MISO will not implement improved combined cycle modeling until it has a new market platform in place, stakeholders learned last week.
The RTO plans to initially offer seven different modeling options, including combinations of combustion and steam turbines, but operators of combined cycle generators must now wait until 2022 for the improved model.
MISO last month completed a conceptual design for the more sophisticated modeling that can accommodate different combinations of combined cycle units and their dependencies. And while the RTO originally hoped to have software in place by 2020 to offer new modeling options, its outdated market platform is limiting what improvements it can undertake. (See “Limited Improvements for Old Platform,” MISO Platform Replacement Risks Delay, Budget Overrun.)
Speaking at a July 12 Market Subcommittee meeting, MISO market analyst Chuck Hansen said the conceptual design will still be turned over to a third-party vendor for more in-depth work during the 18-month pause on the project. He said most of that work is not dependent on having the new market platform operational and can be advanced without delay. He also said MISO’s legal team will begin drafting Tariff language during the hold.
MISO Market Design Engineer Congcong Wang said the proposal will represent one of the most complex participation models in the RTO’s energy and ancillary service markets to date. The RTO has predicted the new model could save an annual $14 million to $34 million in production costs.
MISO currently has 44 combined cycle gas turbine resources, with more predicted to come online. Since its markets began, MISO has been modeling combined cycle units as either a single aggregate resource or as individual units.
CAISO prices surged in the first quarter on falling hydroelectric output and increased costs for natural gas, the ISO’s Department of Market Monitoring told stakeholders Wednesday.
Speaking during a call to discuss the department’s quarterly market issues report, Amelia Blanke, manager of monitoring and reporting, noted that the ISO is accustomed to a pattern of lower prices in the first two quarters followed by rising prices later in the year.
“That was not the case in Q1 of this year,” Blanke said.
Average five-minute prices jumped 50% ($12/MWh) compared with the same period a year earlier, while 15-minute prices rose 20% ($6/MWh), putting prices close to levels seen last fall. Day-ahead prices were also up about $6/MWh during the quarter (See chart).
Average Monthly Price | CAISO Department of Market Monitoring
“One of the factors that influenced this include the availability of hydro generation,” Blanke said, adding that hydro output was just under half the level seen in the first quarter of 2017.
Despite heavy snowfall in March, snowpack in California’s Sierra Nevada mountains ended the winter at just 52% of normal. That was well short of the near-record snowpack many areas reported last year, which required dam operators to release water from reservoirs earlier than usual.
Increased congestion also provided a boost to Southern California day-ahead prices, adding about $2/MWh to average prices in the Southern California Edison area and $5/MWh in the San Diego Gas & Electric area. But the lack of congestion in the north helped reduce Pacific Gas and Electric prices by about $3/MWh.
Tight Gas, High BCR
Tight gas supply was the other key factor driving up power prices, Blanke said. PG&E Citygate gas prices were up 19% over the first quarter of 2017, while SoCal Citygate added 7%, continuing last year’s trend of rising gas prices. (See Gas Costs Drive Sharp Gain in CAISO 2017 Prices.)
“There was a higher frequency of high same-day gas prices and shortage conditions for gas in the southern part of our balancing area,” Blanke said.
Grid operations in Southern California are still hamstrung by limited gas supplies from the Aliso Canyon storage facility north of Los Angeles. As a result of market operations intended to preserve that supply, the ISO paid out $11 million in bid cost recovery (BCR) in February because of a cold snap — the highest BCR expense for any month since 2011, the Monitor said.
Limited gas supply in the SoCalGas system during a period of high gas demand led to both high regional gas prices and the reinstatement of Aliso gas cost scalars, both of which contributed to high real-time bid cost recovery in February, the DMM report said.
CAISO implemented the scalars — or price adders — in 2016 to help ensure that gas-fired generators can recover fuel costs in the face of potential price spikes stemming from the Aliso Canyon limitations. (See FERC Approves CAISO’s Aliso Canyon Response Plan Ahead of Summer.) When activated in the real-time market, the adders boost the commitment proxy gas cost calculation to 175% of the day-ahead gas reference price, while gas prices in the default energy bid calculation are set to 125% of the day-ahead price.
The Monitor has opposed the ISO’s reliance on the scalars, instead recommending the ISO develop the ability to update gas prices in real time.
Hourly System Marginal Energy Prices | CAISO Department of Market Monitoring
“DMM believes that each use of the Aliso Canyon gas adders on default energy bids and commitment costs highlights the problems associated with the use of these adders,” the Monitor said.
The first problem, according to the DMM, is the delay in activating and deactivating gas adders in response to actual conditions.
The second problem is the mismatch between the gas price based on the adders and actual volatility over the same day, the Monitor said.
It noted that bid cost recovery payments totaled $5 million over Feb. 20-23, when SoCal Citygate prices were “significantly high.”
“These events also highlight the need for the ISO to develop the capability to update gas prices used in the real-time market based on same-day gas market price information available each morning, as recommended by DMM” in its comments to FERC after CAISO filed to extend its Aliso provisions. The ISO has defended its use of the adders as a needed, if imperfect, tool. (See Gas Adders a Necessary Tool, CAISO Says.)
Less Negativity
Blanke also pointed to the price impact of the “duck curve,” which illustrates the precipitous drop in net load at midday as solar and wind resources displace higher-cost fossil fuel generation. “As we have throughout last year, you see lower prices in the middle of the day — in all markets — than we do in the traditional off-peak hours,” she said.
