BEFORE THE .us



BEFORE THEPENNSYLVANIA PUBLIC UTILITY COMMISSIONPennsylvania Public Utility Commission:R-2016-2531807 Office of Consumer Advocate:C-2016-2535307Office of Small Business Advocate:C-2016-2536983:v.::Columbia Gas of Pennsylvania, Inc. :RECOMMENDED DECISIONBeforeKatrina L. DunderdaleAdministrative Law JudgeTABLE OF CONTENTSI.HISTORY OF THE PROCEEDINGS1II.DESCRIPTION AND TERMS OF SETTLEMENT3III.DISCUSSION11Treatment of Interstate Pipeline Penalty Credits11Lost and Unaccounted for Gas and Retainage13Gas Exchanges with Affiliates15DTI Capacity17BIE’s Position20F.OSBA’s Position20G.The NGS Parties’ Position21IV.RECOMMENDATION21V.CONCLUSIONS OF LAW22VI.ORDER24I.HISTORY OF THE PROCEEDINGSColumbia Gas of Pennsylvania, Inc. (Columbia), made its required filing under Section 1307(f) of the Public Utility Code, 66 Pa.C.S. § 1307(f)(3), and 52 Pa.Code § 53.65, on April 1, 2016 in connection with the Company’s 2016 Purchased Gas Cost filing for the period ending September 30, 2016. Columbia’s filing of Supplement No. 244 to Tariff Gas Pa. P.U.C. No. 9 (Supplement No. 244), to become effective for service rendered on and after October 1, 2016, proposes a Purchased Gas Cost (PGC) rate of $0.07313 per Therm from $0.038307 per Therm, representing an increase from the currently effective gas cost recovery rate applicable to all firm sales rate schedules of $0.30994 per Therm.Columbia is a public utility and natural gas distribution company which provides retail natural gas sales and transportation services to approximately 423,000 customers in portions of 26 counties of Pennsylvania. (See Joint Settlement Agreement, at 2).The Commission instituted an investigation to determine the lawfulness, justness and reasonableness of the rates proposed in the Section 1307(f) filing and to satisfy the requirements of Sections 1307, 1317 and 1318 of the Public Utility Code (at 66 Pa.C.S.A. §?1307(f); § 1317 and § 1318). On March 9, 2016, the Bureau of Investigation and Enforcement (BIE) filed its Notice of Appearance. On March 22, 2016, the Office of Consumer Advocate (OCA) filed a Notice of Appearance, Formal Complaint and Public Statement at Docket No. C-2016-2535307. On March 29, 2016, the Office of Small Business Advocate (OSBA) filed its Notice of Appearance, Formal Complaint and Public Statement at Docket No. C-2016-2536983. Petitions to Intervene were filed by Columbia Industrial Intervenors (CII) on March 10, 2016; and by Shipley Choice, LLC; AMERIGreen Energy; Interstate Gas Supply, Inc.; and Dominion Retail, Inc. (collectively, the NGS Parties) on March 31, 2016. Thereafter, the presiding officer conducted a prehearing conference on April 7, 2016 at which the following parties were present: OCA, OSBA, BIE, CII, the NGS Parties and the Company. On April 8, 2016, the presiding officer issued the Prehearing Order memorializing the matters discussed, decided and agreed to by the parties during the prehearing conference including the litigation schedule and discovery matters. In addition, the presiding officer consolidated the formal complaints filed by OCA at Docket No. C-2016-2535307 and by OSBA at Docket No. C-2016-2536983, and granted the Petitions to Intervene filed by CII and the NGS Parties. Thereafter, on May 6, 2016, OCA served direct testimony and exhibits on the parties and Columbia served rebuttal testimony and exhibits on May 26, 2016. The presiding officer scheduled the initial hearing to be held in Harrisburg on June 8, 2016 and June 9, 2016, however, prior to the start of the hearing, the parties informed the presiding officer a settlement was reached. Thereafter, the presiding officer suspended the litigation schedule, inter alia, and advised the parties to appear at the scheduled start time on June 8, 2016 in Harrisburg, while the presiding officer would appear via telephone from the Commission’s hearing room in Pittsburgh in order to identify and admit into the hearing record all previously served testimony and exhibits. On June 8, 2016, the presiding officer conducted the hearing with Columbia, BIE, OCA, OSBA, CII and the NGS Parties present. No party appeared at the hearing to oppose the Joint Settlement or the admission of evidence. The parties identified their previously served testimony and exhibits, and moved for its admission into the hearing record. The presiding officer admitted all proposed testimony and exhibits, as listed in the transcript at pages 28 and 29. The parties were given until June 28, 2016 in which to submit a fully executed Joint Settlement Agreement and Statements in Support. On June 28, 2016, the Joint Settlement Agreement (Joint Settlement), including Statements in Support by Columbia, BIE, OSBA and OCA, was filed with the Secretary’s Bureau. Separately, a letter of non-opposition from the NGS Parties was filed with the Secretary’s Bureau on June 28, 2016. On July 12, 2016, the presiding officer issued an Interim Order closing the hearing record. This Recommended Decisionn recommends the Joint Settlement Agreement be adopted.II.DESCRIPTION AND TERMS OF SETTLEMENTIn accordance with Rule 5.231 of the Commission’s Rules of Practice and Procedure, 52 Pa.Code § 5.231, the parties explored the possibility of settlement. As a result of settlement discussions, the parties achieved a settlement in principle under which all issues are resolved. The Joint Petition for Settlement, which is fully executed by Columbia, BIE, OCA and OSBA, consists of 19 pages and Appendices A, B, C and D, which are the Statements in Support of Columbia, BIE, OSBA and OCA, respectively. In Section III, Paragraphs 11 through 32 on Pages 3 to 12, of the Joint Settlement, the settling parties agreed to several proposed findings of fact with citations to the record of admitted evidence. These proposed findings provide the information necessary to support the Joint Settlement and are set forth below in verbatim.11. Columbia’s Exhibit No. 3 lists Federal Energy Regulatory Commission (FERC) proceedings through calendar year 2015 affecting Columbia’s ratepayers. Exhibit No. 3 outlines Columbia’s participation in these FERC proceedings. Columbia has intervened and actively participated in proceedings of the interstate pipelines serving Columbia.Columbia was active in relevant FERC cases involving Columbia Gas Transmission Corporation, L.L.C. (Columbia Transmission), Columbia Gulf Transmission, L.L.C. (Columbia Gulf), Equitrans, L.P. (Equitrans), National Fuel Gas Supply Corporation (National Fuel), Tennessee Gas Pipeline Company, L.L.C. (Tennessee), Texas Eastern Transmission, L.P. (Texas Eastern) and Dominion Transmission Inc. (DTI). (Columbia St. No. 1, pp. 22-25, Columbia Ex. No. 3). Effective July 1, 2015, the pipeline portion of NiSource Inc., Columbia Pipeline Group, was separated from NiSource Inc. Thus, Columbia Transmission and Columbia Gulf are no longer affiliates of Columbia. (Columbia St. No. 1, p. 5).In 2015, Columbia was active before the FERC in rulemakings and policy statements that