john j. polka, jr. national fuel gas distribution ...john j. polka, jr. in behalf of pgc statement...

TESTIMONY OF JOHN J. POLKA, JR.

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(f)),

DOCKET NO. R-2015-2461373

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DIRECT TESTIMONY OF JOHN J. POLKA JR.

State your name and business address.

My name is John J. Polka Jr., and my business address is 6363

Main Street, Williamsville, New York, 14221.

By whom are you employed and in what capacity?

I am employed by National Fuel Gas Distribution Corporation

("Distribution") as an Assistant Vice President.

Can you please describe your responsibilities as Assistant Vice

President for Distribution?

I am responsible for the Gas Supply Administration Department and

the Energy Services Department. The Gas Supply Administration

Department is responsible for the Pipeline Capacity contracting, Gas

Procurement, Gas Accounting and Gas Planning functions. The

Energy Services Department addresses Distribution's Marketing,

Area Development and New Technology functions. I report directly

to the Vice President.

Summarize your prior work experience and education.

I received a Bachelor of Science Degree in Civil Engineering from

the State University of New York at Buffalo in 1978. I received my

New York State Professional Engineering License in March 1987.

am a member of the Pennsylvania Independent Oil and Gas

Association, the National Society of Professional Engineers, and a

Director of the Independent Oil and Gas Association of New York.

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In June 1978, I joined Distribution as a Management Trainee.

2 I was transferred and promoted in December 1978 to Distribution's

3 Operations-North as a Junior Engineer. In January 1982, I was

4 transferred to Distribution's Industrial Engineering Department. In

5 May 1982, I was transferred to Distribution's Engineering

6 Department. Holding various positions and responsibilities in the

7 Engineering Department, I was promoted to Assistant Engineer in

8 July 1982, Associate Engineer in July 1986, Senior Engineer in

9 November 1988, and Engineer-in-Charge in March 1994. On

10 January 1, 2001, I was transferred to National Fuel Gas Supply

11 Corporation ("Supply") and assigned to the Gas Control Department

12 as Engineer-in-Charge. On June 16, 2001, I was transferred back to

13 Distribution and obtained the position of Assistant General Manager

14 of Distribution's Gas Supply Administration Department with

15 responsibilities for Gas Planning and Gas Accounting. On April 1,

16 2002, I was promoted to General Manager of Gas Supply

17 Administration. On October 1, 2013, I was promoted to Assistant

18 Vice President for both the Gas Supply Administration and the

19 Energy Services Departments. I am responsible for directing

20 Distribution's Gas Procurement, Gas Accounting, and Gas Planning

21 functions associated with the Gas Supply Administration

22 Department, as well as the Marketing, Area Development and New

23 Technology functions of the Energy Services Department.

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Q. What is the subject of your testimony?

2 A. I am testifying to PGC Exhibit No. 4, PGC Exhibit No. 6 and PGC

3 Exhibit No. 8.

4 Q . Were all sections of PGC Exhibit No's 4, 6 and 8 prepared under

5 your supervision and direction?

6 A. Yes, they were.

7 Q . Please explain PGC Exhibit No. 4.

8 A. PGC Exhibit No. 4 is Distribution's response to the Pennsylvania

9 Public Utility Commission's ("PAPUC") filing requirement at 52 Pa.

10 Code§ 53.64(c)(1 ), which requires details regarding the contracts

11 under which Distribution purchases supplies of gas including firm

12 Southwest supplies, spot gas supplies and local gas supplies and

13 regarding renegotiations of such contracts. Exhibit 4 also provides

14 details regarding Distribution's contracts for upstream pipeline

15 transportation and storage services, the design of rates for such

16 services, and recent and pending negotiations of such upstream

17 pipeline contracts. Mr. Robert Michalski and Mr. Christopher Cej will

18 be testifying to the specific elements contained in this Exhibit.

19 An important topic reviewed in the Exhibit is an update on

20 Distribution's initiatives to diversify and adjust its upstream capacity

21 mix as a component of overall system reliability.

22 Q . Please explain PGC Exhibit No. 6 and its associated Appendix A

23 (collectively "Exhibit 6").

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Exhibit 6 responds to the Commission's filing requirement at 52 Pa.