But declining hydro output helped reduce the frequency of negative prices in the market, as prices slipped below zero in about 2% of 15-minute market intervals and 4% of five-minute market intervals, compared with 10% and 13%, respectively, a year earlier.
Frequency of Negative 5-minute Prices | CAISO Department of Market Monitoring
“This is highly correlated with a reduction in self-scheduled hydro generation,” Blanke said.
The DMM report noted that a “reduction in self-scheduled generation would result in increased bidding flexibility and reduce the likelihood of negative prices.
The report again called out an issue the DMM has flagged for nearly two years: the continued funding shortfalls stemming from the ISO’s congestion revenue rights auctions. (See Report Shows Continued Losses in CAISO CRR Auctions.) The Monitor pointed out that first-quarter CRR auction revenues came up $43 million short of payments made to the non-load-serving entities that purchased the rights at auction, compared with a $12 million shortfall a year earlier. It was the second largest shortfall for any quarter since 2015.
“Losses in the first quarter represent 38 cents in auction revenues paid to transmission ratepayers for every dollar paid out to auctioned rights holders,” the report said. “Total ratepayer losses from the congestion revenue rights auction since the market began in 2009 surpassed $770 million.”
FERC earlier this month approved the first stage of the ISO’s CRR rule changes, which will limit allowable source and sink pairs for CRR transactions to those that align with typical supply delivery paths. The changes also require annual transmission outage reporting to more closely match day-ahead models. (See FERC OKs Tighter Rules for CAISO CRR Auction.) While the DMM expressed support for the ISO’s rule changes as “an incremental improvement,” the report said it “continues to recommend that the auction process be replaced by a market for financial hedges based on clearing bids from willing buyers and sellers.”
WASHINGTON — The Senate Energy and Natural Resources Committee returned Thursday to the issue of natural gas infrastructure permitting following reports of increasing delays at FERC.
Two former FERC chairmen, James Hoecker (1997-2001) and Joseph T. Kelliher (2005-2009), agreed with J. Curtis Moffatt, general counsel for Kinder Morgan, and James Murchie, CEO of investment advising firm Energy Income Partners, that failing to build adequate pipelines would lead to higher prices for consumers. They also said delays in state and federal approvals cause uncertainty and could discourage down investment.
While these sentiments aren’t new, they came on the heels of a report by Bloomberg on Wednesday that FERC has notified several developers of LNG export terminals that their applications could be delayed by 12 to 18 months as it struggles to deal with its backlog. The commission asked the developers to consider sending private contractors to help, according to Bloomberg’s sources.
In a series of tweets before the story broke, Commissioner Neil Chatterjee suggested better pay for staff and opening a regional office in Houston, “the center of the world” for natural gas.
FERC Chairman Kevin McIntyre told the committee at an oversight hearing last month that the commission has 14 pending LNG applications, up from four in 2007.
McIntyre said the commission has hired private contractors to supplement its workforce and is seeking to hire additional engineers, while also considering reallocating other staff and hiring additional contractors. It also is seeking to improve coordination with the Department of Energy and the Department of Transportation and seeking internal efficiencies.
The panelists at Thursday’s hearing made no mention of commission staffing as a problem. Rather, they mostly offered suggestions for how the commission could more efficiently process pipeline applications.
Kelliher, executive vice president for federal regulatory affairs for NextEra Energy, said FERC could be more transparent in its certificate orders about how it weighs the benefits and adverse impacts of projects. “There is a need to clarify whether and how environmental impacts should be weighed in this balancing, and whether the commission’s environmental review is under the auspices of the National Environmental Policy Act of 1969 or part of the broader public interest determination in the Natural Gas Act,” he said.
Kelliher said the pre-filing process that formerly took six to eight months now takes up to 12, while the certificate process that used to take nine to 11 months now takes two years or longer. “One factor that has contributed to the length of the certificate process is delays in approvals from other federal agencies,” he said. “If these delays are driven by resource limits at these agencies, the cost incurred by these agencies could be reimbursed by pipeline developers in a manner consistent with how the costs of other federal agencies in the hydropower licensing and relicensing process are recovered from hydropower licensees.”
The witnesses, along with several senators, noted that one of the major factors leading to delays is local opposition from environmentalists and landowners.
Murchie said the challenge for regulators was “getting people to understand that, while their land is being taken [under eminent domain], it’s being taken for a greater good, just like it is with a highway.”
FERC is already considering many of the issues discussed at the hearing as it reviews its 1999 policy statement on gas pipeline approvals. (See FERC Outlines Gas Pipeline Rule Review.)
Fears of FERC Deadlock
Committee Chair Lisa Murkowski (R-Alaska) said Thursday’s hearing was prompted by questions on gas and electric transmission infrastructure remaining following last month’s FERC oversight hearing. The Department of Energy’s efforts to provide financial support to coal and nuclear plants took up most of that discussion. (See FERC: No Emergency on Grid.)
“We had all five commissioners here; it was good to see them,” Murkowski said in her opening remarks. “I don’t know, maybe we jinxed the whole thing.”
Murkowski asked Hoecker and Kelliher later in the hearing what they thought the committee should be looking for in Powelson’s replacement.
“I have long advocated that the members of the commission should include some seasoned economists [and] industry engineers, not just lawyers, as much as I love lawyers,” replied Hoecker, executive director and counsel to the trade group WIRES.
“I think they need someone who is comfortable with criticism,” Kelliher said. He also said they should be willing to work with their colleagues, “but only up to a point. It’s not supposed to be 5-0 on everything. It’s OK to dissent.”
