FERC on Friday approved a NYISO plan to protect consumers from rising capacity prices in southeastern New York but rejected a one-year transition to the new rules, saying it “lacks analytical basis” (ER17-446).
NYISO proposed the plan in the fall to address anticipated price spikes in the capacity market in the Lower Hudson Valley and New York City zones, expected after the commission in October allowed the export of electricity from a New York plant in a constrained zone into ISO-NE. (See FERC Sides with ISO-NE in Capacity Dispute with NYISO.)
The ISO’s current capacity market rules fail to recognize the impact of counterflows: They assume that 100% of a generator’s exports from an import-constrained area must be replaced with generation in that locality. NYISO Market Monitor Potomac Economics warned the anomaly means capacity clearing prices in the Lower Hudson Valley “could rise far above competitive levels.”
In response, the ISO proposed a “locality exchange factor,” based on power flow analyses, which found that 47.8% of the capacity exported to ISO-NE from New York’s G-J zones could be expected to be replaced by capacity in the rest of the state. That meant only the remaining 52.2% would need to be replaced by capacity within the zones. NYISO’s proposal was vehemently opposed by generators, who said it would suppress prices. (See NYISO Board Denies Generators’ Appeal on Capacity Cap.)
FERC’s order approved NYISO’s methodology but rejected its proposal for a one-year transition to the new rules (June 2017 through May 2018), during which the ISO planned to use an 80% locality exchange factor rather than the 47.8% figure.
NYISO said the transition was proposed by stakeholders and received votes in support from four out of the five voting sectors. But the commission said there was no “analytical basis” for the 80% factor.
“In its proposal for the locality exchange factor methodology, NYISO states that ‘the price signal should reflect only the portion of the export that must be replaced by resources located within the locality.’ The one-year transition mechanism, however, is not based off of the same power flow analysis that NYISO argues is the best way of accounting for counterflows,” the commission said.
FERC dismissed supporters’ argument that the ISO needed more time to refine and evaluate the methodology. “If NYISO or, in turn, the commission, had some basis to doubt the efficacy of the locality exchange factor methodology, then rather than implementing a transition, the commission would be required to reject the methodology in its entirety as unjust and unreasonable,” it said.
FERC ordered a new plan submitted within 30 days.
Roseton | Google
The methodology was prompted by the commission’s October order allowing Castleton Commodities International’s 1,242-MW Roseton 1 generator, located 43 miles north of New York City, to export 511 MW of its capacity to ISO-NE beginning next June for the 2017/18 delivery year. If Roseton decides to participate in ISO-NE’s 2017/18 commitment period, NYISO would procure unnecessary replacement capacity, as Roseton would still be providing reliability services for the G-J zone, the ISO argued.
December was marked by all-time high wind output in MISO, along with higher gas prices and erratic weather patterns that challenged the RTO’s forecasters, officials said at a Jan. 24 Informational Forum.
Jeff Bladen, MISO’s executive director of market design, said that while average temperatures in December were “near normal,” the month saw “rapid transitions in temperatures and winds,” leading to inaccurate forecasting and poor unit commitment.
“Ultimately, unit commitment decisions are heavily influenced by weather forecast accuracy,” Bladen said.
There are ongoing efforts to improve load forecasting capabilities, he added. “The challenge is more volatile weather … it’s something we continue to work on to improve our ability to manage and predict,” Bladen said.
Load averaged around 77 GW during December, a 9-GW increase over November. The month’s peak of 100 GW occurred Dec. 19.
MISO’s systemwide energy prices averaged just above $30/MWh, up 22% compared with the previous month. Bladen said the increase could be attributed to an $3.59/MMBtu average natural gas price that was $1.15 higher than in November.
A month-to-month upending of wind output records has become almost standard for MISO, and a new high of 13.7 GW was set Dec.7, surpassing the previous record of 13.3 GW set in late November. Wind production for the month totaled 5,687 GWh, the highest value recorded for the RTO.
MISO Creates Focus Group for IT Refresh
MISO will create a Market System User Experience Focus Group to learn about information technology shortcomings, said Curtis Reister, the RTO’s director of software delivery.
The group will meet Feb. 23 and is open to all users of MISO market systems who would like to comment on their market experiences and make suggestions.
