The Natural Gas Supply Association (NGSA) was late but on May 27 moved for leave to intervene out-of-time and submitted post-technical conference comments to FERC opposing Algonquin Gas Transmission, LLC’s (RP16-618) request for a waiver of the Commission’s capacity release bidding requirements in order to help regional Electric Distribution Companies (EDCs). The producer group believes the waiver request will impact not only the functioning of the secondary market but the functioning of the natural gas market as a whole. NGSA said it became aware that the issues may affect its members upon the issuance of the Commission’s notice setting Algonquin’s proposal for technical conference and the conference subsequently held on May 9.
On 12/29/15, the Commission accepted, and suspended for the maximum suspension period, Algonquin’s primary tariff records, to be effective the earlier of September 31 or the date specified in a further order, subject to refund and the outcome of a technical conference. Post-conference filings by numerous parties were filed at the Commission late last week and early this week.
Algonquin’s waiver, if granted, purportedly would enable certain qualifying electric distribution companies (EDCs) with existing or new firm transportation capacity to release their firm capacity on a prearranged and priority basis to natural gas-fired electric generators under a state-approved electric reliability program, without subjecting them to current capacity release bidding and posting requirements. In its initial filing in this docket, Algonquin explained that gas pipeline infrastructure supplying regional power generation in New England is constrained and reliability has been an issue in the region.
NGSA said Algonquin’s request for waiver raises significant concerns about the impact such a waiver, and possibly similar waivers to follow, may have on the functioning of the natural gas market. The EDC contract concept is not the problem, claims the Association like a number of other parties, but NGSA believes the waiver is unduly discriminatory, provides preferential and subsidized access to capacity for a select few, will impact the competitiveness of the primary and secondary firm transportation capacity markets, and could also distort interruptible capacity and natural gas commodity markets. For example, preferential allocations of capacity to generators can influence all of the decisions generators make in the gas procurement process including the type, the level and the price of services. “Such decisions will influence the overall level of competition in the natural gas market, including the resulting market price for delivered gas.”
Rather, NGSA and other shippers argue that EDCs’ release of primary capacity to generators can be accomplished through the existing capacity release rules without sacrificing the competitiveness of the market. Generally, NGSA believes the best approach to solving New England’s infrastructure constraints is to “focus on market-based solutions in the power market structure, rather than to seek changes to the natural gas market that would compromise its functioning.”
Changes to ISO-New England’s (ISO-NE) power market structure have already been approved or are underway that are intended to improve the market price signals to generators, the group noted, “which should provide generators with a greater ability to be compensated for procuring firm natural gas transportation.”
The well-functioning competitive gas market should not be compromised to provide “a regulatory quick fix” to pipeline funding issues that are an outgrowth of a lack of proper market signals in regional power markets,” stated the producers. The issues are an outgrowth of inaccurate price signals. Algonquin’s solution “would instead impose dysfunction in the natural gas market while sidestepping the underlying problems that should be addressed by competitive power market solutions.”
Given the success of capacity release programs in fomenting a strong secondary market, “utmost caution” should be taken before making any changes that may diminish the competitiveness of the market. While this proceeding is focused on a single pipeline’s request for waiver, NGSA asserted, “we cannot ignore the high likelihood that granting this waiver will result in other pipelines in New England and in other organized power markets requesting similar waivers of the capacity release rules.”
Algonquin’s request cannot be looked at in isolation, declared NGSA. Broad expansion of similar waivers would effectively create a favored customer class for natural gas secondary capacity in regional markets, thereby unduly discriminating against all other gas users. This or similar waivers also would confer an advantage to EDCs participating in open seasons for primary firm capacity and could impact the availability and pricing of all gas market products.
NGSA strongly questioned how granting this waiver could possibly outweigh the potential adverse impacts such an exemption could have on the market, given that the EDCs that intend to hold firm contracts for the new pipeline capacity have stated in other forums that the waiver is preferred but not required. At the conference, the EDCs stated that a primary reason for needing direct assignment to generators is their lack of confidence that generators will be willing to match the highest bid in order to obtain the EDC’s capacity. Such actions “turn competition on its head” by shutting out parties that value the capacity the most while protecting those that are unlikely to value it as highly.
