FERC last week accepted six revised power purchase agreements among Entergy subsidiaries following Entergy Arkansas’ withdrawal from the company’s multistate system agreement.
The company sought in May to amend the PPAs, each of which had been previously filed with FERC because they are being transferred under provisions of the company’s tariff and involve the Grand Gulf Nuclear Station in Mississippi. Under the tariff that replaces the longstanding Entergy system agreement, the resale of power purchased from Grand Gulf must earn FERC approval.
Entergy Arkansas withdrew from the agreement in late 2013 when it joined MISO; the rest of the company’s Gulf Coast operating companies followed suit and set staggered dates to abandon the agreement, prompting Entergy to create a company-wide tariff that governs PPAs among its affiliates. (See FERC OKs 2018 Entergy System Agreement Exit.) The system agreement had been the basis for planning and operating the Entergy utilities’ generation and transmission facilities as a single system since 1982.
Grand Gulf station | Entergy
In accepting the amended PPAs, the commission determined that the language is similar to Entergy’s previously approved agreements and in compliance with Nuclear Regulatory Commission requirements (ER17-1160, et al.). In addition to Entergy Arkansas, the PPAs include Entergy Louisiana, Entergy New Orleans and Entergy Mississippi.
The commission also directed the company to submit a compliance filing specifying the date on which the amended PPAs began to fall under the new tariff rather than the system agreement. FERC noted that Entergy may have meant to fill in Dec. 19, 2013, the date of Entergy Arkansas’ withdrawal from the agreement.
The commission’s order makes the PPAs’ acceptance official. FERC staff had provisionally accepted the company’s filing in June when the commission still lacked quorum.
FERC Orders Compound Interest Refund in Entergy Bandwidth Issue
Entergy’s fading system agreement was at the center of another FERC ruling last week when the commission rejected a compliance filing the company made to provide refunds on the bandwidth payments it received from its operating companies (ER10-1350-006). Entergy submitted the filing a year ago to comply with a commission order to calculate interest on refunds related to the payments. (See FERC: Further Compliance Filings for Entergy, MISO.)
FERC determined the company miscalculated the interest on the refund due back to its Louisiana affiliate. In February 2016, Entergy refunded Entergy Louisiana $27 million in payments, paying the principal but not the interest, and recording the amount in its refund compliance filing. The parent company last November additionally refunded compounded interest, but only up until the Feb. 16 principal payment date. The Louisiana Public Service Commission noticed that the company did not pay interest on the initial missing interest payment and protested the filing, asking that interest-on-interest payments of $25,761 be made for most of 2016.
Entergy argued that interest should have only been calculated from the date of collection until the date refunds are made.
FERC last week ordered another compliance filing, ruling that the company must “calculate interest compounding on the interest component of the payments at issue until the date the interest payment is actually made.”
Entergy’s allocation of production costs among its half-dozen operating companies under its system agreement has been a source of disagreement for a decade. Payments are made annually by the company’s low-cost operating companies to the highest-cost company in the system, using a “bandwidth” solution that ensures no operating company has production costs more than 11% above or below the system average.
An appellate court ruling remanding back to FERC its 2013 order on PJM’s minimum offer price rule (MOPR) has created disagreement among stakeholders about how to move forward.
PJM requested in October that FERC approve its initial 2012 filing on the issue (ER13-535). The RTO had submitted a “hard-fought compromise package” that included two new categorical exemptions to the rule and eliminated a unit-specific one. FERC rejected the initial proposal but said it would approve it if PJM retained the unit-specific exemption and reduced a proposed three-year imposition of the MOPR on affected units to the existing one-year mitigation.
FERC approved PJM’s amended filing, but several stakeholders challenged the action and the D.C. Circuit Court of Appeals ruled in July that FERC overstepped its legal authority in telling the RTO what it would accept. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)
PJM asked FERC to, on remand, “simply accept PJM’s original Section 205 proposal, unchanged, as just and reasonable.”
The commission’s requirements on the unit-specific exemption and mitigation period “have had no practical impact … on the auction results in the five annual auctions conducted since the commission’s initial order in this case,” PJM said in its Oct. 23 request.
FERC’s concern was “to catch possible future competitive offers that might fall through the cracks theoretically left by the two categorical exemptions,” PJM said, but five Base Residual Auctions and nine Incremental Auctions have occurred since then with no unit-specific offers submitted.
“We now know that those cracks, if they exist at all, are quite narrow,” PJM said. The commission can conclude that its “concern” about competitive offers slipping through “was overstated.”