Code§ 53.64(c)(4) and describes Distribution's involvement in

proceedings before the Federal Energy Regulatory Commission

("FERC") and other appropriate regulatory and judicial bodies.

These proceedings encompass FERC rulemakings and other

generic industry-wide issues, as well as proceedings involving the

individual pipelines on which Distribution transports and/or stores

gas. Distribution participates in FERC proceedings, both

independently and as a member of the American Gas Association

("AGA").

What types of FERC issues did Distribution address through its

participation in AGA during the historic period?

Distribution was particularly interested in matters relating to the

operational relationship between the gas and electric industries,

especially as they related to the start of the gas day and timeline for

gas nominations.

Over the past two years FERC has placed considerable

priority on the discussion of Gas-Electric Coordination matters.

Several Technical Conferences have been conducted by the FERC

involving interest from both gas and electric markets. Distribution

contributed to the development of AGA positions in the following

related proceedings: Coordination of the Scheduling Processes of

Interstate Natural Gas Pipelines and Public Utilities (FERC Docket

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No. RM 14-2) and Proposal to Establish an Electronic Information

2 and Trading Platform (FERC Docket No. AD14-19).

3 Q. Were other significant Gas-Electric issues addressed by AGA during

4 the historic period?

5 A Yes. In addition to gas day/nomination issues, FERC has been

6 exploring the impacts of natural gas supplies and capacity as they

7 relate to market price formation within organized electric markets in

8 FERC Docket No. AD14-8 - Winter 2013-2014 Operations and

9 Market Performance in RTOs and ISOs.

10 Q. Is Distribution pursuing Gas-Electric issues independently of AGA?

11 A Yes. Distribution has actively participated in FERC Docket No.

12 RM13-17, Communications of Operational Information Between

13 Natural Gas Pipelines and Electric Transmission Operators.

14 On November 15, 2013, the FERC issued Order 787 in this

15 proceeding, amending its regulations to provide explicit authority to

16 interstate natural gas pipelines and public utilities that own, operate,

17 or control facilities used for the transmission of electric energy in

18 interstate commerce to share non-public, operational information

19 with each other for the purpose of promoting reliable service or

20 operational planning on either the public utility's or pipeline's system.

21 On June 19, 2014, the FERC issued an Order on Rehearing ("Order

22 787-A").

23 Q. What is the significance of Orders 787 and 787-A to Distribution?

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Orders 787 and 787-A permit electric transmission operators to

share non-public, operational information with LDCs, subject to

various conditions, if provided for in tariff provisions approved by the

FERC. Distribution has customers that interact with PJM

Interconnection, L.L.C. ("PJM") and the New York Independent

System Operator, Inc. ("NYISO"), both of which filed tariff revisions

at the FERC under Docket Nos. ER14-1469 and ER14-2895,

respectively.

Does Distribution have any concerns regarding these filings?

Yes. Some of the proposed tariff provisions would impose conditions

that expose LDCs to various risks: principally FERC tariff violations

that could lead to penalties and/or fines. Distribution is seeking

changes to these tariff provisions that would allow Distribution to

communicate with PJM and NYISO without bearing undue risk.

Did Distribution work with AGA on issues before other regulatory

bodies?

Yes. Distribution worked with AGA to develop comments which were

submitted to the Commodity Futures Trading Commission ("CFTC")

in various proceedings, including Request for an Extension of the

Comment Date for the Aggregation of Positions Proposed Rule,

RIN3038-AD82; Comments regarding Aggregation of Positions,

RIN3038-AD82; Comments regarding Position Limits for Derivatives,

RIN3038-AD99; Letter regarding CFTC Staff Public Roundtable to

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Discuss Dodd-Frank End-User Issues, PR6872-14; and Comments

of the American Gas Association, Review of Swap Data

Recordkeeping and Reporting Requirements, Request for Comment,

79 Fed. Reg. 58, RIN3038-AE14.

What significant pipeline proceedings did Distribution participate in

during the historic period?

Proceedings involving Columbia (Docket No. RP14-341 regarding its

Capital Cost Recovery Mechanism and Docket No. RP15-110

regarding operational purchases and sales to ensure adequate gas

flow into northern Ohio), Supply (Docket No. RP14-771 regarding

market area pooling and Docket No. RP13-299 regarding

enhancements to storage services) and Tennessee (Docket Nos.