Preferably, NGSA advocated giving recent efforts to improve regional power market signals an opportunity to work. NGSA has been and continues to be a strong advocate for ensuring that adequate pipeline infrastructure is in place in New England to address current capacity constraints. NGSA has supported ISO-NE’s pay-for-performance proposal to provide incentives in its capacity market for increased reliability, which the Commission approved and is slated to take effect in 2018. Most recently, NGSA supported the Commission’s proposed energy price formation reforms (RM15-24) to better align dispatch and settlement intervals and to remove current restrictions on shortage pricing.
And the EDCs can successfully effectuate releases to generators in New England utilizing the currently effective capacity release rules. For instance, the EDCs could release capacity to generators on a prearranged basis for deals that are greater than one year at the maximum tariff rate. Alternatively, shorter-term releases could be prearranged for one month or less, and if consecutive months are required the generator could still retain the released capacity as long as it simply matches the highest bid. The EDCs could also choose a third-party asset manager to manage their pipeline contracts in order to make the most efficient use of each EDC’s primary capacity.
“While use of an asset management arrangement would not allow the EDCs to hold gas off the market for sole use by generators, the additional capacity made available in the New England market as a consequence of the EDCs’ firm pipeline contracts would increase the likelihood that generators could attain pipeline capacity when needed,” reasoned the producer group.
NGSA also sees a method in multi-party contracting, as proposed in Order No. 809. Given that Algonquin already has incorporated provisions in its tariff to accommodate multi-party contracts, at a minimum the Commission and market participants should be aware of whether such concepts were considered and, if so, understand why such an alternative was rejected.
Post-Tech Conference Timely Filed Comments – Algonquin. Algonquin’s comments listed five takeaways from the conference. It was demonstrated by the presenters that: (1) electric reliability concerns and wholesale gas and electric market price signals indicate there is a need for pipeline infrastructure in New England; (2) the only wholesale electric market participants that are willing and able to enter into long-term commitments for pipeline infrastructure in response to these reliability concerns and price signals are the New England EDCs; (3) to ensure the greatest benefits to the EDCs’ customers, which the EDCs believe is necessary for state commission approval of their commitments in support of infrastructure, the EDCs have conditioned their commitments on Algonquin’s implementation of the proposed tariff provision for targeted releases; (4) the Commission can and should act in this proceeding now to provide timely guidance to the stakeholders and to avoid regulatory impasse and delay; and (5) given that the proposed targeted release tariff provision is necessary to respond to strong signals for the need for infrastructure and is “a narrow exemption” to ensure that pipeline capacity is used to benefit retail customers who are ultimately bearing the cost of such capacity, the proposed tariff record submitted in February is just and reasonable.
In the past, Algonquin noted that its customers, including generators, have relied on system flexibility when their flows have exceeded scheduled volumes. As the system becomes more constrained, however, it will no longer be able to tolerate such over-takes, the pipeline said.
Given the high interdependence between natural gas and electricity prices resulting from the percentage of natural gas-fired generation capacity in the New England generation mix, pipeline constraints have resulted in significantly higher wholesale electric prices in New England compared to other regions. By contrast, during the summer period, when gas distribution companies are better able to release their firm capacity, the wholesale electric prices in ISO-NE and the Midcontinent ISO are similar.
According to Algonquin, its Access Northeast project (ANE) and the targeted release exemption are “filling a void” and constitute the only credible proposal that can bring timely relief. As acknowledged in the technical conference, generators have no opportunity to recover the costs of pipeline infrastructure in the ISO-NE energy and capacity markets.
Accordingly, although individual generators may have competitive market incentives to bid their generation into the wholesale energy market, it does not appear that they have sufficient operating incentives to invest in fixed costs, such as pipeline infrastructure, to address the constraints.