Speaking to reporters after the hearing, Murkowski said she has not yet spoken to the Trump administration regarding a nominee, but that she hoped it would make the commission a priority. “You know, we worked very aggressively last year to get the FERC filled up,” she said, “and we’ll just do it again.”
FERC has questions on MISO’s plan to transform its retirement notification process into a catch-all three-year suspension period.
The commission on Wednesday issued a deficiency letter ordering MISO to provide more specifics and an explanation of how it currently plans for suspension and retirements within 30 days (ER18-1636).
MISO this spring proposed that generation owners planning to retire or suspend their units submit a catch-all suspension notice that would have the RTO terminate their interconnection rights after three years of inactivity. (See “Matching Modeling with Proposed Retirement Process,” MISO Planning Subcommittee Briefs: June 12, 2018.)
| MISO
The commission wants to know how MISO’s open-ended suspension plan may affect its process for designating system support resources — those scheduled for retirement that the RTO needs to keep operating for reliability. It asked MISO whether it would model units in the catch-all as three-year suspensions or permanent retirements.
FERC also asked how MISO currently plans for uncertainty in its suspension and retirement process. In a second filing June 21, MISO told FERC that “the future status of a suspended generator is usually unknown, and the requirement to specify an end-date when the return to service is actually uncertain can lead to false assumptions and unreasonable assurance regarding future developments.”
“For planning purposes, what assumptions are made about a generator’s future status under the current suspension provisions, and how will those assumptions change given this proposal?” FERC asked. The commission also asked MISO to explain how generators’ information on their future status may be unreliable and told MISO to provide it with five years of data on the outcomes of generators that entered suspension. FERC also ordered MISO to explain the difference between how it currently treats suspensions versus retirements in transmission planning.
Earlier this year, Economic Studies Senior Engineer Tim Kopp said less than a third of generators return to service after submitting Attachment Y notices to MISO, and that treating all suspending generation as if it will never return would make for better modeling in transmission planning.
FERC also asked if MISO intends to keep its current 26-week minimum notice requirement for Attachment Y filings.
The Montana Public Service Commission’s final order approving Hydro One’s acquisition of Avista includes several conditions designed to prevent the early closure of the troubled Colstrip power plant.
Most notably, the order released late Tuesday points to pledges by corporate executives that the sale would not shorten the coal-fired plant’s operational life. The commission approved the sale by a 4-1 vote on June 12.
Avista owns 15% of Colstrip Units 3 and 4, which were built in the mid-1980s and have a combined net generating capacity of 1,480 MW. Low natural gas prices and regional opposition to coal resources have bedeviled the Colstrip plant in recent years. The plant’s operator, Pennsylvania-based Talen Energy, has been exposed to low power prices on the open market as a merchant generator.
| Montana Public Service Commission
Hydro One’s $5.3 billion acquisition would result in Spokane, Wash.-based Avista becoming a wholly owned indirect subsidiary of the Canadian power firm.
The sale, however, could be in jeopardy. Ontario Premier Doug Ford, who took office June 29, had campaigned on replacing Hydro One CEO Mayo Schmidt and the company’s board of directors. On Wednesday Schmidt retired and the board resigned under an agreement with the province of Ontario, which owns 47% of Hydro One.
Avista said Wednesday it was surprised by the moves, but didn’t say how they might affect the sale.
On Thursday, the Washington Utilities and Transportation Commission, which has yet to approve a settlement agreement filed in March that insulates Avista from Hydro One financial risk, said it wants Avista to address how the management changes will affect the merger.
Avista, an electric and gas utility with customers in Alaska, Idaho, Oregon and Washington, has only 32 retail electric customers in Montana, most of whom are affiliated with the company.
“As a result, a traditional examination of this sale and transfer is not appropriate,” the commission said. “Instead the commission examines this transaction under the public interest standard focusing on the potential impacts on electric generation as a whole in Montana.”
Under settlements in their Washington and Idaho merger dockets, Avista and Hydro One proposed a 2027 depreciation end date for Units 3 and 4, although the units’ expected 50-year lifespans would run through 2034 and 2036, respectively.
The PSC noted that accelerated depreciation is a strategy sometimes used to “facilitate premature retirement of disfavored utility generation assets” and said the practice “potentially creates regulatory and operational risks for the other Colstrip owners, as each has diverging economic incentives to operate their respective share of the assets.”
Colstrip Power Plant | Talen Energy
The other owners of Units 3 and 4 are Talen, Puget Sound Energy, PacifiCorp, Portland General Electric and NorthWestern Energy.
The commission said it approved the transaction because it had been assured “that the accelerated depreciation adopted in other jurisdictions will not result in an early or different retirement date for Colstrip Units 3 and 4.” It noted that the applicants committed that the units’ depreciation “will not deviate from the existing scheduled as currently approved.”
The PSC declined to endorse any depreciation schedule for the units, saying the issue would be addressed, if necessary, in future rate cases or other contested case proceedings before the commission. It asked Hydro One and Avista to provide the commissioners with their integrated resource plans for their Montana generating resources “when those plans became available.”
The commission also reserved the right to incorporate any increased commitments made in other jurisdictions into its own approval.
Along with the states in which Avista operates, the companies must gain regulatory approval of their merger from several federal agencies.
Colstrip’s other two units, owned by Talen and Puget Sound, are scheduled to be shut down by 2022 under the terms of a 2016 agreement with environmental groups. The units were built in the 1970s and can produce 614 MW of energy. (See Puget Sound Energy, Talen Agree to Close Colstrip Units.)
The D.C. Circuit Court of Appeals on Tuesday rejected environmentalists’ claim that FERC is incented to award pipeline certificates because it collects its operating expenses from regulated parties.