RP11-1566, RP12-514 and RP14-939 regarding secondary in the

path scheduling priority).

Last year you discussed the impact of the Long-term System

Modernization Stipulation and Agreement filed by Columbia at the

FERC on September 4, 2012 under Docket No. RP12-1021

("September 4 S&A") on Distribution. Has there been any related

activity during the historic period?

Yes. One of the provisions of the September 4 S&A was that

Columbia may implement the Capital Cost Recovery Mechanism

("CCRM") for recovery, through an additive demand rate ("CCRM

Rate"), of Columbia's cumulative revenue requirement (i.e., return,

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depreciation, and taxes) for capital investments made to modernize

Columbia's system during an initial 5-year period commencing

February 1, 2014 and ending on the earlier of the effective date of

Columbia's next general NGA Section 4(e) rate filing or January 31,

2019.

On December 31, 2013, Columbia filed the initial CCRM

Rates to be effective on February 1, 2014 ("2014 CCRM Rate")

under Docket No. RP14-341 . The 2014 CCRM Rate applicable to

FTS and SST was $0.393 per Dth.

In addition, on December 30, 2014, Columbia filed the CCRM

Rates to be effective on February 1, 2015 ("2015 CCRM Rate")

under Docket No. RP15-296 ("2014 CCRM Filing"). The 2015

CCRM Rate applicable to FTS and SST will be $0.719 per Dth. The

2014 CCRM Filing indicated that, at the end of the second year of

the CCRM implementation, Columbia made cumulative capital

investments of $618.1 million to undertake numerous projects to

improve reliability and safety.

Does Distribution expect other interstate pipelines to follow

Columbia's example regarding pursuing recovery of system

modernization costs?

Yes. On November 20, 2014, the FERC issued a Proposed Policy

Statement under Docket No. PL 15-1 seeking to provide greater

certainty concerning the ability of interstate natural gas pipelines to

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recover the costs of modernizing their facilities and infrastructure to

enhance the efficient and safe operation of their systems. The

proposed Policy Statement explains the standards the FERC would

require interstate natural gas pipelines to satisfy in order to establish

simplified mechanisms, such as trackers or surcharges, to recover

costs associated with replacing old and inefficient compressors and

leak-prone pipes and performing other infrastructure improvements

and upgrades to enhance the efficient and safe operation of their

pipelines.

The FERC identified its order approving Columbia's

September 4 S&A as establishing general parameters for pipelines

to consider when seeking recovery of pipeline investments for

modernization costs related to improving system safety and

reliability.

Does Distribution plan on participating in this proceeding?

Yes. Distribution worked with AGA to develop comments, which

were filed on January 26, 2015.

What is the significance of Columbia's Operational Transaction Rate

Adjustment ("OTRA") proceeding under Docket No. RP15-11 O?

The OTRA mechanism was initially proposed by Columbia as an

interim solution to recover the costs of certain operational purchases

and sales required to ensure a sufficient amount of gas flowing into

its system in northern Ohio, as discussed in PGC Exhibit No. 6.

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Although the initial OTRA was to terminate on March 31,

2014, the FERC subsequently approved its extension for an

additional two years to March 31, 2016. On October 31, 2014,

Columbia requested a further extension of its OTRA mechanism

through March 31, 2019 ("OTRA Extension Request"). The FERC

rejected Columbia's OTRA Extension Request and encouraged

Columbia to continue to work with its customers on a consensus

solution. Distribution continues to participate in discussions on this

matter.

Moving on to Supply, you indicated in last year's testimony that

Supply was making business system modifications required to

implement its Market Pooling Point Aggregation Service ("MPPAS").

Have there been any developments during the historic period?

Yes. On April 25, 2014, Supply filed revised tariff records to

implement its MPPAS Rate Schedule under Docket No. RP14-771

("RP14-771 Filing") upon its completion of the required business

system modifications. The FERC issued a letter order accepting the

RP14-771 Filing on May 14, 2014.

Has Distribution executed a service agreement for MPPAS Service?

Yes. Distribution and Supply executed a service agreement for

MPPAS Service on July 11, 2014.

What is the status of Supply's Storage Enhancement Proceeding?

