FERC last week denied Occidental Chemical on three fronts in the company’s battle against MISO and Entergy’s treatment of qualifying facilities.
The commission dismissed a 2013 complaint by the Dallas-based chemical manufacturer that claimed MISO’s treatment of QFs violated the Public Utility Regulatory Policies Act (EL13-41). Occidental argued that MISO’s plan to integrate QFs in Entergy’s territory would strip them of their rights under PURPA, as the law assumes that they do not have access to wholesale markets.
This plan was detailed in a document titled “Qualifying Facilities Generator Readiness for MISO Reliability Coordination and Market Integration,” which was circulated at informational meetings with QFs. It included two options for QF participation, one of which was labeled the “hybrid option.” Under this option, a QF is allowed to submit offers or self-schedule in both the day-ahead and real-time markets up to its maximum capacity. MISO said that by using financial schedules, which Entergy would be required to agree to, QFs would be able to maintain their right to sell at the avoided cost rate, pursuant to PURPA.
Occidental argued that the hybrid option would prevent QFs from exercising their right to sell as-available energy under PURPA. The company also argued that MISO should have been required to seek FERC approval for its integration plan.
The commission was unpersuaded by Occidental’s arguments.
“In this instance, registration under the hybrid option allows QFs to participate in the MISO market, while continuing to exercise their rights pursuant to PURPA,” FERC said. “We find that the use of financial schedules in conjunction with the hybrid option preserves a QF’s right to provide as-available energy.”
Complaint Against LSPC
While its complaint against MISO was pending before the commission, Occidental filed a complaint against the Louisiana Public Service Commission in February 2014. Occidental protested that the PSC had essentially adopted MISO’s QF integration plan.
FERC declined to take action on the PSC complaint while Occidental’s MISO complaint was still pending. In response, the company sued Entergy and the PSC in federal district court, which stayed the proceeding until FERC reached a decision in the MISO complaint. Occidental appealed, and in January the 5th U.S. Circuit Court of Appeals overturned that decision, noting that it could take years before FERC reached a decision. It ordered the lower court to give FERC 180 days to resolve the MISO complaint; if FERC had not reached a decision, the court could proceed with the suit (15-301).
With the MISO complaint settled, FERC subsequently issued a notice of intent not to act on the PSC complaint (EL14-28).
Rehearing Denied
Finally, FERC denied a rehearing request from Occidental regarding its order waiving the requirement for Entergy to sign power purchase agreements with QFs that have capacities over 20 MW (QM14-3). (See FERC: Entergy not Required to Buy from Large QFs.)
Occidental argued that the commission ignored evidence showing that MISO’s integration plan would deny its Taft QF, located at its Hahnville, La., chemical plant, nondiscriminatory access to the RTO’s markets.
But FERC noted its decision upholding MISO’s plan. “Given this finding, Occidental’s argument in the instant case that it lacks nondiscriminatory access to the MISO markets based on the MISO QF integration plan is moot,” it said.
FERC last week affirmed its 2012 ruling requiring Entergy to make refunds to ratepayers because of an improper allocation of the sources of off-system energy sales between 2000 and 2009.
The commission denied in part and granted in part requests for rehearing by Entergy Services and the Louisiana Public Service Commission (EL09-61-003).
The PSC set the proceedings in motion with a 2009 complaint alleging Entergy and its affiliates violated their system agreement and engaged in “imprudent utility conduct” when Entergy Arkansas sold excess electric energy to third-party power marketers and other non-agreement members. Entergy’s system agreement is a 1982 contract between the companies and Entergy Services that governs the planning and operation of the companies’ generation and bulk transmission facilities on a single-system basis.
An administrative law judge’s initial decision found Entergy Arkansas had violated the system, ordering refunds. FERC affirmed part of the decision, finding that although the agreement’s relevant provisions are “ambiguous,” it does provide authority for the individual companies to make opportunity sales for their own accounts.
The PSC and Entergy requested a rehearing of the decision based on four issues:
Was the commission correct in finding the system agreement permitted the opportunity sales?
Did Entergy violate the agreement in accounting for the sales?
Was FERC correct in ordering refunds?
Did the commission err in reducing the refund amount as a result of the PSC’s delay in approving a power purchase agreement between Entergy Louisiana and Entergy Arkansas?
FERC rejected Entergy and the PSC’s arguments on each of the first three matters, affirming its previous decision.
“Although the Louisiana commission argues that the system agreement prohibits opportunity sales through its provisions concerning the powers of the operating committee … it is notable that the Louisiana commission can point to no specific provisions that make such a prohibition,” FERC said.
Over-Recovery
However, the commission also rejected Entergy’s contention that no refunds were due to ratepayers because the matter involved a misallocation of costs among different companies rather than an over-recovery. “Entergy Arkansas’ off-system sales of low-cost energy from system resources had the effect of forcing up the rates of captive customers of other operating companies by precluding their purchase of the low-cost energy,” the commission said. “Those captive customers were essentially over-charged as a result of Entergy’s improper accounting under the system agreement and thus are due refunds.”
The commission also clarified that interest on refunds should be included in the payments, consistent with the commission’s general policy.
And it agreed with the PSC’s argument that the refunds should not be reduced by a 12-month period in which the Louisiana regulators delayed approval of a PPA between Entergy Louisiana and Entergy Arkansas. FERC said a more equitable approach would be to reinstate refunds for the 12-month period at issue, saying it could not “necessarily conclude” the PSC’s delay in processing the PPAs was so excessive the refund amounts should be reduced.