Stakeholders were split on their opinions of PJM’s request. The Independent Market Monitor, NRG Energy and Public Service Enterprise Group argued that FERC had already rejected the RTO’s 2012 filing. Several generators said the filing should be approved but with a requirement that PJM address deficiencies in its MOPR within 90 days.
PSEG’s Sewaren 7 natural gas generator is expected to go into operation in summer 2018. | PSEG
American Municipal Power and Old Dominion Electric Cooperative supported PJM’s plan, with ODEC arguing that the new self-supply and competitive-entry exemptions “must be maintained.”
“Otherwise, [load-serving entities] like ODEC face the unreasonable prospect of their loads paying twice for capacity, once through the investment in resources (owned or purchased bilaterally outside of the [Reliability Pricing Model] construct), and then a second time when those resources do not clear in the RPM auctions because they are unreasonably subject to the MOPR,” ODEC said.
FERC “upset the balance that had been struck by conditioning acceptance” on retaining the unit-specific exemption, it said.
“The commission’s authority to issue an order in the form PJM recommends is not in question,” AMP said. “That PJM’s stakeholders overwhelmingly supported the competitive-entry exemption and the self-supply exemption should weigh heavily in the commission’s consideration of how to proceed on remand.”
The PJM Power Providers Group (P3) said it supported the RTO’s request “in the interest of market certainty” and noted that other dockets exist or likely will come before FERC on the topic “to address broader issues.”
Several P3 members, including Calpine, Congentrix Energy Power Management, Dynegy and Eastern Generation, agreed with the group’s comments but voiced concern about “deficiencies with [PJM’s] MOPR process” and argued that FERC should give the RTO 90 days to address them.
“Recognizing that threats may exist to the efficient operation of PJM’s wholesale markets is an understatement, to say the least,” the generators said, noting the zero-emission credits for nuclear generation in Illinois and proposals for similar subsidies in Ohio, Pennsylvania and New Jersey.
“PJM must have in place an effective MOPR, applicable to both new and existing resources, to combat the very real threat of these state actions. It is incumbent on the commission to take decisive action on the issue of state-subsidized existing units by extending the MOPR to those units. Continued failure to do so is an abdication of the commission’s duties and responsibilities.”
PJM had acknowledged in its filing that its finding about unit-specific exemptions “does not rule out the possibility of future low-price competitive offers that do not qualify for the categorical exemptions” and that “that the nature of the potential threats to the efficient operation of its wholesale markets may have evolved since 2012, and accordingly, prospective changes to its MOPR, or its Tariff more generally, may be warranted — but not in this proceeding. PJM has an ongoing stakeholder senior task force considering such issues.”
The Monitor argued that FERC was correct to deny PJM’s original filing and that the court’s order didn’t vacate that decision.
“The commission’s determination that the MOPR was not just and reasonable without an exception for unit-specific cost review was logical,” the Monitor said. “The motion should be denied for the same reasons that the commission denied it initially.”
NRG and PSEG agreed that the court decision required PJM to return to its original MOPR rule, but split on what other mitigations are necessary. NRG said PJM should just move on with the original rule without retroactively examining the auctions since it was replaced. PSEG suggested a method to recreate the auctions and compensate affected participants.
PJM had argued that because all resources that sought a MOPR exemption pursued categorical exemptions rather than unit-specific ones, the auctions had not been impacted.
“NRG sees something very different: clear evidence that PJM’s proposed MOPR is toothless and does nothing to prevent uneconomic entry,” NRG said in its filing. “New entrants are making an already over-supplied market even more over-supplied — and are being totally exempted from any review to ensure that their low bids are economically justified. … In order to have a meaningful MOPR that protects the market from artificially low prices, there simply cannot be categorical exemptions so broad that any new generator could drive a truck through them.”
PSEG argued the issue is whether the categorical exemptions impacted auction prices differently than how the pre-existing unit-specific one alone would have. PJM should recreate the auctions using commission-approved proxy values for units “inappropriately granted one of the two categorical exemptions to establish the ‘but for’ auction price,” PSEG said.
Any “underpayments” that result would be payable to affected generators by zone; “however, the new entrants that relied upon the no-longer-available MOPR exemptions for a particular auction year would not be eligible for any additional amounts.”
FERC denied Baltimore Gas and Electric’s bid to recover $38 million in taxes deferred over decades, saying that “contrary to BGE’s assertion, we find that utilities do not have unfettered discretion to defer these tax amounts on their books for decades without timely seeking regulatory approval to collect them.”