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A. At this time, Supply continues to work on the necessary

2 programming changes required to permit decoupled storage capacity

3 releases on its system. However, Supply has agreed to provide

4 detailed information concerning the impact of its decoupled storage

5 capacity release proposal and associated analyses on or before

6 June 30, 2015 and schedule a conference call no later than

7 September 30, 2015.

8 Q. Let's shift our focus to significant activity before the FERC

9 associated with Tennessee. Last year's testimony included a lengthy

10 discussion of Tennessee's "Scheduling Priority Issue" which is

11 incorporated herein by reference. Have there been any further

12 developments on this matter during the historic period?

13 A. Yes. On May 15, 2014, the FERC issued an Order Denying

14 Rehearing of its October 17, 2013 Order approving Tennessee's

15 proposal to modify its secondary in-the-path scheduling

16 methodology. On May 16, 2014, Tennessee filed tariff records under

17 Docket No. RP14-939 formally implementing its Scheduling Priority

18 Proposal. The FERC accepted the tariff records in a letter order

19 dated June 12, 2014.

20 a. Regarding PGC Exhibit No. 8, could you further explain the Gas

21 Cost Management Plan?

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A. The Gas Cost Management Plan (Exhibit POL-1) lays out in

2 summary form the different gas purchase methodologies Distribution

3 uses to diversify its pricing of gas supplies. In addition to the pricing

4 benefits Distribution obtains through its contracted storage services,

5 the Plan summarizes Distribution's approach for obtaining diverse

6 prices for its flowing supplies.

7 Section I of the Plan identifies the forward pricing measures

8 Distribution will use for purchasing a portion of the monthly supplies.

9 During the winter months (November - March), approximately 20%

IO of the monthly purchases will be forward priced.

11 Section 11 notes that approximately 60% of the supplies for the

12 winter and summer months will be priced at a mix of Index and bid

13 week negotiated (Cash) prices.

14 Section Ill takes into account that the remaining supplies

15 (approximately 20% winter and 40% summer) will be procured on a

16 daily basis and will be priced at Index and/or negotiated (Cash)

17 prices.

18 The Plan provides for the flexibility to adjust the timing of

19 forward prices based on market fundamentals such as hurricanes

20 and unanticipated events.

21 Q . Have there been any changes to the Plan since the last PGC filing?

22 A. No. The Plan remains the same as submitted in the last PGC filing.

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Please explain the rationale behind the decision to retain the forward

pricing of winter purchases at 20%.

Since January 2010, the NYMEX natural gas monthly settle price

has demonstrated a significant increase in price stability relative to

the preceding period of January 2001 to December 2009. The

general industry rationale is that increasing shale production in the

mid-continent and the northeast has increased overall gas supplies

resulting in a decrease in natural gas prices (Exhibit POL-2) and a

decrease in price volatility. Additionally, when combined with the

anticipated storage withdrawals for the winter of 2014-2015, the

current Plan would provide for approximately 51 % of the gas

supplies to be hedged (see PGC Exhibit No. 8-E).

Do you have any reference as to how the proposed 51 % hedged gas

supplies compares to other gas utilities in Pennsylvania?

In response to the Pennsylvania Public Utility Commission's "Annual

Winter Reliability Assessment" request, the Energy Association of

Pennsylvania (EAP) November 1, 2014 response stated , "Based on

a weighted average of the members, 44.4% of this winter's supplies

are hedged". The EAP defined hedges as storage supplies, fixed

price contracts, forward -priced contracts and price caps. Please

refer to page 16 of EAP's report attached hereto as Exhibit POL-3.

It is the Company's position that the Plan is consistent with the

approved plans of the other state gas utilities.

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Q . Please explain the current status of Distribution's off-system sales

2 activities.

3 A In light of and in reliance on FERC's Order 717-A, Distribution

4 resumed off-system sales on non-affiliated pipelines as of November

5 2, 2009. Distribution continues to utilize off-system sales as a

6 mechanism for optimizing system assets and reducing overall

7 system gas costs.

8 Q . Has Distribution explored alternatives other than capacity release

9 and off-system sales to optimize upstream pipeline and storage

10 assets?