Upholding a lower court ruling, the D.C. Circuit also rejected the Delaware Riverkeeper Network’s challenge to FERC’s use of tolling orders to meet its statutory deadlines for acting on rehearing applications (17-5084).
| PennEast Pipeline
The case arose from PennEast Pipeline’s 2015 application with the commission to build a 114-mile natural gas pipeline through Pennsylvania and New Jersey. Riverkeeper, which works to protect the Delaware River and its tributaries, intervened in opposition.
In 2016, while FERC was still reviewing the application, the group filed a complaint in U.S. District Court alleging that the commission’s funding structure creates structural bias in violation of the Due Process Clause of the Fifth Amendment. Riverkeeper also said the commission’s use of tolling orders to satisfy its 30-day deadline for acting on rehearing applications violates its members’ due process rights.
FERC’s Funding Mechanism
Although it receives an annual Congressional appropriation, FERC is required to recover its costs from regulated industries. Riverkeeper said the structure creates improper incentives for FERC to approve more pipelines so that it could seek larger appropriations from Congress.
The district court dismissed the case for failure to state a claim, agreeing with FERC and PennEast that Riverkeeper had failed to identify any liberty or property interest protected by the Due Process Clause.
The D.C. Circuit agreed, citing the Supreme Court’s 1928 Dugan v. Ohio ruling, which concerned a mayor who served a judicial function as one of five members of a city commission. Although the mayor’s salary came from the same general fund in which fines were deposited, the court said the salary was “not dependent on whether [the mayor] convicts in any case or not.”
As in Dugan, the appellate court ruled, “the adjudicator does not control the funds collected,” because FERC’s fees and charges are “‘credited to the general fund of the Treasury,’ not placed into its own coffers. Moreover, the commission’s budget, like the mayor’s salary in Dugan, is fixed by a distinct legislative body.”
“Regardless of how many pipelines FERC may approve, it ‘shall’ charge, for each year, a total amount ‘equal to all of the costs incurred by the commission in that fiscal year,’” the court said.
Due Process Standing
The Due Process Clause forbids the federal government from depriving a person of “life, liberty or property without due process of law.”
Riverkeeper based its due process claim on the 1971 Environmental Rights Amendment to the Pennsylvania Constitution, which guarantees its citizens “a right to clean air, pure water and to the preservation of the natural, scenic, historic and esthetic values of the environment.”
But the court said the amendment “protects not private property rights, but public goods,” and therefore is “too vague and indeterminate to create a federally cognizable property interest.”
In addition, the court said, “the rights created by the amendment bind only state and local government, not the federal government. … For all of these reasons, we conclude that the Environmental Rights Amendment does not create federally protected liberty or property interests, much less ones that FERC could infringe.”
Tolling Orders
The court also rejected Riverkeeper’s challenges to the commission’s use of tolling orders, which grant rehearing for the limited purpose of giving the commission more time to consider such challenges. Riverkeeper complained that the process frustrates judicial review in violation of the Due Process Clause because FERC routinely allows construction to proceed while the rehearings are pending.
“Regardless of whether any protected liberty or property interests are implicated, the commission is not a structurally biased adjudicator, and its use of tolling orders is not facially unconstitutional,” the court said. “We have long held that FERC’s use of tolling orders is permissible under the Natural Gas Act, which requires only that the commission ‘act upon’ a rehearing request within 30 days, not that it finally dispose of it.”
RENSSELAER, N.Y. — NYISO on Monday presented stakeholders details on how a carbon charge would affect locational-based marginal prices (LBMPs) and imports and exports.
The ISO’s market software will not automatically calculate a carbon component of LBMPs because the carbon charge will be included with fuel and other relevant costs when bid into the current structure. Instead, the ISO envisions calculating an after-the-fact estimate of the LBMP carbon impact, said Ethan Avallone, senior market design specialist.
NYISO will report the estimated LBMP carbon impact for each of its 11 load zones, as well as for each external interface proxy bus.
NYISO will report estimated LBMP carbon impacts for each of its 11 load zones, as well as for each external interface. | NYISO
“What information exactly we would use to make these calculations remains to be seen,” Avallone said at a July 9 meeting of New York’s Integrating Public Policy Task Force (IPPTF), the group charged with developing ways to incorporate the cost of CO2 emissions into wholesale energy markets.
“I think we would tie the emission rate to reference levels for the generation resources, so it would be close to the actual,” Avallone said. “But that’s why we say estimates, because it could differ depending on the mix of the fuel, etc.”
He added, “We’re considering whether the estimated LBMP carbon impact could be calculated and posted at a time granularity consistent with today’s LBMPs or if a different frequency would be more appropriate.”
IPPTF Chair Nicole Bouchez, NYISO’s principal economist, said the stability of the emission rates will determine how well the ISO can predict them and the consequences of estimates versus using a detailed cost breakdown.
Marginal Emission Rates
Several complications prevent NYISO from capturing the exact LBMP carbon impact, including the difficulty in identifying the marginal units because of product trade-offs (energy, spin, regulation), and time interval trade-offs involved in the ISO’s look-ahead for the next megawatt of supply, Avallone said.
“To me the big concern is that when you rank the marginal units in terms of costs, break up the costs for different units, that the CO2 component might vary or be rather erratic,” said Pallas LeeVanSchaick of Potomac Economics, the ISO’s Market Monitoring Unit. “First, that might be unnecessarily volatile, and secondly, it would gloss over the impacts of changes in commitment and other things that might not be marginal for one five-minute period, but they’re still marginal.”