have the potential to significantly impact Columbia’s efforts to provide reliable gas service at the least cost. (Columbia St. No. 1, pp. 22-25). Columbia has intervened in proceedings of interstate pipelines involved in construction projects in the Marcellus region. (Columbia Ex. No. 5, p. 22). Columbia has also been an active participant in FERC and North American Energy Standards Board (NAESB) proceedings concerning Gas Electric coordination and interstate pipeline modernization incentives. (Columbia Ex. No. 5, p. 25).15. Columbia will continue its policy of active participation in individual pipeline supplier rate and certificate proceedings before the FERC, along with FERC generic type rulemaking and policy proceedings which could have a material impact on Columbia’s costs or operations, as fully described in Columbia Statement No. 1, pp. 22-25.16. Numerous Columbia Transmission facilities are used to transport and store Columbia’s supply purchases. Because Columbia’s local market areas are spread across Pennsylvania and are connected primarily, and in many cases exclusively, to Columbia Transmission facilities, the vast majority of Columbia’s peak day supply is delivered by Columbia Transmission. (Columbia St. No. 1, pp. 12-13). 17. Columbia has full responsibility for purchasing all of its gas supplies directly from producers and marketers. To the extent that affiliated interests offer Columbia gas supplies under competitive terms and conditions, Columbia will consider those supplies like all others in accordance with its policy of purchasing gas supplies from reliable sources at the lowest cost. (Columbia St. No. 1, pp. 12-13; Columbia Ex. No. 8-C). 18. Columbia’s gas purchasing objectives and strategies seek a portfolio of least-cost supply from both Pennsylvania and interstate producers. Columbia also seeks capacity that is flexible and reliable. These efforts will continue. (Columbia St. No. 1, pp. 25, 27-28). 19. Columbia contracts for firm transportation and storage services to meet customers’ requirements in its diverse market areas. (Columbia Ex. No. 5, pp. 10-14; Columbia St. No. 1, pp. 11-12). Columbia’s firm contracts for gas supply provide it with sufficient supply to meet the human needs demand of firm customers under design weather conditions. (Columbia St. No. 1, p. 25). 20. Columbia’s current day design temperature reflects a 6.67% risk level which translates to the capacity necessary to meet firm customer requirements when there is an average temperature of -5°F on the design day. (Columbia St. No. 1, pp. 8-9; Columbia Ex. No. 5, p. 5). 21. Columbia has several contracts for Firm Transportation Service (FTS) with Columbia Transmission. (Columbia Ex. No. 5, pp. 11-12). In 2014, Columbia extended for two years a Columbia Transmission FTS contract having capacity of 13,334 Dth/day. (Columbia Ex. No. 5, p. 11). This contract was revised to reduce the capacity to 10,000 Dth/day effective October 1, 2015. Columbia plans to renew this capacity beyond October 31, 2016. (Columbia Ex. No. 5, pp. 11-12). Columbia also revised another FT contract with Columbia Transmission from 13,332 Dth/day to 11,666 Dth/day effective October 1, 2015. This contract has a termination date of October 31, 2017. (Columbia Ex. No. 5, p. 12). Columbia also created a tiered approach for an FT contract with Columbia Transmission for 90,788 Dth/day. One tier of this contract is for 21,055 Dth/day of capacity. That capacity has been renewed through October 31, 2022. The second tier equals 30,237 Dth of capacity/day, which had a primary termination date of October 31, 2014. Columbia extended this tier through October 31, 2016. Columbia intends to renew this capacity beyond October 31, 2016. (Columbia Ex. No. 5, p. 12). The third tier equals 39,996 Dth/day, and has a primary termination date of October 31, 2019. (Columbia Ex. No. 5, p. 12).22. Columbia holds a contract for Firm Storage Service (FSS) with Columbia Transmission and a contract for Storage Service Transportation (SST). Columbia uses the FSS service to provide daily injection and withdrawal capacity into or out of storage, along with firm peak day deliverability and seasonal storage capacity. The SST capacity provides firm transportation of storage volumes from storage fields to Columbia’s city gates, and also transports flowing gas supplies to fill storage during the summer. The use of FSS in conjunction with SST provides Columbia with its primary daily no-notice balancing service. (Columbia St. No. 1, p. 12). 23. In addition to its contracts for transportation and storage from Columbia Transmission, Columbia has access to various other pipelines. These arrangements currently include the following:(a)Columbia has a total of five firm transportation contracts and three storage contracts with DTI. Two of the transportation contracts move storage supplies from DTI’s storage fields to Columbia’s city gates. Columbia utilizes these DTI contracts to provide supplies to its customers in Beaver County through its Darlington interconnect and in Cranberry Township through its Warrendale interconnect. The first transportation contract provides 6,000 Dth/day. The second provides 3,000 Dth/day November through March and 2,000 Dth/day April through October. The associated Columbia storage contract with DTI provides Columbia with 9,000 Dth/day of peak day deliverability and approximately 941 MDth of seasonal supply. (Columbia St. No. 1, p. 14). (b)Columbia acquired additional storage and transportation capacity on DTI, effective April 1, 2014, to provide Elective Balancing Service (EBS) to General Distribution service customers and peak day service to sales and CHOICE customers in the State College markets. This storage contract provides for daily withdrawal rights of 4,800 Dth/day and a seasonal quantity of 240,000 Dth. The firm transportation contract has 4,800 Dth/day of capacity. (Columbia Ex. No. 5, p. 13; Columbia St. No. 1, pp. 14-15).(c)Effective May 1, 2015, Columbia acquired three additional capacity contracts with DTI. One contract is for storage with a maximum daily quantity of 15,000 Dth and seasonal quantity of 930,000 Dth. An associated FT contract provides 15,000 Dth/day of capacity to move gas from and into storage. The third is an FT contract for 5,000 Dth/day. All of this capacity is used to serve the State College market. The capacity facilitates abandonment of Columbia’s Snowshoe Lateral. (Columbia St. No. 1, pp. 18-19; Columbia St. No. 1-R, p. 10).