11 A Yes. The Company has discussed various proposals with suppliers

12 regarding asset optimization utilizing Asset Management

13 Arrangements ("AMAs"). As discussed in PGC Exhibit No. 6, on

14 June 19, 2008, the FERC issued Order No. 712 revising its capacity

15 release regulations to, among other things, permit market based

16 pricing for short-term capacity releases and to facilitate AMAs by

17 relaxing restrictions on tying and bidding requirements for certain

18 capacity releases, including conditions associated with gas inventory

19 held in storage for releases of firm storage capacity. The FERC

20 issued additional clarifications on the issues with Order No. 712-A on

21 November 21 , 2008 and Order No. 712-B on April 16, 2009.

22 Q . Has the Company investigated or entered into any AMAs or similar

23 transactions?

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DIRECT TESTIMONY OF JOHN J . POLKA JR.

1 A Historically, the Company has investigated and entered into

2 transactions involving storage fill agreements. Specifically, through

3 the storage fill agreements Distribution realized shareable credits

4 relative to what it would have paid if purchases were made ratably

5 over the injection season at first of the month index rates. Mr. Cej's

6 testimony will review the most recent activity regarding AMAs.

7 Distribution intends to continue to investigate and enter into

8 storage fill transactions, when appropriate, with viable

9 counterparties. Distribution will also utilize, where appropriate,

10 alternative arrangements permissible as a result of FERC Order 712.

11 Distribution will continue to optimize its capacity and gas

12 supplies through capacity releases, off-system sales and/or AMAs.

13 Pursuant to previous 1307(f) settlements, revenue from capacity

14 releases, net off-system sales and AMAs will continue to be credited

15 75% to the ratepayers and the remaining 25% to Distribution.

16 Q. Please explain Section IV Staffing and Expertise of Fuel

17 Procurement Personnel, in PGC Exhibit No. 8.

18 A This section of PGC Exhibit No. 8 discusses Distribution's Gas

19 Supply Administration Department. PGC Exhibit No. 8-D provides a

20 chart detailing the use of functional teams that handle the duties and

21 responsibilities of all of the areas that encompass the department.

22 Q . Is there anything additional you would like to discuss regarding

23 Exhibit No. 8?

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A Yes. The winter of 2013 - 2014 was historic from a temperature

2 perspective. The volume of Heating Degree Days (HOD) were

3 15.6% Colder Than Normal (CTN) resulting in the winter of 2013-14

4 being the 4th coldest winter in Erie, PA in the past 60 years. (See

5 Exhibit POL-4, POL-5 and POL-6) Based on historic weather data,

6 the winter of 2013-2014 also produced 28 days where the daily

7 mean temperature was equal to or colder than 15 Degrees F. This

8 was a significant departure from normal temperatures since based

9 on the ten most recent winters on average there were 9 such days

10 per year. (See Exhibit POL-7).

11 The peak day during the winter of 2013-14 was January 7, 2014

12 where the daily mean temperature was 64 degrees F which was 10

13 degrees warmer than the Design Day utilized for capacity planning.

14 On that day, system throughput was 414,064 Dth which exceeded

15 the 74 HOD Design Day of 383,453 Dth by 30,611 Dth or 8%.

16 As a result of this temperature pattern and the resultant system

17 throughput, Distribution reviewed the potential system adjustments

18 required to meet the reliability needs of a 74 HOD day. Mr.

19 Michalski's testimony reviews the analysis and the actions

20 implemented.

21 Q . Does this conclude your direct testimony?

22 A Yes, it does.

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National Fuel Gas Distribution Corporation

Pennsylvania Division GAS COST MANAGEMENT PLAN

January 1, 2015

Volatility mitigation through price diversification (100% of forecasted monthly purchases)

Exhibit POL-1

I. Forward pricing: Fix prices for approximately 20% of forecasted winter (November - March) monthly purchases. Prices for these winter delivery quantities will be established evenly over the preceding summer (April -October).

II. Monthly Pricing: Approximately 60% of forecasted monthly purchases for both winter and summer shall be priced at a mix of Index and bid week negotiated (cash) prices.

Ill. Daily Pricing: Approximately 20% of winter and 40% of summer forecasted monthly purchases shall be priced at a mix of Index and negotiated (cash) prices.

The timing of when to fix prices, and the percentages indicated above, are general guidelines based on normal weather and operating conditions. Adjustments may be necessary to accommodate operational requirements and unanticipated events.