BGE sought approval for three adjustments to its formula rate for how taxes are recovered (ER17-528). The revisions would have returned $4 million to customers related to tax rate changes but also collected approximately $42 million. The collections broke down to $29 million related to deferred tax liability for the equity component of allowance for funds used during construction (AFUDC) and approximately $13 million for an accounting adjustment to claw back tax benefits that were flowed through to customers at the time they originated, rather than relying on BGE’s current tax normalization methodology that collects tax liabilities and distributes benefits over time.
FERC said BGE took too long to make the adjustments.
“Although these accumulated amounts may represent legitimate deficiencies in accumulated deferred income taxes, we find that these deficiencies should have been captured in BGE’s formula rate since its implementation in 2005,” the commission said.
FERC cited 1981’s Order 144, which stipulated that all utilities use the normalization methodology. It additionally required them to begin the process of accounting for any tax excesses or deficiencies through rate adjustments. The order called for companies to make the adjustments in their next rate case following the order’s implementation or at least “within a reasonable period of time.”
“Had BGE properly addressed the tax deficiencies when its formula rate was initially filed in 2005, BGE may have been allowed to collect some portion of these deficiencies over the remaining life of the underlying plant assets that created the deficiencies,” the commission said.
BGE’s failure to “match” tax effects with the revenues that created them in a timely manner was “particularly noticeable” regarding the flow-through items because they are related to assets from prior to 1976, “most of which have been either fully depreciated or retired by 2016.”
“It is unclear if there are any relevant assets left on BGE’s books in 2017 to match the amortization period over the next 28 years,” FERC said.
RENSSELAER, N.Y. — NYISO year-to-date monthly energy prices averaged $34.89/MWh in October, a 4% increase from a year earlier, Senior Vice President for Market Structures Rana Mukerji told the ISO’s Business Issues Committee (BIC) on Wednesday.
Locational-based marginal prices (LBMPs) averaged $28.35/MWh for the month, down 4.1% from September and up 27% from October 2016. The ISO’s average daily sendout was 398 GWh/day, compared with 437 GWh/day in September and 391 GWh/day a year earlier.
New York natural gas prices rose nearly 4% in October, averaging $2.36/MMBtu at the Transco Z6 hub. Prices were double those of a year ago, although still “historically low,” Mukerji said.
Distillate prices rose 14.9% year on year, with Jet Kerosene Gulf Coast averaging $12.30/MMBtu, down from $13.40 in September. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $12.86/MMBtu, compared with $12.80 in September.
The ISO’s local reliability share was 14 cents/MWh, down 2 cents/MWh from the previous month, while the statewide share remained unchanged at -50 cents/MWh. Total uplift costs were lower than in September.
External Capacity and Imports
Reviewing the Broader Regional Markets report, Mukerji highlighted NYISO’s effort to clarify the minimum deliverability requirements for PJM resources seeking to export into the ISO’s installed capacity (ICAP) market. He noted that during an October ICAP Working Group meeting, the ISO provided an overview of the current approach to assessing the deliverability of external resources into the New York Control Area for purposes of qualifying eligible capacity within the market.
NYISO is also modifying the documentation requirements for capacity imports across the PJM AC ties, with a planned effective date of May 1, 2018. The process change will require submission of documentation on the day the ICAP Spot Market Auction results are posted to demonstrate that external resources with capacity awards relating to imports across the PJM AC ties have firm transmission service for the month.
The ISO also is considering whether an Atlantic Economics proposal, or an alternate formula-based model, may be viable for calculating locality exchange factors (LEFs). NYISO has engaged General Electric to investigate the viability of potential refinements to the current methodology for determining LEFs.
NRG’s Kelli Joseph Elected Vice Chair
The BIC last week elected Kelli Joseph, NRG Energy’s director of market and regulatory affairs, to serve as vice chair of the committee for the 2017/18 term.
Joseph advocates on behalf of NRG at NYISO and the New York Public Service Commission and worked at NYISO as a grid operations senior analyst prior to joining NRG in 2014. She attended Houghton College and earned a Ph.D. in political economy at the University of Virginia and an international MBA at the IE Business School in Spain.
BIC Approves Developing New LCR Methodology
The committee also voted for NYISO to continue developing a new methodology to determine locational capacity requirements (LCR), subject to updating the net cost of new entry curve to be used in the ISO’s baseline assumptions.
