Staff were invited to meet with FERC staff in October, which Lanford said was more about building bonds. “Senior staff had some questions for us, but not about particular issues,” he said.
Texas RE staff has also scheduled a conference call in March and another in-person meeting in May with FERC staffers.
FERC staff have “said we didn’t do anything wrong. … ‘We just never see you,’” Lanford said. “I guess they want to see us. That’s good, because we have a positive story to tell.”
Case in point: Violations in the region have dropped from 103 in 2016 to 94 in 2019. With 240 registered entities, the regional entity’s enforcement case load numbers 425 in the first quarter of 2020.
The organization has once again secured a contract as the Public Utility Commission’s Texas Reliability Monitor. Thanks to its work, the PUC issued $602,000 in penalties last year.
Texas RE’s footprint continues to grow. It certified Rayburn Country Electric Cooperative as a transmission operator (TOP) last year before the co-op integrated about 130 miles of transmission lines and 190 MW of load into the ERCOT balancing authority. Texas RE will conduct a similar TOP certification of Lubbock Power & Light, which plans to migrate 470 MW of its load from SPP to ERCOT by June 2021.
COO Jim Albright told the board that the RE is “in the best place we’ve been since I’ve been involved in this.”
“The relationships we’re building with NERC and other regions are the best they’ve been,” Albright said. “They’re in a really good place, and it’s showing.”
Committee Assignments Handed out
The Texas RE board approved placements on several of its committees:
Crystal Ashby, Milton Lee and Curt Brockmann were appointed to the 2020-21 Hearing Body, with Delores Etter as an alternate. The group, which meets only when a contested case hearing is requested, will select its chairman in the near future.
Independent Directors Ashby and Etter; affiliated Directors Liz Jones, with Oncor, and Brockmann, with CPS Energy; and Lanford will fill out the Director Compensation Committee, as dictated by the organization’s bylaws. Ashby agreed to serve as the committee’s chair.
Lee, Etter and Jones will serve on the 2020 Nominating Committee, with Lee chairing. The group will be responsible for finding a replacement for board Chair Fred Day, whose final term expires in December.
Ashby Begins Board Tenure
The board meeting marked Ashby’s first as a director. A Michigan undergraduate — “Go Blue!” she said — Ashby has 32 years of experience in compliance, ethics and risk assessment. Much of her career has been in the energy industry, including time in BP’s government affairs unit during the 2010 Deepwater Horizon oil spill.
Left to right: Texas PUC Chair DeAnn Walker, and Texas RE Directors Delores Etter, Fred Day, Milton Lee and Crystal Ashby during February’s board meeting. | Texas RE
“I plan to bring those traits and skill sets to the discussions the board has,” Ashby said.
She also serves as vice chair of The Executive Leadership Council, which is focused on increasing African-American representation in the C suite and on corporate boards. She earned her law degree from DePaul University.
Texas RE to Co-host GridSecCon 2020
A scheduling change to NERC’s annual GridSecCon and Electric Power Human Performance Improvement Symposiums means the Texas RE will be hosting one of these events every three years, beginning this fall, Albright said during the Member Representatives Committee meeting that preceded the board meeting.
The RE will co-host GridSecCon 2020 Oct. 20-23 in Houston with NERC’s Electricity Information Sharing and Analysis Center. “We’ll definitely be doing some heavy lifting,” Albright said.
The Western Electricity Coordinating Council will co-sponsor the Human Performance event Sept. 29 to Oct. 1 in Denver. With each of NERC’s six REs hosting the event, Texas RE’s turn should come up in 2023.
General Counsel Tammy Cooper told the MRC that Texas RE’s draft of a renegotiated regional delegated agreement will be considered by NERC in May.
A PJM task force considering the implementation of carbon pricing continued its education sessions Tuesday with an analysis on the impact of Virginia and Pennsylvania joining the Regional Greenhouse Gas Initiative (RGGI).
At its sixth meeting since its formation last summer, the Carbon Pricing Senior Task Force heard PJM officials walk through an analysis of the impact on emissions, prices and interregional trading of a “carbon price region” composed of up to five PJM states.
RGGI, which includes New York and the six New England states, currently has only three PJM states: Delaware, Maryland and New Jersey.
However, Virginia would join RGGI under the Clean Economy Act currently before the legislature.
Carbon sub-region (in green) including RGGI states and Pennsylvania and Virginia | PJM
Pennsylvania Gov. Tom Wolf issued an executive order in October directing state officials to develop a rulemaking by July 31 for joining RGGI, although his authority to do so has been challenged by the Republican-controlled legislature. (See Critics: Pa. RGGI Hearing Stacked with Detractors.)
Although PJM officials have taken pains to emphasize that the analysis is theoretical and that the RTO is not proposing a carbon price, it has said a carbon price could provide a way for ensuring states’ clean energy policies do not distort wholesale markets. (See PJM: Carbon Pricing the Answer to Subsidy Dispute.)