14.00

12.00

10.00 l I

~ 8.00 I ~ I

6.00

4.00

2.00

Jan-97 Jan-99

NYMEX Natural Gas Settlement Price

Jan-01 Jan-03 Jan-OS Jan-07 Jan-09 Jan-11 Jan-13 Jan-15

NYMEX Futures As of

1/21/15

Jan-17

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Energy Association

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Terrance J. Fitzpatrick President & Chief Executive Officer Energy Association of Pennsylvania

November 1, 2014 Harrisburg, PA

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The Energy Association of Pennsylvania represents the interests of its

Member Natural Gas Distribution Companies:

Columbia Gas of Pennsylvania National Fuel Gas Distribution Corp.

PECO Energy Company Peoples Natural Gas Co.

Peoples TWP Peoples Natural Gas - Equitable Gas Division

Philadelphia Gas Works Pike County Light & Power UGI Central Penn Gas, Inc. UGI Penn Natural Gas, Inc.

UGI Utilities, Inc. - Gas Division Valley Energy

Distributing natural gas to just under three million residential, commercial and industrial customers in Pennsylvania

'~ Energy sociation Pennsylvania

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Supply and Demand Winter 2014-2015 (all natural gas volumes in billions of cubic feet)

Expected Demand

Expected Supply Flowing Interstate Gas Storage Withdrawals Local Production Peak Shaving

TOTAL

'----Energy

Association Pennsylvania

212.8 Bcf

106.8 94.0 10.8

1.2 212.8

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Winter 2013-2014: Supply Sources by Type

209.8 Bcf

Local Production Peak

Shaving

Storage Withdrawal

',___-Energy


Winter 2014-2015: Supply Sources by Type

212.8 Bcf

Local Production

Peak Shaving

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Objective: To identify supply resources (including upstream transportation and storage capacity) that will be necessary to preserve service reliability at anticipated levels of firm demand

~~ Energy

Association , Pennsylvania 6

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Capacity and Supply Assets: NGDCs commit to capacity and supply assets as necessary to meet firm customer needs, including operational swings. Commitments may include a reserve, but do not include service to interruptible customers. These assets include:

- Pipeline deliveries per firm transportation agreements - Underground storage withdrawals (on-system, off-system) - Pennsylvania production (where available) - Peak shaving facilities

;$,__--Energy


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• Record high natural gas production this year is helping to ensure that adequate supplies of natural gas are available, after ending last winter with the lowest storage inventories since 2003. Current production for the year-to-date is running 4.3 percent higher than year-to-date production in 2013. The Energy Information Administration (EIA) forecasts that natural gas production will increase to 71.4 billion cubic feet (Bcf) per day, on average, this winter. This is an increase of 3.3 Bcf per day over last winter's 68.1 Bcf per day average. In 2015, EIA expects natural gas marketed production to grow by an annual rate of 2.0 percent.

• The productivity of natural gas wells is steadily increasing in many basins across the United States because of the increasing precision and efficiency being realized in oil and natural gas extraction.

• The combination of two technologies -horizontal drilling and hydraulic fracturing -has made it possible to produce shale gas economically. The United States has experienced a rapid increase in natural gas production from shale resources.

(American Gas Association (AGA), Natural Gas Market Indicators, 10115114; US Energy Information Administration (EIA). Natural Gas Weekly Update. 10123114; US EIA. Short Term Energy and Winter Fuels Outlook, released 10fl/14; US EIA. Growth in U.S. Hydrocarbon Production from Shale Resources by Drilling Efficiency, 3111114,

~~.eia.gov/todayinenergy/detail.cfm?id=15351)

Energy Association

Pennsylvania 8

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2007

-

Gas Produced 182,277 MMcf

State Rank - Gas Production 15th

, "

Wholesale Gas Price $9.35 per Mcf

Wholesale Electricity Price* $83.70/MWh**

~~ Energy

Association \ Pennsylvania

MMcf = volumetric measure of natural gas, per 1 million cubic feet; Mcf = per 1 thousand cubic feet

• PJM annual average day ahead on-peak price

•• Data from 2008

Sources: EIA, http://www.eia.gov/dnav/ng/ng_prod_sum_a_EPGO _FGW _mmcf _a.htm FERG, http://www.ferc.gov/market-oversighVmkt-electric/pjm.asp#prices

2012

2,256,696 MMcf

3rd

$5.52 per Mcf

$40.86/MWh

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• The Henry Hub in southern Louisiana is the best known spot market for natural gas. The Energy Information Administration (EIA) expects the Henry Hub natural gas spot price, which averaged $4.53 per million British thermal units (MM Btu) last winter, to average $4.00 per MMBtu this winter. Their price forecast reflects the significantly higher natural gas production this winter and also lower than expected heating demand.