In addition, it is not clear that generators can fully recover infrastructure costs given the current structure of the ISO-NE capacity market. The ISO-NE Forward Capacity Market (FCM) provides for annual commitments of capacity three years in advance of an operating period. According to Exelon, however, the FCM is not designed to permit recovery of generators’ investment in pipeline infrastructure. Moreover, the three-year planning horizon of the FCM does not provide a reasonably foreseeable revenue stream to support generators’ investment in long-term pipeline contracts. Other customers, like Tenaska, a natural gas marketer, said they do not have an incentive to invest in pipeline infrastructure. Tenaska makes commitments in the three to five year range and would be unable to hedge a pipeline contract commencing three years later with a 20-year term.
Although the price signals may be insufficient to incentivize generators and marketers to invest in firm capacity continued Algonquin, the EDCs have responded to the price signals by entering into precedent agreements for the ANE. This does not constitute a scheme to suppress prices or improper subsidization. Instead, Algonquin suggested, the EDCs’ commitment is an economically rational decision by a market participant, in response to price signals, to remove a burden from the New England gas market due to lack of infrastructure. Moreover, the Commission does not have to decide whether the EDCs are correct regarding their cost-benefit analysis because the state commissions will review whether the benefits of removing the constraint outweigh the costs.
As reflected in statements by Eversource and National Grid at the conference, Algonquin agreed the proposed exemption for targeted releases is important to the EDCs and many of the states because it will ensure that there will be electric reliability and pricing benefits for the EDCs’ customers that are being asked to support the ANE project. +Although many of the states are still considering whether to mandate targeted releases as part of their respective electric reliability programs, Connecticut’s draft request for proposal included a provision for targeted releases. Thus, without the proposed targeted release exemption, Algonquin believes certain EDCs may be unable to commit to the project, and without sufficient participation the project may not go forward.
As discussed at the conference, Algonquin added that there also could be a need for the targeted exemption for short-term releases to address (1) the Commission’s removal of the price ceiling for releases of one year or less, and (2) gaps in the capacity release bidding timeframe and limits of existing exemptions.
Finally, Algonquin insisted its proposal is not an industry-wide proposal that would necessitate a notice and comment rulemaking. And the Commission should act now to provide stakeholders with certainty with respect to this proposal to address electric reliability. “Concurrent consideration of federal and state aspects of these proposals is necessary to maintain the proposed schedule to address pipeline constraints causing electric reliability and pricing concerns as soon as possible.” Algonquin is concerned that opponents of the proposal are advocating a “do nothing” approach that is akin to advocating for delay in both the FERC and state proceedings.
Although details of the state programs are still being worked out and may vary from state to state, the overall structure of the proposals is known. Additional details regarding the cost recovery from retail ratepayers, releases to capacity managers, requests for generator bids, bidding periods and credits to ratepayers are being evaluated at the state level but have been submitted to the Commission as guidance of the types of details being considered. Accordingly, “the Commission has sufficient information to provide guidance on any state program details that it may require.”
Further, claims that the state programs are not defined, are a blank check, or are “a pig in a poke” are exaggerated. The details of these electric reliability programs contain a similar level of detail as the retail access programs for which the Commission granted an exemption and acknowledged that program details may vary from state to state.
And, Algonquin “is willing to consider tariff revisions from the Commission if necessary to accommodate legitimate concerns over implementation.”
Moreover, the pipeline suggested the proposed targeted releases are not expected to adversely affect the secondary market for released capacity on its system. Currently, approximately 80-90% of releases there are pre-arranged non-biddable releases. The proposed targeted releases of the ANE capacity may, or may not, impact the percentage of releases that are non-biddable. But capacity not used by generators will be posted for release to all secondary market participants and, as a result, the number of biddable releases on Algonquin’s system is expected to increase.
Algonquin’s Allies. In Algonquin’s corner, supportive initial comments were filed by the National Grid Electric Distribution Companies1 (NG EDCs) who requested FERC to approve Algonquin’s proposal. The NG EDCs are Massachusetts Electric Co. and Nantucket Electric Co. d/b/a National Grid. Other supporting parties included the Eversource Companies, the National Grid Gas Delivery Companies and the New England Local Distribution Companies (NE LDCs), and the Connecticut Public Utilities Regulatory Authority.