In a separate order, FERC set further hearing procedures to determine the final allocation of refunds, which the Louisiana commission has estimated at $77.5 million (EL09-61-002). Entergy contends the amount should be less than $25 million.
The commission agreed with the ALJ that a full re-run of Entergy’s intra-system bill was necessary to provide a fair accounting of damages. FERC found the damages should be altered to reflect adjustments to service schedules and other provisions in the system agreement, including for bandwidth payments.
Entergy’s companies essentially operate as one system, although each has different operating costs. Low-cost companies make annual payments to the highest-cost company, using a “bandwidth” remedy that ensures no operating company has production costs more than 11% above or below the system average. Regulators in Entergy’s states have regularly challenged the annual bandwidth filings, which began in 2007.
New York environmental officials on Friday denied a water quality permit for a 124-mile pipeline that would have delivered shale gas from Pennsylvania to markets in eastern New York and New England.
The New York Department of Environmental Conservation said developers of the Constitution Pipeline failed to address regulators’ concerns during a yearlong review.
The water quality permit, which is required under Section 401 of the federal Clean Water Act, was the last regulatory approval needed by Williams Partners and its co-developers, Cabot Oil & Gas, Piedmont Natural Gas, and WGL Holdings, for the pipeline through northeastern Pennsylvania and New York.
FERC approved the pipeline in December 2014, but developers lost the 2016 construction season when FERC would not allow limited tree cutting along the project route after New York officials protested because of the lack of the Section 401 permit. (See Constitution Pipeline Delayed Nearly a Year.)
Failed to Address Environmental Concerns
The DEC said Constitution’s “application fails in a meaningful way to address the significant water resource impacts that could occur from this project and has failed to provide sufficient information to demonstrate compliance with New York state water quality standards.”
Constitution said it “will pursue all available options to challenge the legality” of the decision. The project was intended to deliver 650,000 dekatherms of natural gas per day to the Wright, N.Y., compressor station for transport farther east.
“In spite of NYSDEC’s unprecedented decision, we remain absolutely committed to building this important energy infrastructure project, which will create an important connection between consumers and reliable supplies of clean, affordable natural gas. We believe NYSDEC’s stated rationale for the denial includes flagrant misstatements and inaccurate allegations, and appears to be driven more by New York state politics than by environmental science,” the company said in a statement released Monday.
The department blamed the company for failing to adequately address its concerns about the project’s impact on 251 streams and 500 acres of forest. The denial also cited the short- and long-term effects of trenching during construction, the loss of shade critical to stream health and the impact the loss of vegetation would have on potential flooding.
“Although the department repeatedly asked Constitution to analyze alternative routes that could have avoided or minimized impacts to an extensive group of water resources, as well as to address other potential impacts to these resources, Constitution failed to substantively address these concerns,” the DEC wrote.
Constitution said it “voluntarily agreed” to incorporate re-routes, adopt trenchless construction methods, commit to trout stream restoration and spend $18 million for wetland mitigation and $8.6 million for migratory bird habitat restoration and preservation.
Tree Cutting
The department was also annoyed that it received reports that landowners, “possibly with Constitution’s knowledge, clear cut old-growth trees along the right of way for the pipeline, including trees near streams and water bodies, even after the FERC ruled that Constitution could not cut trees in the right of way.”
First sections of Constitution Pipeline arrive in New York Source: Constitution Pipeline
Constitution said that allegation is “completely inaccurate and contradicts the third-party environmental monitors working on behalf of FERC.”
The DEC said it conducted a “rigorous review,” including receipt of 15,000 public comments.
Environmentalists lauded the decision.
“Gov. [Andrew] Cuomo’s rejection of the Constitution Pipeline represents a turning of the tide, where states across the nation that have been pressured into accepting harmful gas infrastructure projects by FERC may now feel emboldened to push back,” said Roger Downs, conservation director for the Sierra Club’s Atlantic Chapter. “Cuomo’s leadership could inspire a domino effect of related pipeline rejections as other states begin to put the protection of water and our climate before flawed energy projects that do not serve the public interest.”
Constitution’s rejection came two days after Kinder Morgan announced it was shelving its Northeast Energy Direct pipeline, which was to deliver Pennsylvania shale gas through New York, Massachusetts and New Hampshire. It cited an uncertain regulatory climate for the project as well as a lack of commitments from electric utility customers. (See Kinder Morgan Suspends Northeast Energy Direct Pipeline.)
Kinder Morgan said Wednesday it has suspended work on the Northeast Energy Direct pipeline, citing an uncertain regulatory climate and a lack of commitments from New England power generators to reserve capacity.
The $3.3 billion project, being developed by subsidiary Tennessee Gas Pipeline, was to deliver shale gas from Pennsylvania into New York, with a line also running through Massachusetts and New Hampshire. The Kinder Morgan board approved the project last summer and it sought federal approval late last year (CP16-21). (See Northeast Energy Direct Files for FERC Certificate.)
“The board’s initial approval was based on existing contractual commitments at the time by local gas distribution companies to purchase natural gas from the project, as well as expected commitments from additional LDCs, electric distribution companies and other market participants in New England,” the company said in a statement. “Unfortunately, despite working for more than two years and expending substantial shareholder resources, TGP did not receive the additional commitments it expected. As a result, there are currently neither sufficient volumes, nor a reasonable expectation of securing them, to proceed with the project as it is currently configured.”
The company conducted an open season last year to engage potential customers and received commitments for only 751,650 dekatherms per day of the pipeline’s 1.3 million dekatherms per day capacity.
