TESTIMONY OF JOHN J. POLKA, JR.
IN BEHALF OF
PGC Statement No. 4
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-2014-2399610
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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.
What are your duties as Assistant Vice President?
I am responsible for the Gas Supply Administration Department and
the Energy Services Department. 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.
In June 1978, I joined Distribution as a Management Trainee.
I was transferred and promoted in December 1978 to Distribution's
Operations-North as a Junior Engineer. In January 1982, I was
transferred to Distribution's Industrial Engineering Department. In
May 1982, I was transferred to Distribution's Engineering
Department. Holding various positions and responsibilities in the
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Engineering Department, I was promoted to Assistant Engineer in
July 1982, Associate Engineer in July 1986, Senior Engineer in
November 1988, and Engineer-in-Charge in March 1994. On
January 1, 2001, I was transferred to National Fuel Gas Supply
Corporation ("Supply") and assigned to the Gas Control Department
as Engineer-in-Charge. On June 16, 2001 , I was transferred back to
Distribution and obtained the position of Assistant General Manager
of Distribution's Gas Supply Administration Department with
responsibilities for Gas Planning and Gas Accounting. On April 1,
2002, I was promoted to General Manager of Gas Supply
Administration. On October 1, 2013, I was promoted to Assistant
Vice President for both the Gas Supply Administration and the
Energy Services Departments. I am responsible for directing
Distribution's Gas Procurement, Gas Accounting, and Gas Planning
functions associated with the Gas Supply Administration
Department, as well as the Marketing, Area Development and New
Technology functions of the Energy Services Department.
What is the subject of your testimony?
I am testifying to PGC Exhibit No. 4 , PGC Exhibit No. 6 and PGC
Exhibit No. 8.
Were all sections of PGC Exhibit No's 4, 6 and 8 prepared under
your supervision and direction?
Yes, they were.
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
Q . Please explain PGC Exhibit No. 4.
2 A. PGC Exhibit No. 4 is Distribution's response to the Pennsylvania
3 Public Utility Commission's ("PAPUC") filing requirement at 52 Pa.
4 Code§ 53.64(c)(1 ), which requires details regarding the contracts
5 under which Distribution purchases supplies of gas including firm
6 Southwest supplies, spot gas supplies and local gas supplies and
7 regarding renegotiations of such contracts. Exhibit 4 also provides
8 details regarding Distribution's contracts for upstream pipeline
9 transportation and storage services, the design of rates for such
10 services, and recent and pending negotiations of such upstream
11 pipeline contracts. Mr. Robert Michalski and Mr. Christopher Cej will
12 be testifying to the specific elements contained in this Exhibit.
13 An important topic reviewed in the Exhibit is an update on
14 Distribution's initiatives to diversify its upstream capacity mix as a
15 component of overall system reliability. The current mix of capacity
16 provides access to Southwest, Mid-continent, Rockies, Canadian
17 and market area gas supplies, which allows for an increased level of
18 gas supply reliability through pipeline and basin diversity.
19 Q. Please explain PGC Exhibit No. 6 and its associated Appendix A
20 (collectively "Exhibit 6'').
21 A. Exhibit 6 responds to the Commission's filing requirement at 52 Pa.
22 Code§ 53.64(c)(4) and describes Distribution's involvement in
23 proceedings before the Federal Energy Regulatory Commission
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
("FERC") and other appropriate regulatory and judicial bodies.
2 These proceedings encompass FERC rulemakings and other
3 generic industry-wide issues, as well as proceedings involving the
4 individual pipelines on which Distribution transports and/or stores
5 gas.
6 Distribution participates in FERC proceedings, both
7 independently and as a member of the American Gas Association
8 ("AGA"). Exhibit 6 identifies a number of generic industry issues
9 before the FERC during the historic period that Distribution
10 responded to through its participation in AGA. These include
11 Revisions to Procedural Regulations Governing Transportation by
12 Intrastate Pipelines (FERC Docket No. RM12-17); Enhanced Natural
13 Gas Market Transparency (FERC Docket No. RM13-1);
14 Communication of Operational Information between Natural Gas
15 Pipelines and Electric Transmission Operators (FERC Docket No.
16 RM13-17); and Coordination between the Natural Gas and Electricity
17 Markets (FERC Docket No. AD12-12). In addition, Distribution
18 worked with AGA to develop comments which were submitted to the
19 Commodity Futures Trading Commission ("CFTC") in various
20 proceedings, including Request for Interpretive Guidance on the
21 Treatment of Certain Natural Gas Supply Contracts with Volumetric
22 Optionality; Comments in Support of Request for No-Action Relief
23 Extending the Compliance Date for Reporting Swap Transactions
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
Under Parts 43, 45 and 46 of the Commission's Regulations; Letter
2 Supporting the Commercial Energy Working Group's Request for
3 No-Action Relief Extending the Compliance Date for Reporting of
4 Trade Options; Comments in Support of the Futures Industry
5 Association's Request for Relief for Contingent EFS/EOO Trades;
6 Comments Regarding Rules Issued Jointly with the Securities and
7 Exchange Commission Establishing a De Minimis Threshold of Swap
8 Dealing Activity Prior to Registration With the CFTC as a Swap
9 Dealer; Request for No-Action Relief from 17 CFR Part 43
10 Procedures to Establish Minimum Block Sizes for Large Notional Off-
11 Facility Swaps and Block Trades Final Rule; and Comments in
12 Response to Notice of Meeting of the Technology Advisory
13 Committee.
14 Exhibit 6 also discusses the pipeline proceedings of most
15 significance to Distribution during the historic period, including
16 Columbia's Long-Term System Modernization Filing (FERC Docket
17 No. RP12-1021), Supply's compliance proceedings regarding
18 Reservation Charge Credits (FERC Docket No. RP13-189), Market
19 Area Pooling (FERC Docket Nos. RP13-298, RP13-580 and RP13-
20 1348) and Storage Service Enhancements (FERC Docket No. RP13-
21 299), Tennessee Gas Pipeline Company, L.L.C.'s ("Tennessee")
22 Supply Area Mitigation Filing (FERC Docket Nos. RP12-887, CP12-
23 490 and RP13-1374), Secondary in Path Scheduling Priority Filing
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
(FERC Docket Nos. RP11-1566 and RP12-514) and Rich Gas
Transportation Service (FERC Docket No. RP13-464), as well as
Texas Eastern Transmission , LP's ("Texas Eastern") Gas Quality
Filing (FERC Docket No. RP 13-1015).
