)

1 o are 18,554,728 Mcf for Commodity and Demand - NGS and

11 21,264,051 Mcffor Demand- DC. As shown on PGC Exhibit

12 21, Schedule 1, Sheets 1-3, Distribution projects, through July

13 31, 2014, an "E" factor overcollection of $4,852,903 or

14 ($0.2651)/Mcf 2. The projected sales for passback of the "E"

15 factor this period (TME July 2014) are 18,335,882 Mcf for

16 Commodity and Demand- NGS and 20,721,402 for Demand-

2

Commodity: ($18,913,435) + 18,554,728 Mcf= ($1.0193)/Mcf Demand- NGS: $4,935,363 + 18,554,728 Mcf = $0.2660/Mcf Demand- DC: ($404,069) + 21,264,051 Mcf = ($0.0190)/Mcf

Commodity: ($3,883,552) + 18,335,882 Mcf = ($0.2118)/Mcf Demand- NGS: ($1,032,349) + 18,335,882 Mcf= ($0.0563)/Mcf Demand- DC: $62,998 + 20,721,402 Mcf = $0.0030/Mcf

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DC. The projected overcollection produces an increase in rates

of $0. 5072/Mcf3.

The "C" factor rate also increased. The current "C" factor

reflected in rates as of November 1, 2012 is $119,539,221. The

projected sales for this period (TME July 2013) are 18,554,728

Mcf for Commodity and Demand-NGS and 21,264,051 Mcf for

Demand-DC. As shown on PGC Exhibit 21, Schedule 1,

Sheets 1-3, Distribution projects, through July 31, 2014, "C"

factor costs of $125,504,781 4. The projected sales for this

period (TME July 2014) are 18,335,882 Mcf for Commodity and

Demand-NGS and 20,721,402 Mcf for Demand-DC. The

change in the "C" factor results in an increase in rates of

$0.4106/Mcf.5 As shown on PGC Exhibit 21, Schedule 1, Sheet

1 this increase includes ($0.0075)/Mcf for the passback of

Where ($0.7723)/Mcf ("E" factor included in current rates) and ($0.2651)/Mcf ("E" factor included in projected rates); then ($0.7723)- ($0.2651) = $0.5072/Mcf.

$125,504,781 = $89,821,650 (PGC Exhibit 21, Schedule 1, Sheet 1, Commodity) + $30,398,042 (PGC Exhibit 21, Schedule 1, Sheet 2, Demand - NGS) + $5,424,569 (PGC Exhibit 21, Schedule 1, Sheet 3, Demand- DC)- $139,480 (PGC Exhibit 218, Sheet 2, Commodity- Storage).

$6.8108 (PGC 2013) less $6.4002 (PGC 2012 November 1) = $0.4106/Mcf. Where $6.8108/Mcf ("C" factor in projected rates)= ($120,219,692 + 18,335,882 Mcf)- ($139,480 + 18,335,882 Mcf) + ($5,424,569 + 20,721,402 Mcf) or $6.5565-$0.0075 + $0.2618, respectively /Mcf); and $6.4002/Mcf ("C" factor in current rates)= ($113,809,307 + 18,554,728 Mcf)- ($439,001 + 18,554,728 Mcf) + ($6, 168,915 + 21,264,051 Mcf); or $6.1337-$0.0237 + $0.2902, respectively /Mcf).

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storage interest expense. The sum of the increase in the "E"

factor and the "C" factor represents a total increase of

$0.9178/Mcf [$0.5072 + $0.4106 = $0.9178].

PGC Exhibit 21, Schedules 2 through 11 explain the

derivation of Distribution's experienced over/under collection

factor ("E" factor) used in PGC Exhibit 21, Schedule 1.

PGC Exhibit 21, Schedules 4 and 10 detail refunds, by

component, received by Distribution, and these schedules also

calculate interest on each refund. There were no refunds

'received during the twelve months ended November 30, 2012.

Ms. Suarez will explain Distribution's proposal to reflect pipeline

refunds in current rates in her testimony.

The information provided above was derived on the

assumption that rates effective November 1, 2012 will remain in

effect through July 31, 2013. In all likelihood, the quarterly filing

for May 1, 2013 will adjust rates. The amount of net adjustment,

however, is not presently known.

Please describe the methodology used to determine the interest

rate that is applied to the over/undercollection of purchased gas

costs and storage injections/withdrawals.