A controversial aspect of the project, and that of another proposed pipeline, Access Northeast, is the proposal to have EDC ratepayers foot some of the project costs through their utility bills. (See Massachusetts Regulators Endorse Pipeline Contracts.) Massachusetts Attorney General Maura Healey has opposed the move, and similar proposals in other New England states have yet to be enacted.
“The New England states have not yet established regulatory procedures to facilitate binding EDC commitments, that the process in each state for establishing such procedures is open-ended and that the ultimate success of those processes is not assured,” Kinder Morgan added in its statement.
Project opponents were elated.
“It’s a rare thing to see a fossil fuel company admit there simply isn’t enough need for what they’re selling,” Conservation Law Foundation President Bradley Campbell said. “It is increasingly apparent that free market forces are rapidly driving us toward a clean energy future, and today’s decision by Kinder Morgan is a telling sign of things to come. Our environment, our economy and the health of our communities depend on continuing to see fossil fuels out the door.”
WASHINGTON — The U.S. Supreme Court today unanimously rejected Maryland regulators’ attempt to subsidize Competitive Power Ventures’ combined cycle plant in Charles County, saying it interfered with FERC’s jurisdiction over wholesale electric markets.
The court upheld a ruling by the 4th Circuit Court of Appeals, which found that Maryland’s contract for differences with CPV could distort price signals in PJM’s annual capacity auctions (Hughes v. Talen, 14-614, 14-623).
“We agree with the 4th Circuit’s judgment that Maryland’s program sets an interstate wholesale rate, contravening the [Federal Power Act’s] division of authority between state and federal regulators,” Justice Ruth Bader Ginsburg wrote for the court. She said the contract also violated the Constitution’s Supremacy Clause, which establishes that federal law preempts contrary state law.
In April 2012, the Maryland Public Service Commission ordered Baltimore Gas and Electric, Potomac Electric Power Co. (PEPCO) and Delmarva Power and Light to enter into a contract that guaranteed CPV — winner of a PSC competitive solicitation — an income stream so that it could finance the facility.
Contract for Differences
Under the contract for differences, CPV St. Charles’ revenues for the sale of 661 MW of energy and capacity would be compared to what the company would have received had the contract prices been controlling. If the contract prices were higher than the market prices, the three electric distribution companies would pay the difference to CPV; if market prices were higher than the contract, CPV would make payments to the EDCs.
The contract was challenged by Talen Energy’s predecessor, PPL, and other generators. The opponents said Maryland’s action would suppress capacity prices and that allowing the contract to stand would mean that eventually only subsidized units would enter the auction because those without support could not compete.
“FERC has approved the PJM capacity auction as the sole rate setting mechanism for sales of capacity to PJM and has deemed the clearing price per se just and reasonable,” the court said. “By adjusting an interstate wholesale rate, Maryland’s program invades FERC’s regulatory turf.”
Maryland and CPV contended the contract for differences was no different than traditional bilateral contracts for capacity, which FERC allows.
But the court said Maryland’s contract with CPV “does not transfer ownership of capacity from one party to another outside the auction. Instead, the contract for differences operates within the auction; it mandates that [load-serving entities] and CPV exchange money based on the cost of CPV’s capacity sales to PJM.”
The Supreme Court had declined to review a ruling by the 3rd Circuit Court of Appeals finding New Jersey regulators’ subsidy of a CPV generating plant also in violation of the Constitution’s Supremacy Clause (PPL EnergyPlus LLC, et al. v. Hanna, 11-0745).
Guidance for States
But the court did provide state regulators’ guidance for crafting their programs in the future, saying it rejected Maryland’s initiative only because it disregards FERC’s wholesale rate.
“We therefore need not and do not address the permissibility of various other measures states might employ to encourage development of new or clean generation, including tax incentives, land grants, direct subsidies, construction of state-owned generation facilities or re-regulation of the energy sector,” it said. “So long as a state does not condition payment of funds on capacity clearing the auction, the state’s program would not suffer from the fatal defect that renders Maryland’s program unacceptable.”
Justice Clarence Thomas concurred in the judgment but said the court did not need to cite “implied preemption” under the Supremacy Clause.
“To resolve these cases, it is enough to conclude that Maryland’s program invades FERC’s exclusive jurisdiction” under the Federal Power Act’s division of federal (wholesale) and state (retail) jurisdiction, Thomas wrote.
The Electric Power Supply Association, which had filed amicus briefs in support of federal preemption of the Maryland and New Jersey subsidy programs, called the ruling “a victory for the economic integrity and viability of wholesale power markets. The unanimous decision strengthens FERC’s hand at a critical time when it comes to properly defining the appropriate roles for federal and state actions impacting wholesale power markets.”
The American Public Power Association (APPA) called the decision “another regrettable setback for restructured states in Regional Transmission Organization regions that take seriously their obligations to ensure that their state’s retail customers have reliable, affordable and environmentally responsible electric service.”
The group said it was pleased, however, that the ruling was narrowly drafted “and does not impair the ability of public power utilities to serve their own retail customers with owned and contracted-for generation resources.”
Travis Kavulla, president of the National Association of Regulatory Utility Commissioners, said “the line between the federal and state jurisdictions appears largely unaltered” by the ruling.
“Following the Supreme Court’s logic, it seems possible that the state of Maryland could have accomplished substantially the same result of obtaining new generating capacity in the state, just so long as it did not condition the generator’s compensation on the wholesale market’s clearing price for capacity,” he said in a statement.
But Kavulla said the ruling will “inevitably will result in further litigation of these issues by leaving many open questions.”
“Someday soon, consumers, utilities, power generators, and regulators alike will need greater certainty about what is and is not permissible on the part of federal and state regulators. But today is not that day.”