What is the estimated financial 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?
The September 4 S&A represented a collaborative resolution
between Columbia and a majority of its shippers addressing
Columbia's recovery of significant capital investments to modernize
its gas transmission system infrastructure. The September 4 S&A's
provisions were discussed in detail in last year's Exhibit 6. Three
aspects of the September 4 S&A have a direct financial impact on
Distribution: (1) the Refund Settlement Payment of $50 million to be
paid to eligible shippers; (2) a two stage Base Rate Reduction to
reflect a $35 million annual revenue reduction in Columbia's cost of
service, effective as of January 1, 2012 ("First Base Rate
Reduction"), and an additional $25 million annual cost of service
reduction commencing on January 1, 2014 ("Second Base Rate
Reduction"); and (3) a Capital Cost Recovery Mechanism ("CCRM"),
whereby Columbia may recover its cumulative revenue requirement
(i.e. , return, depreciation, and taxes) for capital investments made to
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
modernize its system through an additive demand rate during an
initial 5-year period commencing February 1, 2014. The First Base
Rate Reduction ($.377/dth reduction in FTS and SST reservation
rates) was effective March 1, 2013. On March 11 , 2013, Columbia
issued refunds associated with the First Base Rate Reduction for the
period of January 1, 2012 through February 28, 2013 and the $50
million Refund Settlement Payment. Distribution's combined refund
amounted to $194,617.69.
The Second Base Rate Reduction ($.204/dth reduction in FTS
and SST reservation rates) was effective January 1, 2014 and the
first additive CCRM Rate ($.393/dth for FTS and SST) was effective
February 1, 2014. The net annual increase to Distribution of the
combined effect of the Second Base Rate Reduction and the CCRM
Rate will be approximately $25,000. Columbia will recalculate the
CCRM Rate annually, pursuant to the provisions of the September 4
S&A, and implement through limited annual filings under NGA
Section 4(e) to be effective each February 1.
Were there any outstanding issues regarding Supply's general
section 4 rate case in Docket No. RP12-88 that continued to be
addressed during the historic period?
Yes. Proceedings which were initiated by Supply pursuant to
Articles VI 11 , IX and X of the partial settlement of its general section 4
rate case in Docket No. RP12-88 which was approved by the FERC
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
on August 6, 2012 ("RP12-88 Settlement") to address: (1) the
reservation charge crediting provisions of its tariff under FERC
Docket No. RP13-189 ("Reservation Credit Proceeding"); (2) the
creation of new market pooling points, related pooling mechanisms,
and a new Market Pooling Point Aggregation Service ("MPPAS")
Rate Schedule under FERC Docket Nos. RP13-298, RP13-580 and
RP13-1348; and (3) certain enhancements to storage service under
FERC Docket No. RP13-299 ("Storage Enhancement Proceeding")
extended into the historic period.
You indicated in last year's Exhibit 6 that, on November 28, 2012,
FERC issued a letter order in the Reservation Credit Proceeding
("November 28 Letter Order") giving parties additional time to
comment. Upon reviewing these comments, has the FERC issued a
subsequent ruling in this proceeding?
Yes. The FERC issued an order, on May 6, 2013, approving
Supply's revised tariff records effective April 28, 2013, subject to
Supply making several modifications to bring its reservation charge
crediting provisions into full compliance with FERC policy. Supply
filed revised tariff records reflecting these modifications on June 5,
2013 ("June 5 Filing"). On October 2, 2013, the FERC issued a
letter order accepting Supply's June 5 Filing to be effective April 28,
2013.
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
There was a significant amount of discussion in last year's testimony
regarding the extensive negotiations between Supply and its
customers which resulted in a November 19, 2012 tariff filing by
Supply, under Docket No. RP13-298, to establish Market Pooling
Points ("MPP") ("Pooling Proceeding"). You also indicated that, on
December 18, 2012, the FERC issued a letter order in the Pooling
Proceeding finding that the parties raised a number of substantive
issues regarding Supply's pooling proposal warranting further
scrutiny and deliberation. Has there been any further activity in the
Pooling Proceeding?
Yes. The participating parties, including Distribution, held
discussions in an effort to resolve the issues discussed in the
December 18 Order as described in last year's Exhibit 6. As a result
of these discussions, a consensus was reached with respect to two
key issues: (1) the location of the Oswayo pooling point, and (2) the
priority of EFT and FST services at MPPs. On February 22, 2013,
Supply filed a supplement to its previous filing under a new Docket
No. RP13-580 ("Supplemental Filing"). The Supplemental Filing
proposed the following changes to reflect that consensus:
• A fifth pooling point was added at Sweden, PA, to be located south of Ellisburg Station on Line Y-M53, creating a second point in the vicinity of Ellisburg. The Oswayo point would remain located west of Ellisburg on Line Y-M2. This section was also revised to reflect a slight change to the location of the Aurora point, and the renaming of that point to Wales.
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• The process for determining when EFT or FST service at an MPP will receive priority equivalent to "on-the-path" secondary FT service was clarified with the addition of maps and tables, in lieu of a tariff description of the methodology and point references in individual EFT and FST service agreements.
Supply proposed to make its pooling proposal effective at
some indefinite date in the future, after it makes significant changes
to its automated business program.
Has the FERC ruled on Supply's pooling proposal as modified by the
Supplemental Filing?
Yes. On May 17, 2013, the FERC issued an order ("May 17 Order")
finding that Supply's proposal to make its pooling proposal effective
at some indefinite date in the future, after it makes significant
changes to its automated business program, is contrary to the
regulations. Specifically, Supply should have instead filed pro forma
tariff records setting forth its proposal to be ruled on by the FERC.