At the technical conference, questions arose as to why the capacity release bidding exemption was necessary. From the NG EDCs’ perspective, the primary reason that the exemption is necessary is that it will ensure that pipeline capacity purchased by the EDCs and ultimately paid for by EDC customers is used to supply gas for electric generation. Just as FERC has recognized that it is appropriate to provide LDCs with an exemption from the capacity release regulations to enable LDCs to release their capacity to marketers who are serving the LDCs’ retail customers,26 so too is it appropriate to provide EDCs with an exemption that will permit them to ensure that the capacity they purchase to support electric generation is used for that purpose.
Comments – NE LDCs. The New England Local Distribution Companies’ initial comments after the conference reaffirmed their support of the concept set forth in Algonquin’s proposal and urged the Commission to approve it expeditiously.
Stakeholders in New England have been unable to resolve issues related to the need for additional interstate pipeline infrastructure to deliver natural gas from west of the region – including from the Marcellus shale production area – to support gas-fired generation there, the LDCs noted. So the underlying problem is a “logjam” with respect to the funding of the necessary pipeline infrastructure. Algonquin’s proposal is “the only proposal under consideration that will resolve the funding logjam.”
According to them, the LDCs have a peak day of about 4.2 Bcf when there is only 2.7 Bcf of capacity. On top of that the LDC’s have 1.4 Bcf of LNG peaking. “So that confirms that the LDCs’ design peak and infrastructure are pretty well matched.” Now, on top of that there’s electric generation demand, and those numbers can range from 1Bcf to 2 Bcf, depending upon the assumption of dual fuel. “The reality is we have a winter reliability problem in New England.”
On peak winter days, west-to-east pipeline capacity in the region is insufficient to meet LDC demand, which is why the LDCs in New England contract for peaking services using LNG in order to ensure their high priority load receives necessary gas supplies. On these peak days, “New England has no west-to-east interstate pipeline capacity available for use by electric generators.”
While the region is forced to rely on dual-fuel capability or deliveries of LNG from the east in order to meet electric demand, these options may be limited as a result of environmental restrictions or worldwide demand for LNG.
In addition, New England LDCs are concerned about “pressure concerns, rapid pressure changes,” and LDCs serve “residential and commercial customers who have no dual fuel and [receive] essential service.” These LDCs have also been concerned about the lack of “slack” on an aging system that increasingly serves electric generation. In the last three or four years, unplanned maintenance and repairs have been much more prevalent than they were in the past, further reducing available capacity.
Existing mechanisms, such as asset management arrangements (AMAs) or capacity segmentation, have done nothing to address the funding logjam in the past and no one at the conference offered any reason for the Commission to think they will solve that problem in the future, asserted the New England LDCs.
If EDCs release capacity built to serve electric generators to asset managers using the existing waiver applicable to releases under AMAs, electric retail ratepayers would be footing the bill for the long-term firm contracts signed by the EDCs, with no guarantee that the asset managers will use the capacity to provide service to electric generators. In addition, the costs associated with AMAs may increase costs to ratepayers in New England. Asset managers simply become the middleman. Algonquin’s waiver proposal in this docket is a more direct way of ensuring that the new capacity is used for the purpose for which it was constructed – to serve gas-fired generators.
Capacity segmentation likewise in and of itself does not create infrastructure. Only firm capacity holders may segment their capacity.
In the view of the New England distributers, Algonquin’s waiver proposal is akin to the state retail access exemption. LDCs wishing to release capacity to marketers participating in state retail access programs may do so without going through the posting and bidding process in order to ensure that the capacity is provided to marketers that will use it to provide service to retail consumers. Algonquin’s proposed waiver would serve the same purpose. Electric retail customers in New England will be ultimately responsible for the costs of the new capacity under contract to the EDCs, and just as with gas retail access programs, the Commission should permit waivers of the capacity release posting and bidding requirements to permit the capacity to be used for its primary purpose.
Finally, the New England distribution companies asked FERC to provide guidance to the region but without foreclosing the EDC approach.