FERC last week accepted rule changes meant to prevent generation owners in ISO-NE from exercising market power by retiring resources that are still economic (ER16-551).
The commission approved revised Forward Capacity Market rules that will require retiring generators to declare their intention with de-list bids in March rather than October, while moving the “show of interest” deadline for new capacity market entrants from February to April.
The order also gives the Internal Market Monitor greater leeway in determining whether an economic generation resource is being retired to raise capacity prices.
“ISO-NE’s proposal includes several changes to the FCM timeline, which will benefit the market,” FERC wrote. “By requiring retirement bids to be submitted in March and by requiring ISO-NE to post shortly afterwards information regarding the amount of existing capacity that may exit the FCM, project sponsors that are considering developing new resources will have better and more timely information about when and where new capacity may be needed.
“By moving the show of interest window to a date after the retirement bid deadline, new entrants will be able to use the information about potential retirements to inform their decision on whether to enter the FCM in the next auction,” the commission said.
The rules will take effect with the 11th Forward Capacity Auction next year for the 2020/21 commitment period.
Generators submit de-list bids that specify a price below which an existing resource would not provide capacity. A static de-list bid signifies a one-year absence from the capacity market; a permanent de-list bid means the resource will exit the market. A capacity supplier wishing to permanently retire an existing resource regardless of price would submit a non-price retirement request.
IMM Review
The order also approved rule changes to address premature retirements of economic resources, a need ISO-NE said was identified by both its IMM and External Market Monitor. The RTO defines “uneconomic” retirement as the retirement of a capacity resource that would be expected to remain profitable if it continued running.
ISO-NE proposed that its IMM issue a determination on the reasonableness of generators’ cost assumptions and the appropriateness of their proposed bids. Based on that, the RTO will file with the commission either the supplier’s original bid or a mitigated bid.
Generators objected, saying the IMM should not be given such discretion, but FERC was not persuaded.
“The proposed reforms permit flexibility in the submitted forecasts and inputs of a retirement bid, so long as a supplier can show that those forecasts and inputs are reasonable,” FERC said. “We find that this process will not result in an undue preference for the IMM’s estimates of a supplier’s retirement costs, but rather will initiate a dialogue whereby suppliers would have the opportunity to demonstrate that their proposed inputs to their retirement bids are reasonable.”
Generators also contended there was no evidence of market power abuses in New England. But the commission said such proof was unnecessary.
“It is irrelevant whether suppliers have previously used physical withholding through retirement as a means to exercise market power. Our review here is limited to whether ISO-NE’s proposal is just and reasonable and not preferential or unduly discriminatory,” FERC wrote.
Brayton Point Allegations
The backdrop for the rule changes is the Utility Workers Union of America’s contention that the 1,517-MW Brayton Point plant in Massachusetts is being closed to raise capacity prices.
Brayton Point
Energy Capital Partners did not offer the plant in capacity auctions for 2017/18 and 2018/19 after announcing the plant would close in 2017. Brayton Point was sold last year to Dynegy, which said it would close the plant as scheduled.
On April 14, the union filed a new challenge, citing ISO-NE’s retirement rule changes to bolster its case for throwing out the results of FCA 10 (ER16-1041).
“As both ISO-NE and the commission have recently recognized … omitting ‘retiring’ capacity entirely from the calculation of the Forward Capacity Auction price, as has occurred here, rather than including it at a ‘proxy’ or other price which represents its true costs, results in the auction being non-competitive and the resulting prices not just and reasonable,” the union wrote.
A conservation group named the Susquehanna River as the nation’s third-most endangered, blaming Exelon’s Conowingo Dam for allowing pollutants and sediment to flow into the Chesapeake Bay. American Rivers said the 88-year-old dam’s ability to capture those materials is exhausted.
The Susquehanna, which runs nearly 500 miles from Cooperstown, N.Y., drains half of the state of Pennsylvania and provides more than half of the Chesapeake’s fresh water. Nitrogen from farm runoff feeds algae blooms, creating dead zones.
Maryland officials have asked the U.S. Senate to reject legislation they say would allow Exelon to avoid complying with state water quality standards. Exelon, which is seeking to renew its federal license for the dam, said the company is working with stakeholders to protect the bay’s health.
Documents Show ExxonMobil, Others Hid Climate Change Info
Documents released by the Center for International Environmental Law as part of its ongoing project on the energy industry’s studies of climate change suggests industry insiders had hard knowledge of carbon dioxide’s effect on the global climate as early as 60 years ago.
“From 1957 onward, there is no doubt that Humble Oil, which is now Exxon, was clearly on notice” about rising CO2 levels, said Carroll Muffett, the center’s director. Muffett and others involved in the project say the industry put together a group to monitor pollution studies and to encourage public skepticism to fight against environmental legislation.
The documents are the latest released by the center, which have led four attorneys general to begin investigating Exxon.
A European utility company is teaming up with a Kansas developer to build a 400-MW wind farm in the southwest portion of the state. Enel Green Power North America, the American subsidiary of Italy’s Enel, and Tradewind Energy announced the project April 8.
The $613 million Cimarron Bend project will be the largest wind farm Enel has ever built, and it will be the second largest wind farm in Kansas. The developers say the project will create 350 construction jobs and produce enough energy to power 150,000 households.
The project will consist of 200 wind turbines on 60 square miles. It will sell power to the Kansas City Board of Public Utilities, which serves as the municipal electric utility for the city, and Google.
FirstEnergy Customers Offered 100% Wind Power at SOS Price
FirstEnergy is offering a limited number of Ohio customers the opportunity to switch to 100% wind-generated energy at the same price as standard power. The program, Switch2Green4Free, is open to the first 1,000 residential customers who enroll.