Consistent with this policy, the FERC assessed Supply's rejected
tariff records as if they were pro forma and ruled that it would permit
Supply to file identical tariff records to be effective at a definite date
with certain modifications.
The FERC noted positively that Supply's MPPAS proposal
should provide shippers with additional flexibility and service options
not currently offered under its tariff. These changes may also
enhance the value of Supply's services to existing customers, as well
as attract new shippers to the system. However, the FERC found
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
that Supply's proposal is in violation of FERC policy which requires
that any proposed title transfer tracking fee be determined on a per
transaction basis, and not volumetrically.
Has Supply made any further attempts to implement its pooling
proposal with the modifications set forth in the May 17 Order?
Yes. On September 26, 2013, Supply submitted revisions to the
provisions of its tariff concerning Appalachian pooling to be effective
as of November 1, 2013 under Docket No. RP13-1348 ("RP13-1348
Filing") . The RP 13-1348 Filing reflected identical language approved
by the FERC in the May 17 Order, wherein, the FERC treated the
proposed tariff record as proforma and permitted Supply to file an
identical tariff record at a later date, as discussed above. In the
RP13-1348 Filing , Supply indicated that, because the changes
relating to Appalachian pooling can be implemented within its
existing business system, there is no reason to delay implementation
of the Appalachian pooling revisions.
On October 24, 2013, Supply filed an amendment to its RP13-
1348 Filing postponing the effective date until December 1, 2013.
Supply indicated that the postponement was necessary to provide
producers with sufficient time to implement the proposed changes to
the Appalachian pooling provisions.
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
On November 27, 2013, the FERC issued a letter order
accepting the tariff revisions proposed by Supply in the RP13-1348
Filing to be effective December 1, 2013.
Has there been any further developments with respect to MPPAS?
Supply stated in its RP13-1348 Filing that the business system
modifications required to implement MPPAS service are underway
and that its goal is to put this service into effect on February 1, 2014.
Now, let's focus on the Storage Enhancement Proceeding. Please
recap Supply's November 19, 2012 filing in this proceeding
("November 19 Filing").
The November 19 Filing modifies Supply's tariff to permit a firm
storage customer under the ESS or FSS rate schedule to release a
portion of its Maximum Storage Quantity ("MSQ") with withdrawal
and/or injection rights that represent a different percentage of its
MSQ than the corresponding percentage under the releasing
customer's service agreement, subject to certain limitations designed
to protect its system operations. These limitations are that (1) the
term of any decoupled release can't exceed 24 months; (2) a
decoupled release cannot exceed 30 percent of its contracted
storage capacity; (3) decoupled releases of ESS capacity must be
accompanied by an amount of EFT transportation service equal to
the released injection and/or withdrawal rights; and (4) the
replacement shipper under a decoupled release would be subject to
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
the lowest injection and withdrawal ratchets applicable to the
releasing shipper's service regardless of the amount of its storage
capacity it occupies.
In addition , the Storage Enhancement Filing provides ESS
customers with firm summer period withdrawal rights equal to
twenty-four percent of each customer's Maximum Daily Withdrawal
Quantity (MDWQ). It also provides that Supply may temporarily limit
or suspend summer season firm withdrawals as necessary to
conduct pressure tests of its storage fields.
Last year you described how the provisions of the November 19
Filing will enhance the value of Supply's storage services. Please
reiterate here.
Under Supply's existing storage terms and conditions, the
percentage of injection rights and withdrawal rights are tightly linked
to the contracted capacity of storage and the amount of capacity that
has been utilized. For example, if during the injection cycle an ESS
customer fills one-half of its storage, it still has its full injection rights
based upon the total contracted capacity. If the ESS customer
releases the remaining half of storage capacity, it only can release
one-half of its contracted injection and withdrawal rights to
accompany the released capacity. Furthermore, the ESS customer
cannot simultaneously release the entire ESS contract capacity (and
accompanying full injection and withdrawal rights) and retain title to
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
the gas already injected without running afoul of the FERC's
"shipper-must-have-title" requirement. Physically nothing has
changed, however, since the capacity retained by the ESS customer
is full, half of the original injection and withdrawal rights associated
with the retained capacity are necessarily required to become fallow.
This limitation is a significant impediment to many potential
AMAs, because a potential asset manager could better optimize the
capacity, as well as fill storage in the remaining injection season if it
had access to the full injection rights the ESS customer would have
had itself if it did not enter into the AMA. Supply's unbundling of the
injection/withdrawal rights and the capacity rights (i.e ., "decoupling"),
therefore, helps to facilitate asset management deals.
Likewise, having the ability to withdrawal gas from storage
during the summer months provides customers with additional
flexibility.
Last year's Exhibit 6 stated that the FERC issued a letter order on
December 19, 2012, accepting the tariff records proposed by Supply
in the November 19 Filing and suspending them for the maximum
period of five months. The FERC found that parties raised a number
of substantive issues regarding Supply's proposal which warranted
further scrutiny and deliberation. What progress has been made in
the Storage Enhancement Proceeding since then?
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
Supply held telephonic meetings to discuss the parties' concerns
regarding its storage enhancement proposals and provided
additional information to facilitate further discussion. Of primary
concern at these meetings were the limitations that Supply placed on
a shipper's ability to decouple releases. According to Supply, these
limitations were necessary due to the uncertain impact that such
releases may have on its system operations. As an alternative,
Supply was requested by one of the parties to offer its decoupling
proposal as a pilot program to be resubmitted after it has had time to
assess the impact of the program on its system operations.
Ultimately, consensus was reached that Supply will submit to
the parties in this proceeding detailed information concerning the
impact of its decoupled storage capacity release proposal and
associated analyses on or before June 30, 2015 and schedule a
conference call no later than September 30, 2015. Supply further
agreed that the information to be provided would reflect various
specified daily quantities and percentages, aggregated over all
decoupled releases (e.g., storage capacity released as a percentage
of total storage capacity). On February 28, 2013, Supply submitted
supplemental information to the FERC describing the consensus
among the parties resolving all outstanding issues in the Storage
Enhancement Proceeding.