Power Generators. The Electric Power Supply Association (EPSA) and the New England Power Generators Association, Inc. (NEPGA) (collectively, “Joint Associations”) disagree with Algonquin’s idea and asked the Commission to reject it. In their collective opinion, the conference highlighted that the tariff language setting out the Algonquin waiver request lacks sufficient detail regarding how the “new” capability would function, which entities may participate, and how those entities would participate, “all of which highlight that the proposal is premature.”
Further, despite claims that the waiver was designed to benefit electric generators, the generators that commented on the proposal and/or participated in the technical conference explained that the proposal threatens to do the following: distort markets on which they rely; interfere with the existing primary and secondary firm capacity markets by granting preferential and subsidized access to released capacity for certain generators; distort interruptible capacity markets by allowing unduly discriminatory access by a select few; and, upend the competitiveness of the gas pipeline and commodity markets.
Moreover, there has been no showing that the proposed program will improve gas reliability or support electric reliability.
The generator associations emphasized that “energy and ancillary service price formation reforms” already are under way or under consideration by FERC for all of the Independent System Operator/Regional Transmission Organization (ISO/RTO) markets and will improve signals to generators that support the investment necessary to ensure they can meet power market obligations.
Additionally, individual regional markets have made or are making rule changes to improve reliability and system operations within their particular region, as ISO New England has done with the implementation of its pay-for-performance enhancements to the FCM construct in order to provide clear incentives for increased reliability. Such market improvements “should be allowed to play out without risk that their intended effect will be compromised by other market design changes, like the Algonquin filing, that have not been fully thought through and whose impacts are impossible to predict.”
Among other continuing concerns of these generators, the Algonquin proposal does not comport with that pro-competitive intent underlying Order 712 “in that it removes significant capacity from the competitive secondary market in order to administratively suppress prices in New England’s wholesale power market.” This is true as to the expected new pipeline and LNG capacity associated with the ANE project, but also potentially as to current Algonquin capacity. Besides that, there are no current state programs that address gas market issues to maintain electric reliability which require the support or changes proposed by Algonquin.
The technical conference presentations by Algonquin and the EDCs failed to provide evidence of specific electric reliability problems that would be resolved by the proposed exemption. Nor was data or evidence offered regarding reliability interruptions caused by constrained access to gas supplies.
Importantly, the Joint Associations pressed the view that electric generators, whose livelihood depends on the reliable provision of electricity, do not agree with the assessment by Algonquin and the EDCs regarding electric reliability. “EPSA and NEPGA members have firm natural gas pipeline contracts in their portfolios, but also balance those with the other options available to them in the natural gas market.”
Joint Associations believe the Commission should not prematurely approve the “administrative interference at the heart of the Algonquin waiver,” particularly as there are 13 other Commission actions being implemented to address suppliers’ performance obligations.
More Protesters. Parties filing protests or raising other concerns included Calpine Energy Services LP, Dynegy Marketing and Trade, LLC and PSEG Energy Resources and Trade, LLC, the Conservation Law Foundation, Engie Gas and LNG, LLC, Exelon Corp. and NextEra Resources LLC, the Indicated Shippers, the Attorney General of the Commonwealth of Massachusetts, Sequent Energy Management, L.P., Repsol Energy North America Corp. and Consolidated Edison Co. of New York, Inc. and Orange & Rockland Utilities, Inc.
Massachusetts and Connecticut. The Office of the Attorney General of the Commonwealth of Massachusetts offered its own post-tech conference written comments. As the AG reads it, Algonquin has no responsibility or liability for determining whether a customer is in compliance with its state-regulated electric reliability program. In place of FERC’s established reliance on competitive bidding to ensure transparent and non-discriminatory allocation of released capacity, Algonquin “proposes that the Commission rely on unspecified, inchoate state regulation that might be developed in state regulatory review of ‘precedent agreements’ executed by the EDC affiliates of Algonquin’s ANE project co-venturers for project capacity.”