The group, part of MISO’s wider effort to make software improvements in 2017, will gauge customer satisfaction with usability, performance and security and seek to understand customer experiences. (See MISO to Study Aging Software; Market Improvements Planned for 2017.)
The RTO noted that its electronic market systems are more than 10 years old. While some applications have been improved for functionality, there have been “minimal” changes to front-end design.
“There is some dissatisfaction out there, and we want to understand it,” Reister said.
The focus group will also decide which IT investments will have the biggest payback, he added.
MISO CEO John Bear said software investments are needed to manage a larger, more diverse fleet. “We’re dealing with a lot more intermittency and a lot more generators,” he said.
Some of the improvements might require members to make system changes implemented over the long-term in order to give those members adequate time to update, Bear said.
MISO will also switch platforms for its external website, according to Executive Director of External Affairs Kari Bennett.
Stakeholder Input Needed on Cost Allocation
Patrick Brown, manager of transmission planning for MISO South, said the RTO expects stakeholders to submit comments on transmission cost allocation by Feb. 27, in time for a Hot Topic discussion at the March 22 Advisory Committee meeting.
The RTO released a market efficiency project (MEP) cost allocation strawman in December, proposing to lower the current 345-kV voltage threshold and remove a footprint-wide postage stamp allocation of costs in favor of one in which costs are borne solely by participants in benefiting transmission pricing zones. (See MISO Stakeholders Propose Changes to Market Efficiency Cost Allocation Process.)
MISO expects cost allocation refinement to continue into the third quarter before Tariff changes are drafted in the fourth quarter and filed sometime in mid-2018.
In a sprawling decision, FERC last week rejected requests for rehearing by multiple energy sellers implicated in market manipulation during the Western Energy Crisis of 2000/01 (EL00-95-289).
The sellers — which include Hafslund Energy Trading, Illinova Energy Partners, MPS Merchant Services, Shell Energy North America and APX — had asked the commission to reconsider previous findings related to the disgorgement of overcharges the companies raked in from May to October 2000, the so-called “Summer Period” of the crisis, which ultimately cost California ratepayers billions of dollars.
In that decision, the commission set out what it deemed the “appropriate remedy” for the anomalous bidding, false export and false load scheduling tariff violations engaged in by the companies in an effort to drive up market clearing prices during the crisis: the disgorgement of any payments received in excess of a marginal cost-based proxy price.
The commission decision dealt with companies implicated in manipulating prices during the initial “Summer Period” of the Western Energy Crisis.
A subsequent opinion required that companies found to have engaged in those practices would be forced to disgorge overcharges for all sales made during trading intervals in which market prices were affected by any of the companies’ tariff violations.
FERC dismissed as moot rehearing requests by MPS, Illinova, Hafslund and Shell that called into question the commission’s previous findings of tariff violations by the companies. The commission pointed out that the 9th U.S. Circuit Court of Appeals had already determined that FERC’s orders on those matters were final and that the commission “reasonably concluded that the sellers engaged during the Summer Period in the practices deemed tariff violations.”
The commission also denied a request for rehearing by MPS and Illinova in which the two companies contended that FERC’s requirement that an individual seller disgorge profits not directly connected to any violation they committed represents an award of retroactive refunds to buyers rather than disgorgement. The two companies had complained that FERC’s disgorgement remedy is limited to the return of profits obtained illegally. The commission countered that the 9th Circuit has recognized that the Federal Power Act “gives FERC authority to order refunds if it finds violations of the filed tariff and imposes no temporal limitations.”
FERC rejected an argument by all five companies challenging the validity of the marginal cost-based proxy price methodology being used in the proceeding. “The commission has affirmed the presiding judge’s finding that the marginal cost-based proxy methodology … provides for a credible proxy of prices in a normal competitive environment,” the commission wrote.
The commission also rebuffed the companies’ argument that they should not be responsible for disgorgement of profits from all sales affected by the tariff violations by any of the market’s participants. Commissioners said they found persuasive the arguments of a California expert witness that the tariff violations had “intertemporal” effects on the state’s market during the crisis.
The commission also rejected a contention by MPS and Illinova that the prices established by the CAISO and now-defunct California Power Exchange markets were contract rates subject to the public interest standard of review embedded in FERC’s landmark Mobile-Sierra decision.