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
On May 17, 2013, the FERC issued a letter order in this
proceeding approving the tariff records associated with summer
period storage withdrawals to be effective May 19, 2013. However,
the FERC rejected the tariff records associated with decoupled
storage capacity releases, because, once again, Supply indicated
that the proposal would take effect at some indefinite time in the
future, in violation of FERC regulations. Nevertheless, the FERC
evaluated the rejected tariff records as though they were pro forma
and indicated that Supply will be permitted to file actual tariff records
identical to the pro forma tariff records no less than 30 or more than
60 days in advance of the proposed effective date of the tariff
records.
Has Supply filed the pro ·forma tariff records to implement storage
capacity releases?
No. Supply has indicated that it will file the pro forma storage tariff
records following full implementation of the aforementioned pooling
proposal.
Let's shift our focus to significant activity before the FERC
associated with Tennessee.
Regarding Tennessee's Supply Area Mitigation ("SAM")
proposal, in last year's testimony you indicated that, on April 2, 2012,
Tennessee and Kinetica Partners, LLC ("Kinetica") entered into an
amended and restated purchase and sale agreement ("ARPSA") for
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
the purchase and sale of certain onshore and offshore supply
facilities located in the Gulf of Mexico and in the state of Louisiana
("Original SAM Facilities"), as well as substantially all of Tennessee's
remain ing facilities in the offshore production area (collectively,
"Transferred Assets").
You also stated that, on July 26, 2012, under Docket Nos.
CP12-490 and RP12-887, Tennessee submitted to the FERC an
application requesting authorization to abandon the jurisdictional
portion of the Transferred Assets and approval of a related offer of
settlement ("July 26 S&A"). Kinetica applied in a companion filing,
under Docket No. CP12-489, for certificate authorization to own and
operate the balance of the Transferred Assets not previously found
by the FERC to perform a gathering function.
You testified that Distribution was in favor of Tennessee's
proposed divestiture of the Transferred Assets and associated
abandonment of those facilities by sale to Kinetica. Please recap
Distribution's position regarding the benefits associated with the
divestiture.
Distribution believes that Tennessee's proposal demonstrates an
appropriate recognition of changing gas flows in the geographic
regions in which it operates and of the need to shorten capacity as
natural gas supplies move from off-shore to on-shore locations as
new technologies are implemented.
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Moreover, as consideration for the sale of the Transferred
Assets, Kinetica has agreed to pay Tennessee the sum of $32
million, as adjusted pursuant to the ARPSA, and to assume and pay,
perform and discharge certain obligations, responsibilities, costs and
expenses including abandonment and/or decommissioning cost
liability for all of the Transferred Assets, as well as environmental
liability for such facilities, with a few exceptions as defined in the
ARPSA. In addition, the July 26 S&A removes rate uncertainty
associated with the divestiture and provides for the prospect of
meaningful, near-term rate relief for Tennessee's Part 284 shippers.
What is the status of the FERC proceedings associated with the
revised SAM proposal?
On May 31 , 2013, the FERC issued an order approving Tennessee's
request to abandon the Transferred Assets and granting certificate
authority for Kinetica to acquire and operate the Transferred Assets
found to be jurisdictional transmission facilities ("May 31 Order").
The May 31 Order also approved the July 26 S&A as a contested
settlement and directed Tennessee to file tariff records in a
compliance filing implementing the settlement with respect to all
consenting and contesting parties 30 days prior to the sale of the
Transferred Assets. The FERC instructed Tennessee to continue to
offer service to contesting parties under its currently fi led rates,
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
unless and until it makes a filing under NGA section 4 to modify its
rates applicable to service to those contesting parties.
On September 30, 2013, Tennessee submitted its compliance
filing under Docket No. RP 13-137 4 ("Compliance Filing")
implementing the rate adjustment provisions of the July 26 S&A
effective September 1, 2013. In this regard , the July 26 S&A requires
Tennessee to establish a regulatory asset for a portion of the
unrecovered net book value of the Transferred Assets and to adjust
its Part 284 transportation rates established pursuant to the rate case
settlement in Docket No. RP11-1566 ("2011 Rate Settlement") to
reflect the cost of service effect of the removal of depreciation, return
and related income taxes associated with the sales proceeds and $5
million of stipulated operation and maintenance expense savings .
Given the limited number of contesting parties to the July 26 S&A,
Tennessee proposed to waive its right to charge such contesting
parties the higher rates established in the 2011 Rate Settlement and
instead sought to provide such contesting parties the benefit of the
lower rates pursuant to the July 26 S&A.
What is the financial impact of the Compliance Filing on Distribution?
Pennsylvania's share of the annual savings associated with the rate
reduction is $215,425.
A significant portion of your testimony last year was devoted to
Tennessee's "Scheduling Priority Issue," an unresolved issue
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associated with Tennessee's rate case proceeding under Docket No.
2 RP11-1566. Please describe the Scheduling Priority Issue.
3 A. The Scheduling Priority Issue relates to Tennessee's proposal to
4 treat firm quantities scheduled from secondary receipt points to
5 primary delivery points as primary, for purposes of allocating
6 mainline capacity, when the pipeline constraint occurs within the
7 primary capacity path of the applicable service agreement. The
8 FERC rejected Tennessee's proposal as formulated in its rate case
9 and reiterated this rejection on rehearing.
10 Q . Why is the Scheduling Priority Issue of particular interest to
11 Distribution?
12 A. Tennessee's proposal to treat firm quantities scheduled from
13 secondary receipt points to primary delivery points as primary, for
14 purposes of allocating mainline capacity, when the pipeline
15 constraint occurs within primary capacity path of the applicable
16 service agreement would permit firm transportation holders, such as
17 Distribution, to source the lowest priced supplies, short-haul or long-
18 haul, without any reduction in service priority.
19 Q . Per Exhibit 6, it appears that the Scheduling Priority Issue is
20 progressing on two separate tracks. Is that correct?
21 A. Yes. A petition for review of the FERC's scheduling priority
22 determination in Tennessee Gas Pipeline Company, LLC, Docket
23 No. RP11 -1566 was brought before the United States Court of
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
Appeals for the District of Columbia Circuit on June 15, 2012
("National Fuel Gas Distribution Corporation v. Federal Energy
Regulatory Commission, Case No. 12-1261"). This appeal is
currently held in abeyance pending the resolution of related
administrative proceedings at the FERC, as described below.