• The Henry Hub price is currently about $3.68 per MMBtu.

• Prices in the Northeast trading hub have remained below prices at the Henry Hub. The price is currently about $2.68/MMBtu at the Transcontinental Pipeline Zone 6 (New York). Some Northeast hubs, such as Dominion South and Leidy Interchange, dropped to $1.50/MMBtu earlier this month.

(American Gas Association (AGA) Natural Gas Market Indicators - 10115114; US Energy Information Administration (EIA) Short-Term Energy and Winter Fuels Outlook, released October 7, 2014; US EIA, Natural Gas Weekly Update, for week ending 10/22/14, released 10/23/14)

~y----Energy sociation Pennsylvania

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System Planning Strategies - Pipeline Capacity Reliability

•

•

•

The national pipeline network is comprised of 305,000 miles of interstate and intrastate transmission pipelines and 400 underground natural gas storage facilities. Development of this infrastructure helps meet the needs of the market, bringing natural gas to households, businesses, industrial customers, refineries and electric power generators.

More than on.e-third of the pipeline projects since 2008 addressed a growing need for additional natural gas pipeline capacity to support transportation of new natural gas production to regional markets. According to FERC, access to new production and added natural gas transportation capacity has contributed to breaking down long standing price differences between market hubs and has helped to reduce bottlenecks significantly

About 27,800 miles of new natural gas transmission pipeline were placed in service in the U.S . from 1998 to 2011. At least 25 major pipeline projects were completed in the U.S. in 2011, adding a total of about 2,400 miles of pipeline and 13. 7 billion cubic feet per day of capacity. After several years of this robust growth, pipeline capacity investment slowed in 2012. Over half of the U.S. pipeline projects in 2012 were concentrated in the Northeast and focused on the fast-growing Marcellus shale gas production

(US Energy Information Administration (EIA). Today in Energy, 3125113, 2117112; US EIA Natural Gas Year-In-Review 2011, released July 2012 and Year-ln-Rev1ew 2009, released July 2010; US EIA, Major Changes in Natural Gas Transportation Capacity 1998-2008, J. Tobin, Office of OJ/ & Gas; FERG

~,_fe.!1Jmer 2012 Energy Market & Reliability Assessment, 5117112; www.eia.gov/pub/oil_gas/natural_gas/analysis_publications/ngpipeline/index.html)

Energy sociation 11 Pennsylvania

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Ability to contract for interstate pipeline capacity

• Firm capacity assets are used to transport supplies and manage storage to serve firm customers and operationally balance system requirements

• Members routinely review the interstate capacity market to try to obtain the optimum portfolio of assets to meet their needs

• The temperature sensitive loads of residential and human needs customers require dedicated, firm gas supply assets, including interstate transportation and storage services: There is no substitute

• Members do not report difficulty contracting for firm interstate capacity when it is available

~----Energy Association

Pennsylvania 12

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• Inventories must be maintained at the levels necessary to fulfill obligations per planning criteria. Aggregate projected storage levels on Nov. 1, 2014 are sufficient to meet anticipated winter demand

• Warmer than normal weather affects storage utilization, given the need to meet minimum turnover requirements for the integrity of fields and to comply with pipeline tariff

. . prov1s1ons

~~ Energy

Association Pennsylvania 13

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Where contractually and operationally permissible, an NGOC may leave gas in storage if projected replacement costs exceed current prices, or an NGOC may use storage in lieu of firm transportation if replacement costs are favorable

Storage inventory is managed to prevent deliverability from being reduced before potential design day occurrence, and to prevent firm markets from going unserved for some part of the remainder of the season

Working natural gas is the volume of gas in a reservoir that is available for withdrawal. Nationally, natural gas working inventories ended September of this year at an estimated 0.40 trill ion cubic feet (Tcf) below the previous five year average (2009-2013).