Analysis
PJM’s analysis compared the status quo with a region pricing carbon at a low-end reference of $6.87/short ton (the trigger price for the RGGI Emissions Containment Reserve) and a high-end reference of $14.88/short ton (the trigger for the RGGI Cost Containment Reserve). The analysis modeled the year 2023, the most recent planning case from the Regional Transmission Expansion Plan and market efficiency process.
It used PLEXOS software to simulate the commitment and dispatch of resources and the resulting market and emissions outcomes. Resources both internal and external to PJM were included in the optimization.
The analysis of adding Virginia without Pennsylvania found that at a price of $14.88/ton, emissions in the carbon zone would decrease from 52 million tons of CO2 for the year to 35 million tons. That reduction would be almost entirely offset by an increase in emissions in the rest of PJM, resulting in only a small reduction in total emissions from 278 million tons to 277 million. Meanwhile, NOx and SO2 emissions for the entire RTO would actually increase.
Shift in generation production by sub-region from adding one-way (1W) and two-way (2W) border adjustments | PJM
But the analysis also found that PJM would increase its net exports from about 37,000 GWh to more than 45,000 GWh, meaning that the PJM region would be providing substantially more power to its neighbors without increasing its emissions.
“If you look at emissions across the entire [Eastern] Interconnection outside of PJM, it’s not a wash,” said economist Paul Sotkiewicz of E-Cubed Policy Associates, representing Elwood Energy. “But I think what that also tells us is that trying to cure leakage within PJM is a fool’s errand because it’s going to leak to outside of PJM. … It’s going to leak one balancing area away from PJM [where] PJM has no control.”
When including Pennsylvania in the carbon region, PJM-wide CO2 emissions would drop from 278 million tons to 259 million tons at a $14.88/ton price, with reductions of NOx and SO2 emissions as well. In this case — without any border adjustments to capture leakage — PJM’s net exports would drop substantially.
Leakage
PJM also found that a one-way border adjustment would have very little impact on generation in either the carbon region or the rest of the RTO at either the low- or high-end price for carbon. The modeling of the one-way adjustment — capturing transfers into the carbon region — was based on the 2013 draft final proposal for CAISO’s Energy Imbalance Market.
But the two-way border adjustment — covering transfers into and out of the carbon region — would result in a big increase in generation inside the carbon zone and a smaller decrease in generation outside of it, with a large increase in net generation exports.
“One way doesn’t do much,” PJM’s Anthony Giacomoni said.
Study methodology | PJM
PJM officials cautioned that their analysis did not consider state-specific approaches such as programs that reduce electricity demand or load-based greenhouse gas compliance obligations.
It also did not capture how higher power prices could affect power demand. “We can add a low-demand sensitivity” in the future, PJM’s Natalie Tacka said in response to a request for that data.
Next Steps
Task force facilitator Jennifer Tribulski said the group will meet next on March 27, when it will consider the legal, regulatory and technical considerations of a carbon pricing program.
Tribulski said the RTO will also issue a call for speakers for that meeting. “We want to hear about … what you expect to see; what you’d like to see in future meetings so we can really gauge where we are and what comes next.”
Despite a year that saw PJM cancel its 2022/23 capacity auction and part ways with its CEO, CFO and general counsel, 89% of members who responded to the RTO’s biennial stakeholder satisfaction survey said they are satisfied with its performance, officials told the Members Committee on Thursday.
“Given the complexities we experienced last year, I personally think this is a good result,” said Jim Gluck, director of member relations.
The score was down 3 percentage points from the results in 2017 and the second-lowest score PJM has recorded in the six surveys since 2010.
Some 626 people from 372 companies responded to the survey, which ran from Sept. 30 through Oct. 11.
2019 was perhaps the most tumultuous year in recent PJM history, with the departures of three long-time executives — CEO Andy Ott, CFO Suzanne Daugherty and General Counsel Vince Duane — in the wake of the GreenHat Energy default. The RTO also parted ways with Denise Foster, its popular vice president of state and member services. (See PJM Chooses CFO, Promotes Haque.)
CEO Manu Asthana, who joined in January, said he read all 1,100 comments submitted, which he said underscored “how important it is to improve the stakeholder process.”
“There are things we could be doing better,” he acknowledged. “We don’t get it 100% right.”
Still, he said, PJM’s 89% score is “higher than Apple’s net promoter score.”
The net promoter score — an index ranging from -100 to 100 that measures the willingness of customers to recommend a company to others — is a widely cited but controversial metric.
“This was not meant to be an apples-to-Apple comparison,” PJM spokeswoman Susan Buehler explained later. “The 89% overall satisfaction rating was based on the one high-level question we asked around PJM’s performance from members only. Manu simply meant to imply that a 89% is a high level of satisfaction even when looked at in the context of a leading consumer brand, but we continue to strive for even higher results.”