“The prices set by the CAISO and CalPX auction markets do not constitute contract rates because they result from a generally applicable auction mechanism set forth via tariff,” rather than from an arms-length transaction between two parties, the commission said.
The CAISO and CalPX tariffs did not contain the terms of a public interest standard of review, the commission noted.
The commission also denied a request by Exelon, the successor-in-interest to AES NewEnergy, for a rehearing on the issue of the fuel costs the company submitted to offset its refund amounts.
“The commission considered the full array of evidence, noting certain CAISO records submitted by Exelon related to the transaction, but ultimately finding that Exelon had not ‘clearly linked any evidence of its actual incurred costs to the resource and sale at hand,’” the commission said, citing language in a previous ruling. The commission reiterated a requirement that fuel cost information be “clearly linked” with a resource and an energy sale and “easily verifiable by supporting evidence.”
Settlement Agreements
In two other orders stemming from the energy crisis, FERC rejected two of California’s motions to preserve remedies or refunds against other non-settling parties as a condition for concluding settlement agreements with Illinova and MPS (EL00-95-299, EL00-95-300).
California had asked for the commission to affirm that a settlement with either company would not release non-settling parties from facing the possibility of having to disgorge profits from energy sales inflated by tariff violations committed by Illinova and MPS. The state argued that FERC’s failure to grant the motion would make future settlements impossible by reducing the liability of the remaining sellers and incent them to wait for others to settle first, thereby deterring California from settling with any of them.
In denying California’s motion, the commission stated that it “has dismissed from the proceeding parties that settled … before and during the instant proceeding, excluded the conduct of non-parties from the scope of the proceeding and emphasized that the trading hours impacted by the settled parties’ tariff violations will not be included in disgorgement amounts due from the remaining respondents.” The state failed to provide a compelling reason for the commission to reverse that long-standing practice, the commission added.
The commission noted that it was not ruling on either settlement agreement and directed California to notify FERC within 30 days whether it wished to revise or withdraw from the agreements.
CARMEL, Ind. — MISO’s Steering Committee last week advanced three topics for discussion: the RTO’s settlement with SPP, a potential cost recovery defect and potential cost-sharing for customer-funded upgrades.
The committee decided that the Market Subcommittee will discuss a possible cost recovery gap, an issue raised by Entergy. The gap arises when MISO decommits or manually redispatches a resource to offline status, the utility contends.
“If the resource is later brought back online to fulfill the remainder of an existing commitment period or to meet a subsequent commitment period, the resource is not guaranteed start-up cost recovery,” Entergy said.
The company wants the RTO’s Tariff revised “to provide incentive for resources to follow MISO instructions and to ensure that a resource owner is not forced to choose between following MISO instructions and incurring an uncompensated cost, and disregarding MISO instructions.”
A discussion on generator-funded upgrades that benefit other interconnection customers was assigned to MISO’s Regional Expansion Criteria and Benefits Working Group (RECBWG), despite a request by EDF Renewables that the topic be directed to the Interconnection Process Task Force (IPTF). The company wants such projects to receive some reimbursement through MISO, EDF said.
Jeff Webb, MISO director of planning, said the IPTF would be appropriate if project costs were only to be shared among interconnection customers, but he doubted that cost-sharing would be that limited. He suggested that the RECBWG first discuss the potential scope for cost allocation.
A stakeholder discussion on metrics used for the SPP-MISO transmission cost allocation settlement will initially be assigned to the Resource Adequacy Subcommittee for an examination of possible capacity benefits.
Jesse Moser, MISO director of seams relations and strategy, said internal decisions on the metrics belong in the RECBWG, which is already considering broader cost allocation changes. Still, some stakeholders contended that the issue should first move into the RASC for exploration of potential capacity benefits from the settlement.
The settlement requires MISO to “conduct a stakeholder discussion regarding the use of capacity benefits as an alternative way to allocate costs” of the joint operating agreement (ER14-1736). (See “Cost Allocation Set in MISO-SPP Settlement,” MISO Market Subcommittee Briefs.)
Madison Gas and Electric’s Megan Wisersky said she was surprised to learn MISO would delve into a cost allocation discussion before assessing the resource adequacy impacts of the settlement.