Simultaneously, the Scheduling Priority Issue is being
separately addressed pursuant to the December 5, 2011 settlement
reached in the rate case under Docket No. RP11-1566 ("December 5
Settlement"). The December 5 Settlement provided that Tennessee
would convene a meeting with its customers to discuss a proposal to
elevate the scheduling priority of in-the-path transportation
transactions from secondary receipt points to primary delivery points,
and file and support such a proposal at the FERC. Tennessee made
a filing to comply with that obligation in Docket No. RP12-514
("Scheduling Priority Proposal").
What did Tennessee put forward in its Scheduling Priority Proposal?
Tennessee's Scheduling Priority Proposal established two additional
scheduling priority categories, just below the scheduling priority of
nominations from primary receipt points to primary delivery points,
such that nominations from secondary receipt points to primary
delivery points where a constraint is within the primary path would be
scheduled before nominations from primary receipt points to
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
secondary delivery points where a constraint is within the primary
path.
Have there been any further developments in Docket No. RP12-514
during the historic period?
Yes. On January 17, 2013, the FERC issued an order establishing a
technical conference in this proceeding. The FERC found that
Tennessee's proposal raised operational and technical issues that
would best be addressed at a technical conference where staff and
all parties would have an opportunity to further discuss the issues
presented by Tennessee's proposal. Accordingly, FERC Staff was
directed to convene a technical conference to address the issues
raised by Tennessee's filing and to report the results of the
conference to the Commission.
Did Distribution participate in the technical conference?
Yes. The technical conference to discuss Tennessee's Scheduling
Priority Proposal and the issues related thereto occurred on April 10,
2013. Tennessee made a presentation in support of its Scheduling
Priority Proposal and responded to Staff's questions. A number of
parties, primarily producers and marketers, indicated their opposition
to Tennessee's proposal. Distribution appeared, presented and
offered evidence at the technical conference strongly supporting the
scheduling changes proposed by Tennessee. Following the
technical conference, Distribution filed jointly with the National Grid
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
Gas Delivery Companies detailed post-technical conference
comments, also in support of Tennessee's Scheduling Priority
Proposal.
What was the outcome of the technical conference?
On October 17, 2013, the FERC issued its Order on Technical
Conference and Denying Rehearing ("October 1 ?1h Order") approving
Tennessee's Scheduling Priority Proposal.
Has Tennessee implemented its Scheduling Priority Proposal?
No. Tennessee sought an extension of time to complete the system
changes and testing required to implement the approved scheduling
priority provisions. The FERC granted the extension to no later than
30 days prior to the implementation date of the scheduling priority
changes.
Furthermore, on November 18, 2013, the Indicated Shippers
requested rehearing of the October 1 ?1h Order. Shortly thereafter, on
December 3, 2013, Distribution filed an Answer opposing the
Indicated Shippers' rehearing request. The rehearing request is
currently pending before the FERC.
Now let's talk about Tennessee's proposal to provide a new rich gas
transportation service filed under Docket No. RP13-464 on January
18, 2013 ("Rich Gas Proposal"). Does the Rich Gas Proposal
require that Tennessee lay additional pipe?
23
DIRECT TESTIMONY OF JOHN J. POLKA JR.
A. No. Tennessee proposes to use an existing segment of one of its
2 four parallel mainlines that are within the known boundaries of the
3 Utica Shale play to provide the proposed rich gas transportation
4 service ("Rich Gas Line"). Tennessee maintains that new gas
5 supplies located in Tennessee's market area, such as those from the
6 newly developed Marcellus Shale play, are displacing other
7 traditional sources of supply from the Gulf Coast, freeing up capacity
8 in this segment of pipe.
9 Q. Does Tennessee's Rich Gas Proposal envision associated gas
10 processing?
11 A. Yes. Tennessee has indicated that it entered into a straddle
12 agreement with its affiliate, El Paso Midstream Group Inc.
13 ("Midstream"). Under the straddle agreement, Midstream will have
14 the exclusive right to construct one or more straddle plants
15 (consisting of one or more processing plants, including cryogenic
16 and/or refrigeration plants) and will pay all costs for Tennessee's
17 facility modifications to accommodate the Rich Gas Line.
18 Tennessee has further stated that all processing
19 arrangements will be made between Midstream and its processing
20 customers, and Tennessee will not be a party to such processing
21 agreements and will not share in any processing revenues.
22 Q . Does Tennessee's Rich Gas Proposal provide for a new
23 transportation service?
24
DIRECT TESTIMONY OF JOHN J. POLKA JR.
A. No. Tennessee proposes to apply the existing generally applicable
2 Rate Schedule FT-A and IT rates (Zone 4-4) for the new rich gas
3 service, including the generally applicable fuel (including electric
4 power) charges as well as surcharges. Tennessee states that it will
5 selectively discount and negotiate rates as required to market the
6 proposed rich gas transportation service.
7 Tennessee further explains that rich gas service under the
8 FT-A and IT Rate Schedules will have limitations on certain rights
9 because the transportation service will be provided solely on the
10 Rich Gas Line. For example, changes to primary points, extended
11 receipts and deliveries, capacity segmentation, and capacity release,
12 which are generally available under Rate Schedule FT-A, will be
13 limited such that shippers that do not have primary receipt and
14 delivery points on the Rich Gas Line will not have access to those
15 receipt and delivery points on a secondary basis, and will not be
16 permitted to release capacity on the Rich Gas Line portion of the
17 system. Similarly, shippers having receipt and delivery points solely
18 on the Rich Gas Line will not be permitted to access the lean gas
19 portions of the system.
20 Q. What is Distribution's position regarding Tennessee's Rich Gas
21 Proposal?
22 A. Distribution generally supports the concept of permitting Tennessee
23 to provide rich gas transportation service using segregated facilities
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
in Zone 4 to encourage Utica Shale producers to attach their
suppl ies to Tennessee's pipeline system. However, Distribution
believes that the Rich Gas Proposal raises a number of unanswered
questions which Tennessee should be required to address at a
technical conference.