About 62% of PJM members rated the RTO as very or extremely good, and another 27% rated it good with 11% calling it fair or poor.
Nonmembers were less impressed, with 17% rating it fair or poor, up from 11% in 2017. Gluck said many of the nonmembers were agents and developers concerned about the transparency of PJM’s transmission planning.
However, Gluck said PJM’s ratings improved over 2017 on each of seven individual “dimensions”: core deliverables, integrity, communication, customer relationship management, change management, project management and impact.
For the first time, the survey provided respondents the option of asking PJM to contact them for additional feedback. About 100 people said they were interested in more dialogue. “Expect PJM to contact you in next month or so,” Gluck said.
VALLEY FORGE, Pa. — Stakeholders on Thursday approved proposed changes to the RTO’s fuel-cost policy (FCP) despite concerns that new safe harbor provisions would create loopholes permitting the exercise of market power.
A proposal by the PJM Industrial Customer Coalition won a sector-weighted vote of 3.57 (71%), with majority support from all sectors except End Use Customers (EUC), where it was backed by seven of 14 voters.
The Markets and Reliability Committee approved the proposal after rejecting a “joint stakeholder” package that had been the top vote getter with 87% support at the Market Implementation Committee in December. (See “Fuel-cost Policies,” PJM MIC Briefs: Dec. 11, 2019.)
The MRC rejected the joint package with a sector-weighted vote of 1.91 (38%). It won majority support from only the Generation Owners sector and no votes from the EUC and Electric Distributors sectors.
Both proposals eliminate the annual FCP review and the FCP requirement for zero-marginal-cost offer units. They also would eliminate or adjust submission and review deadlines. The ICC proposal accepted a safe harbor provision proposed by the generators but modified the terms for imposing penalties for noncompliance.
The joint proposal would impose the full penalty if the unit clears in the day-ahead market or runs in real time on a cost-based offer and is paid DA/balancing operating reserves. The joint proposal also would apply the full penalty if the unit fails the three-pivotal-supplier (TPS) test for constraints or the cost offer is above $1,000/MWh.
The ICC proposal, which had won 81% support at the MIC, built on the joint proposal and would also apply the full penalty if the unit is marginal in DA or RT on its cost-based offer. It would not apply the full penalty if the unit failed the TPS test but was running on a price-based schedule because it passed the test at the time of commitment.
The vote followed a spirited debate over last-minute changes to a new safe harbor section in both the joint stakeholder and ICC proposals, which would allow a generator to avoid penalties if it deviates from its FCP because of a force majeure event.
MIC Chair Lisa Morelli said the joint proposal used North American Energy Standards Board’s definition of force majeure and would ensure the safe harbor would only be triggered by events beyond the control of the market seller and that its affiliates could not control and could not have contemplated.
PJM would determine if the generator provided sufficient evidence to avoid penalties following a review by the RTO and the Independent Market Monitor.
Greg Carmean, executive director of the Organization of PJM States Inc. (OPSI), questioned that the proposed Operating Agreement language lists pipeline interruptions as an “unforeseen event.” Carmean said state regulators care about FCPs when the system is strained, wanting a way to verify the high prices that result.
But Morelli said natural gas pipeline declarations of force majeure would not qualify for the safe harbor because generators can expect such actions. “It doesn’t mean that just because this condition exists that the exemption is automatically triggered,” she said.
The IMM’s Catherine Tyler said FCPs are a core part of market power mitigation and that the proposal would weaken protections.
Tyler said generators have exercised market power through weak FCPs in the past. “This makes it all quite a bit worse,” she said. It would “make legal market power abuses currently prohibited by the Tariff.”
Monitor Joe Bowring said flexible FCPs can address all of the force majeure events cited by generation owners. “PJM proposed and FERC adopted language requiring fuel-cost policies to be verifiable. With this loophole, fuel-cost policies are not and cannot be verifiable. There is simply no good reason to make this change.”
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said he shared OPSI’s and the Monitor’s concerns.
Bob O’Connell, of Panda Power Funds, one of the companies that negotiated the joint proposal, said the Monitor “may not fully understand the challenge our gas traders face.” He cited an instance in which flooding in Houston disrupted the operations of pipelines on which his company had firm transportation.
The joint proposal “balances all the issues that need to be balanced,” he said.
Susan Bruce, representing the ICC, said the joint proposal has “very large hole in it. The marginal unit, by definition, is impactful.”
After the joint motion failed, O’Connell offered a friendly amendment to the ICC proposal requiring generators to file force majeure claims to PJM at least one hour prior to the deadline for submitting offers. They would be subject to the same verification process that applies to offers above $1,000/MWh.
But Calpine’s David “Scarp” Scarpignato objected to use of the verification process.