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The interest rate to be applied to the

over/undercollection of purchased gas costs and storage

injections/withdrawals is based on the Commission's Order at

docket number R-00072043. Under this methodology, the

Demand-DC component of purchased gas costs is calculated

separately from the other components of purchased gas costs

using the net over/undercollection for the twelve month period

ended November. The interest rate to be applied to

over/undercollections of Commodity and Demand - NGS

purchased gas costs is calculated based on the combined net

over/undercollection for both of these components for the

twelve month period ended November.

As shown in PGC Exhibit 218, Sheets 1-2, the interest

rate used in the storage interest calculation is determined on a

stand-alone basis using the twelve month period ending July,

per the Commission's Order at Docket number R-201 0-

2150861. The storage interest calculation is addressed under

the explanation of PGC Exhibit 21 B.

There was a net undercollection for the Demand-DC

component of purchased gas costs for the twelve months ended

November 30, 2012, as shown on PGC Exhibit 21A, Schedule

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1 2, Sheet 2. Therefore, the interest rate of 6% was used to

2 calculate monthly interest. The projection for the twelve month

3 period ending November 30, 2013 is a net overcollection for the

4 Demand-DC component of purchased gas costs. Therefore,

5 the interest rate of 8% was used to calculate monthly interest.

6 For the twelve months ended November 30, 2012 there

7 was a net overcollection for the Demand- NGS and

8 Commodity components of purchased gas costs. Therefore,

9 the interest rate of 8°/o was used to calculate monthly interest.

10 The projection for the twelve month period ending November

11 30, 2013 is a net overcollection for the Demand - NGS and

12 Commodity components of purchased gas costs. Therefore,

13 the interest rate of 8% was used to calculate monthly interest.

14 Q. Please describe PGC Exhibit 21A.

15 A. PGC Exhibit 21 A is the Statement of

16 Over/Undercollections for the twelve months ended November

17 30, 2012. The exhibit provides separate detail for the

18 Commodity, Demand- NGS and Demand- DC components of

19 purchased gas costs, and the exhibit is self explanatory.

20 Q. Please explain the purpose of PGC Exhibit 21 B.

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PGC Exhibit 21 8 is a calculation of interest on storage

injections and withdrawals. Sheet 1 shows the twelve months

ending July 31, 2013 and Sheet 2 shows the twelve months

ending July 31, 2014.

For base rate purposes, Distribution has valued gas in

storage at its average inventory cost. That is, withdrawals from

and injections into storage are priced at the average cost of all

gas in storage at the beginning of the gas storage cycle.

However, for purchased gas cost purposes, Distribution uses

the last-in, first-out ("LIFO") method. The LIFO method prices

withdrawals and injections at the average cost of all gas

purchases for the current year. The LIFO method is appropriate

for gas cost purposes because it recognizes that current

purchases of gas are used to serve current requirements and

that storage withdrawals used to serve peak requirements are

only short term and are refilled every year.

Over a normal twelve month period, withdrawals and

injections will be equivalent, and thus the beginning and ending

storage balances under the two methods will be the same.

However, Distribution recognizes that there is a time value of

money component to pricing storage gas at the average

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1 inventory cost, for working capital purposes in base rates. For

2 example, in a winter month, Distribution will be using storage

3 having an inventory value of $0. 7839/Mcf to serve peak

4 requirements, and will charge customers a higher, fiscal year

5 rate of $5.8012/Mcf for such gas. Conversely, in a summer

6 month, Distribution will refill storage using purchases priced at

7 $5.8012/Mcf, but the inventory value of these injections will be

8 the lower $0.7839/Mcf average inventory rate.

9 In order to recognize time value of money differences in

10 this 1307(f) proceeding, interest is calculated on storage

11 injections and withdrawals based upon the rate differential

12 between the storage rate and the inventory rate on a fiscal year

13 basis.

14 Q. Please summarize the calculation of interest shown on PGC

15 Exhibit 21 B.

16 A. PGC Exhibit 21 B, Sheets 1 and 2 show the interest

17 calculation for the twelve months ending July 31, 2013 and July

18 31, 2014, respectively. This calculation projects the estimated

19 interest to be incurred during the indicated PGC period. The

20 calculation, as detailed below, allows for immediate passback or

21 recovery on the basis of a uniform amount per Mcf during the

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1 current twelve month PGC period in which expense or income

2 arises. This methodology, as approved per the order at Docket

3 No. R-201 0-2150861, matches the occurrence of income or

4 expense with the reflection of such income or expense in rates.