Zachary Stines, associate market design specialist for the ISO, told the BIC that the new optimization methodology results in increased stability as generation changes occur within the system. He said the ISO sought to develop capacity requirements that maintain reliability while minimizing the total cost of capacity at the level of excess condition, i.e., the applicable minimum installed capacity requirement, plus the capacity of the relevant peaking plant.
| NYISO
David Clarke of the Long Island Power Authority opposed the proposed methodology, saying it is based on an unrealistically low estimate of net CONE on Long Island.
Mark Younger of Hudson Energy Economics wanted the ISO to commit to refreshing the database with the current net CONE values so that the optimization uses the same CONE as that used in the energy market. Stines said the ISO would do so early in 2018.
Questions on Integrating Public Policy Task Force
NYISO Senior Manager for Market Design Michael DeSocio’s progress report from the Integrating Public Policy Task Force (IPPTF) elicited a half-hour of stakeholder dissension over the ISO’s definitions of “harmonizing” versus “accommodating” public policy.
NYISO and the New York PSC jointly formed the task force in October to create a forum for stakeholders to discuss pricing carbon into the wholesale electricity market along the lines described in a previous Brattle Report. (See New York Stakeholders Question Carbon Pricing Process.)
| NYISO
Representing New York City, attorney Kevin Lang of Couch White, expressed concerned about the lack of transmission planning in the task force process, given the amount of offshore wind being sought by the state. Younger agreed, saying that new transmission will be required for the grid to absorb increased amounts of new renewable energy and that nobody should assume the issue has been settled.
“Even if you price carbon, it’s unlikely to be high enough to incent renewables development,” said NRG’s Joseph. “We need to be talking about design changes; that’s why we proposed a two-tier market. Not instead of carbon pricing, but while we are at it, look at capacity markets.”
In response to a question about whether the task force had a coherent mission, DeSocio said it is focused on fulfilling the goals of New York’s Clean Energy Standard.
The IPPTF’s next public hearing is scheduled for Nov. 20 in Albany.
Pacific Gas and Electric has signaled it will challenge a California administrative law judge’s recommendation that the utility be granted only about 10% of the $1.8 billion in recovery it requested for the retirement of the Diablo Canyon nuclear plant in San Luis Obispo County.
The California Public Utilities Commission has scheduled final oral arguments for Nov. 28 over a joint settlement agreement filed by PG&E and interest groups regarding the plant, which the utility has proposed to shut down when its federal operating licenses expire in 2024 and 2025. PUC Administrative Law Judge Peter Allen on Nov. 8 approved the retirement plan but proposed that PG&E be allowed to recover about $190 million of the nearly $1.8 billion in requested rate recovery detailed in the settlement. Allen’s decision has no weight until voted upon by the five-member commission.
“While the proposed decision preserves several elements of the joint proposal, it differs in regards to certain key areas, including the employee, community and energy replacement programs,” PG&E said in a Nov. 8 statement, adding that it “strongly disagrees with these proposed adjustments.”
The utility said it thinks the proposed settlement is appropriate, and “we look forward to advocating for this in our comments back to the CPUC and during final arguments at the end of November.”
PG&E first filed the settlement it forged with environmental, labor and anti-nuclear groups in August 2016. It would replace output from the 2,240-MW facility with a portfolio of renewable resources, energy efficiency measures and energy storage. (See PG&E Files Diablo Canyon Shutdown Request.)
The utility requested approval to recover $1.3 billion for energy efficiency procurement, $363 million for employee retention and retraining, $85 million to mitigate impacts on the local community, $19 million for license renewal activities, and unspecified canceled capital project costs.
Allen’s proposed decision rejected the energy efficiency money and approved $172 million for employee retention and retraining, $19 million for license activities, and a portion of canceled project costs. He recommended that issues related to the procurement of replacement capacity be handled in an integrated resource planning proceeding.
The judge sided with the Office of Ratepayer Advocate (ORA) and Energy Producers and Users Coalition (EPUC), which noted that state policy already requires PG&E to first meet its resource needs through all available energy efficiency resources. PG&E has proposed to increase its approved energy efficiency goals by more than 53% for 2018-2024, which ORA and EPUC indicated would only be possible by lowering PUC’s cost-effectiveness threshold.
“ORA and EPUC make a good point — it is not clear that PG&E could actually procure over 50% more energy efficiency than a goal that is already supposed to include all cost-effective energy efficiency (unless PG&E procures energy efficiency that is not cost effective),” Allen said. “There is no reason to approve a $1.3 billion rate increase for a proposal that will most likely either fail to achieve its goal or will achieve a goal not worth reaching.”