“I cannot vote for … that kind of material change [at the] last minute,” he said. “I’d have to work through it [with other Calpine officials]. … I’m not saying I’m against the idea, but I’m against putting it up on the fly.”
The approved ICC proposal, which will require changes to the Tariff and Manual 15, will go to a final vote by the Members Committee in March.
American Electric Power CEO Nick Akins, a Louisiana native, says he roots for the Ohio State Buckeyes “if they’re not playing” Louisiana State University.
Makes sense, given that AEP shares its Columbus, Ohio, headquarters city with the Buckeyes. However, LSU’s ride to a 15-0 season and this year’s national championship gives him reason to celebrate his home state.
“I have to use an LSU analogy given their victory in the college football national championship,” Akins said during AEP’s fourth-quarter earnings call Thursday. “The way in which the LSU office executed during the season is the way I feel about our AEP team. … The results of 2019 indicate that.”
AEP reported fourth-quarter earnings of $153.5 million ($0.31/share), down from $363.4 million ($0.74/share) the year before. When adjusted for $98 million in charges linked to the retirement of three coal plants in Virginia and the planned shutdown of another coal plant in Ohio, adjusted earnings per share met analysts’ expectations of 60 cents/share.
Year-end results of $1.921 billion ($3.89/share) were virtually unchanged from 2018’s final numbers of $1.923 billion ($3.90/share).
Operating earnings for 2019 came in at $4.24/share, which was at the top end of AEP’s revised guidance range of $4.14 to $4.24/share.
“AEP has a habit of hitting the upper half of the guidance range, if not exceeding it, and this year has been no exception,” Akins said. “As we have said repeatedly, we would be disappointed in not achieving the same track record in the future.”
AEP set its 2020 guidance at $4.25 to $4.45/share and reaffirmed its 5 to 7% operating earnings growth rate.
Renewable energy will continue to play a major role as AEP continues to shed its coal resources. The company acquired Sempra Energy’s renewables business last year and is making progress on its North Central Wind initiative, a proposed $2 billion project involving Invenergy’s construction of three wind farms in Oklahoma with 1,485 MW of nameplate capacity.
AEP’s North Central Wind initiative | AEP
Shortly after AEP’s earnings call, Oklahoma regulators signed off on a deal that allows Public Service Company of Oklahoma, an AEP subsidiary, to recover costs for 675 MW of wind energy. Should Arkansas approve the project, AEP would have a “critical mass” of 846 MW and a $1.1 billion investment to move forward.
AEP still needs approval from the Louisiana and Texas commissions which, along with Arkansas, have the ability to “flex up” and take any wind capacity other jurisdictions turn down.
Should Arkansas approve a settlement as well, Akins said, “the project is moving forward; that’s a given. Then the question becomes, ‘OK, what scale?’ And that’ll be determined by the other two jurisdictions and the amount of flex up that’s enabled in those settlements.”
AEP shares, which hit an all-time high of $104.97 on Feb. 18, fell to $101.70 on Friday, losing $1.75 following its close before the earnings announcement.
The New England Power Pool Reliability Committee on Wednesday voted to recommend that ISO-NE approve pool-supported pool transmission facility (PTF) costs totaling $236.6 million for Eversource Energy projects to replace wood 115-KV structures in Connecticut ($200.3 million) and Massachusetts ($36.3 million).
Eversource maintains more than 20,000 115-kV structures in New England, and the work to replace aging wood structures with tubular steel pole structures is composed of 21 projects in Connecticut, three in Massachusetts and one cross-border project.
Inspections have indicated significant degradation and decreased load-carrying capacity of the wood structures. Eversource said that replacing the structures resolves multiple structural and hardware issues and supports safe and reliable operation.
Inspections have indicated significant degradation and decreased load carrying capacity of wood 115-kV structures. Eversource estimates cost for the 115-kV structure replacements in Connecticut and Massachusetts at $236.6 million. | Eversource Energy
Projects with additional scope, such as replacement of conductor and lattice tower lines, are generally presented individually.
In addition, the committee recommended RTO approval of approximately $18 million in PTF costs for Eversource to build a new control house for the Canal 345/115-kV substation in Sandwich, Mass., and elevate it above hurricane-level flooding. The station serves a large portion of Cape Cod load.
The RC also approved $7.5 million in PTF costs for Eversource to rebuild the 115-kV line from the Colony substation to Schwab Junction in Connecticut.
Attleboro Upgrade
The RC recommended the RTO approve $10.3 million in PTF costs for National Grid to replace worn-out assets at the Robinson Avenue 115-kV Substation in Attleboro, Mass., which dates from the 1960s.
National Grid said it will replace 115-kV components, including two oil circuit breakers, eight sets of disconnect switches and nine capacitor-coupled voltage transformers.
Two breakers were previously upgraded to support the new Highland Park distribution substation and were not included in the current project.
The new control house with modern protection and control systems should be completed by June 2021.