The Mass. AG urged the Commission to reject Algonquin’s exemption request for at least the following four reasons: (1) The exemption request is at best premature, given that no “state-regulated electric reliability programs” of the type advocated by Algonquin’s proposal exist at this time, and the Commission is therefore unable to assess their effectiveness in ensuring transparent and nondiscriminatory access to released pipeline capacity; (2) The proposal is discriminatory and non-transparent on its face, because it carves out an unprecedented exception to the competitive bidding requirements for pipeline capacity releases; (3) In place of the assurances of transparency and non-discrimination provided by the existing competitive bidding requirements for capacity releases, Algonquin’s proposal facilitates a conflict of interest between Eversource and National Grid (together, the majority owners of ANE) and their affiliated EDCs; and (4) Algonquin’s proposal is neither necessary nor useful to the development of new natural gas transportation infrastructure in New England.
The AG argues, among other things, that Algonquin’s proposal is neither consistent with nor similar to exemptions permitted by the Commission, “for the simple reason that there is nothing open or transparent about permitting side deals for pipeline capacity between EDCs and merchant generators.” The exemption seeks an uneconomic allocative outcome at odds with that promoted by competitive bidding for released capacity.
Besides, the AG argued, there is no need for Algonquin’s proposal because price signals are suggesting there is no need for the ANE project. When customers are not willing to commit to long-term, firm pipeline capacity despite the existence of persistent peak period shortages, the appropriate signal for Algonquin to expand is not sent. “That is exactly what has been happening in New England where Algonquin has not been receiving a signal to expand its system because generators cannot reliably recover the cost of firm transportation through the ISO-NE markets.”
In summary, concluded the lawman from Massachusetts, contrary to Algonquin’s characterization, price signals for gas infrastructure expansion in New England are not “broken,” and Algonquin’s exemption proposal is not a constructive response to the messages being sent by the primary and secondary capacity markets in New England. As the presentations at the May 9 conference demonstrated, those markets are instead simply operating to promote more efficient use of existing capacity, rather than massive expansion of pipeline capacity. “Interfering with those markets in the manner proposed by Algonquin in this proceeding poses significant risks of harm to the interests of New England consumers in terms of unnecessary costs now and potentially stranded assets in the future.”
Remarkably, from an entirely different standpoint, however, the Connecticut Public Utilities Regulatory Authority supplied comments in support of the revised tariff language submitted February 19 by Algonquin. The Connecticut PURA supports the proposed language as a just and reasonable means to ensure that capacity acquired by EDCs can actually be used for the purpose for which ratepayers in New England, and in particular, Connecticut, pay for the capacity.
The Connecticut agency would welcome similarly tailored proposals by other pipelines for consideration by FERC and other interested entities in New England. Accordingly, FERC should find that Algonquin’s limited waiver proposal is in the public interest because it supports the efforts of states and EDCs to increase the amount of natural gas pipeline capacity under contract to serve gas-fired generation.
In Connecticut at least, “Algonquin’s limited waiver proposal allows capacity procured by any EDC under state reliability programs to be used in a manner which best supports the state statutory obligation of EDCs to provide adequate, safe, and reliable electric power deliveries.” The new provisions and waivers therefore support the viability of state-regulated electric reliability programs that have been proposed and are being considered before state regulatory commissions in New England. The waiver proposal is “properly tailored to the circumstances facing New England.” If the capacity is not released pursuant to the state-regulated reliability program, any other release of that capacity will be subject to the standard capacity release provisions of Algonquin’s tariff.
Finally, Connecticut PURA noted that FERC itself has stated that it “is open to considering requests for waiver of its capacity release regulations and/or the shipper-must-have-title rule on a case-by-case basis, where it is shown that such a waiver would be in the public interest, for example by assisting natural gas-fired generators in obtaining access to firm transportation service in a transparent and not unduly discriminatory manner.” Given the state proceedings ongoing in New England, Algonquin’s concept is “exactly the type of proposal which should be considered and accepted.” Approval of Algonquin’s revisions should also further the goal of using firm pipeline capacity, instead of the secondary market, to transport gas to electric generators. Use of firm capacity should increase the reliability of the pipeline system to the benefit of all users of that system, as well as reduce the exposure of electric ratepayers to unnecessary cost spikes and reliability risks.