Bouchez said, “Just to remind everyone, when we talk about marginal, we mean what unit would you be moving to serve the next megawatt of load, so the unit that is on a fixed schedule would not be the one that would be moved. … Pallas is also thinking a bit larger, which is do you actually change commitment to serve that next megawatt of load?”
Mark Reeder, representing the Alliance for Clean Energy New York (ACE NY), asked, “If a generator is in a zone, do you know how often the carbon on the margin on their bus would likely be quite different from what you get in terms of a zonal calculation?”
“The point to consider is that the generator at the bus that receives the carbon charge (impact in its bus LBMP) must pay the carbon charge for its emissions,” Avallone said.
Carbon Charge on External Transactions
NYISO staffer Nathaniel Gilbraith summarized the ISO’s proposal to rely on a “status quo” carbon pricing approach (referred to as Option 1) that would not consider the specific carbon content in energy trades from out of state. A second option under consideration would evaluate marginal emissions rates from out-of-state imports. (See NYISO Floats Carbon Pricing Straw Proposal.)
The ISO’s first consideration “was to avoid distorting import and export incentives, so that the goal here was to avoid creating a seam at the border where certain resources were compensated differently than others, which would result in a reshuffling of resources or fundamentally change import-export engineering,” Gilbraith said.
Representing New York City, Couch White attorney Kevin Lang said, “If what we’re trying to do is lower carbon emissions, then I’m not sure what the concern is about incentivizing more carbon-free imports into New York. In other words, we should be trying to create a level playing field for imports, just like what we’re doing in-state, where we’re trying to incentivize renewable resources.
“By trying to avoid the carbon character of imports and exports, you’re really creating an unlevel playing field, when what we are really trying to do is create a fundamentally competitive market with anyone to be able to compete on an equal basis.”
“I’d rephrase it as we’re trying to draw a specific border, and I think you would like to expand that border to include a broader set of resources that are potentially subject to the carbon pricing,” Gilbraith said.
Howard Fromer, director of market policy for PSEG Power New York, asked whether the complexity of calculating the marginal emission rate in neighboring areas is still the “driving reason” for the preference for this Option 1.
“There are several reasons why Option 1 is preferable and that’s one of the major ones,” Gilbraith responded.
Erin Hogan, representing the Department of State’s Utility Intervention Unit, said, “A generator that wants to export will have their carbon charge in the LBMP, but yet they’ll get a credit back at the border; so theoretically, if it’s equal, we could be exporting a significant amount of energy outside the state and … that would be the status quo.”
“That’s exactly right,” Gilbraith said. “If a generator is currently competitive with generation in an external control area and would like to export its power, let’s say in New England, it can do that today and they can profit on its relative efficiency compared to New England’s current system.”
“So then the drawback is not necessarily that it doesn’t incentivize cost-effective carbon abatement outside of New York, but that it also could limit the carbon abatement within New York,” Hogan said.
Warren Myers, DPS director of market and regulatory economics, said, “This has become focused on the technical aspect of the quantity of the emissions external to New York, and everybody’s just glossing over the fact that … it’s not just the quantity, it’s the value of carbon.
“In this proposal, New York state, not Pennsylvania, not Tennessee, not Massachusetts, would be saying how much each ton of carbon is worth,” he said. “To my mind, Option 1, for good or ill, minimizes the exporting of a New York state policy when it comes to interstate trade.”
Revised Charter
NYISO Senior Manager for Market Design Michael DeSocio presented a revised charter for the task force, which requires that all proposed analyses and their methodologies go through the ISO’s stakeholder process, starting at the Market Issues Working Group before going to the Business Issues Committee.
The task force next meets July 16 at NYISO headquarters to review draft recommendations for issue Tracks 2, 3 and 4 covering, respectively, wholesale energy market mechanics, policy mechanics and interaction with other state policies.
Exelon announced Tuesday it has signed an agreement to purchase the retail business of bankrupt FirstEnergy Solutions for $140 million in cash, an acquisition that would increase the number of customers for its Constellation unit by almost 50%.
The deal, which must be approved by the U.S. Bankruptcy Court for the Northern District of Ohio, would transfer FES’ retail electricity and wholesale load-serving contracts and other commodity contracts to Constellation.
Constellation currently serves about 2 million customers, including residential customers in 17 states and Washington D.C. | Constellation
In an 8-K filing, Exelon said it will close the deal in the fourth quarter if it is successful in a bankruptcy court-supervised auction. Either party can cancel the transaction if it is not complete by the end of the year.
FES filed for a Chapter 11 bankruptcy restructuring on March 31. (See FES Seeks Bankruptcy, DOE Emergency Order.) On Monday, FES filed a motion seeking approval for bidding procedures and scheduling an auction for Sept. 6, with bids due Aug. 23.
FES’ retail power business serves 900,000 commercial, industrial and residential customers in Michigan, Ohio, Pennsylvania, Illinois, Maryland and New Jersey.
“The purchase would leverage Constellation’s significant retail platform and is in line with our generation-to-load strategy, strengthening our position as the nation’s largest competitive energy supplier and bringing Constellation’s total customer base to more than 3 million residential and business customers across the continental United States,” Exelon said in a statement. “We would honor all existing retail customer contracts and look forward to offering newly acquired customers the same quality products and services that existing Constellation customers currently enjoy.”
FES said in a press release that it expects to receive a net of $280 million in cash from the transaction “subject to certain purchase price adjustments, including the return of cash collateral and collection of retained net working capital.”