5 In addition, this methodology allows for quarterly updates to the

6 estimated interest, based on actual information, through the C-

7 Factor gas cost recovery mechanism.

8 The net interest expense in the amount of $722,321 on

9 PGC Exhibit 21 B, Sheet 1 flows to Exhibit 21, Schedule 11,

1 o Sheet 4. This amount is compared to the total estimated

11 interest expense to be passed back during the twelve months

12 ending July 31, 2013 through the C-Factor. The difference

13 represents the estimated amount that will be included in theE-

14 Factor for the twelve months ending July 31, 2014.

15 PGC Exhibit 21 B, Sheet 2 shows the interest calculation

16 for the twelve months ending July 31, 2014. The calculation

17 shows an estimated net interest expense in the amount of

18 $139,480. This amount is projected to be passed back during

19 the rate application period in which it occurs, which is the twelve

20 months ending July 31, 2014. As shown on Sheet 2, the net

21 interest expense of $139,480 will be passed back at a rate of

Page 26 of 29

2

3 Q.

4

5 A.

6

7

8

9

10

11

12

13

14

15

16

17

18

19

20

21


($0.0075)/Mcf, included in the C-Factor on Exhibit 21, Schedule

1, Sheet 1.

Please explain the calculation of interest shown on PGC Exhibit

21 B, Sheet 2.

The schedule identifies months with estimated or actual data

as open or closed periods. Columns 1 and 2 show storage

injections and withdrawals. Column 3 shows the rate differential

which represents the difference between the storage inventory

rate included in base rates calculated on an average cost method

and the inventory rate charged through the 1307(f) gas cost

recovery mechanism based on the LIFO valuation method.

Storage injections represent decreases to purchased gas

expense as theoretically a portion of volumes purchased and paid

by Distribution exceed the current requirements. The Cost Paid

by Distribution but not Charged through the PGC, Column 5, is

calculated by multiplying the injections (column 1) by the rate

differential (column 3). These costs result in interest income to

be recovered from the ratepayer, as they will not be charged

through purchased gas costs until the gas is withdrawn. Storage

withdrawals represent increases to purchased gas expense, as

theoretically requirements exceed current purchases. The Cost

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1 Charged through the PGC but not Paid by Distribution, Column 4,

2 is calculated by multiplying the withdrawals (column 2) by the rate

3 differential (column 3). These costs result in interest expense to

4 be passed back to the ratepayer, as they are charged through

5 purchased gas costs when the gas is withdrawn, but were paid by

6 Distribution when the gas was injected. Storage Net Paid/Net

7 Charged in Column 6 is the sum of columns 4 and 5.

8 The Interest Weight (column 7) represents the ratio of

9 the twelve month PGC period the interest is expected to be

10 outstanding. The Interest Rate (column 8) represents the

11 statutory rate to be charged for interest based on the estimated

12 net over/undercollection of associated storage costs for the

13 twelve months ended July. Column 9 represents the calculation

14 of gross storage interest expense or interest income. This is

15 calculated by multiplying the Storage Net Paid/Net Charged

16 (column 6) by the applicable prorated interest rate (column 7 x

17 column 8). The sum of the monthly values in column 9 (Gross

18 Storage Interest Expense/Revenue) represents the amount of

19 storage interest expense/income due to/from ratepayers.

20 Q. Please explain PGC Exhibit 21C.

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A. PGC Exhibit 21 C, provides the "Explanation that

2 Over/Undercollections for the Twelve Months Ended November

3 30, 2012, Resulted from a Least-Cost Procurement Policy,"

4 which is a statement that is required to be filed with the

5 Commission pursuant to their regulation at 52 Pa. Code Section

6 53.64(i). The exhibit is self-explanatory.

7 Q. Will any of the filed exhibits be updated?

8 A. Yes. Updates will be provided during the course of the proceeding to

9 correct the interest rate used on Exhibit 21, Schedule 3, Sheets 1-2

10 Demand-DC and Exhibit 21, Schedule 6, Sheets 2-3 Commodity for

11 the twelve month period ended November 2013. The rate for the

12 twelve month period ended November 2013 for both of these

13 components, as stated in testimony above, should be 8%. This rate

14 was incorrectly reflected in the filed exhibits as .08%.

15 Q. Does this conclude your direct testimony?

16 A. Yes.

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karen m. snyder national fuel gas distribution … · direct testimony of karen m. snyder...

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