Nor does the Natural Gas Act (NGA) require that all shippers be treated exactly the same, noted the Connecticut state agency. Differing treatment is not “undue discrimination” if the various entities are not similarly situated. EDCs participating in electric reliability programs are not similarly situated from entities that do not participate in stated-regulated programs. Participation in those programs is more than adequate basis to treat that category of shippers differently from those who do not participate in those programs.
Other Parties (selective). Sequent Energy Management, LP and Tenaska Marketing Ventures (TMV) still hold that Algonquin’s request is premature, poses unacceptable risks to the existing capacity markets, and is irreconcilable with FERC’s open-access transportation policies and objectives. While the instant proposal must be rejected outright, Sequent/Tenaska argue, they accept that Alqonquin is entitled “to seek such authority through a generic, industry-wide proceeding, such as a formal request for rulemaking,” but “only after these state programs are implemented and subsequently reviewed by the Commission.”
The ANE expansion capacity should succeed (or fail) on its independent merits. There is no basis for Algonquin’s efforts to “artificially to promote the project” by means of the capacity bidding exemption sought in this proceeding. The fact that none of putative beneficial users of the ANE capacity – the electric generators – is a subscriber speaks not to a “failure of price signals” (as Algonquin argues), but, rather, is evidence of exactly the opposite: the price signals sent by the gas and electric markets to the power generators “unequivocally do not support contracting for this incremental capacity.”
As TMV explained at the technical conference, the bidding exemption and underlying capacity allocation proposal are highly dubious, because, once implemented, they will reduce competition, limit segmentation and optimization opportunities, and may actually compromise reliability by reducing supply flexibility. This potential damage is magnified because the proposed bidding exemption applies to all Algonquin capacity now held by or thereafter acquired by EDCs, even non-ANE capacity under any of Algonquin’s firm rate schedules.
The EDCs would thus gain a special exception to allocate and administer all of their capacity in essentially “a new tertiary market” that is outside of, and thus free from, the dictates of the competitive secondary capacity markets, and, importantly, is outside of the Commission’s scrutiny and control. “Algonquin’s proposal to exempt nearly 1 Bcf of new expansion capacity from the Commission’s capacity release regulations is objectionable enough; exempting all firm capacity held by EDCs is nonsensical.”
Finally, stated Sequent/Tenaska, the exemption proponents failed to explain why their commercial objectives cannot be achieved under the existing capacity release regulations. The marketers warned that approval of the bidding exemption would inappropriately sacrifice the Commission’s oversight of the secondary market for interstate transportation capacity to state regulators, and “would do so on a preemptive, entirely-blind basis.”
Repsol Energy North America Corp. joined in requesting FERC to reject the exemption that Algonquin seeks. According to Repsol, market participants reported at the technical conference that the capacity release market is well-functioning and robust. And so far, Repsol reported, Algonquin, Eversource, and National Grid have only put forward very generalized statements and data that they believe support Algonquin’s proposal. And among other deficiencies in the record, the record does not contain any indication that generators support Algonquin’s proposal or were even consulted about how it should be designed to meet their needs, even though Algonquin claims they will benefit from it.
Moreover, the ANE load that could be served by that capacity is currently being served by the existing capacity available from Algonquin, the capacity release market, AMAs, or by purchases of delivered gas from marketers. In the near future, it will also be served by expansion capacity resulting from the AIM and Atlantic Bridge Projects. Because of the preferential rules requested by Algonquin, the ANE capacity will not compete with this existing and soon-to-be existing capacity on equal terms, and this will result in two detrimental effects.
First, it will needlessly devalue all of the capacity in the market that does not qualify for the exemption (i.e., most of the available capacity) since the capacity that is exempt from the capacity release rules will have the distinct advantage of not being subject to competitive bidding. Second, Algonquin’s proposal will result in stranded existing capacity to the extent that new incremental capacity that would be eligible for the exemption (e.g., ANE capacity) is duplicative of existing capacity.
Repsol believes it important to recognize that “to an overwhelming extent” generators receive either primary firm or secondary firm service, not “interruptible service.” Moreover, the data does not take into account generators that do not nominate transportation capacity but instead receive reliable service by purchasing delivered gas.