“We believe this transaction is another important step in our restructuring plan,” said FES Chief Financial Officer Kevin Warvell. “If approved, we will work with Constellation to ensure the transition of customer accounts is seamless. During the sale process, our daily operations will continue as usual.”
FES hired Barclays Capital early last year in a bid to sell the assets but decided not to proceed after receiving initial proposals from eight suitors. The company said it abandoned the sale because the purchasers’ proposed terms “made it challenging” for the company to complete a deal outside of a bankruptcy proceeding.
Before entering bankruptcy in March, FES retained Lazard to handle an in-court divestiture. Lazard contacted 35 potential buyers, including “broadly focused financial investors, power- and energy-focused financial investors, strategic retail and power generation companies,” FES said.
The second effort yielded offers from six bidders in March, one of which was rejected because it did not include FES’ entire retail business. FES said it ultimately selected Exelon’s offer as the best, or “stalking horse,” bid.
Under the proposed auction procedures, a bidder challenging Exelon would need to offer an “initial topping bid” of $146.6 million, with subsequent bids in increments of at least $1 million. The auction will be canceled if no bids other than Exelon’s are received.
In a separate motion Monday, FES sought to file the unredacted sale agreement under seal to prevent it from disclosing the details of a mechanism that could adjust the purchase price and that allocated value by individual customer accounts. FES said disclosure of those details could reduce the ultimate purchase price.
Constellation serves residential customers in 17 states and D.C. after acquiring retail operations from Consolidated Edison in 2016 and Integrys Energy Group in 2014. (See Exelon’s Constellation to Buy Con Ed’s Retail Operation.)
FirstEnergy shares closed Tuesday at $35.39, up 0.2%. Exelon rose 0.76% to $42.17.
FERC on Monday denied Cloverland Electric Cooperative’s request for relief from its mandatory purchase obligation under the Public Utility Regulatory Policies Act (PURPA), citing the co-op’s lack of RTO membership as a primary reason (QM18–11).
Cloverland, which serves customers in Michigan’s Upper Peninsula, filed in April to terminate its PURPA obligation to buy power from qualifying facilities (QFs) over 20 MW, arguing that, as a transmission-dependent utility that purchases transmission service from American Transmission Co. (ATC), QFs over 20 MW could not “safely interconnect” to the co-op’s distribution system “even with significant upgrades.”
Cloverland’s hydroelectric plant | Cloverland
Cloverland argued “the only practical way” for a QF over 20 MW to sell its input to the co-op would be to interconnect to ATC’s transmission system. It also contended that, although it doesn’t participate in MISO, ATC is a member of the RTO, where QFs have nondiscriminatory market access. The co-op said QFs within its service territory could utilize ATC’s transmission system to gain nondiscriminatory access, a prerequisite for utilities seeking relief from PURPA purchase obligations.
A utility can be exempted from its PURPA energy and capacity purchase obligations if it can demonstrate a need for relief and is a member of an RTO/ISO market.
But FERC said Cloverland could not use ATC’s MISO membership as a proxy for securing its own RTO/ISO membership.
“In essence, Cloverland, while not itself a MISO member, is seeking to claim the benefit of ATC’s MISO membership in requesting relief from the mandatory purchase obligation under PURPA … We are not persuaded to grant Cloverland’s application,” FERC said.
FERC determined that, because Cloverland is not a member of MISO, it is not entitled to relief from the purchase obligation despites its claim that nearby QFs nevertheless have access to MISO’s markets.
“We are not persuaded to change our position on the reach of PURPA … Membership in an RTO/ISO remains a requirement for claiming an exemption under PURPA … ” FERC said. “ … Accordingly, since Cloverland is not itself a member of MISO, it is not entitled to relief.”
WASHINGTON — The 12,000 attendees at the World Gas Conference last month seemed unaware that the ground is shifting under their feet. Yet that is what’s happening, the Rocky Mountain Institute contends in a new analysis.
The clean energy think tank says that utilities, investors and regulators should be skeptical of any new investments in natural gas-fired generation because the combination of renewables and storage is already cheaper than combustion turbine peakers in some regions and will fall below the cost of combined cycle plants within a decade.
RMI’s analysis is the latest to sound warnings for gas. In March, IHS Markit published an analysis that found that batteries with access to cheap renewable power can be cheaper than CTs.
Greentech Media Research says storage will be competitive with gas peakers within four years and cheaper within 10 years. “I can’t see a reason why we should ever build a gas peaker again in the U.S. after, say, 2025,” Shayle Kann, a senior adviser to GTM Research and Wood Mackenzie, told GTM’s Energy Storage Summit last December. “If you think about how energy storage starts to take over the world, peaking is kind of your first big market.”
However, Bloomberg New Energy Finance does not see gas’ role as the “bridge” fuel between coal and renewables ending any time soon, instead forecasting an increased role for gas peakers for the next three decades.
At the World Gas Conference at the Walter E. Washington Convention Center, speakers on a panel on the role for gas in power generation also were more bullish.
With global power consumption expected to double by 2050, gas has a “great opportunity” to grow, said Shankari Srinivasan, vice president and managing director of global gas and EMEA power for IHS.
She acknowledged the growing competition from renewables and batteries and the impact energy efficiency can have on power demand growth. But in constructing future scenarios, IHS “found it very difficult to construct a case … where [global] gas-fired generation declines,” she said. “Renewables on their own are unlikely to be able to support this level of growth. In the U.S., I think we will continue to see gas taking a large share of power generation and remaining a fundamental part of the power generation mix.”