The power will be sourced through a contract with subsidiary FirstEnergy Solutions from wind farms throughout the country.
But Trish Demeter, managing director of Energy & Clean Air Programs at the Ohio Environmental Council, was skeptical about the promotional program’s aim, saying that FirstEnergy still appears committed to fossil fuel generation. “We’re not really seeing any clear path forward for FirstEnergy as far as making any real and substantial transition to a cleaner portfolio,” she said.
Exelon removed Nine Mile Point Unit 2 from service last week for a planned refueling outage. For several weeks, more than 2,000 workers will replace nearly one-third of the reactor’s fuel and perform thousands of inspections and maintenance activities.
The Unit 2 outage comes as Exelon is urging state utility regulators to implement new “clean energy” subsidies to help its nuclear plants survive the financial stresses caused by low-cost natural gas-fired power plants.
Nine Mile Point Unit 1 will continue to generate electricity during the Unit 2 outage.
Marathon Oil Selling Wyo. Holdings to Merit Energy
Marathon Oil announced last week it is selling its Wyoming oil-producing assets to Merit Energy for $870 million. It is selling leases in the Big Horn and Wind River basins, a reflection of the continued downturn in oil operations in those regions.
Marathon, which has a 100-year history of oil production in Wyoming, announced its intention earlier this year to sell up to $1 billion in assets in order to concentrate on wells that produce higher returns. Its core assets are in North Dakota and Texas.
“Ongoing portfolio management continues to drive the simplification and concentration of our portfolio to lower-risk, higher-return U.S. resource plays and support our 2016 objective of balance-sheet protection,” Marathon CEO Lee Tillman said.
Duke Retires Wabash River Station Units After 63 Years
Four coal-fired units at Duke Energy’s Wabash River Generating Station near Terre Haute, Ind., have gone cold after 63 years of service. Units 2, 3, 4 and 5 shut down about a week before their air permits expired Friday.
One unit at Wabash Station is still active. Duke says it is investigating a possible fuel switch to natural gas.
Purdue University scientists are working with Swiss researchers to develop “hydricity,” a term they’ve coined for a thermal-solar system that generates electricity and produces hydrogen to generate power when solar power is unattainable.
Hydricity uses concentrated solar energy to superheat water to produce steam for immediate power generation, as well as hydrogen, which is stored for generating electricity when there’s little to no sunlight. Although the process is expensive, researchers see value in the project because stored hydrogen doesn’t lose energy over time, unlike batteries.
“Here what we’re doing by co-producing hydrogen, we avoid a step of making electricity and then storing it,” said Purdue chemical engineering professor Rakesh Agrawal. “We directly make hydrogen from sunlight, and that’s what makes it more efficient. We can do almost anything: purify water, produce chemicals, create fertilizer for food production.”
Merger Credits Begin Rolling Out to Md., DC Pepco customers
Pepco customers in Montgomery and Prince George’s counties will begin receiving the first of two $50 bill credits this month as part of the company’s recent merger with Exelon. The second credit will be applied to bills in 2017.
D.C. ratepayers also should see a $54.59 credit in their bills this month.
Pepco said information about credits for customers in Delaware and New Jersey, also affected by the merger, will be forthcoming.
Exelon has agreed to sell its century-old New Boston Generating Station to Hilco Global and Boston developer Redgate Real Estate for undisclosed terms. The sale is set to close by the end of June.
The buyers have not disclosed their redevelopment plans, said a spokesman for Hilco, a Chicago-area financial services conglomerate whose redevelopment arm specializes in “maximizing the value of obsolete industrial sites.” Hilco and Redgate beat out at least six other bidders for the property.
The plant, built in 1892 to burn coal, was later converted to oil and then to natural gas before being largely retired in 2007.
HOUSTON — Almost 500 electric and gas industry participants attended the Gulf Coast Power Association’s 30th annual conference, where low gas prices, environmental rules and new technologies dominated discussion. Here are some of the highlights of the two-day meeting.
Texas Rep. Phil King, chairman of the state House of Representatives’ State and Federal Power and Responsibility Committee, said he was proud lawmakers didn’t change their 1999 law creating a competitive retail electricity market after natural gas prices spiked to more than $13/MMBtu in 2005. But he said the current low gas prices, which are putting pressure on the state’s coal and nuclear generators, could necessitate some “incremental” changes to the market.
“You know, 1999 was a long time ago,” he said, adding that changes should be made by the Public Utility Commission and not by the legislature. “I like the legislature for making policy; I’m not really crazy about us getting into the weeds on things, and that is a very weedy issue.”
Rep. Eddie Lucio III spoke about the impact of diminished water supplies on the power industry, saying “desalination is part of our future,” although current technology is not economical.
He also decried the fragmented, “Byzantine” structure of water authorities in the state, urging consideration of a proposed water grid that could deliver water from Louisiana and Oklahoma throughout Texas. “It seems very forward thinking,” he said of the proposal, though acknowledging “some people really have concerns with it.”
Neel Mitra, director of power and utilities for Tudor, Pickering, Holt & Co., said the U.S. could see an additional 10 GW of coal-fired generation retire by the end of 2017 if gas prices stay below $2/MMBtu.
Mitra said conditions are the worst for coal plants in Pennsylvania, which can’t compete with gas plants built near Marcellus Shale supplies, but that Texas plants also are in distress.