On January 30, 2013, Distribution joined with other members
of the Northeast Customer Group ("NCG") in the submission of a
protest and request for technical conference ("January 30 Protest").
Refer to Exhibit 6 for the details of the January 30 Protest.
What is the status of the Rich Gas Proposal proceeding?
On May 16, 2013, the FERC issued an order in this proceeding
accepting Tennessee's January 2013 Filing subject to certain
conditions and directing Tennessee to file actual tariff records,
between 30 and 60 days prior to the in-service date of its rich gas
transportation service ("May 16 Order"). The specifics of the May 16
Order are discussed in detail in Exhibit 6.
It is notable that, although the FERC found that it is
reasonable for Tennessee to commence its firm and interruptible rich
gas transportation service using its existing Rate Schedules FT-A
and IT, the FERC directed Tennessee to maintain sufficient records
to allow related cost allocation concerns to be fully investigated in its
next rate case.
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
The FERC also found that, although Tennessee's exclusivity
provision with Midstream does not appear to impact FERC policies
on tying or anti-competitive practices, it does violate FERC's open
access interconnection policy and also appears to violate
Tennessee's own tariff language on interconnections.
On June 17, 2013, Tennessee filed a request for rehearing of
the May 16 Order regarding the FERC's determination that the
Midstream exclusivity provision violates FERC's open access
interconnection policy. The rehearing request is currently pending
before the FERC.
Moving on to Texas Eastern's gas quality tariff provisions, you note
in Exhibit 6 that, on June 28, 2013, Texas Eastern filed to establish a
second Control Point at Berne for the Control Zone Exemption under
Docket No. RP13-1015 ("June 28 Filing"). Please reiterate the
significance of the Control Zone Exemption in general.
On November 1, 2010, the FERC approved a Stipulation and
Agreement submitted by Texas Eastern on August 4, 2010 ("2010
Settlement") in Texas Eastern's gas quality proceeding under Docket
No. RP10-30. The 2010 Settlement served to accommodate
increasing natural gas production in the Appalachian basin, where
the otherwise-applicable quality limits are regularly exceeded through
the creation of the "Control Zone Exemption," whereby Texas
Eastern will accept receipts of gas with higher levels of ethanes and
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
heavier hydrocarbons ("C2+"), heating value, and Wobbe Index
Number at points located within the "Control Zone," which extends
from the discharge of the Berne, Ohio compressor station ("Berne")
to the "Control Point" at the discharge side of the Uniontown,
Pennsylvania compressor station ("Uniontown"), provided that the
blended gas stream meets the standard quality specifications at the
Control Point.
Please describe the change in circumstances which Texas Eastern
maintains necessitates a second Control Point for the Control Zone
Exemption to be established at Berne.
One of the key assumptions underlying the 201 O Settlement and
associated tariff provisions, namely that gas would continue to flow
through Texas Eastern's system from the Gulf Coast to the northeast,
as it historically has flowed, is no longer valid . Production of natural
gas from the Appalachian basin has been much greater than Texas
Eastern anticipated during the prior settlement negotiations.
Receipts of Appalachian gas within the Control Zone can at times
exceed demand from Texas Eastern's markets east of Uniontown,
resulting in gas flowing out of the Control Zone to the west from
Berne, as well as to the east from Uniontown. Therefore, Texas
Eastern maintains that the effects of high C2+ gas on customers west
of Berne are as relevant as the effects on customers east of
Uniontown.
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
What was Distribution's position on this matter?
Distribution was concerned that not enough information was
provided to determine whether the proposed gas quality limits will
provide a benefit to Texas Eastern's system west of Berne. Simply
applying the gas quality limits that were designed for Texas
Eastern's system east of the Uniontown Control Point to its system
west of Berne may be overly conservative and unnecessarily
restrictive. Overly conservative limits could lead to additional costs
to producers which ultimately may result in higher prices to be paid
by consumers. Therefore, Distribution requested that a thorough
review of the facts as they apply to Texas Eastern's system west of
Berne be undertaken to develop appropriate gas quality limits.
Did Texas Eastern's ultimate resolution of this issue assuage
Distribution's concerns?
Yes. Distribution participated in subsequent settlement
discussions with Texas Eastern and the other interested parties and,
on December 4, 2013, Texas Eastern submitted a settlement to the
FERC ("December 4 Settlement"). The December 4 Settlement
provides for additional procedures for parties to make arrangements
to schedule alternative gas supplies to bring the Control Points within
tariff gas quality specifications, requires Texas Eastern to install
additional gas chromatographs west of Berne, and provides for
enhancements to Texas Eastern's bulletin board.
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
What is the status of this proceeding?
On December 26, 2013, the FERC issued a letter order approving
the December 4 Settlement.
Regarding PGC Exhibit No. 8, could you further explain the Gas Cost
Management Plan?
The Gas Cost Management Plan (Exhibit POL-1) lays out in
summary form the different gas purchase methodologies Distribution
uses to diversify its pricing of gas supplies. In addition to the pricing
benefits Distribution obtains through its contracted storage services,
the Plan summarizes Distribution's approach for obtaining diverse
prices for its flowing supplies.
Section I of the Plan identifies the forward pricing measures
Distribution will use for purchasing a portion·of the monthly supplies.
During the winter months (November - March), approximately 20%
of the monthly purchases will be forward priced.
Section 11 notes that approximately 60% of the supplies for the
winter and summer months will be priced at a mix of Index and bid
week negotiated (Cash) prices.
Section 111 takes into account that the remaining supplies
(approximately 20% winter and 40% summer) will be procured on a
daily basis and will be priced at Index and/or negotiated (Cash)
prices.
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
The Plan provides for the flexibility to adjust the timing of
forward prices based on market fundamentals such as hurricanes
and unanticipated events.
Have there been any changes to the Plan since the last PGC filing?
No. The Plan remains the same as submitted in the last PGC filing .
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 2013-2014, the
current Plan would provide for approximately 53% of the gas
supplies to be hedged (see PGC Exhibit No. 8-E).