In contrast, Srinivasan said Europe may be seeing “the beginning of the end” of combined cycle gas turbine construction.
“I am, I think, being a little provocative. But it is possible to envisage new generation capacity as a mix of renewables and maybe only open cycle gas turbines,” she said.
The price of gas will be paramount in China and the rest of Asia, which will each account for one-third of global power demand growth through 2050.
“In Asia, development and growth of gas will depend on how competitive it is with coal … and the strength of clean air policies. … Gas as a bridge to a zero-carbon future may be skipped entirely — replaced by a gray-green world of coal and renewables in certain parts of the world.”
Another panelist, De la Rey Venter, Royal Dutch Shell’s executive vice president for integrated gas ventures, insisted that gas will remain essential to balancing the variability of renewables for at least a decade.
“There are those who say that ultimately batteries will eat gas for breakfast. We don’t quite subscribe to that logic,” he said. “There are many things that need to happen before batteries can play a meaningful role beyond short-term balancing of fluctuations in the system.”
In addition to reducing their cost and improving their performance, Venter said batteries need frequent access to low- or no-cost power for charging to be competitive.
Venter said the gas industry needs to “fight this notion that …. there’s this existential competition between gas and renewables.”
“Gas is the ultimate enabler of renewables,” he said. “If you really want to see a … widespread penetration of renewables, you need to have gas for the next decade or two.”
Stakes: Replacing Half of Thermal Capacity by 2030
Although there is disagreement over when gas will lose its appeal for power generation, there’s no doubt that the stakes are huge, both for the industry and consumers.
RMI notes that more than half of U.S. thermal generating capacity is more than 30 years old and expected to reach retirement age by 2030. It estimates that it would cost more than $500 billion to replace all retiring power plants with new natural gas-fired capacity (including $110 billion in investments already announced by utilities and independent power plant developers).
Distribution of thermal power plant capacity by fuel type and on-line date | Rocky Mountain Institute / Data from Energy Information Administration
“This will lock in another $480 billion in fuel costs and 5 billion tons of CO2 emissions through 2030, and up to 16 billion tons through 2050,” RMI says. “The current rush to gas in the U.S. electricity system could lock in $1 trillion of costs through 2030.”
RMI sees a $350 billion (net present value) market opportunity through 2030 for renewables and distributed energy resources supplanting gas projects where cost effective. That would eliminate $370 billion of gas capital costs and operating expenses, a net savings of more than 2%, it said.
“This investment trajectory would unlock a market for renewables and DERs many times larger than today’s,” RMI said. It would also reduce carbon emissions and save consumers money — even excluding DERs’ value to the distribution system beyond peak load reduction or avoided fuel price risk or any emission costs.
Cheaper than Peakers, Nearing Parity with Combined Cycle
RMI’s analysis found that the clean energy portfolio — wind, solar and DERs, including batteries — was cheaper than two CT plants planned for serving peaks, beating one in the Mid-Atlantic by 60% and one in ERCOT by 47%.
In a comparison with CCGT power plants with higher capacity factors, RMI said the clean portfolio was 8% cheaper than a CCGT in California but 6% more costly than such a project in Florida, RMI said.
Proposed new natural gas-fired power plants in the U.S. | Rocky Mountain Institute analysis of S&P Global data
“Factoring in expected further cost reductions in distributed solar and/or a $7.50/ton price on CO2 emissions, all four cases show that an optimized clean energy portfolio is more cost-effective and lower in risk than the proposed gas plant,” the report said.
Comparison of combined cycle operating costs vs. clean energy portfolio levelized costs (2020–2040) | Rocky Mountain Institute
In addition to competing with proposed gas generation, clean energy portfolios will also undermine the profitability of existing plants within eight years, RMI says. In some areas, clean energy portfolios’ combined construction and operating costs — levelized cost of electricity — will be lower than CCGTs’ operating costs by 2026, assuming $5/MMBtu gas (translating to operating cost of $36/MWh). Assuming gas prices remain about $3/MMBtu ($23/MWh), the alternatives won’t be cheaper until about 2040 — still within the operating lives of plants being proposed now, RMI says.
$144 Billion Stranded?
“In other words, the same technological innovations and price declines in renewable energy that have already contributed to early coal plant retirement are now threatening to strand investments in natural gas,” the report says. “Thus, the $112 billion of gas-fired power plants currently proposed or under construction, along with $32 billion of proposed gas pipelines to serve these power plants, are already at risk of becoming stranded assets.”
With about 83% of announced gas projects proposed for restructured markets, independent power producers would bear most of the risk of competition from DERs and renewables.
The trends are also beginning to pinch IPPs’ suppliers. Bloomberg reported in June that Siemens is considering selling its gas turbine business. The company’s CFO told investors in March that the market for large gas turbines will fall to 100 units in 2018, 10% below the company’s previous projections.
Competitor General Electric also sees a “soft” market for gas turbines for several years. Two-thirds of its power capacity additions in 2017 were renewables. But in announcing a corporate restructuring in June, the company told investors, “Gas remains key to long-term energy mix.”
California, Arizona Leading the Transition
RMI cites as examples 11 alternatives to new thermal power plant investment now under consideration. Six of them are in California, where the abundance of solar and wind — and the state’s environmental goals — have made gas-fired generation an endangered species.
Alternatives to new thermal power plant investment under consideration | Rocky Mountain Institute
In February, the California Public Utilities Commission issued its first integrated resource plan. Intended to help the state meet its 2030 greenhouse gas reduction goals — a 50% reduction in electric sector GHG emissions from 2015 levels — the plan sees no new gas-fired capacity through 2030. Incremental generation needs are instead satisfied by utility-scale solar (73%), in-state wind (9%), battery storage (16.3%) and geothermal (1.7%).