Indiana Utility Regulatory Commission staffer Dave Johnston said the topic should be discussed in the RASC.
“To me, RECBWG is for transmission projects,” Johnston said. “This is not what this is. This is a settlement between parties with a bucket of money.”
WILMINGTON, Del. — PJM must determine how to handle different rules for new and existing pseudo-ties after stakeholders vetoed a package of reforms for external resources at Thursday’s Markets and Reliability Committee meeting but then agreed on applying the updated rules only to new pseudo-tie requests.
The package appeared headed back to the drawing board after failing to reach the 3.33 out of 5 necessary in a sector-weighted vote. But Exelon’s Jason Barker immediately motioned for a vote on an “alternative” package that excluded existing pseudo-ties from the new requirements, saying it would “move toward something that we think is an improvement over the status quo.”
The original proposal, developed through the Underperformance Risk Management Senior Task Force, called for making deliverability requirements uniform for resources within and outside of PJM’s footprint and requiring confirmatory feasibility studies for all pseudo-ties. Existing pseudo-ties would have had until delivery year 2022/23 to conform to the deliverability standards for internal resources. (See No End in Sight for PJM Capacity Market Changes.)
By Oct. 1, 2018, PJM would notify external resource owners whether their pseudo-tie is operationally feasible. Owners of resources that fail would be required to perform the required upgrades or would be declared ineligible to offer capacity.
Stakeholders balked at the implication that their units might become nonviable if the transmission owner — over which neither they nor PJM has authority — declined to meet the new standards.
“It’s their system; they can do things their way,” said Mike Borgatti of Gabel Associates.
PJM’s Adam Keech acknowledged, “We’re not in a place where we can require someone to upgrade to our standards.” He estimated there is roughly 3,500 MW of external generation pseudo-tied to PJM.
Joe Bowring, PJM’s Independent Market Monitor, called the original proposal “a significant step forward” but still inadequate because imported capacity remains an inferior substitute for internal capacity resources and suppresses market prices.
“If units don’t meet the rules and requirements, they don’t meet the rules and requirements. That should be the end of the story,” he said.
When the measure failed and Barker proposed applying the updated standards to new pseudo-ties, Bowring questioned whether Barker intended for existing pseudo-tied units to then be grandfathered in perpetuity. Stakeholders agreed that the alternative proposal would be silent on existing pseudo-ties and that portion would be sent back to the task force for further consideration. The measure was endorsed, receiving 3.97 in favor on a sector-weighted vote. The same proposal was later approved during the Members Committee meeting with 3.88 in favor.
PJM Senior Vice President of Operations and Markets Stu Bresler said there will need to be a discussion with the Board of Managers on having separate rules for similar groups. “We certainly can’t live that way for very long,” he said.
Work on Uplift Moves Forward Despite NOPR
In three decisive votes, stakeholders swiftly moved forward on efforts to address uplift.
The action was a far cry from last month, when PJM’s Dave Anders explained that the Energy Market Uplift Senior Task Force had only been successful in half of its goals. The task force endorsed two proposals to reduce uplift and volatility. However, it considered more than a dozen proposals to address cost allocation issues and couldn’t find majority agreement on any of them. The MRC instructed the task force to revote on the top five.
Earlier this month, the task force endorsed a package for the MRC to consider on Thursday. The proposal would maintain much of the status quo but include up-to-congestion transactions in the allocation of day-ahead and balancing operating reserves in the same way incremental offers and decremental bids are included. It would also remove the ability for internal bilateral transactions to offset deviation charges.
However, with FERC having issued a Notice of Proposed Rulemaking on uplift and UTCs on Jan. 19, PJM staff assumed stakeholders might want to postpone action on the issue until receiving clear direction from the commission. (See FERC Proposes More Transparency, Cost Causation on Uplift.)
Not so. “I think that PJM has shown in a lot of studies that UTCs do impact commitment and decommitment … and that’s a cause of uplift,” FirstEnergy’s Jim Benchek said. “If down the road that NOPR results in rulemaking actually happening … then we’ll deal with that rulemaking at that time. My final comment is let’s vote today.”