“What we’ve been seeing in real time is that the Texas plants that run mainly on [Powder River Basin coal] and lignite, which practically costs nothing, have been seasonally mothballing going into the summer, and capacity factors for those plants have been the lowest we’ve seen since we began tracking it in 2010,” he said. “We’ve been tracking the fully loaded costs — fixed costs plus [operations and maintenance] plus fuel — and really we see only one plant in Texas that is covering its fixed costs in a $2 gas scenario.”
Mitra said things would be worse if railway shippers, which had been charging $25 to $30/ton to ship PRB, hadn’t reduced their prices, which he said are now between $15 to $20/ton. With PRB available from mines at $10/ton, he noted, two-thirds of the delivered cost can be transportation.
The South Texas Power Project and Comanche Peak nuclear plants also are at risk from the low prices, he said.
Mitra said he is “more bullish” for 2017. “LNG exports are probably the biggest piece that could get us back to higher natural gas prices.”
Jen Snyder, vice president of North America natural gas research for Wood Mackenzie, said LNG exports will likely be affected most by whether Russia’s Gazprom seeks to fight for market share in Europe.
“If Russia decides to support price and gives up market share as they did in 2009-2010, then the U.S. [LNG capacity utilization] is likely to run somewhere around 75%,” she said. “But if Russia decides to go for market share … [it] would discourage further U.S. LNG projects,” with utilization of existing projects ranging from 40 to 50%.
John Fainter received GCPA’s Pat Wood Power Star Award, honoring him for his 18 years as CEO of the Association of Electric Companies of Texas.
Parker McCollough, vice president of legislative affairs for NRG Energy, praised Fainter, who retired at the end of last year, as a “champion herder of cats.”
“During the course of his tenure at AECT, we never lost” in the legislature, McCollough said.
Former FERC Chairman Pat Wood, who presented the award, recalled meeting Fainter after being appointed to the PUCT in 1995. Wood said then-Gov. George W. Bush in 1995 appointed him with a mandate to create a competitive electric market.
The “very politically powerful” investor-owned utilities who made up AECT “were not that keen on getting into a market,” Wood said.
Wood said Fainter’s calm style and sense of humor were crucial to the enactment of the 1999 law, Senate Bill 7. “He was for me, for the industry, a lighthouse in the storm,” Wood said.
In a keynote speech earlier, Fainter commented on technological changes reshaping the grid and new market entrants such as battery maker Tesla. “We’re going to see new players in the industry. It’s not going to be the same … seven companies … as when I came to AECT in 1998,” he said.
Fainter also lamented EPA’s regulatory “silos,” which have subjected coal plants to separate regulations controlling carbon emissions, mercury emissions and particulate matter.
“Everybody wants clean air. Everybody wants clean water. Everybody wants a healthy environment,” he said. “But there’s got to be a reasonable way to deal with it. [Congress should] fix it so you can have an integrated way to address these issues and not do them one at a time with a different set of enforcement processes. To me that makes sense.”
Two-thirds of attendees who participated in a GCPA poll at the conference said they believed Lubbock Power & Light’s plan to join ERCOT will lead the PUCT to implement a process to bring additional loads to the grid operator.
David McCalla, Lubbock’s director of electric utilities, said the transition will save Texas’ 11th largest city (population 4 million) $350 million to $700 million it would have had to spend on a new generating plant after its full requirements contract with Xcel Energy expires in 2019. (See SPP Ponders Response to Lubbock’s ERCOT Move.)
The switch wouldn’t have been possible, McCalla said, if not for the transmission added as a result of the state’s Competitive Renewable Energy Zones.
Former PUCT Chairman Paul Hudson cautioned that the commission is dealing with “CCN fatigue,” a reference to state regulators’ power to grant certificates of convenience and necessity for new transmission lines.
“Looking landowners in the eye is one of the most difficult tasks the PUC has,” said Hudson, now a managing principal at Stratus Energy Group.
Environmental Debate
A present and former member of the Texas Commission on Environmental Quality sparred with a Sierra Club executive over what they called EPA’s overreach.
Jon Niermann, who was appointed to the CEQ last September, said EPA exceeded its authority in the Clean Power Plan and that its Regional Haze rule would cost Texas $2 billion for no appreciable difference in visibility. Niermann said EPA rejected Texas’ approach to the haze rule even though it would reach visibility goals much earlier than other states whose plans the agency approved. “It feels to me like EPA is imposing a double standard on Texas,” he said.
Former CEQ Chairman Kathleen White, now director of the Armstrong Center for Energy & the Environment at the Texas Public Policy Foundation, decried what she called a “deterioration of the science that EPA uses in its risk assessments.”
White said EPA is improperly using “co-benefits” to justify its rules, such as the CPP’s potential to reduce particulate matter in addition to CO2 emissions. “It’s a little problematic,” she said. “They’re using the same basket of co-benefits over and over again.”
Al Armendariz, senior representative for the Sierra Club’s Beyond Coal campaign, said White’s complaint EPA has issued an “unprecedented” number of regulations in recent years reflects the agency’s effort to complete long-delayed rulemakings authorized by the Clean Air Act, including revamps of George W. Bush-era rules that were rejected by federal courts.
Armendariz said coal-burning generators have escaped paying for the environmental costs of their CO2 emissions. “In order to have a functioning free market, people who are producing the products need to be paying the full cost of producing that product, including the climate impact. And that’s not happening today,” he said.
That brought a retort from Niermann. “I’m just skeptical of that causal connection, that fossil fuel burners are responsible for CO2 and therefore for climate change and for paying for the economic costs that they’re adding,” he said.
White also jumped in, saying the United Nations Intergovernmental Panel on Climate Change has reported no evidence that “more frequent droughts, more frequent floods, more frequent extreme weather events” are occurring.