(d)Columbia also contracts for firm transportation and storage service on Equitrans. Columbia has a storage contract and associated FTS contract daily delivery and storage capacity that provide a peak day deliverability capacity of 14,348 Dth and a seasonal capacity of 1,500,000 Dth. This capacity, in combination with DTI capacity identified above, is used to provide EBS to General Distribution service customers and peak day service to sales and CHOICE customers. (Columbia St. No. 1, p. 15). (e)Columbia currently contracts for firm transportation service with Tennessee totaling 36,100 Dth/day. Effective October 31, 2016, Columbia is terminating one of the Tennessee contracts, with 12,500 Dth/day capacity. When the gas supply available through Tennessee is not needed to serve daily demand in Columbia markets that are directly served by Tennessee, Columbia can direct the supply to interconnections with Columbia Transmission for injection into storage or to serve other local markets, thereby increasing Columbia’s operating flexibility. (Columbia St. No. 1, pp. 15-16, 18). (f)Columbia also has contracts for long-haul firm transportation service with Texas Eastern, totaling 22,335 Dth/day. A total of 19,253 Dth/day is required to serve peak day firm customer demand in Columbia markets directly connected to Texas Eastern, while 3,082 Dth/day must be delivered to Columbia Transmission as an upstream supply in order to meet peak day demand in Columbia markets served by Columbia Transmission. Similar to operations on Tennessee, on days when the 19,253 Dth/day delivered directly to Columbia cannot be absorbed by those markets, Columbia can divert that supply to secondary delivery points off Texas Eastern or to Texas Eastern interconnects with Columbia Transmission for injection into storage or delivery to other Columbia markets served by Columbia Transmission. Columbia also contracts for 10,000 Dth/day of winter season, market-area firm backhaul transportation capacity. Columbia utilizes this capacity to satisfy cold weather requirements behind the city gates connected to Texas Eastern. (Columbia St. No. 1, pp. 16-17). (g)Columbia also contracts for 4,281 Dth/day of city gate capacity under the FTS rate schedule of National Fuel. This capacity provides service to Columbia’s Warren market area. (Columbia St. No. 1, p. 17). 24. In order for Columbia to meet its objective of securing and delivering competitively-priced, reliable gas supplies, Columbia has developed a portfolio of gas purchase contracts, which can include long-term, short-term and spot contracts, that have flexibility both to meet reliability standards and be able to take advantage of low price opportunities where available and operationally feasible. (Columbia St. No. 1, pp. 26-27).25. Columbia maintains a program for purchasing local production. In addition to local gas purchases delivered directly into Columbia’s system, Columbia purchased Appalachian pool gas delivered by producers into Columbia Transmission’s system and redelivered to Columbia under transportation agreements. Although it is certain that Pennsylvania production enters the Appalachian production pools, once the gas is part of pool supplies it is commingled with other sources of supply. Thus, the portion of these supplies coming from Pennsylvania production is not known. (Columbia St. No. 1, pp. 30-31). 26. Columbia annually submits a Request For Proposal (RFP) to numerous suppliers identified as capable and willing to provide firm gas supplies to Columbia. Columbia requests proposals for supplies with varying term lengths, nomination flexibility and innovative pricing options. (Columbia St. No. 1, p. 27-28). 27. Columbia’s gas purchases were a least cost supply mix during the historic reconciliation period, consistent with reliable service. (Columbia Ex. No. 8-C). 28. In the twelve months ended January 31, 2016, Columbia did not shut in or withhold from the market any gas supply or transportation or storage capacity other than for the purposes of retaining sufficient supply to assure reliable supply and balancing services under colder than normal conditions. (Columbia Ex. No. 8-E).29. Neither Columbia nor its affiliates withheld any gas from the market or caused any gas supplies to be withheld from the market that should have been utilized as part of a least-cost fuel procurement policy. (Columbia Ex. No. 8-E.) 30. Columbia retains firm contractual rights to all storage, other upstream pipeline and capacity, if any, and all capacity assignments made to Natural Gas Suppliers (NGSs) participating in Columbia’s Customer Choice program are made on a recallable basis. This allows Columbia to maintain service in the event an NGS fails to deliver supplies under Columbia’s Customer Choice Program, which is consistent with Columbia’s obligations as the SOLR. (Columbia St. No. 1, pp. 37-38). 31. The Snowshoe Lateral is a 21-mile, 8-inch steel pipeline extending from an interconnection with Columbia Transmission near Snowshoe, PA, to an interconnection with a 12-inch Columbia pipeline near Pleasant Gap, PA. Columbia has utilized the Snowshoe Lateral to provide a majority of the supplies used to serve customers in the State College market area. The pipeline is nearly 60 years old and was constructed by a predecessor of Columbia. Columbia had initially decided, in 2014, to replace the Snowshoe Lateral because of its age, lack of complete documentation to comply with the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, and absence of available alternative capacity sufficient to serve the State College market at that time. The estimated cost for replacement was $53 million. (Columbia St. No. 1-R, pp. 6-8).32. The availability of DTI capacity in 2015 caused Columbia to re-assess the decision to replace the Snowshoe Lateral. The acquisition of 20,000 Dth/day of capacity from DTI would allow Columbia to abandon a 54,200 foot section of the Snowshoe Lateral, thereby saving $36.9 million in capital investment. (Columbia St. No. 2-R, pp. 9-10).In Section IV, Paragraph 33 of the Joint Settlement, the parties express their agreement with respect to five separate issues, as provided in Section IV, Paragraphs 34 through 38 on Pages 12 and 13, as stated below in verbatim: (1)?Natural Gas Supply Rates; (2) Treatment of Interstate Pipeline Penalty Credits; (3) Lost and Unaccounted for Gas; (4) Gas Exchanges with Affiliates; and (5) DTI Capacity. general34. Columbia’s 2016 PGC filing is approved as filed, subject to the additional items set forth below.treatment of interstate pipeline penalty credits35. Columbia has received approximately $808,000 in penalty credits in 2015 from interstate pipeline suppliers. Columbia has pending before the Commission at Docket No. P-2015-2465533 a Petition to use a portion of these penalty credits towards its Hardship Fund. The Petitioners take no position here with respect to that pending Petition. The Petitioners agree that no determination is being made in this proceeding as to whether such penalty credits are “gas costs” for purposes of Section 1307(f) of the Public Utility Code, and Petitioners reserve the right to contend for different treatment of any penalty credits received by Columbia in the event the Commission were to deny Columbia’s Petition, or with respect to penalty credits received by Columbia in the future.lost and unaccounted for gas and retainage36. Columbia’s general retainage rate for transportation customers will be set at 1.1% effective