So they did: The Phase 1 proposal was approved with a sector-weighted vote of 4.1 out of 5. It largely maintains the status quo, except that it includes in the determination of balancing operating reserve credits only the day-ahead revenues from the hours the resource operated in real-time, not all day-ahead revenues.
The proposal to postpone voting on Phase 2 for one year was opposed by 3.8 out of 5 in a sector-weighted vote, and a vote on the package succeeded with 4.01 out of 5. The proposals will go for a vote before the Members Committee at its Feb. 23 meeting to approve the Operating Agreement revisions and endorse revisions to the addendum to Attachment K of the Tariff. The Tariff revisions will then need to be approved by the Board.
Separately, stakeholders also approved a problem statement and issue charge to reconsider historical practices and provisions in the Operating Agreement and Manual 33 restricting the sharing of data that is considered confidential or market sensitive. Changes could result in more transparency on transmission constraints, the reliability assessment commitment process and conservative operations in day-ahead and real-time operations.
Stakeholders OK Manual Changes
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Revisions to Manuals 11 and 12 to account for the updated regulation requirement developed by the Regulation Market Senior Issues Task Force. (See “Regulation Requirement Changing from ‘Peak’ to ‘Ramp,’” PJM Operating Committee Briefs.)
Revisions to Manual 27 developed as part of an annual review.
Revisions to Manual 38 developed as part of a periodic review to provide more clarity on outage coordination.
Revisions to Manual 40 that, among other things, reduce the grace period for completing operator training. (See “Manual 40 Revisions Approved with Exelon’s Addendum,” PJM Operating Committee Briefs.)
Revisions proposed by the Governing Document Enhancement & Clarification Subcommittee to clean up definitions in the Tariff, Operating Agreement and Reliability Assurance Agreement.
Members Committee
Members Approve Charter for Security Committee
Despite stakeholder inquiries about its non-decisional status, the Members Committee endorsed by acclamation the charter for a new Security & Resiliency Committee.
American Municipal Power’s Ed Tatum asked what purpose the group would serve if it didn’t make any decisions. PJM staff said it would operate in an advisory capacity like the Transmission Expansion Advisory Committee. Exelon’s Gloria Godson clarified that the group was not formed at the behest of transmission owners.
“This was not a [Transmission Owners Agreement-Administrative Committee] idea,” she said. “In fact, a lot of TOA-AC folks have an issue with this idea.” (See “Preview of Security Committee Receives Tepid Response,” PJM Markets and Reliability and Members Committees Briefs.)
According to PJM, the new committee will serve as a forum to discuss threats and hazards and offer case studies, solutions or other best practices. To avoid compromising company security, the committee won’t include any Critical Energy Infrastructure Information in meetings and the news media will be barred. It will password-protect its minutes and only allow external partners by invitation. Corporate nondisclosure agreements will be used as needed.
Consent Agenda Endorsed
The committee also endorsed:
Operating Agreement revisions associated with residual auction revenue rights enhancements.
NextEra Energy boosted its adjusted earnings by 5% in the fourth quarter and 11% for all of 2016, despite falling short of investor expectations on both measures.
The Florida-based company Friday reported fourth-quarter adjusted earnings of $566 million ($1.21/share) and full-year adjusted earnings of $2.88 billion ($6.19/share), missing the Zacks consensus estimates of $1.29/share and $6.22/share, respectively.
Investors rewarded the company with a $2.07 increase in its stock price, from $119.30/share to $121.37/share.
Adjusted earnings exclude the mark-to-market effects of some hedging, non-temporary impairments, operating results from a solar project in Spain and expenses related to its proposed acquisition of Texas-based Oncor. Also excluded from the 2016 results were gains from the sale of natural gas generation facilities.
Subsidiary NextEra Energy Resources’ investments provided much of the growth. It commissioned about 2,500 MW of new wind and solar projects — the most wind and solar megawatts ever added by a single company in North America, NextEra said. It has signed contracts for another 540 MW of wind and 100 MW of solar energy since its third-quarter call.
“I remain as enthusiastic as ever about our future,” NextEra CEO Jim Robo told financial analysists during a conference call. He said the company’s performance reinforces “the overall strength and diversity of our growth prospects.”