Operating Procedure Revisions
The RC voted to recommend that the Participants Committee support revision of ISO-NE Operating Procedure No. 3 (OP3) to extend the maximum duration for opportunity transmission outages from 96 hours to 108 hours.
Opportunity outages represent those that fail to meet the minimum advance notice required for planned short-term outage processing and are submitted for RTO “approval as a result of an unexpected opportunity to accomplish work that would otherwise require another outage at a less opportune time,” the RTO says.
The extra 12 hours will allow these non-impactful outages to be evaluated using the seven-day load forecast, which assumes a maximum continuous outage of five days, the RTO said.
The RC also supported revisions to OP18 to add a requirement to telemeter station frequency, identify equipment requirements, specify which requirements apply to existing and new equipment, and revise Section I to reflect current practice.
The committee also approved revisions to OP23 to provide audit requirement compliance measures for resources for which the RTO has not provided an asset ID number.
Planning Procedure Revisions
Dominion Energy is replacing the Unit 3 generator and feedwater measurement equipment at the Millstone nuclear power plant in Connecticut and in April will seek a committee vote on expanding the RTO’s interconnection limits.
Dominion representatives who wished to remain unidentified told the RC how the new equipment would allow the reactor unit to increase its output to 1,262 MW year-round, up from the current 1,225 MW in summer and 1,245 MW in winter.
The increase in output will bump the unit’s output just over ISO-NE’s interconnection limit for such resources, as defined in Planning Procedure 5-6 (PP5-6), which limits interconnection to 1,200 MW for new resources and elective transmission upgrades.
Dominion is replacing the Millstone Unit 3 generator and feedwater measurement equipment, which will bump the unit’s year-round output to 1,262 MW, just over ISO-NE’s interconnection limit for such resources. | NRC
Regardless of the results of a system impact study, the RTO indicated it likely could not approve the increase in interconnection rights because of this “pretty straightforward” language, one Dominion representative said. Revising PP5-6 would allow ISO-NE to approve the uprate if no issues were found on their review of the system impact study.
Dominion proposes allowing existing capacity resources above 1,200 MW, which are “increasing output as a result of good stewardship of their resources,” to “increase their interconnection rights accordingly.”
“The new generator and new equipment we’re putting into it allows to provide some extra benefits to the grid. … You’re going from a hollow core to a solid-core rotor, so you’re going up roughly an additional 50,000 pounds on that rotor, and all that’s online and provides additional inertia, so during a voltage transient, it’s like a flywheel on your car to keep providing energy for a while,” the representatives said.
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
In a separate matter, the RC also approved recommending that the Participants Committee approve revisions to Planning Procedure 3 (PP3) to conform to defined terms. As part of the changes being made, the term “governance participant” was replaced with “market participant” and/or “transmission owner” to conform to Section I.3.9 of the ISO-NE Tariff.
FERC last week denied multiple requests for rehearing and clarification of Order 860, its 2019 rulemaking lessening the reporting requirements of electricity sellers with market-based rate authority (MBRA) (RM16-17-001).
Currently, sellers are required to describe the activities of all their upstream owners, often requiring them to submit multiple amendments to their filings. Once the new rule goes into effect on Oct. 1, sellers will only need to identify their “ultimate” upstream affiliate — the furthest upstream owner. (See FERC Reduces MBRA Data Requirements.)
The commission denied requests to clarify several aspects of the order, including:
NRG Energy and Vistra Energy’s request to clarify that an investor will not be considered a seller’s ultimate upstream affiliate based solely on holdings of publicly traded securities;
the Edison Electric Institute’s request to extend the implementation timeline of the order’s requirements; and
the Transmission Access Policy Study Group’s (TAPS) request for safeguards from being penalized for reporting errors. (“We expect that most inadvertently erroneous or incomplete submissions will be promptly corrected by reporting entities without the imposition of any penalty.”)
FERC did clarify in response to a request by TAPS that the public will have access to the relational database it will establish to collect all the required information. It also noted in response to EEI that this Thursday it will hold a technical conference, announced last month, to discuss the implementation and use of the database.
Types of market-based rate authority filings | FERC
The commission also denied a request for rehearing by several state consumer advocate agencies, which argued that it erred in not adopting its original proposal to require submission of connected entity information (CEI) and that traders of financial transmission rights and virtual products also submit affiliate information. The agencies “assert that the final rule deprives the commission of important tools to address and combat market manipulation and fraud,” FERC summarized.
In the alternative, the agencies requested that their arguments be filed in the docket that FERC created when it dropped the CEI proposal in order to leave it open for consideration (AD19-17), a request the commission granted.
The agencies also requested “that the commission expediently implement the connected entity proposal and any additional reforms offered in [AD19-17] given the clear potential for future market manipulation, fraud and default.” But in his partial dissent of last week’s order, Commissioner Richard Glick said that was unlikely to happen.