Allen’s Nov. 8 proposed decision also took issue with a settlement provision that would replace the property tax paid to San Luis Obispo County with $85 million in ratepayer money, arguing that PG&E has no obligation to pay the taxes once the facility shuts down and that utility rates should be used for utility — and not government — services.
PG&E proposed shutting down both units at Diablo Canyon by 2025.
PG&E has proposed to replace Diablo Canyon with greenhouse gas-free resources in three tranches: 2,000 GWh of energy efficiency; 2,000 GWh of energy efficiency and renewables; and a voluntary 55% renewables commitment from PG&E. The utility said additional resource procurement could be required to replace Diablo Canyon, the two units of which began operating in 1985 and 1986. The plant is used as a system resource and not for local reliability, and its output is exported on the bulk transmission system.
The settlement is supported by the Natural Resources Defense Council, Friends of the Earth, Environment California, International Brotherhood of Electrical Workers Local 1245, Coalition of California Utility Employees and the Alliance for Nuclear Responsibility.
Protests against the settlement were filed by California Large Energy Consumers, Californians for Green Nuclear Power, EPUC, several cities, the Sierra Club, Shell Energy North America, SolarCity, public interest groups and others.
After a 25-day public comment period, the ALJ’s proposed decision will be forwarded to the PUC. PG&E has requested that the commission reach a decision on the settlement by the end of the year.
MARLBOUROUGH, Mass. — ISO-NE is “in the final throes” of a stakeholder process to reach agreement with the New England Power Pool on a two-settlement market construct to integrate state-sponsored renewable energy resources into its wholesale market, CEO Gordon van Welie said last week.
Speaking at the Northeast Energy and Commerce Association’s Power Markets Conference on Nov. 14, van Welie said, “We plan to bring this to a vote at the upcoming NEPOOL [Participants Committee] meeting in December and then are going to file it [with FERC] in the December time frame.” He referred to the conference as a “quasi NEPOOL meeting,” considering that most attendees also participate in the organization’s stakeholder meetings.
As part of NEPOOL’s Integrating Markets and Public Policy (IMAPP) process begun in 2016, the RTO this year came up with a two-tier market concept called Competitive Auctions with Sponsored Policy Resources (CASPR). (See “CASPR May Exclude New Resources from Substitution Auction,” NEPOOL Markets Committee Briefs.)
Van Welie said CASPR “is creating the opportunity for existing resources that have capacity obligations and that wish to retire to trade out their obligation with incoming state-sponsored resources in a manner that doesn’t affect price formation in the primary auction.”
“As much as the states would like to see that their renewable contracts get automatic credit in the Forward Capacity Market, that would run counter to the other objective that we have (aside from reliability), which is to maintain price formation in the capacity market,” van Welie said. “CASPR will tend to accelerate the retirements of the marginal units, with significant payout opportunities for some of the older resources that wish to retire.”
Seeking Broad Consensus
Sebastian Lombardi, an attorney with Day Pitney who serves as counsel to NEPOOL, said, “We’re hoping for consensus because NEPOOL can’t have an affirmative institutional position without some broad agreement being reached. Broad agreement has not been reached yet.”
The NEPOOL Markets Committee considered a number of modifications to CASPR, he said.
“Although some of those proposals were close to getting broad support, at this stage none of them have reached the requisite support needed for NEPOOL approval, but sometimes three weeks is a lifetime in a stakeholder process,” Lombardi said. “Folks have been discussing this for a long time and we’re now getting to the endpoint and folks are going to have to make some hard decisions.”
Christopher Geissler, an economist at ISO-NE, said that while a number of stakeholder amendments did not pass at the Markets Committee, they could be voted on again by the Participants Committee. For context, he said, stakeholder support in this scenario means a 60% vote by the committee.
“We’ve made a number of changes to our design on the basis of stakeholder feedback and we continue to elicit and evaluate stakeholder ideas,” Geissler said. “However, while stakeholder support is important, we also feel that the design has to meet the objectives that we set out at the beginning of the process, so just because something receives stakeholder support doesn’t mean that it’s something the ISO will support. It also has to be good market design.”
Lombardi added that New England has a unique set of rules and governance arrangements whereby “if NEPOOL were to support something that was different from what the ISO wants to file, more than one proposal could be teed up to FERC on equal legal footing, which would provide FERC some optionality.”
Not So Fast
Brett Kruse, vice president of market design for Calpine, gave the NEPOOL talks a 30 to 40% chance of success and described some of the obstacles to reaching an agreement.