Central to NextEra’s future is completing its $21 billion acquisition of Oncor, the largest transmission and distribution provider in Texas. The deal has FERC’s approval, but it next faces a Public Utility Commission of Texas review scheduled for Feb. 21-24. (See FERC OK in Hand, NextEra Faces More Questions on Oncor Deal.)
The PUC has until April 29 to act on the acquisition or it will be automatically approved.
“We see an opportunity to make two already great companies even stronger,” Robo said. “We believe we have the ability to bring real value to Oncor stakeholders, and in turn find attractive investment opportunities to create long-term shareholder value.”
Robo reminded analysts that NextEra will use its A– credit rating and balance sheet — “One of the strongest in the sector,” Robo said — to save Oncor customers “hundreds of millions of dollars by removing the debt that hangs over Oncor right now.”
He said intervenors have raised questions that could result in NextEra being immediately downgraded once Oncor’s debt is moved by either prohibiting the company from appointing a majority of the Oncor board or placing restrictions on dividends and approval of budgets.
“We are unwilling to compromise our A- corporate credit rating as a result of any transaction,” Robo said. “We need to address these issues in order to avoid being downgraded, so we can close the transaction.”
CARMEL, Ind. — MISO has named a business executive with almost two decades of experience in the energy industry as its new chief financial officer.
Brown | MISO
Melissa Brown most recently served as CFO for Atlanta-headquartered Drax Biomass, a wood pellet manufacturer with locations throughout the southeastern U.S.
The new hire comes just over six months after former Vice President of Finance Jo Biggers left abruptly in mid-August and the RTO opened a candidate search. (See Vice President of Finance Biggers Exits MISO.)
MISO spokesperson Jay Hermacinski said Brown will assume all the responsibilities that Biggers held in her role.
Since Biggers’ departure, corporate service tasks were delegated to Senior Vice President of Compliance Services Steve Kozey. Finance and corporate planning responsibilities were handled by Vice President of Strategy and Business Development Wayne Schug.
MISO CEO John Bear said Brown’s financial experience coupled with her energy background make her an ideal fit for the position. “Grid reliability and value-creation are our two top priorities at MISO. We need leaders like Melissa who will help MISO stay ahead of the constant changes we face in the energy industry,” Bear said.
Brown was Drax’s CFO from March to November and worked as an energy consultant for seven years with consulting firm Alix Partners.
She has also worked in different management roles at major utilities, including corporate treasurer and senior vice president of strategy and financial planning and analysis at Calpine; executive director of business development at NRG Energy; and manager of corporate financial analysis at AES. The RTO said Brown has a combined 19 years of experience in power generation, fuel supply and public utilities.
“I am excited to join this dedicated team of professionals and look forward to helping the organization be the most reliable, value-creating RTO,” Brown said.
Biggers’ predecessors include Mike Holstein, who served from 2001 to 2011, and James Torgerson, who served from 1999 to 2001.
FERC on Wednesday approved the Atlantic Bridge Project, which will expand natural gas delivery capacity in New York and New England (CP16-9).
In issuing a certificate of public convenience and necessity for the project, the commission accepted an environmental assessment released last spring that found “no significant impact.” (See Atlantic Bridge Environmental Assessment Released.)
“We agree with the conclusions presented in the EA and find that the project, if constructed and operated as described in the EA, and in compliance with the environmental conditions in the appendix to this order, does not constitute a major federal action significantly affecting the quality of the human environment,” FERC wrote.
The project will expand Spectra Energy’s Algonquin Gas Transmission and Maritimes & Northeast Pipeline systems by 132,700 dekatherms/day to serve the New England and Canadian natural gas markets.
The $452 million project would replace existing pipelines and add new or expand existing compressor stations in New York, Connecticut and Massachusetts.
Six miles of existing pipeline in New York and Connecticut would be increased from 26 inches to 42 inches. A 7,700-horsepower compressor station would be built in Weymouth, Mass., along with numerous infrastructure improvements.
The commission said “the vast majority” of public comments concerned the Weymouth station, but it said that facility did not require an additional environmental impact statement. Concerns were adequately addressed by conditions set out in the order, it said.
FERC turned aside opponents’ claims that excess project capacity will be used to export LNG outside of North America.