“The commission has relegated even those common-sense reforms to a hollow administrative docket that has not seen any action and likely never will under the commission’s current construct,” he said. “As I explained in my earlier dissent, the commission’s retreat from the … proposal is part of a troubling pattern in which the majority seems indifferent to detecting and deterring market manipulation.”
Order 861
FERC also upheld Order 861 — issued at the same time as 860 — which eliminated the requirement for sellers with MBRA to submit pivotal supplier and wholesale market share screens in PJM, ISO-NE, MISO and NYISO (RM19-2-001).
Sellers of capacity in SPP and CAISO, which do not have capacity markets, will still need to submit the screens. In explaining the reason for this in its original order — and in response to requests for CAISO to receive the same treatment as the RTOs — FERC said the soft offer cap in the ISO’s capacity procurement mechanism “is an estimate of the cost of new entry and does not necessarily reflect a mitigated, ‘going forward’ cost of any existing generator and does not address concerns regarding local market power.”
CAISO took issue with that description, requesting clarification that the “soft offer cap represents an estimate of going-forward costs plus a 20% adder, as opposed to an estimate of the cost of entry.” Pacific Gas and Electric went further and requested rehearing of the order based on FERC’s erroneous description of the offer cap, arguing that the commission should remove the requirement to submit indicative screens.
FERC granted CAISO’s request but said its error does not affect its determinations in Order 861, denying PG&E’s request.
“The commission declined to extend Order No. 861’s relief to capacity sellers located in CAISO for several reasons, including the lack of a transparent market price for capacity in CAISO and the fact that capacity sales are not reviewed, approved or monitored by CAISO,” FERC said. We find that these reasons continue to apply and, therefore, deny PG&E’s request.”
New York Gov. Andrew Cuomo last week announced a push to amend this year’s state budget to speed up the permitting and construction of renewable energy projects.
If the legislature passes the amendment, a new Office of Renewable Energy Permitting will be set up to streamline the siting process for large-scale renewable energy projects.
“This legislation will help achieve a more sustainable future … with a revamped process for building and delivering renewable energy projects faster,” Cuomo said.
The state’s existing energy generation siting process was designed for permitting coal-, oil- and natural gas-fired power plants, dating from prior to the growth of clean energy.
New York in 2011 revised Public Service Law Article 10 to unify siting reviews of new or modified electric generating facilities under one state agency, the Board on Electric Generation Siting and the Environment.
The 100.5-MW Bliss Wind Farm near Eagle, N.Y.
“The renewable energy industry is ready to invest in New York, and a more sensible permitting process that still retains all the environmental protections is sorely needed,” said Anne Reynolds, executive director of the Alliance for Clean Energy New York. “The proposal also includes transmission planning, which is so critical to moving clean power to where it is needed.”
The Climate Leadership and Community Protection Act (A8429), signed into law last July, calls for 70% of New York’s electricity to come from renewable resources by 2030 and for electricity generation to be 100% carbon-free by 2040. It also nearly quadrupled New York’s offshore wind energy target to 9 GW by 2035.
The law’s clean energy mandates also include doubling distributed solar generation to 6 GW by 2025, deploying 3 GW of energy storage by 2030 and raising energy efficiency savings to 185 trillion BTU by 2025.
The executive branch proposes that the New York State Energy Research and Development Authority collaborate with the Department of Environmental Conservation and Department of Public Service to develop build-ready sites for renewable energy projects.
“Permitting is a process that involves basically anyone who wants to be involved, which is a good thing, but a challenge for the state,” Sarah Osgood, director of policy implementation at the Department of Public Service, told a conference in 2018. (See New York Plans for Wind Energy, Related Jobs.)
The proposal includes a bulk transmission investment program and streamlined siting process for transmission infrastructure built within existing rights of way, and foresees NYSERDA working with the New York Power Authority, the Long Island Power Authority, NYISO and the state’s utilities to identify cost-effective bulk electric system upgrades and file such evaluations with the Public Service Commission.
The PSC in turn would establish a distribution and local transmission system capital program, with benchmarks and reviews, for each relevant utility.
Consolidated Edison on Thursday reported 2019 net income of $1.34 billion ($4.09/share), down slightly from $1.38 billion ($4.43/share) the previous year.
Net income for the fourth quarter was $295 million ($0.89/share), compared to $331 million ($1.06/share) in 2018.
The company attributed the decline in income to depreciation and amortization expenses increasing 14.6% year-on-year, and taxes other than income taxes going up 8.4% in the same period.
“While meeting many challenges in 2019, Con Edison delivered solid financial results and remained focused on leading the way towards a cleaner energy future for our customers and the planet,” CEO John McAvoy said. “Our recently approved three-year rate plans are essential to helping New York state achieve its clean energy goals, as well as to continue providing safe and reliable service to our customers.”