January 1, 2017, based upon a three-year average of Lost and Unaccounted for Gas (LUFG) and Company use gas for the period ended August 31, 2015. The Petitioners acknowledge that Columbia LUFG percentage for the twelve months ended August 31, 2015 is in compliance with the Commission’s regulations at 52 Pa. Code §?59.111(c)(1). Columbia commits to continue its various efforts to reduce LUFG.gas exchanges with affiliates37. The Petitioners do not oppose the three exchange transactions identified by OCA and undertaken by Columbia with its distribution company affiliates. Columbia agrees to identify any affiliate exchange, capacity release or off system sale transactions in its 1307(f) filings on an on-going basis.DTI Capacity38. The Petitioners do not oppose Columbia’s acquisition of 20,000 Dth/day of additional DTI capacity acquired to serve the State College, PA market area.In Section V, Paragraphs 39 through 44 on Pages 13 to 16 of the Joint Settlement, the parties express their agreement with respect to three separate issues, as stated below in verbatim: (1) Standards and Findings; (2) Historic Reconciliation Period Standards; and (3) Projected and Interim Period Findings. STANDARDS AND FINDINGs39.This proceeding is a consolidation of two reviews that the Commission is required to undertake pursuant to Sections 1307 and 1318 of the Public Utility Code. Pursuant to Section 1307(f) of the Public Utility Code, 66 Pa.C.S. § 1307(f), the Commission must determine whether Columbia has met the standards of Section 1318, 66 Pa.C.S. § 1318, with regard to the gas costs Columbia has incurred during a historic 12-month period. The historic period reviewed in the proceeding is the 12 month reconciliation period ended January 31, 2016. In addition, because Columbia has filed a tariff proposing a new rate reflecting a change in its natural gas costs, the Commission must determine whether the specific findings of Section 1318 can be made with regard to the period that rates will be in effect in the Application Period. This finding is a condition precedent to the Commission’s approval of the Company’s proposed rates. 66 Pa.C.S. § 1318. It is to be noted that the provisions of Section 1318(a) are applicable to all gas utilities that recover their gas costs pursuant to Section 1307(f). The new tariff rate is intended to become effective October 1, 2016.40.Prior to July 1, 2015, Columbia Pipeline Group was affiliated with Columbia. Because Columbia purchased various transportation and storage services from Columbia Transmission and Columbia Gulf during the historic period that are necessary to serve Columbia’s diverse local market areas, it is also necessary that the Commission make the findings under Section 1318(b) concerning purchases from affiliates. Historic Reconciliation Period Standards.41.With respect to Columbia’s gas purchases and gas purchasing practices during the twelve-month historic reconciliation period ended January 31, 2016, it is requested that the Commission find that Columbia has met the standards set out in Section 1318 of the Public Utility Code, 66 Pa.C.S. § 1318, and required by Section 1307(f)(5) of the Public Utility Code, 66 Pa.C.S. § 1307(f)(5), as to all actual purchased gas costs in the historic period. It is requested that the Commission find, pursuant to Section 1307(f)(5) of the Public Utility Code, and based upon the evidence presented by the Petitioners in this case, that, during the twelve months ended January 31, 2016: (1) Columbia met the requirements of Section 1318(a) of the Public Utility Code by pursuing a least-cost fuel procurement policy, consistent with its obligation to provide safe, adequate and reliable service to its customers; and (2) Columbia met the requirements of Section 1318(b) of the Public Utility Code relating to its purchases of gas, transportation and storage services from affiliates.Projected and Interim Period Findings.42. With respect to the twelve-month period beginning October 1, 2016, which is the period of time during which the proposed rates contained in this Settlement would be in effect, it is requested that the Commission make the findings under Section 1318 of the Public Utility Code, including Sections 1318(a)(1) through (a)(4), and 1318(b)(1) through (b)(3), based upon information presently available and based upon evidence of record in this proceeding concerning Columbia’s purchasing policies.43. The Petitioners agree that, based upon evidence of record in this proceeding concerning Columbia’s projected gas purchases and gas purchasing policies, it appears that Columbia’s projected gas purchases and projected gas purchasing policies will comply with the standards of Section 1318 of the Public Utility Code. Nevertheless, it is expressly understood and agreed that the findings relating to the rate to become effective October 1, 2016, are made solely for the purpose of setting prospective rates that shall be subject to the standards of Section 1318, and further review in an appropriate future proceeding. This Section of the Settlement is not intended to limit or prevent in any way present or future complainants from reviewing, after such projected gas purchases have been made and gas purchasing practices have been implemented, whether Columbia’s gas purchases and gas purchasing practices have, in fact, complied with the standards of Section 1318. If, in an appropriate future proceeding, gas purchases and gas purchasing practices relating to the period October 1, 2016, through September 30, 2017, are challenged, the Commission’s findings in this Section of the Settlement shall pose no bar to the examination of such purchases and practices including, but not limited to, disallowance of, or reductions to, such costs during the one-year period commencing October 1, 2016.44.The Petitioners agree that future examination of the gas costs relating to the period February 1, 2016, through September 30, 2016, to determine whether Columbia’s experienced and projected gas purchases and gas purchasing practices complied with the standards set forth in Section 1318 of the Public Utility Code shall be permitted and that the Commission’s adoption of the findings under this Section of the Settlement shall not be construed to limit or prevent any disallowance or reduction of such costs.III.DISCUSSIONThe issues specifically addressed by Columbia Gas and OCA in the Statements in Support were: (1) treatment of Interstate Pipeline Penalty Credits; (2) Lost and Unaccounted for Gas and Retainage; (3) Gas Exchanges with Affiliates; and (4) DTI Capacity.A.Treatment of Interstate Pipeline Penalty CreditsOCA raised the issue concerning how Columbia treated the interstate pipeline penalty credits received and, specifically, how Columbia described the basis for receipt of the credits. (OCA St. No. 1, p. 8). Columbia explained that, when shippers on interstate pipelines flow more gas onto the pipeline than they are entitled, the interstate pipeline imposes a