CAISO has approved battery energy storage (BES) as a capacity resource if it can maintain its rated output for four consecutive hours over three consecutive days.
NRG Energy last October asked the California Energy Commission to suspend its review of the proposed 262-MW Puente plant in Oxnard after commissioners recommended rejecting the application. The turnabout came following criticism that the 2014 analysis that supported the gas addition did not reflect steep price declines since then for non-emitting alternative resources. (See NRG Signals Pull-out on Proposed Puente Plant.)
California regulators in January ordered Pacific Gas and Electric to solicit energy storage, renewables and load management options to replace three uneconomic Calpine gas peakers. On June 29, PG&E proposed to fill its need with four storage projects totaling 567 MW.
In March, PG&E solicited proposals to develop up to 45 MW of “clean energy” resources, including at least 10 MW of energy storage, to replace the aging 165-MW Dynegy Oakland jet fuel-fired power plant. It would be the first time PG&E used clean energy resources as an alternative to fossil fuels for transmission reliability. (See PG&E to Seek Storage, EE to Replace Dynegy Plant.)
Also in March, the Arizona Corporation Commission rejected Arizona Public Service’s plans to double its natural gas fleet over the next 15 years, instead ordering that utilities show that storage is not a cost-effective option before seeking approval of new natural gas units.
APS and Xcel Energy Colorado are among the utilities whose solicitations have produced renewable and storage bids at lower energy or capacity costs than thermal generation. Xcel received 87 bids for solar/storage projects at a median price of $36/MWh — compared with the $85/MWh levelized cost of electricity for an advanced CT, according to the Energy Information Administration.
To be sure, battery technologies will have to improve to be a solution in colder climates, where winter peaks can last for more than four hours.
Nevertheless, Xcel Energy CEO Ben Fowke toldThe Wall Street Journal earlier this year, “I could see in 10 to 15 years where you have 30% of what is traditionally a peaker market served by storage.”
Mark Dyson, RMI | Rocky Mountain Institute
Mark Dyson, one of the authors of the RMI study, discussed its findings in a webinar last week, citing evidence that investors agree with its conclusions.
Dyson cited the 7% one-day drop in GE’s share price in late May after CEO John Flannery told investors that the market for the company’s large gas turbines will remain weak through 2020. “The narrative was around the bad bet that it made in doubling down on new gas as a growth opportunity,” Dyson said.
“We see other investors looking at the PJM capacity market results and seeing how much uncleared gas there was that was in the queue. That’s kind of another hint that the market is cooling,” he added.
IHS also Bearish on Peakers
The results of RMI’s analysis were consistent with those published in March by IHS Associate Director Wade Shafer and senior analyst Sam Huntington.
The two compared a scenario in which California’s incremental resource adequacy needs from 2021 to 2030 were met entirely with CTs versus one using four-hour lithium-ion (Li-ion) BES.
They concluded that despite projected cost declines, the levelized fixed cost (capital and fixed operations and maintenance costs) of a four-hour Li-ion BES system will remain more expensive than a typical CT through 2030. But with inexpensive power for charging, they said, batteries would have a lower operational cost. “If the savings in systemwide production costs exceed the premium in fixed costs, BES systems would yield net benefits relative to CTs,” they said.
IHS’ analysis assumes that by 2030, more than half of California batteries will be linked to otherwise-curtailed solar PV, giving them access to low- and no-cost power.
If California met all its peaking capacity needs from 2021 to 2030 with BES instead of CTs, net present value benefits to the power sector would be about $16 million — essentially break-even given the size of the investments, the study found. “Savings also arise from the higher efficiency of the remaining thermal fleet — batteries smooth the variability in net load, resulting in fewer start-ups by peakers and allowing mid-merit plants to operate at lower heat rates,” they wrote.
Their conclusion: “California appears to be on the right track in terms of requiring batteries to cost-effectively manage the excess solar energy created by the [renewable portfolio standard]; however, IHS Markit has not evaluated the optimal year to fully transition from new gas-fired capacity to batteries.”
In an interview, Huntington said the RMI analysis appeared sound. He said he was somewhat surprised that RMI found not only peakers but CCGTs at risk. “A lot [of the RMI analysis] relied on energy efficiency and demand response, something we haven’t looked at as closely,” he said.
Dissenting Voices
In contrast, BNEF contends gas will remain vital through 2050.
Its 2018 New Energy Outlook report predicts coal and nuclear will “have almost disappeared from the electricity mix” by 2050, while renewables penetration will reach 55%. Supporting renewables, batteries will “grow in significance” beginning in 2030, it said.
BNEF projects PV module prices to continue dropping at the 28.5% “learning rate” of the last 40 years — meaning costs drop 28.5% for each doubling of deployed capacity.
Li-on battery pack prices will fall by almost two-thirds between 2017 and 2030, BNEF says, driven by the learning rate of a 27-fold increase in electric vehicle sales.
But while cheaper renewables and batteries will hurt most thermal power sources, BNEF sees an increased role for gas peakers.
“As thermal plants retire and variable renewables increase the variability on the supply side … peaking gas emerges as a critical technology to back up renewables during the extremes when wind and solar are at a minimum (sometimes this can be up to weeks at a time),” BNEF said. “We expect peaker gas to grow by almost a factor of four by 2050, as a cheaper, more nimble alternative to large-scale CCGT and coal-fired power plants running at low capacity factors.”