“We note that while there are currently several proposals to export liquefied natural gas from the United States and Canada to overseas countries, there is no evidence that the applicants are constructing the Atlantic Bridge Project for this purpose. The project shippers receiving gas in Canada are industrial and commercial users of natural gas within Canada, not companies involved in the export of LNG,” the commission wrote. “We also note the commission does not have jurisdiction over the export or import of natural gas as a commodity. Such jurisdiction resides with the U.S. Department of Energy (DOE), which must act on any applications for natural gas export and import authority. Thus, the issue of whether the export of LNG will cause economic harm is beyond the commission’s purview.”
Spectra said the pipelines’ capacity was fully subscribed by five local distribution companies, two manufacturers and a municipal utility during its open season in 2014 and 2015.
The expansion project has a proposed in-service date of November 2017.
WILMINGTON, Del. — Following months of debate on the scope of the undertaking, a coalition of load-serving stakeholders won approval at Thursday’s PJM Markets and Reliability Committee meeting to review the capacity market construct.
Overcoming what had appeared to be strong opposition, the problem statement and issue charge were endorsed with a sped-up timetable revised to make potential changes in time for the 2018 Base Residual Auction.
The initiative cites the aborted power purchase agreements for FirstEnergy and American Electric Power in Ohio and the zero-emission credits approved for nuclear plants in Illinois as examples of the impacts public policy initiatives may pose to price formation in the capacity market. It notes a pending complaint by Calpine asking FERC to impose the minimum offer price rule (MOPR) on existing generation. (See FERC Rescinds AEP, FirstEnergy Affiliate-Sales Waivers.)
Illinois Statehouse | Illinois Asset Building Group
“The failure to successfully anticipate these occurrences resulted in important policy debates circumventing the PJM stakeholder process and going directly to litigation at FERC,” the problem statement says. “The sponsors of this problem statement believe the stakeholder process forum is the appropriate place for these discussions. It is apparent to the problem statement sponsors that each state may take actions to meet its environmental, political and policy objectives that could affect” the Reliability Pricing Model.
The coalition, which includes Old Dominion Electric Cooperative, American Municipal Power, the Delaware Municipal Electric Corp., the PJM Public Power Coalition and the Public Power Association of New Jersey, has been asking since August for approval to review the RPM.
Focus Tightened
Since then, the measure’s focus has been revised and repeatedly pared down. AMP’s Ed Tatum, the coalition’s spokesman, noted on Thursday that Direct Energy and Dominion Virginia Power have withdrawn as sponsors. As recently as last month’s MRC, stakeholders remained hesitant to investigate the potential impacts of any governmental action on CP, concerned the implications could be too disruptive to the market, which is still digesting the rule changes under Capacity Performance. (See “Stakeholders Remain Skeptical of Campaign to Revisit CP,” PJM Markets and Reliability Committee Briefs.)
The sponsors returned on Thursday focused just on state actions and explained that they had taken pains to limit the scope, despite suggestions to broaden it in certain ways. The effort still nearly faltered, as stakeholders remained concerned it inappropriately targeted states. Bob O’Connell of Panda Power Funds suggested focusing on “out-of-market actions” instead.
“Panda Power Funds has no interest in picking a fight with states. Our biggest focus is on price formation,” he said. “I’m indifferent to who pushes the wheelbarrow with money into the room. I’m just concerned about the money in the room.”
Alex Stern of Public Service Electric and Gas voiced support for O’Connell’s efforts to focus on market design, but Tatum said “out-of-market” doesn’t have a specific definition. Tatum also clarified that the focus had changed to not target the states for taking actions they deem necessary. Others agreed, including Dan Griffiths of the Consumer Advocates of the PJM States (CAPS) and Susan Bruce of the PJM Industrial Customer Coalition, who called it a “rabbit hole.”
External ‘Forces’
John Farber of the Delaware Public Service Commission praised the sponsors’ acknowledgment that state actions can be “manifestations” of external “forces” applying pressure on government, not necessarily internally motivated. Ruth Ann Price, Delaware’s deputy public advocate, was mild in her criticism, merely echoing a request to “soften” the language that had been made by other stakeholders during previous discussions. Tatum responded, as he has in the past, by asking for suggestions.
With the state advocates indicating interest in finding consensus, a small group huddled to craft mutually acceptable language.