“There’s no historical anomaly going on at this point,” she said. “To talk about a causal connection is very, very problematic, as [are] claims that climate science is somehow unequivocally settled. No science is unequivocally settled.”
Allan Stewart, executive director of North American power for PIRA Energy Group, predicted innovations in battery technology will start changing electric market fundamentals as soon as 2020 in California and Hawaii, by 2025 in New York and 2030 in ERCOT, MISO South and southern SPP. (See related story, FERC to Examine RTO Rules for Energy Storage.)
As batteries flatten the load curve and distributed generation reduces net load, Stewart said, marginal prices will be set by the least efficient baseload plants. “In this environment, I would argue a peaker is useless. It’s absolutely worthless,” he said.
Stewart said one source of innovation may be graphene polymer batteries, which have been licensed by car companies. “It has the potential, soon, to increase the range of electric vehicles to 600 miles and [reduce] the recharge time to eight minutes,” he said. “Space age, you say. 2050 or beyond. Think again.”
SANTA FE, N.M. — With wind energy reaching unprecedented penetration levels, SPP’s Markets and Operations Policy Committee asked staff last week to re-evaluate whether two transmission projects in the windy Texas-Oklahoma Panhandle region should have their need dates accelerated.
Staff had been hoping to receive approval to accelerate the two projects, a recommendation that had already been OK’d by three working groups. However, stakeholder concerns over a lack of technical input, outdated studies of wind energy and going outside normal planning processes caused the MOPC to request further staff analysis.
The motion was unanimously approved. SPP staff will return the recommendation to July’s MOPC meeting and will eventually need approval from the Regional State Committee.
“We can accommodate [the motion] and not impact reliability if we come back in July and make a decision,” said Casey Cathey, SPP’s manager of operations engineering analysis and support.
SPP said it set a new record for North American ISOs and RTOs when it registered a 48.32% wind-penetration peak April 5. (See “SPP Leapfrogs ERCOT with 48.32% Wind Penetration Mark,” SPP Briefs.)
SPP’s 2015 wind integration study recommended 19 transmission projects with notices-to-construct (NTCs) as candidates for acceleration. Ten of the projects have already been voluntarily sped up by transmission owners, four were found to be not feasible for acceleration and three were withdrawn as part of a near-term assessment and will be incorporated into the RTO’s new planning process.
The two remaining NTCs — a 230-kV Southwestern Public Service project in the Texas Panhandle and a 345-kV Oklahoma Gas & Electric project in West Oklahoma — were recommended for acceleration. Cathey said accelerating the projects will reduce existing congestion and ease voltage-collapse fears.
Existing Congestion
“Both [systems] have congestion on them right now. … It’s not wind coming three years from now,” Cathey said. “The longer we delay, the more your benefits are reduced.”
Cathey said SPS could shave half a year off its timeline without a cost to its sponsors, while the OG&E project could reduce its timeline by almost two years, saving $437,000 in the process.
The acceleration recommendation was approved by the Transmission, Economic Studies and Operating Reliability working groups.
Some MOPC members, however, expressed concern about re-evaluating projects outside the Integrated Transmission Planning (ITP) process and a lack of involvement by some of the working groups.
“I do not think the Tariff supports a re-evaluation or acceleration of an NTC outside of the ITP process,” Sunflower Electric Power’s Al Tamimi said in opposing the ESWG recommendation.
“My biggest concern is the lack of involvement, or minimal involvement, with the TWG through this process,” Westar Energy’s John Olsen said. “I get very uncomfortable sitting around this table to be making those kind of calls without having our technical folks review them.”
American Electric Power’s Richard Ross asked whether the re-evaluations could be conducted through SPP’s high-priority study process. The RTO can conduct up to three such studies a year at the stakeholders’ request.
“It seems we’re tying SPP’s hands here,” Ross said. “To me, it makes sense to accelerate these projects, if this is the proper way of doing this. Has legal bought off on sprinkling some high-priority magic dust on this?”
“It may be we need a supplemental analysis to warrant the two accelerations,” SPP Vice President of Engineering Lanny Nickell said. “Now we have to figure out a way legally to justify the acceleration of the projects in accordance with the Tariff. If the two TOs want SPP to direct acceleration, that’s a change in the planning processes.”
Wind Integration Study
The MOPC also unanimously approved staff’s proposed scope for a second phase of a wind integration study, but only after revising the recommendation to ensure the TWG and ESWG are included in the review process.
The study will build on last year’s analysis, with updated models and assumptions looking at wind cases as high as 60%. The results are to be published before next January’s MOPC meeting.
Cathey said the report is intended to be a reliability study rather than a high-priority study and will use 2017 planning models. He said the Electric Power Research Institute will help staff on the report, which will also use data from PowerTech Labs’ voltage security assessment tool.
“Phase II is about what we didn’t have time to assess in Phase I,” he said. “We’re trying to do something that’s [defensible] and accurate. We’d like to get a more dynamic, up-to-date look.”
Cathey noted that with firm transmission rights now part of SPP’s transmission congestion rights market, “We don’t know what firm rights are any more.
Smoky Hills Wind Farm in Kansas Source: Wikipedia
“The wind blows, and it’s in the money. We’re backing down coal, and that’s the reality of what’s happening on the system.”
Cathey said he expects the study to recommend policy and procedure changes, but that it “won’t mandate anything.”
“There’s a good chance we’ll be at 60% wind penetration in 2017,” said Bruce Rew, SPP’s vice president of operations. “The sooner we can get [the study] done, the sooner we can be prepared for that.”
Staff said the study will cost approximately $145,000, but it is waiting on further information from vendors.