For example, the current renewable technology resource exemption is being challenged in federal court, with briefings due Jan. 12, 2018. Kruse said only a couple generators support the CASPR proposal as is, but more would support it if it was modified to protect price formation. He suggested that Calpine’s bid shading amendment might win ISO-NE support, particularly as it is already supported by the RTO’s internal and independent Market Monitors.
In addition, generators do not support an amendment proposed last week by the New England States Committee on Electricity for a 200-MW “backstop” allowing entry of sponsored resources around CASPR in perpetuity.
“I look at CASPR as an interim solution; I think that’s the way the ISO has talked about it,” Kruse said. “I’m not that positive on the long-term outlook for markets here in New England. Now will that be five years, 10 years? I can’t see it getting to 20 years. But even if we get something like this done, I think all that we’ll be able to do is slow down the convergence.”
Although Calpine is expanding its retail and commercial load-serving business in New England, the company is not looking to develop any new generation other than wind because of Massachusetts’ solicitation for thousands of megawatts of clean energy.
“The fundamental stuff shifted because we tend to take the state at their word,” Kruse said. “A goal is one thing, a mandate is another, a law is something else. A lot of people I talk to believe there’s no way they’re going to be able to build that much offshore wind — it’s crazy, it will cost way too much money. But when the legislature puts it in a law and the governor signs it, we believe. So we believe all that stuff’s going to come in that shifts all the underlying fundamentals.”
Regulatory Risk Perceptions
Todd Schatzki, vice president of Analysis Group, said the region’s desire to transition to a low-carbon future is driving the market. “But moving from desire to developing market designs and public policies that send effective price signals — we’re not there yet. Now we have the dilemma of legislators entering the markets through the back door,” he said.
Dan Dolan, president of the New England Power Generators Association, which represents 80% of the region’s generating capacity, said regulatory risk is what he hears about most from his members.
“It’s the uncertainty of what’s next: What is the next large-scale procurement coming from a state?” Dolan said. “It’s those issues that then make investing in the tens of billions of dollars in assets that we have here very challenging. … I challenge you to find another sector of the economy that does not have guaranteed rate recovery and a rate of return investing any multiple close to that in new infrastructure in New England. We are the last major manufacturers in New England.”
Darren Matsugu, senior manager for market design and integration at the Independent Electricity System Operator in Ontario, said his ISO has only 8% natural gas-fired generation, compared to nearly 50% in New England. The Canadian province’s Legislative Assembly voted in 2003 to phase out coal, and the last coal plant there closed in 2014.
“The majority of our system’s installed capacity comes from very low marginal cost resources, whether it’s from hydro resources, from nuclear, or from solar and wind,” Matsugu said. “Along with the impact of lower natural gas prices, we’ve seen a significant decrease in the level of our wholesale energy prices. Often at the shoulder periods we fluctuate in the $0 to $10/MWh range.”
Beth Garza, director of ERCOT’s Independent Market Monitor and vice president at Potomac Economics, provided some perspective for the New Englanders struggling to achieve or accommodate the public policy goals set forth by the region’s six states.
“Unlike other areas that have centralized clean energy goals, Texas has not had that, but the markets are responding as if we did,” Garza said. “Texas has become a leader in wind generation simply because the zero-cost resource offers investors a good chance to make a profit.”
FERC last week approved two requests by FirstEnergy Solutions (FES) to sell power to Potomac Edison and West Penn Power. All three companies are subsidiaries of FirstEnergy (ER17-1267, ER17-1272, ER17-1559). The agreements are retroactive to June 1.
FES won the bids through competitive solicitations from the affiliates to serve customers who do not take service from competitive retail suppliers. Potomac serves customers in Maryland and West Virginia; West Penn’s customers are in western Pennsylvania.
FERC uses standards set out in its 1991 Edgar Electric Energy (ER91-243) and 2004 Allegheny Energy Supply rulings (ER04-730) to prevent utilities from self-dealing. The commission determined that the affiliate deals met the four criteria of transparency, definition, evaluation and oversight.
CARMEL, Ind. — MISO will next month submit two filings with FERC to further refine its new generation interconnection process, while a third filing early next year will seek to facilitate connections for merchant HVDC lines, the RTO said last week.
MISO Manager of Resource Interconnection Neil Shah said the two near-term filings — one to limit the amount of time interconnection customers can change their megawatt values and the other to update the interconnection request form — serve as a “clean up” to implement details the RTO missed in its filing to redesign the queue.
The first revision would shorten the period for generation owners to change the capacity volume associated with network resource interconnection service (NRIS), moving the final selection to the second decision point in the queue rather than just before MISO begins an interconnection facilities study.