In the meantime, Neal Fitch of NRG Energy pointed out that the issue’s scope had been reduced, yet its timeline for results had been extended into late 2018. He said it seemed likely the issue could be resolved in time for the 2018 BRA in April.
A vote on the measure was deferred until after lunch to incorporate the updated language. When it finally came time to vote, the package referred to “state public policy initiatives” and anticipated results by the end of the year. PJM Senior Vice President of Operations and Markets Stu Bresler confirmed this left enough time for it to be incorporated in the planning criteria for the BRA.
EnerNOC’s Katie Guerry questioned the continued focus on state actions, but Price defended the language, saying that local initiatives would not impact PJM’s markets. Despite opposition from most of the Transmission Owner sector, the revised problem statement passed a sector-weighted vote with 3.95 out of 5, with the End Use Customers and Electric Distributors unanimously in support.
The issue charge assigns the initiative to a new Capacity Construct/Public Policy Senior Task Force (CCPPSTF) reporting to the MRC. It will identify the “objectives and characteristics” of a well-functioning capacity market and “identify areas where state actions and the current RPM capacity construct may not be aligned.”
The group will seek to address the conflicts with potential changes to the PJM Operating Agreement, Tariff, Reliability Assurance Agreement and manuals.
Calling 2016 “very successful” and predicting 2017 will be “another transformational year,” American Electric Power CEO Nick Akins paid tribute to the late television icon Mary Tyler Moore during a Thursday conference call with financial analysts.
“In respect to the passing of Mary Tyler Moore, I will just say, we are going to make it after all,” Akins said during the company’s fourth-quarter and year-end report. “This has been a year of repositioning and de-risking the company. … We have come through with flying colors, but as a premium energy regulated company, our work is far from done.”
Akins’ optimism is fueled by the pending sale of four competitive power plants for $2.2 billion, the company’s hopes for restructuring Ohio’s electric market and possible corporate tax reform under the Trump administration.
The company reported fourth-quarter operating earnings of 67 cents/share, up almost 40% from a year earlier, which beat the Zacks consensus estimate of 55 cents/share. For the year, operating earnings were $3.94/share, up from $3.69/share a year ago. Its transmission segment contributed 54 cents to earnings for the year, an increase of more than 38%. AEP reaffirmed its 2017 operating earnings guidance range of $3.55 to $3.75/share.
Investors reacted to the news by driving AEP’s share price up 40 cents to $62.97 at Friday’s close.
Under Generally Accepted Accounting Principles (GAAP), the company reported 2016 earnings of almost $611 million, a $1.4 billion drop from 2015 that reflected its $2.3 billion write-down on its Ohio competitive generation assets in the third-quarter, as well as a federal tax audit settlement over the sale of its commercial barge operations and mark-to-market impact of hedging activities.
Akins said AEP expects to close its sale of three natural gas plants, with 2,533 MW of capacity, and the mammoth 2,665-MW Gen. James M. Gavin coal plant to Lightstone, a joint venture between The Blackstone Group and ArcLight Capital Partners, “sometime in 2017.”
AEP’s Gavin Power Plant. | AEP
Three of the gas plants are in Ohio, and the fourth, the 1,186-MW Lawrenceburg Generating Station, is just across the state line in Indiana. Akins said the company was continuing a “strategic review process” for the remaining merchant generation units.
“This was a year of reducing risk and volatility of earnings for the company in the future and reinforcing our balance sheet to provide a strong platform for future growth,” Akins said.
The CEO said the company is discussing with other utilities and stakeholders its proposed legislation to restructure Ohio’s competitive market and expects a bill to be introduced as early as the second quarter.
“AEP will not invest in new generation in Ohio unless we have a clear path to recovery of our investment, so enabling legislation is critical,” he said. “There’s already drafts of legislation that are circulating around, and we just need to make sure all the parties are comfortable with that.”
Though AEP saw signs of an improving economy in its service territory in the fourth quarter, Akins called the growth “minimal.” He said the company will continue to watch the economy closely under the new administration’s “pro-growth agenda.”
“President Trump’s focus of enhancing the ability for manufacturing industries to thrive and produce jobs … well that’s AEP’s service territory,” he said. “AEP should prosper, and we are very much looking forward to working with the Trump administration to bring prosperity and jobs back to this country.”