The state’s Public Service Commission last month approved electric and gas rate plans for January 2020 through December 2022 reflecting an 8.8% return on equity, and the New Jersey Board of Public Utilities approved an electric rate increase, effective Feb. 1., of $12 million for Rockland Electric, reflecting a 9.5% ROE.
The PSC last month also issued an order directing energy efficiency targets and budgets for New York utilities, approving $2 billion statewide for EE programs, heat pump budgets and associated targets through 2025 to meet the goal of reducing electric use by 3% and gas use by 1.3% annually by 2025 (19-E-0065).
Con Ed’s DER meter, ConnectDER | Con Edison
In December, Con Ed completed a study of climate change vulnerability. Considering the increased risk of sea level rise, coastal storm surge, inland flooding from intense rainfall, hurricane-strength winds and extreme heat, the company estimates it might need to invest between $1.8 billion and $5.2 billion by 2050 on programs to adapt to impacts from climate change.
Con Ed is still extremely exposed to Pacific Gas and Electric’s bankruptcy through a large volume of power purchase agreements sold to the California utility. At year-end, Con Ed’s balance sheet included $819 million of net non-utility plant relating to PG&E projects, approximately $1 billion of intangible assets relating to PG&E PPAs, $282 million of additional projects that secure the related debt and approximately $1 billion of non-recourse related project debt. (See PG&E Reports $3.6 Billion Q4 Loss.)
Pursuant to the related project debt agreements, Con Ed reported distributions from the related projects to the Clean Energy Businesses have been suspended.
“Unless the lenders for the related project debt otherwise agree, the lenders may, upon written notice, declare principal and interest on the related project debt to be due and payable immediately and, if such amounts are not timely paid, foreclose on the related projects,” the company said.
FERC’s Dec. 19 order expanding PJM’s minimum offer price rule (MOPR) prompted outrage among some officials in the RTO’s 13-state footprint and shoulder shrugs from others (EL16-49, EL18-178).
Filings by officials in Delaware, Virginia, West Virginia and D.C. show they share some of the concerns that regulators from Illinois, Maryland, Pennsylvania, Ohio and New Jersey expressed last week in a webinar with RTO Insider. (See related story, PJM’s MOPR Quandary: Should States Stay or Should they Go?)
But regulators in Indiana, Tennessee, Kentucky, Michigan and North Carolina — which are only partly within the PJM footprint — say they expect little impact from the ruling. Here’s a summary of where regulators in the nine jurisdictions not represented in the webinar stand.
D.C.
The D.C. Public Service Commission sought rehearing or clarification on the MOPR’s impact on new renewables, new demand response and the district’s default service procurement program, which provides 28% of the district’s electricity, including 85% of residential customers’ usage.
It noted that Maryland and Delaware have similar procurement processes for their default customers.
The PSC said it is unclear if the commission intended the MOPR to apply to the default service procurements. Commissioner Richard Glick said in his dissent that the MOPR could apply to New Jersey’s similar default program, but the PSC noted that the order suggested such programs could be protected under the competitive market exemption or unit-specific exemption.
D.C. also is concerned that the order could make it more expensive for it to comply with district law requiring a 50% cut in greenhouse gas emissions by 2032 and reaching carbon neutrality by 2050.
PJM transmission zones | PJM
It said only 7% of PJM’s power comes from renewables, below the national average (17%) and the shares in MISO (15%), ISO-NE (18.8%) and ERCOT (21.5%).
Using the net cost of new entry (CONE) to set the price floor for renewables could leave PJM further behind, the PSC said. “Thus, we request that FERC consider exempting new renewable resources from the MOPR or treat such resources as an exception — using the net ACR [avoided-cost rate] as opposed to the net CONE for the price floor for new renewables.”
The district also raised concerns about the order’s directive that PJM average the last three years’ DR offers to determine the default offer price floor value for DR that has not previously cleared a capacity auction. A new DR program targeting water heating would have no history, it noted.
It said new and existing DR should have a zero floor price “due to the fact that demand response programs are producing negawatts, not kilowatts.”
“Inasmuch as customer participation in demand response programs is ‘voluntary’ and the programs produce benefits greater than their costs, we do not fully understand why demand response is considered as a subsidized resource. Furthermore, the demand response programs from [electric distribution companies], due to their proximity to load, offer significant reliability values and lead to reduced market power and reduced final price to consumers especially during scarcity hours.”
Delaware
The Delaware Division of the Public Advocate’s rehearing request sought a declaration that the MOPR does not apply to the Regional Greenhouse Gas Initiative, which includes Delaware, Maryland and New Jersey in PJM. Pennsylvania Gov. Tom Wolf is attempting to join also but is facing opposition from the Republican-controlled legislature. (See Critics: Pa. RGGI Hearing Stacked with Detractors.)