The second change would update the interconnection request form that prospective generation owners fill out upon entering the queue to include options for external NRIS and MISO’s fast-track request option for small generating facilities.
Shah said he did not expect the filings to elicit protests from stakeholders, who offered no public comment on the changes during a Nov. 15 Planning Advisory Committee meeting.
Wind on the Wires’ Natalie McIntire said she hoped the filings were as harmless as Shah characterized. “It’d be nice to finally have some queue changes that are uncontested,” she joked.
The apparently benign queue changes come as some stakeholders are already calling for a fundamental reconsideration of the interconnection queue not even a year after the RTO rolled out a redesign of the process.
Earlier this month, EDF Renewables asked MISO to consider a two-stage queue instead of the RTO’s selected three-stage design, while FERC denied a request to rehear its approval of the new design, which generation developers said should include a fast-tracked queue for vetted projects. (See EDF Asks MISO to Revisit Queue Overhaul.) EDF will return to the Steering Committee in January to make its case for a streamlined queue.
HVDC Interconnection
Another interconnection-related filing in January or February would revise MISO’s Tariff to allow merchant HVDC lines to inject energy into the RTO’s transmission system at certain points of connection. Under the proposed rules, merchant HVDC would advance through the queue much like other interconnection customers and earn injection rights. However, MISO would draw a distinction between “injection rights” and “interconnection rights.” A merchant HVDC owner could only secure injection rights, and its associated generator must also line up in the queue and reference the HVDC injection rights. MISO would then convert the injection rights into interconnection rights for the generator without further queue studies. Only then would the rights be usable to offer energy or capacity into the MISO markets.
In response to a question by Indiana Utility Regulatory Commission adviser Dave Johnston, Shah said there are currently HVDC projects on hold in the queue, most of which are requesting injection rights into MISO.
WOW consultant Rhonda Peters said it’s still unclear how MISO will treat a merchant HVDC line wishing to withdraw from the system and inject into another balancing authority.
“As of now, these procedures are not supported,” Peters said.
Shah said some existing Tariff provisions would allow for withdrawal. “There’s some work needed, but it’s mostly educational in my mind,” he said.
Peters countered that the “thousands of megawatts” that HVDC lines are able to move is “unprecedented” and MISO’s current $4,000/MW upfront fee for the definitive planning phase is prohibitively high and will hinder the connection of projects. She asked for MISO to consult with other RTOs about their merchant HVDC interconnect policies.
Shah said he would take those suggestions into consideration and asked stakeholders to provide other input by Dec. 1. More discussion on merchant HVDC interconnection procedures is planned for the December PAC meeting.
FERC last week refused to reconsider how Entergy should calculate ratepayer refunds resulting from Entergy Arkansas’ off-system sales to non-Entergy entities from 2000 to 2009. FERC denied rehearing requests from the Arkansas Public Service Commission, the Louisiana Public Service Commission and Entergy (EL09-61-006).
The order stems from a 2012 ruling requiring the company to make refunds to ratepayers because it improperly allocated lower-cost system energy in off-system energy sales to third-party power marketers and other non-agreement members between 2000 and 2009. The allocation violated the circa-1982 Entergy system agreement, driving up the rates of captive customers of other operating companies by preventing their purchase of the low-cost energy.
Last year, in Opinion 548, FERC ordered a full rerun of Entergy’s intra-system bill that reflects how the purchases should have been priced to determine damages. Final damages have not yet been determined, and the issue is still in hearing procedures. (See FERC Affirms Entergy Refund Order on Off-System Sales.)
The commission also affirmed its 2012 Opinion No. 521, in which it decided that although the opportunity sales in question are not joint account sales — sales to others for the joint account of all of the company’s operating companies — they should be given the same treatment under the company’s responsibility ratio.
Entergy Arkansas’ Mayflower Substation | Entergy
It dismissed the Louisiana PSC’s argument that FERC erred in requiring that the opportunity sales load be excluded from Entergy Arkansas’ responsibility ratio because the subsidiary is solely responsible for the sales.
“The Louisiana commission’s interpretation of Opinion No. 521 ignores the commission’s full findings,” FERC said. “Entergy Arkansas should not have to pay for the capacity used to service the opportunity sales if it did not also have the ability to draw upon the cheaper energy for sales to its own load.”
FERC rebuffed the company’s argument that its remedy was “arbitrary and capricious in deviating from the long line of orders” that held that the system agreement granted each operating company first call on the energy from their generation facilities. “The precedent Entergy cites does not interpret the system agreement with respect to the type of off-system sales at issue in this proceeding,” FERC explained.