penalty. However, the interstate pipelines are not permitted to retain the credits, but must distribute the penalty amounts to non-offending shippers. (Columbia St. No. 2, p. 23; OCA St. No. 1, pp. 8-9). As a result, Columbia received approximately $808,000 in penalty credits in 2015 from interstate pipelines. (Columbia St. No. 2, p. 23; OCA St. No. 1, p. 9), and Columbia filed a request with the Commission to use the residential portion of penalty credits to help fund its Hardship Fund for low-income customers. (Columbia St. No. 2, pp. 23-24; OCA St. No. 1, p. 9).OCA’s witness agreed with Columbia’s proposal to use interstate pipeline penalty credits toward its Hardship Fund (OCA St. No. 2, p. 9), but objected to Columbia’s statement that penalty credit revenues “do not correspond to charges reflected in the interstate pipelines’ rates.” OCA contended the credits do not correspond to gas costs the Company previously passed through or will pass through in the future to its customers. (Columbia St. No. 2, p. 23; OCA St. No. 2, p. 10). OCA asserted that penalty credits do “correspond” to gas costs paid by PGC customers because the cost of firm transportation contracts, used to allocate penalty credits, are charged as demand costs to customers. (OCA St. No. 1, pp. 10-11.) In rebuttal, Columbia reaffirmed its definition of penalty credits and distinguished penalty credits from traditional pipeline refunds, and explained that a traditional pipeline refund results when an interstate pipeline is permitted to implement increased rates subject to refund. Those increased rates are reflected in Columbia’s PGC calculations. When FERC issues a final order on the requested increase, and if the approved rates are less than the filed-for rates, the interstate pipeline must return the difference to its customers, such as Columbia, and Columbia includes the refund amount in PGC rates. (Columbia St. No. 2R, pp. 1-2). A penalty credit, on the other hand, is not a return of monies previously paid by Columbia and its PGC customers. Instead, the penalty credits result from the failure of third party shippers to comply with the interstate pipelines’ tariffs, and Columbia receives the penalty credits because Columbia remained in compliance with the pipelines’ requirements. (Columbia St. No. 2R, pp. 2-3). Columbia argued there was no reason to determine the status of interstate pipeline penalty credits in this case, because the treatment of pending pipeline credits was before the Commission in another proceeding. (Columbia St. No. 2R, p. 3).Columbia asserts the parties recognize that no determination of the status of interstate pipeline penalty credits is being made in this proceeding, and the parties further reserve the right to contend for different treatment of any interstate pipeline penalty credits if the Commission denies Columbia’s pending Petition, or with respect to penalty credits received by Columbia in the future. (Settlement ? 35).OCA agreed the parties have reserved their right to argue for different treatment of the penalty credits, in the event the Commission does not approve Columbia’s Petition seeking approval to apply these penalty credits to its Hardship Fund at Docket No. P-2015-2465533. OCA avers this settlement provision is a reasonable resolution to the issue it raised regarding the penalty credits because litigating how these penalty credits should be applied in the event the Commission denies Columbia’s Petition is premature, but the Joint Settlement preserves the parties’ rights to address the issue in the future if necessary. B.Lost and Unaccounted For Gas and Retainage OCA raised concerns about Columbia’s Lost and Unaccounted for Gas (LUFG) experience and the Retainage Rate Columbia proposed to become effective January 1, 2017. OCA noted the Retainage Rate will increase from 0.7 % to 1.1% effective January 1, 2017. (OCA St. No. 1, pp. 11-12). Columbia explained its LUFG rate for the twelve months ended August 31, 2015 was 2.2%, which increased the 3-year average to 1.1%. (Columbia St. No. 2R, p. 3). Columbia noted this percentage was well below the current metric of a 4.5% LUFG rate established by the Commission at 52 Pa.Code §?59.14(c)(1), and this percentage was also well below the Commission’s Year 5 metric of 3% contained in that same regulation. (Columbia St. No. 2R, p. 4). Columbia explained that, at low levels of LUFG, it can be difficult to pinpoint exact causes for year-to-year variances. While some causes can be traced to differences in the amount of leaks and breaks in a year, other possible causes for these variances include:The timing of meter readings by interstate pipelines and readings of customers’ meters which can create small mismatches in UFG data between years, and2) The distribution main pressures, which can increase or decrease the amount of gas that is held in the Company’s mains, causing changes in LUFG because the gas has been measured at the pipeline but not yet measured at distribution meters.(Columbia St. No. 2R, pp. 4-5). Columbia opined the most likely cause for the increase could be tied to Columbia Transmission’s efforts to change out its meters to reduce high LUFG on its system. (Columbia St. No. 2R, p. 5). As Columbia Transmission replaced slow reading meters with more accurate meters, it registered more gas flowing through the city-gate meters. Columbia argued that much of the difference was not due to increased LUFG on its distribution system, but instead was due to understated measurement of gas deliveries into Columbia’s system in prior years. (Columbia St. No. 2R, p. 5). In the Joint Settlement, the parties recognize OCA’s request for further information was satisfied, and specifically accept that the Retainage Rate effective January 1, 2017 will be set at 1.1%, and that Columbia’s LUFG for the twelve months ended August 31, 2015 complies with the Commission’s regulations at 52 Pa.Code §?59.111(c)(1). The Joint Settlement also contains Columbia’s commitment to continue its efforts to reduce LUFG. (Settlement ? 36). With the filing of the Joint Settlement, OCA agrees the Company explained why its retainage rate increased between 2014 and 2015, and avers its concerns have been satisfied. Since no party objects to the proposed retainage rate, OCA avers the settlement provision (Settlement ? 