Likewise, west-to-east constraints on Algonquin do not translate into reliability concerns because of the availability of gas supply in the market area in the east. Repsol provides gas supply from its Canaport LNG terminal in Canada to Algonquin’s market area through the Maritimes & Northeast pipeline, which interconnects with Algonquin at Beverly, Massachusetts. Gas supplies are also provided in the east by the Everett LNG terminal, the Northeast Gateway offshore LNG buoys, and from deliveries of non-LNG sourced gas from Maritimes and the Portland Natural Gas Transmission System. All of these sources “backfeed” gas into Algonquin from the east and thus are not subject to west-to-east pipeline constraints. These sources effectively and efficiently provide supply to the markets on peak winter days, including to electric generators, and have done so reliably for years, according to Repsol.
From Repsol’s viewpoint, finally, too many unanswered questions remain about how the exemption would be implemented in practice for FERC to approve it.
Also holding firm in the thumbs-down camp, Consolidated Edison Co. of New York, Inc. and Orange and Rockland Utilities, Inc. submitted joint initial post-tech conference comments to emphasis their continuing skepticism. These large utilities claim to be unable to evaluate Algonquin’s proposal without further information about who would be permitted to receive such releases and the planned mechanics for such releases. They indicated however that they would anticipate Algonquin’s right to file a more detailed bidding exemption proposal that can be found to be just and reasonable and not unduly discriminatory. Their specific concerns are mostly local in nature, i.e., the potential impact of this kind of policy modification on the gas markets in New York State and New Jersey.
In principle though, ConEd/O&R agree with Algonquin that electric reliability and pricing concerns in New England should be addressed. The companies also agree that an exemption from bidding requirements of some kind may be appropriate to address these concerns. However, they suggested that the exemption for AMAs (Order No. 712), not the exemption for retail choice programs, should serve as a model for the state-regulated electric reliability program exemption.
“Like asset management agreements, and unlike retail choice programs, there is no universal understanding of how state-regulated electric reliability programs will operate and little historical information from which to draw. The Commission should provide an exemption for releases under state-regulated electric reliability programs only if in doing so it provides a means to distinguish them from other transactions.”
Among other suggestions proffered by ConEd/O&R, first, if Algonquin’s aim is to facilitate the development of additional pipeline capacity serving New England, it should be required to explain why its proposed exemption is not more targeted. Second, Algonquin should provide additional information about the restrictions that will apply to capacity release under the proposed exemption for state-regulated programs, and take steps to minimize the impacts of those restrictions on market efficiency.
Third, the two utilities remain concerned that capacity could be allocated based on local preferences (e.g., to maximize economic development or tax revenues in particular areas) or perceived environmental benefits, rather than based on reliability or economic criteria. Further, no party has clarified whether generators receiving capacity releases under the program would be eligible to participate in electric energy or capacity markets outside New England, and, conversely whether generators outside New England would be eligible to obtain releases pursuant to the proposed exemption. Such limitations could “potentially create unnecessary and inefficient seams within the Northeastern region.”
Fourth, it remains unclear how the assessment of electric reliability needs will be conducted, because EDCs do not operate the bulk power system and may not have full information about reliability needs of the electric system.
Another party to the proceeding, ENGIE Gas & LNG LLC attached to its initial post-conference comments a report prepared at the request of GDF SUEX Energy North America (its current parent company) produced by Energyzt Advisors LLC titled, Analysis of Alternative Winter Reliability Solutions for New England Energy Markets.” Reference had been made at the technical conference to information in the report, and members of the Commission present had requested a copy.
In essence, according to the filing,” during the challenging weather of the past two winters, a lack of sufficient gas pipeline capacity was not the real struggle; there is more than adequate natural gas delivery infrastructure in the region. Rather, it was the lack of commercial arrangements to access the existing infrastructure that created the issue.”
 The ANE project is owned 40% Spectra, and 60% by the EDCs parent companies — 40% Eversource and 20% National Grid. ANE consists of a 500,000 dth/d pipeline capacity expansion, together with LNG liquefaction, storage, and regasification facilities capable of delivering 400,000 dth/d of gas.
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