FERC also found no merit in the company’s argument that the refund methodology is at odds with provisions of the system agreement that prohibit an operating company from simultaneously buying and selling energy. The commission said Entergy failed twice to point out such a provision in its system agreement.
The commission also declined to decide whether payment for damages should be distributed to ratepayers or shareholders, calling it outside of the scope of proceeding.
California’s utilities are about 2,000 MW short of local resource adequacy (RA) requirements for 2018 according to CAISO, which has asked state regulators to restructure the RA program.
In a Nov. 13 report, the ISO evaluated the 2018 resource adequacy plans of Pacific Gas and Electric (PG&E), Southern California Edison (SCE), and San Diego Gas and Electric (SDG&E). RA requirements are broken down by Transmission Access Charge (TAC) areas, which are based on the service areas of the state’s three investor-owned utilities.
“The ISO’s evaluation has identified individual [load-serving entity] and collective capacity deficiencies in several Local Capacity Areas in the PG&E, SCE and SDG&E TAC Areas,” the ISO said.
San Diego Gas & Electric’s Encina plant
Because CAISO evaluates RA for local load pockets as well as the overall system, capacity procurements made through the California Public Utilities Commission RA program don’t always align with the reliability needs identified by the ISO. As a result, the ISO at times depends on out-of-market payment schemes to keep fossil-based resources online to support local reliability, a practice that has created tension among market participants and concern at the ISO’s Board of Governors. (See Board Decisions Highlight CAISO Market Problems.)
The CPUC’s RA program requires an LSE’s capacity to be available to CAISO when and where needed. There are three types of RA: system resources, local resource adequacy and flexible resources, a category added in 2015 to help manage the changing resource mix.
Deficiencies Abound
The CAISO Tariff allows LSEs and electricity suppliers to address individual capacity deficiencies before the ISO obtains “backstop” procurement. The LSEs are not required to purchase capacity from a specific resource to meet a local need, but can purchase from any resource located locally or with adequate transmission.
“However, to the extent that the aggregate LSE showings do not comprise the right mix of resources that meet the LCR [local capacity requirement] criteria and ISO effectiveness needs, a deficiency may exist that would cause the ISO to procure individual and/or collective backstop capacity,” the ISO said.
Such deficiencies did indeed show up in CAISO’s findings. The report found an local capacity resource (LCR) shortfall of 1,072 MW in the PG&E TAC, nearly all of which represents a “collective deficiency” to be addressed by all LSEs within the area. Individual LSE deficiencies represent just 72 MW of the total.
PG&E area shortfalls include a 574 MW need in the South Bay-Moss Landing sub-area in the San Francisco Bay Area, and a 422 MW need in the “South of Palermo” section of the Sierra Area.
Pacific Gas & Electric’s Moss Landing Gas-Fired Power Plant
The SCE area needs an additional 317 MW in the Moorpark portion of the Big Creek-Ventura area, the report shows.
CAISO’s 2018 assessment for SCE includes generators that are set to retire in 2020 because of once-through-cooling rules, including a combined 2,076 MW of capacity from NRG Energy’s Mandalay and Ormond units. The proposed replacement, NRG’s proposed Puente natural-gas fired plant, is strongly opposed by environmental groups and some in the local community.
NRG asked the California Energy Commission to suspend the permit application after two members of the agency recommended the full commission deny the permit for the plant. (See NRG Signals Pull-out on Proposed Puente Plant.)
In SDG&E’s TAC, the overall deficiency is 560 MW, with individual LSE deficiencies accounting for 475 MW of the total.
Reforms Needed
Separately from the Nov. 13 report, the ISO recently joined with IOUs in asking the CPUC to make fundamental changes to the RA program, which is meant to procure sufficient resources to meet reliability needs. CAISO filed comments Nov. 9 in the CPUC’s latest RA proceeding saying it agrees that the commission should “establish a separate track of this proceeding to address fundamental resource adequacy issues.”
The IOUs want the CPUC to simultaneously consider the interplay among the CAISO market structure, the RA construct and state policy goals.
CAISO and others cite the increasing number of reliability-must-run agreements that the ISO has been forced to sign with natural gas units, the most recent being Calpine’s Metcalf Energy Center. CAISO said “the rapid transformation and nature of the resource fleet and other factors are exposing fundamental inadequacies in the current resource adequacy framework.”
But the ISO also noted that RMR designations “are a result of these events, not the root cause, and they highlight the need to comprehensively re-examine the resource adequacy program.”