36) is in the public interest for Columbia’s proposed PGC rate to be approved as filed.C. Gas Exchanges with AffiliatesOCA expressed concerns and sought further information regarding four exchange transactions between Columbia and three of its distribution company affiliates: Columbia Gas of Maryland; Columbia Gas of Virginia; and Columbia Gas of Ohio. (OCA St. No. 1, p. 13). Columbia demonstrated how the four exchanges were undertaken and how the four exchanges benefited Columbia’s customers.On February 15, 2015 and February 19, 2015, Columbia provided 3,500 Dth and 3,000 Dth, respectively, to Columbia Gas of Maryland, Inc. (CMD), with the gas returned to Columbia about one week later. Columbia was paid 5? per Dth for the exchanges, or a total of $325. CMD sought the exchange gas in order to temporarily meet its firm requirements. (OCA Ex. No. MW-2, p. 2; Columbia St. No. 1R, p. 4). The amount paid was consistent with the historical range of rates of 3? to 5? per Dth for exchanges between Columbia affiliates. (Columbia St. No. 1R, p. 5). Columbia explained that while these exchanges were undertaken on cold days, neither day was close to Design conditions and, therefore, Columbia had adequate supplies to satisfy this small request. (Columbia St. No. 1R, p. 2). Columbia further explained that the small volume of the exchanges had no effect on operations for transportation customers. (OCA St. No. 1R, p. 3). PGC customers received 75% of the net proceeds under Columbia’s Unified Sharing Mechanism. (Columbia St. No. 1R, p. 2).In October of 2015, Columbia undertook an exchange in which it received gas from Columbia Gas of Virginia (CGV). Columbia was paid 3? per Dth for the exchange. CGV requested the exchange because it had too much gas in storage and was at risk of being penalized. (OCA Ex. No. MW-2, p. 2; Columbia St. No. 1R, p. 4). Columbia’s PGC customers also received 75% of the net proceeds from this exchange.In early 2016, Columbia undertook an exchange in which it delivered gas to Columbia Gas of Ohio, Inc. (COH). Columbia was in an excess gas position, due to warmer than normal conditions this past winter. Columbia had already cut back incremental purchases, but still faced the risk of being penalized for excess gas in storage. (Columbia St. No. 1R, p. 4).The exchange, undertaken at a cost of 3? per Dth, was the best cost option to respond to this unusual circumstance. If Columbia had done nothing, it risked confiscation of gas in storage, at a cost of over $2.00 per Dth. (Columbia St. No. 1R, p. 5). Making an operational off-system sale also was not a least cost option, as the cost of gas would have been about $2.14 per Dth at a time when gas was selling for a price of about $1.36 per Dth. Thus, an operational off-system sale would have cost customers about $0.77 per Dth. In addition, because of interstate pipeline delivery restrictions, Columbia could not complete an off-system sale. (Columbia St. No. 1R, p. 5). Columbia was able to undertake an exchange with COH only because they shared a common Market Area on the Columbia Transmission system. (Columbia St. No. 1R, p. 5).In the Joint Settlement, the parties agreed not to oppose any of the exchange transactions. Columbia agreed to identify affiliate exchange, capacity release or off-system sale transactions with affiliates in future PGC filings. (Settlement ? 37). Columbia provided evidence the exchanges were reasonable, and that it has committed to further reporting of similar affiliate transactions in the future, to facilitate parties’ review of any such transactions.OCA agreed the Company explained these gas exchanges, and averred its concerns were satisfied. Since no party objected to the three exchange transactions identified by OCA, OCA averred the settlement provision (Settlement ? 37) is in the public interest for Columbia’s proposed PGC rate to be approved as filed. OCA pointed out Columbia agreed to identify any affiliate exchange, capacity release or off system sale transactions in its 1307(f) filings on an on-going basis, which practice will aid in OCA’s examination of the Company’s future 1307(f) proceedings, and ensure that such affiliate transactions are reviewed appropriately. D.DTI CapacityThrough direct testimony, Columbia explained it added three new contracts with Dominion Transmission, Inc. (DTI) which contracts provide capacity to serve the State College, Pennsylvania area. Columbia explained this capacity will facilitate Columbia’s abandonment of a portion of its Snowshoe Lateral, which currently interconnects with Columbia Transmission’s facilities near Snowshoe, Pennsylvania and extends to other Columbia facilities near Pleasant Gap, Pennsylvania. Abandonment would save Columbia and its customers over $36 million in replacement costs. (Columbia St. No. 1, pp. 18-19).Through direct testimony, OCA stated additional information was needed to assess whether the acquisition of this additional capacity was consistent with least-cost planning. (OCA St. No. 1, p. 16). Columbia provided additional information regarding the acquisition of the additional DTI capacity in the Company’s rebuttal testimony. Columbia explained the addition of 20,000 Dth/day of DTI capacity is necessary to serve the State College market following abandonment of a portion of the Snowshoe Lateral and that acquisition of the DTI capacity is consistent with least cost planning. (Columbia St. No. 1R, pp. 9-11).The Snowshoe Lateral is an approximately 21-mile long, 8-inch steel pipeline placed into service by Columbia’s predecessor in 1958. (Columbia St. No. 1R, pp. 6). Columbia traditionally used the Snowshoe Lateral to deliver the majority of gas supplies used to serve its customers in the State College market area. (Columbia St. No. 1R, pp. 6-7). However, the Company can also receive gas supplies for the State College market through interconnections with Texas Eastern Transmission Corporation and DTI. (Columbia St. No. 1R, p. 7). Columbia initially decided to replace the Snowshoe Lateral after discovering that the Company lacked adequate pressure test records for the pipeline as required by Section 23 of the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011. Due to concerns that the aging line would not be able to withstand hydrostatic testing and the significant costs associated with performing hydrostatic testing on the line (over $14 million), Columbia determined the Snowshoe Lateral should be replaced. (Columbia St. No. 1R, pp. 7-8).Columbia subsequently reevaluated its decision to replace the Snowshoe Lateral after learning that around 20,000 Dth/day of DTI capacity could be made available to Columbia at Pleasant Gap. Columbia became aware of the potential available capacity during discussions between DTI and the Supply Development Group in NiSource’s Corporate Services Company concerning the availability of capacity to serve Columbia’s affiliated local distribution companies in Maryland and Virginia. (Columbia St. No. 1R, p. 9). Obtaining 20,000 Dth/day of capacity from DTI would allow Columbia to abandon a 54,200-foot middle section of the Snowshoe Lateral and replace the upper and lower sections of the lateral with 6-inch and 8-inch plastic pipe, respectively, for a total cost of approximately $16.1 million as opposed to replacing the entire Snowshoe Lateral for approximately $53 million. (Columbia St. No. 1R, p. 9). The addition of the DTI capacity was essential to Columbia’s decision to sever a portion of the Snowshoe Lateral. (Columbia St. No. 1R, pp. 9-10). Because any potential capacity at Pleasant Gap would be replacing Columbia Gas Transmission, LLC (TCO) no-notice service delivered via the Snowshoe