For the week ending October 17, 2014, working natural gas in underground storage totaled 3,393 billion cubic feet (Bcf). Injections of natural gas into underground storage have been at a record pace and well above the five year average. Even with this rapid rate of injections, the deep starting point for inventories at the beginning of the injection season still means storage volumes are about 10 percent below last year. However, in conjunction with record production , injections are on course to be the largest seasonal refill on record.

(American Gas Association (AGA) Natural Gas Market Indicators -10115114; US Energy Information Administration (EIA), Short-Term Energy and Winter Fuels Outlook, released October 7, 2014; US EIA, Weekly Natural Gas Storage Report, released October 23, 2014; US EIA Natural Gas Weekly Update, released October 23, 2014)

4---Energy Association

Pennsylvania 14

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• Two Association members inject into member-owned facilities

• Total volume injected: 3.4 Bcf

• PECO Energy anticipates using LNG to meet 1°/o of winter day requirements, PGW anticipates using LNG to meet 3°/o of winter requirements

• Management of LNG facilities is primarily a matter of preparedness

'Energy Association

t~ of Pennsylvania 15

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• Based on a weighted average of the members, 44.4°/o of this winter's supplies are hedged

• Supplies are considered hedged if they are

Already purchased and in storage

If they are contracted for delivery under:

• Fixed-price contracts

• Forward-priced contracts

• Price caps

~----Energy Association

Pennsylvania 16

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• Members are well prepared to accommodate the conditions forecasted in their winter season planning design.

• Underground storage and peak shaving inventories will be adequate to handle design conditions.

Thank you.

"

nergy Association

Pennsylvania 17

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Weather Summary ~ National Fuel

National Fuel Degree Days (HOD) Erie PA - 2013-2014

I Actual HDD as of 3-31-14 15.6% CTN - j 70

60

50

40 0 0 z

30

20 +-1--1-1--U-"- l-I-

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- Normal HDDs (by Day)

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National Fuel Degree Days (HOD) Cumulative Erie PA - 2013-2014

6,000

5,000 l

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- Actual HDDs (by Day) Winter 2013-14 - Actual HDDs (by Day) Winter 2012-13

3.2 % WTN through 3/31/13

22.4 % WTN through 3/31/12

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- Actual HDDs (by Day) Winter 2011-12

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Erie, PA Erie, PA 5 Coldest Winters 5 Warmest Winters

Based on 60 years of data Based on 60 years of data

Winter % Colder Winter % Warmer

1969-70 19.8% 2011-12 21.9%

1977-78 18.1% 2001-02 16.9%

1976-77 17.3% 1982-83 13.7%

~013-14 15.3% 1997-98 12.1%

1978-79 13.1% 1999-00 11.9%

Note: Prior to Winter 2012, normals are based on NOAA 1971-2001 data

Winter 2012 forward normals are based on NOAA 1981-2011 data

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Weather Summary

Historical Weather Data - Erie, PA

2004-2005 4 8 1

2005-2006 3 0

2006-2007 0 0 11

2007-2008 0 1

2008-2009 1 7

2009-2010 0 5

2010-2011 0 4 3

2011 -2012 0 1

2012-2013 0 4 0

2013-2014 1 10 13

Average 1 4 3

~ National Fuel

0 13

5

0 11

2 5

10

7

0 7

1

0 4

4 28

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Verification

I, John J. Polka Jr., Assistant Vice President of National Fuel Gas Distribution Corporation, state that the

facts set forth in the foregoing Purchased Gas Cost Filing under Section 1307(f) of the Public Utility Code

and 52 Pa. Code§§ 53.64 and 53.65 Docketed at R-2015-2461373 including

Statement No. 5 Exhibit Nos. 4 (partial), 6, and 8 (partial)

are true and correct to the best of my knowledge, information and belief, and that I expect to be able to prove the same at a hearing held in this matter. This statement is made subject to the penalties of 18 Pa. C.S. § 4904 relating to unsworn falsifications to authorities.

Joh:#I/ This 30th day of January, 2015

john j. polka, jr. national fuel gas distribution ...john j. polka, jr. in behalf of pgc statement...

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