The advocate expressed concern that the order appeared to limit the MOPR exemption for existing renewable resources based on the PJM Tariff’s definition of “intermittent resources,” which it said does not cover all renewable resources that have generated or received renewable energy credits (RECs) and solar RECs (SRECs).
“For example, Delaware’s [renewable portfolio standard] statute includes geothermal energy technologies, biomass generators, landfill gas generators and fuel cells as electricity generators that are eligible to produce RECs, SRECs or their equivalencies,” it said. “These resources are not intermittent.”
Virginia
The Virginia State Corporation Commission filed a brief rehearing request that referred back to its October 2018 comments in the docket, in which it called for continuing the self-supply exemption for vertically integrated utilities in regulated states. The order exempted existing self-supply resources but indicated new self-supply would be subject to MOPR. (See Is Self-supply Suppressing Prices?)
“Customers in vertically integrated states should not bear the risk of paying twice for capacity, because the states in which such customers reside have made no out-of-market payments to generators,” it said. “What the commission concluded [in 2013] remains true today: Utilities in regulated states have no incentive to attempt to artificially suppress capacity prices, and a properly configured self-supply exemption would fully address the intent of an expanded MOPR.”
West Virginia
West Virginia, which remains fully regulated, has one load-serving entity that meets its capacity obligation through PJM’s fixed resource requirement (FRR): American Electric Power’s Appalachian Power and Wheeling Power, which together serve a little over half of the state’s load. Appalachian also serves significant retail load in Virginia.
The remainder of the state’s load is served by FirstEnergy’s Monongahela Power, which owns or controls 3,580 MW of generation, and Potomac Edison, which owns no generation but is supplied by Mon Power.
Mon Power’s load is almost entirely in West Virginia, while three-quarters of Potomac Edison’s load is in Maryland. Mon Power bids its capacity into PJM and buys its requirements, and those for Potomac Edison’s West Virginia operations, from the PJM market.
“The commission is still reviewing the order, but it appears that the decision to grandfather existing regulated plants that have been selling capacity into the PJM capacity market means that there is no immediate MOPR-related effect on our RPM [Reliability Pricing Model] LSE,” said Susan Small, communications director for the Public Service Commission of West Virginia.
The ruling would not impact the current operating decisions of the AEP companies, but their “option to elect to switch to RPM is now compromised,” Small said.
“We are concerned that new or existing regulated power plants that have not been selling into the PJM capacity market in the past will be subject to the MOPR, a treatment that we believe is unreasonable and discriminatory. This will mean that future options for West Virginia capacity additions and existing FRR regulated plants may be limited.
“By regulating the bid price of only certain unfavored power supply, including regulated power supply, not only will our options regarding how to serve West Virginia load be limited, but the cost of RPM capacity will grow over time because of the discriminatory treatment of resources that are bidding at a price that is considered by some to be too low.”
Indiana
Indiana Michigan Power (I&M), a subsidiary of AEP, is the only investor-owned utility in Indiana operating in PJM and meets its capacity obligation through the FRR, said Stephanie Hodgin, deputy director of communications and media for the Indiana Utility Regulatory Commission.
“Indiana also has rural electric membership cooperatives and municipal electric utilities that may participate in PJM; however, the IURC does not have information on how FERC’s MOPR order may or may not affect them,” she added.
Tennessee
Only a small portion of the northeast corner of Tennessee is within PJM. It is served by AEP’s Appalachian and its affiliate Kingsport Power, according to Tim Schwarz, chief of the communications and external affairs division for the Tennessee Public Utility Commission.
AEP, which serves about 47,000 customers and does not generate any power in the state, is exempt from the MOPR because it uses FRR.
Kentucky
Four Kentucky utilities participate in PJM, including AEP’s Kentucky Power and Duke Energy Kentucky, which use the FRR, and Big Rivers Electric, which is an “other supplier” in PJM but participates in the market through MISO.
Only East Kentucky Electric Cooperative participates in PJM’s capacity market, according to Andrew Melnykovych, director of communications for the state’s Public Service Commission. In its request for rehearing, EKPC called the expanded MOPR a “frontal attack” on practices used by cooperatives for decades.
EKPC said FERC’s ruling was “the most drastic and likely most destructive measure taken by the commission to date” in its attempt to transform PJM’s “resource adequacy market away from a residual capacity auction … to a mandatory sole source for PJM and its LSEs to meet regional capacity obligations.” (See MOPR Ruling Threatens to Upend Self-supply Model.)
Michigan
The only Michigan utility in PJM is AEP’s I&M, which uses FRR.
“It’s a very minimal impact, if anything,” said Matt Helms, spokesman for the Michigan Public Service Commission.
North Carolina
Dominion North Carolina is the only FERC-jurisdictional utility regulated by the North Carolina Utilities Commission. Dominion, which serves about 120,000 customers in the state, uses FRR. Only about 5% of North Carolina’s load is in PJM.