FERC is seeking comment on energy storage’s participation in the wholesale energy markets, questioning whether RTOs’ rules are creating barriers for the resource (AD16-20).
The commission’s Office of Energy Policy and Innovation last week sent identical letters to each of the grid operators under its jurisdiction, requesting data on “the eligibility of electric storage resources to participate in the RTO and ISO markets; the technical qualification and performance requirements for market participants; required bid parameters; and the treatment of electric storage resources when they are receiving electricity for later injection to the grid.”
FERC staff simultaneously issued a request for comments on the same issues. Staff said it expects comments to take into account the RTOs’ responses to their data requests, which are due May 2. Comments are due May 23.
There have “been some key developments in the technology and cost-effectiveness of electric storage resources,” FERC staff said. “In light of these developments, staff is interested in examining whether barriers exist to the participation of electric storage resources in the capacity, energy and ancillary service markets.” The commission also expects to examine whether tariff changes are needed if barriers to participation exist, staff added.
“Many energy storage project developers have experienced difficulty in accessing wholesale markets. Grid operations and markets were not originally designed with energy storage in mind,” Jason Burwen, Energy Storage Association policy and advocacy director, said in a statement. “The Energy Storage Association supports efforts that increase access to wholesale markets for storage and establish market structures to realize energy storage’s full value in lowering system costs and increasing system reliability.”
5 Categories
The commission divided its questions to the RTOs into five categories:
Eligibility: Which types of storage resources are qualified to participate in the markets and which are not? Are there different rules for different types? If so, why?
Requirements: What are the minimum and technical requirements for storage to participate in the markets? What are the bases for these requirements (NERC reliability standards, for example)?
Parameters: What are the required bid parameters for storage resources? Are there any parameters unique to storage?
Distribution: Are there opportunities for aggregate storage resources or those connected at the distribution level to participate at the wholesale level? If so, what are they?
Load: When would storage be considered a buyer of energy in the wholesale markets? What are the requirements when storage resources purchase electricity? Are they required to pay LMPs? Are there circumstances when storage can receive electricity but not be considered load?
Current RTO Discussions
FERC also asked the RTOs if there are any ongoing discussions or pending rule changes concerning energy storage.
Here is a snapshot of where they stand:
CAISO last month asked FERC to approve a new Tariff provision that would allow storage and other distributed energy resources to participate in California’s energy and ancillary services markets. An ongoing stakeholder initiative is focused on refining the ISO’s market model to lower barriers for grid–connected DER. (See CAISO Tariff Change Would Extend Market to DER.)
ERCOT last year created a Distributed Resource Energy and Ancillaries Market (DREAM) Task Force, providing a forum for stakeholders and staff to develop market rules related to DER. The DREAM team has submitted a final report for the Technical Advisory Committee’s consideration at its April 28 meeting. (See “DREAM Task Force Submits Final Report,” ERCOT Technical Advisory Committee Briefs.)
ISO-NE has two large-scale pumped hydro storage facilities that can provide nearly 2,000 MW. The RTO developed a paper in January explaining how storage resources of at least 1 MW can participate in the energy and capacity markets. An updated white paper incorporating stakeholder feedback was released on March 31.
NYISO says it was the first grid operator, in 2009, to establish FERC-approved market rules for limited energy storage resources. Its energy limited resources classification allows a capacity provider to sell a minimum of 1 MW for at least four hours. Several other products participate in the ancillary market. The ISO’s Market Issues Working Group has begun a process to expand storage’s presence. In November, FERC accepted NYISO’s method for compensating Beacon Power’s 20-MW flywheel storage facility for frequency regulation (ER12-1653).
PJM is studying a way to remove barriers that distributed battery storage systems face when entering the markets. Currently, such resources have two options: interconnect as a generation source through the queue process or register as demand response. The review, prompted by a problem statement approved by stakeholders in February, will be limited to behind-the-meter generation of 20 MW or less. (See “Faster Path to Market for Distributed Resources to be Studied,” PJM MRC & Members Committee Briefs.)
SPP members are considering a staff proposal to create a technology steering committee as a forum for discussions on incorporating storage and other technologies. (See “More Detail Requested on Technology Committee,” Strategic Planning Committee Briefs.)
At the Gulf Coast Power Association’s spring meeting last week, Allan Stewart, executive director of North American power for PIRA Energy Group, predicted innovations in battery technology will start changing electric market fundamentals as soon as 2020 in California and Hawaii. (See “Energy Storage Ready to Disrupt Industry?”, Overheard at GCPA Annual Meeting.)
Robert Mullin, Suzanne Herel, Tom Kleckner and William Opalka contributed to this article.
The commission dismissed a 2013 complaint by the Dallas-based chemical manufacturer that claimed MISO’s treatment of QFs violated the Public Utility Regulatory Policies Act (EL13-41). Occidental argued that MISO’s plan to integrate QFs in Entergy’s territory would strip them of their rights under PURPA, as the law assumes that they do not have access to wholesale markets.
The commission denied in part and granted in part requests for rehearing by Entergy Services and the Louisiana Public Service Commission (
The DEC said Constitution’s “application fails in a meaningful way to address the significant water resource impacts that could occur from this project and has failed to provide sufficient information to demonstrate compliance with New York state water quality standards.”
The commission’s Office of Energy Policy and Innovation last week sent identical letters to each of the grid operators under its jurisdiction, requesting data on “the eligibility of electric storage resources to participate in the RTO and ISO markets; the technical qualification and performance requirements for market participants; required bid parameters; and the treatment of electric storage resources when they are receiving electricity for later injection to the grid.”