Lateral, the Company required no-notice capabilities from DTI to enable it to serve the temperature-sensitive State College market. The Company engaged in extensive discussions with DTI to arrive at a combination of flow through and storage service to meet the Company’s no-notice service requirements. (Columbia St. No. 1R, p. 10). The Company uses Requests for Proposal (RFPs), as appropriate, for term purchases of commodity supplies and for requests of replacement offers on non-operationally required capacity. However, an RFP was not a viable option to obtain the required capacity herein. RFPs are not used in circumstances, such as the addition of the new DTI contracts, where the acquisition of the DTI capacity was operationally driven by the need to obtain a replacement for the TCO no-notice service previously delivered via the Snowshoe Lateral. (Columbia St. No. 1R, p. 6). An RFP does not allow for the type of cooperative discussion necessary to ensure that Columbia’s no-notice service requirements are met. Since the Company requires no-notice service at DTI Pleasant Gap to replace the equivalent service that would be lost if the Snowshoe Lateral were severed, the only way to obtain such service on a guaranteed basis was to contract directly with DTI. (Columbia St. No. 1R, p. 10). Acquisition of the additional DTI capacity is in the economic interest of Columbia’s customers. If not for the addition of 20,000 Dth/day of DTI capacity, it would have been necessary for Columbia to make a $53 million capital investment to replace the Snowshoe Lateral. (Columbia St. No. 1R, pp. 9-10). In addition, the annual demand costs for the three new DTI contracts total approximately $1,495,800 while the annual cost of service on a net $36.9 million capital investment to replace the Snowshoe Lateral would be approximately $4.9 million annually. (Columbia St. No. 1R, pp. 9-10). In addition to the capital cost and cost of service savings, the annual demand costs on DTI are less expensive than on TCO by approximately $280,000 and the cost of gas delivered on DTI has been less expensive than on TCO for the past 3 years. (Columbia St. No. 1R, p. 11). Through settlement, the petitioners agreed not to oppose Columbia’s acquisition of an additional 20,000 Dth/day of DTI capacity to serve the State College market area. (Settlement ? 38). The foregoing settlement provision is in the public interest and should be approved. Columbia demonstrated that its acquisition of 20,000 Dth/day of DTI capacity will save customers over $36 million in replacement costs by facilitating the abandonment of the Snowshoe Lateral and the addition of the three new DTI contracts is consistent with least cost planning. OCA agrees the Company explained how these new contracts were consistent with least cost planning objectives despite not being selected using the RFP process. (CPA 1R at 6-12). OCA avers its concerns have been satisfied. Since no party objects to the three exchange transactions identified by OCA, OCA avers the settlement provision (Settlement ? 38) is in the public interest. E. BIE’s PositionAlthough BIE did not speak directly to the four enumerated issues, BIE did aver through its Statement in Support that BIE conducted a thorough review of Columbia’s filing and supporting information, discovery responses and submitted filing data, and contributed to the discussions amongst the parties during settlement talks. BIE specifically represents the agreement reflects adherence to the proper regulatory standards and contains adequate protections for ratepayers. BIE acknowledges that the natural gas costs incurred by Columbia during the historic period were done so under adherence to a least cost fuel procurement policy. A least cost fuel procurement policy protects ratepayers from unnecessary and imprudent gas costs and prevents Columbia from making a profit on gas supplies provided to its Purchased Gas Cost customers. BIE averred that line-by-line identification of the ultimate resolution of every potential issue is not necessary, because the Joint Settlement maintains the proper balance of the interests of all parties. Lastly, BIE contends the Joint Settlement is in the public interest because the provisions adequately protect the interests of all affected parties, including the signatories, and BIE is satisfied the provisions and data contained in Columbia’s 1307(f) filings accurately support the finding that the purchased gas costs and Columbia’s practices adequately protect the public interest. F. OSBA’s PositionSimilarly, although OSBA did not speak directly to the four enumerated issues, OSBA represented through its Statement in Support that, after careful review of the filing and a review of numerous sets of discovery materials, Columbia’s filed claims for unaccounted-for gas costs, its proposal for gas retainage rates for transportation customers, and its design day demand forecasting method were all reasonable with respect to the expected impacts on small business customers. OSBA further averred the Company’s upstream capacity was consistent with the aforementioned design day demand forecast and, for these reasons, OSBA did not deem it necessary to submit testimony in this proceeding. OSBA contended the Joint Settlement avoids the litigation of complex, competing proposals, serves judicial efficiency, allows OSBA to more efficiently employ its own resources to other areas, and saves the significant costs of further and more extended administrative proceedings, which costs would be borne not only by the Joint Petitioners, but ultimately by Columbia’s customers as well. G. The NGS Parties’ PositionThe NGS Parties were not signatories to the Joint Settlement and did not file a Statement in Support, however, the NGS Parties represented they were not opposed to the Settlement as being in the public interest.IV.RECOMMENDATIONThe Commission encourages parties in contested on-the-record proceedings to settle cases. Settlements eliminate the time, effort and expense of litigating a matter to its ultimate conclusion, which may entail review of the Commission’s decision by the appellate courts of Pennsylvania. Such savings benefit not only the individual parties, but also the Commission and all ratepayers of a utility, who otherwise may have to bear the financial burden such litigation necessarily entails.By definition, a “settlement” reflects a compromise of the positions the parties of interest held, which arguably fosters and promotes the public interest. When active parties in a proceeding reach a settlement, the principal issue for Commission consideration is whether the agreement reached suits the public interest. In their supporting statements, Columbia, BIE, OSBA and OCA conclude, after extensive discovery and discussion, this Joint Settlement resolves the issues in this case, fairly balances the interests of Columbia and its ratepayers, is in the public interest, is consistent with the requirements of Sections 1307 and 1318 of