Do you have any reference as to how the proposed 53% 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, 2013 response stated , "Based on
a weighted average of the members, 39.4% of this winter's supplies
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
are hedged". The EAP defined hedges as storage supplies, fixed
price contracts, forward-priced contracts and price caps. Please
refer to page 15 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.
Please explain the current status of Distribution's off-system sales
activities.
In light of and in reliance on FERC's Order 717-A, Distribution
resumed off-system sales on non-affiliated pipelines as of November
2, 2009. Distribution continues to utilize off-system sales as a
mechanism for optimizing system assets and reducing overall
system gas costs.
Has Distribution explored alternatives other than capacity release
and off-system sales to optimize upstream pipeline and storage
assets?
Yes. The Company has discussed various proposals with suppliers
regarding asset optimization utilizing Asset Management
Arrangements ("AMAs"). As discussed in PGC Exhibit No. 6, on
June 19, 2008, the FERC issued Order No. 712 revising its capacity
release regulations to, among other things, permit market based
pricing for short-term capacity releases and to facilitate AMAs by
relaxing restrictions on tying and bidding requirements for certain
capacity releases, including conditions associated with gas inventory
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DIRECT TESTIMONY OF JOHN J. POLKA JR.
held in storage for releases of firm storage capacity. The FERC
issued additional clarifications on the issues with Order No. 712-A on
November 21, 2008 and Order No. 712-B on April 16, 2009.
Has the Company investigated or entered into any AMAs or similar
transactions?
Historically, the Company has investigated and entered into
transactions involving storage fill agreements. Specifically, through
the storage fill agreements, Distribution realized shareable credits
relative to what it would have paid if purchases were made ratably
over the injection season at first of the month index rates. Mr. Cej's
testimony will review the most recent activity regarding AMAs.
Distribution intends to continue to investigate and enter into
storage fill transactions, when appropriate, with viable
counterparties. Distribution will also utilize, where appropriate,
alternative arrangements permissible as a result of FERC Order 712.
Distribution will continue to optimize its capacity and gas
supplies through capacity releases, off-system sales and/or AMAs.
Pursuant to previous 1307(f) settlements, revenue from capacity
releases, net off-system sales and AMAs will continue to be credited
75% to the ratepayers and the remaining 25% to Distribution.
33
DIRECT TESTIMONY OF JOHN J. POLKA JR.
Q . Please explain Section IV Staffing and Expertise of Fuel
2 Procurement Personnel, in PGC Exhibit No. 8.
3 A. This section of PGC Exhibit No. 8 discusses Distribution's Gas
4 Supply Administration Department. PGC Exhibit No. 8-D provides a
5 chart detailing the use of functional teams that handle the duties and
6 responsibilities of all of the areas that encompass the department.
7 Q . Is there anything additional you would like to discuss regarding
8 Exhibit No. 8?
9 A. Yes. Exhibit POL-4 is a graphical representation of Distribution's
10 calculations of the design peak day requirements implied by the
11 sendout data for each day of the three-day peaks for the 5 most
12 recently completed winter heating seasons including November 2008
13 - March 2009, November 2009- March 2010, November 2010 -
14 March 2011, November 2011 - March 2012 and November 2012 -
15 March 2013.
16 Distribution is also providing Exhibit POL-5 which is a
17 graphical presentation of Distribution's calculations of the design
18 peak day requirements implied by the sendout data for those days
19 during the 5 most recently completed winter heating seasons that
20 averaged equal to or less than 15 degrees Fahrenheit and were not
21 a holiday or a weekend day.
22 Q. Please describe what the studies indicate.
34
DIRECT TESTIMONY OF JOHN J. POLKA JR.
A. The calculations and illustrations associated with the attachments
2 indicate that when the total consumption on Distribution's System is
3 extrapolated out to 74 HOD, there are days in which calculated total
4 requirements fall within the contingency factor and a number of days
5 where this consumption exceeds the calculated forecast design peak
6 day total requirements including the contingency factors. Since the
7 last 70+ HOD occurred more than 20 years ago (January 19, 1994, -
8 11°F Mean, 76HDD), there is no recent historical experience
9 available on how customer consumption patterns will be impacted by
10 design day temperatures.
11 As noted in PGC Exhibit No. 4, in September 2012
12 Distribution updated its forecast design day requirements for the
13 winter of 2013-2014. The update indicated that Distribution's
14 contingency capacity level for the winter of 2013-2014 was forecast
15 to be approximately 27,700 Dth/day. Distribution, therefore, decided
16 to reduce its EFT capacity by 9,585 Dth/day to be effective April 1,
17 2013, in keeping with its practice of not reducing capacity on a "one-
18 for-one" basis with reduced market forecasts.
19 This decision was consistent with Distribution's conservative
20 approach to capacity reduction for Design Day Requirements, which
21 will total 59,651 Dth/day since 2003 (see Exhibit MIC-4).
22 a. Does this conclude your direct testimony?
23 A. Yes, it does.
35
National Fuel Gas Distribution Corporation
Pennsylvania Division GAS COST MANAGEMENT PLAN
January 1, 2014
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.
III. 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.
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November 1, 2013 Harrisburg, PA
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The Energy Association of Pennsylvania represents the interests of its
Member NGDCs:
Columbia Gas of Pennsylvania Equitable Gas
National Fuel Gas Distribution Corp. PECO Energy Company Peoples Natural Gas Co.
Peoples TWP Philadelphia Gas Works
Pike County Light & Power UGI Central Penn Gas, Inc. UGI Penn Natural Gas, Inc.