the Public Utility Code, and should be approved. I recommend the Commission accept Columbia’s 1307(f) filing as augmented and modified by the Joint Settlement. This recommendation is based in large part upon the representations made by the statutory advocates averring the Settlement is in the interests of the constituencies that they represent. In sum, the parties thoroughly investigated Columbia’s PGC filing through discovery and the submission of testimony. Columbia addressed the contested issues through the specific provisions of the Joint Settlement and all of the issues noted by the parties are resolved with the additional information the Company provided. That information showed Columbia has engaged in least cost policies to procure natural gas for its customers. I recommend the Commission approve Columbia’s § 1307(f) filing because this Joint Settlement constitutes a fair, just and reasonable resolution of the Commission’s investigation for the reasons identified and discussed by the parties above. Therefore, the Settlement is in the public interest and should be approved.V.CONCLUSIONS OF LAWThe Commission has jurisdiction over the subject matter and the parties to this proceeding. 66 Pa.C.S.A. §§ 501, et seq.There is sufficient evidence in the record to make the findings required by Section 1318 of the Public Utility Code. 66 Pa.C.S.A. § 1318.Columbia Gas of Pennsylvania, Inc. is pursuing a least cost fuel procurement policy during the relevant time period consistent with its obligation to provide safe, adequate and reliable service to its customers in compliance with Section 1318 of the Public Utility Code, 66 Pa.C.S.A. § 1318.Columbia Gas of Pennsylvania, Inc.’s rates for purchased gas costs, as the settling parties have agreed upon in this proceeding, during the relevant time period, are just and reasonable and in compliance with Section 1318 of the Public Utility Code, 66 Pa.C.S.A. § 1318.Columbia Gas of Pennsylvania, Inc. has fully and vigorously represented the interests of its ratepayers in proceedings before the Federal Energy Regulatory Commission and other relevant non-PUC proceedings during the relevant time period in compliance with Section 1318(a)(1) of the Public Utility Code, 66 Pa.C.S.A. § 1318(a)(1).Columbia Gas of Pennsylvania, Inc. has taken all prudent steps necessary to negotiate favorable gas supply contracts and to relieve itself or alleviate the impact from terms in existing contracts with its gas suppliers, which are or may be adverse to the interests of its ratepayers, during the relevant time period in compliance with Section 1318(a)(2) of the Public Utility Code, 66 Pa.C.S.A. § 1318(a)(2).Columbia Gas of Pennsylvania, Inc. has taken all prudent steps necessary during the relevant time period to obtain lower cost gas supplies on both short-term and long-term bases both within and outside the Commonwealth, including the use of gas transportation arrangements with pipelines and other distribution companies in compliance with Section 1318(a)(3) of the Public Utility Code, 66 Pa.C.S.A. § 1318(a)(3).Columbia Gas of Pennsylvania, Inc. has not withheld from the market or caused to be withheld from the market during the relevant time period any gas supplies which should have been used as part of a least cost fuel procurement policy in compliance with Section 1318(a)(4) of the Public Utility Code, 66 Pa.C.S.A. § 1318(a)(4).Columbia Gas of Pennsylvania, Inc. has fully and vigorously attempted to obtain less costly gas supplies on both short-term and long-term bases from nonaffiliated interests during the relevant time period in compliance with Section 1318(b)(1) of the Public Utility Code, 66 Pa.C.S.A. § 1318(b)(1).Columbia Gas of Pennsylvania, Inc.’s contracts for the purchase of gas from any affiliated interest during the relevant time period are consistent with a least cost fuel procurement policy in compliance with Section 1318(b)(2) of the Public Utility Code, 66 Pa.C.S.A. § 1318(b)(2).Neither Columbia Gas of Pennsylvania, Inc. nor any affiliated interest during the relevant time period has withheld from the market any gas supplies, which should have been used as part of a least cost fuel procurement policy in compliance with Section 1318(b)(3) of the Public Utility Code, 66 Pa.C.S.A. § 1318(b)(3).The Joint Petition for Settlement of the Rate Investigation pursuant to 66?Pa.C.S.A. § 1307(f), that Columbia Gas of Pennsylvania, Inc., the Commission’s Bureau of Investigation and Enforcement, the Office of Consumer Advocate and the Office of Small Business Advocate have executed and submitted at this docket, is in the public interest. VI.ORDERTHEREFORE,IT IS RECOMMENDED:That the Joint Petition for Settlement of the Rate Investigation pursuant to 66?Pa.C.S.A. § 1307(f), that Columbia Gas of Pennsylvania, Inc., the Commission’s Bureau of Investigation and Enforcement, the Office of Consumer Advocate and the Office of Small Business Advocate have executed and filed at Docket No. R-2016-2531807, be approved. That Columbia Gas of Pennsylvania, Inc. be permitted to file a tariff supplement, on at least one day’s notice to the Commission, containing changes in rates to provide for the recovery of its costs of purchased gas, consistent with the terms and conditions of the Joint Petition for Settlement of the Rate Investigation pursuant to 66 Pa.C.S.A. § 1307(f).That the formal complaints of the Office of Consumer Advocate and the Office of Small Business Advocate at Docket Nos. C-2016-2535307 and C-2016-2536983, respectively, be marked satisfied.That Columbia Gas of Pennsylvania, Inc., the Commission’s Bureau of Investigation and Enforcement, the Office of Consumer Advocate and the Office of Small Business Advocate be ordered to comply with the terms and conditions of the Joint Petition for Settlement of the Rate Investigation pursuant to 66 Pa.C.S.A. § 1307(f) executed and submitted in this proceeding as though each term and condition stated therein had been the subject of an individual ordering paragraph.That upon the filing of a tariff supplement by Columbia Gas of Pennsylvania, Inc. acceptable to the Commission as conforming with this Order and the Joint Petition for Settlement of the Rate Investigation pursuant to 66 Pa.C.S.A. §?1307(f), and the Commission’s approval thereof, the purchased gas cost rates established therein become effective for service rendered on and after October 1, 2016. That upon acceptance and approval by the Commission of the tariff supplement and supporting data filed by Columbia Gas of Pennsylvania, Inc., as being consistent with this Order and the Joint Petition for Settlement of the Rate Investigation pursuant to 66 Pa.C.S.A. §?1307(f), the inquiry and investigation at Docket No. R2016-2531807 be terminated and the docket be marked closed; and that Docket Nos. C-2016-2535307 and C-2016-2536983 be marked closed. Date: July 12, 2016/s/Katrina L. DunderdaleAdministrative Law Judge ................
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