UGI Utilities, Inc. - Gas Division Valley Energy
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Supply and Demand Winter 2013-2014 (all natural gas volumes in billions of cubic feet)
Expected Demand
Expected Supply Flowing Interstate Gas Storage Withdrawals Local Production Peak Shaving
TOTAL
209.8 Bcf
126.3 71.0 11.2
1.3 209.8
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Winter 2012-2013: Supply Sources by Type
210.9 Bcf
Storage Withdrawal
Local Production Peak
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Flowing Interstate
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mter 2013-2014: Supply Sources by Type
209.8 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 pr~serve service reliability at anticipated levels of firm demand
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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
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In the past few years, the United States has experienced a rapid increase in natural gas production from shale resources. The combination of two technologies -horizontal drilling and hydraulic fracturing - made it possible to produce shale gas economically
The Energy Information Administration (EIA) projects that natural gas production from unconventional resources in the U.S. will increase 35% between 2007 and 2030
Increases in shale gas production in the Marcellus Region alone accounted for about 75% of natural gas production growth over the past year. The majority of Marcellus production is coming from Pennsylvania and West Virginia. According to EIA, Marcellus production is more than six times the 2009 production rate. In Pennsylvania, natural gas production rose 69% in 2012 in spite of a drop in the number of new natural gas wells started during the year
• It is anticipated that North America will become a net exporter of energy by 2020. In a recent report, EIA estimates that the United States will be the world's top producer of petroleum and natural gas hydrocarbons by the end of 2013, surpassing Russia and Saudi Arabia
r~1~~ 8£ktr..~·8%i%gr;,~~~~:;1~':~o"rt~'dtt~t:; bi~~~~~e 1f.~{i~~eucl1'87i2Jf/00°s"'E7~0~t;,~JnJS,:,:'b'51~i< ~'b~"i.' t;~!?~ J~%1~. ~~~~:·2i%
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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 $2. 75 per million British thermal units (MMBtu) in 2012, to average $3.71 per MMBtu in 2013 and $4.00 per MMBtu in 2014
• The Henry Hub price is currently about $3.70 per MMBtu
(US Energy Information Administration (EIA) Short-Term Energy and Winter Fuels Outlook, released October 8, 2013· US EIA, Natural Gas Weekly Update, for week ending 10/9/13, released 10/10/13) ·
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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
More than one-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
EIA notes that 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. About 27,800 miles of new natural gas transmission pipeline were placed in service in the U.S. from 1998 to 2011. 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 YearIn-Review 2009, released July 2010; US EIA, Major Changes in Natural Gas Transportation Capacity 1998-2008, J. Tobin, Office of Oil & Gas; FERG Summer 2012 Energy Market & Reliability Assessment 5117112; www.eia.govlpub/oil!Jaslnaturat_gas/analysis_pub/icationslngpipeline/index.html)
10
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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
11
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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, 2013 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
12
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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 0.04 trillion cubic feet (Tcf) above the previous five year average (2008-2012). According to the Energy Information Administration (EIA), and based on projects already under construction, another 71 billion cubic feet (Bcf) of planned design storage capacity may be added to the grid in the Lower 48 states in 2013
• For the week ending October 4, 2013, working natural gas in underground storage totaled 3,577 billion cubic feet (Bcf) which is 1.6% above the five year average, and closing rapidly on last year's total
(American Gas Assodation (AGA J Natural Gas Market lndicators-10/14113; US Energy Information Administration (EIA), Short· Term Energy and Winter Fuels OuNook, released October 8, 2013 ; US EIA, Today In Energy, 7124113)
13
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• Two Association members inject into member-owned facilities
• Total volume injected: 4.7 Bcf
• PECO Energy anticipates using LNG to meet 1 o/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
14
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• Based on a weighted average of the members, 39.4°/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
15
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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.
16
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1 - Total Requirements RARA Estimate 2 - Contingency Capacity
450,000
400,000 ..
350,000
300,000
250,000 .
Iii" ..c .... e.
200,000
150,000
100,000
50,000
0
•
1- 401,553 2 -18,323
•
•
1- 392,192 2 - 24,241
~ -;;. ~ -,, ~ ~ ~ ~
NFGDC-PA Peak Day Comparisons Winter 3-day Peaks
(Temperature data 10 to 10)
1- 399,384 2 - 25,761
~ ~ ~ ~ ~ ~ ~ ?. ?. ~ ~ ~ <e, ~ ~ ~ ~ ~ ~ ~ 'b 'b ~ % % ~ ~ >o ~ ~ ~
• •
• Contingency Capacity
D Pea k Day Planned
• Extrapolated 74 HOD Design Day
•
•
•
1- 379,683 2 - 22,786
1 - 373,666 2 - 25,425
~ ~ ~ %
~ -,., ~ %
~ ~
\ ~
~ ?. ~ %
~ ~ ~ %
~ ~ ~ ~
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1 - Total Requirements RARA Estimate 2 - Contingency Capacity
450,000 .
4 00,000 .
350,000
300,000 .
250,000 .
iii .t:
0
200,000
150,000 .
100,000 .•
50,000 .
•
1-401,553 2 -18,323
1- 392,192 2- 24,241
NFGDC-PA Days = 15 Deg. F or Colder For seasons 2008 to 2018
1- 399,384
2 - 25,761
(No Weekends or Holidays) (Tem perature data 10to10)
1 - 379,683 2 - 22,786
• • •
Ill Contingency Capacity
GI Peak Day Pla nned
+ Extrapolated 74 HOD Design Day
~~~~~~~ ~ 0 -~ I I I I I I I I I I I I I .1 I I I I I I· I I I I -I 1. ,, · I 1 . .j .. 1 1. I I I I I
~~~~~ ?. ? ?.?.~ ~~ ~~ ~~ ~~ ~~ -e.~~ ~~~~ ~ '2i '2i ~ 'b. 'b. 'b. ~~~~ill 19 19
~ ~ ~
~~~,1,~ ~' ~ ~~~ ;.>~ ;.>~ ;.>~ ;.>q. ~q. ~'O'O~~ 'o. ~ ~~~ p~ "'~ 0\(11(1 ;..1(\) fP(\) 0.;.>;.>C).C). ;.> o.o.o.o. ~ ~ ~ ~ ~ ~~~~ ~ ~ ~~~~ ~ ~ ~ ~ ~
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Verification
I, John J. Polka Jr., Assistant Vice President of the Gas Supply Administration Department and the Energy
Services Department 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-2014-2399610 including
Statement No. 4 Direct Testimony of John J. Polka Jr. Exhibit Nos. 4 (partial), 6, 8 (partial) as well as POL-1, POL-2, POL-3, POL-4 and POL-5
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~ This 31st day of January, 2014
