Generators that planned to retire coal-fired units just ahead of the Environmental Protection Agency’s mercury rule extension deadline in April 2016 say they may have to accelerate retirements by a year to avoid incurring MISO capacity deficiency penalties.
But that will force them to buy capacity — and sellers wise to the generators’ dilemma are capitalizing on the situation, with capacity prices in the bilateral market tripling recently, Indianapolis Power & Light complained to the Federal Energy Regulatory Commission Oct. 1 (EL14-70).
“IPL believes that this threefold increase is indicative of a market that is seeking to capitalize on the current anomalous circumstances created by the six and one-half week disconnect between [the Mercury and Air Toxics Standard (MATS)] and MISO’s capacity planning year,” the utility said.
Last July, IPL asked the commission for a waiver from MISO’s open access transmission, energy and operating reserve markets tariff. It said there’s no clear mechanism within the MISO tariff that would permit it to buy replacement capacity through the auction to cover the six-and-a-half-week period between the planned April 16, 2016, retirement of its Eagle Valley units and the end of MISO’s planning year on May 31, 2016.
Instead, IPL told the commission, it would need to spend up to $22 million to purchase replacement capacity for the entire year. The utility is building a 650-MW gas generation plant near the 216-MW Eagle Valley units, which date to the 1950s, but the new generation isn’t expected to be on-line until late 2016.
IPL seeks a waiver from FERC for the six-week period so it can continue offering Eagle Valley capacity without MISO penalty through April 16, 2016.
Otherwise, IPL could retire the plant in mid-2015 and purchase capacity to meet its planning resource margin requirements.
“Our customers should not be made to pay for the ongoing costs of operating these units for 10 ½ months going forward plus the cost of procuring an additional full year of capacity in order to fill a capacity hole that is for a six-week period,” the company said.
IPL isn’t alone. Alliant Energy, MidAmerican Energy, Xcel Energy Services and Consumers Energy are among utilities that made filings in support of IPL’s request for a waiver.
In a filing last August, Consumers Energy said it’s in the same boat as IPL, with plans to shutter its 940-MW Classic Seven units on April 15, 2016, due to MATS.
Consumers said that it, too, would have to essentially “over-procure” capacity for 10 ½ months to meet MISO resource adequacy requirements — or may be exposed to replacement costs or a deficiency charge for the six-and-a-half-week period.
But MISO opposes such requests for a waiver from capacity resource performance requirements in its tariff, including the Must Offer and Resource Replacement requirements.
MISO told FERC on July 25 that such waivers “anytime during the last five months of a planning year could result in a substantial deficit in resources needed to meet demand.”
MISO noted that the five-month period would include the winter, “and as we learned during the polar vortex events of this past winter, winter demand can be significant even in a summer-peaking region.”
Further, changing the tariff as proposed by IPL, Alliant and MidAmerican “could have catastrophic resource adequacy consequences.”
But MISO downplayed the idea that other generators beyond IPL are grappling with the six-and-a-half-week gap between the MATS deadline and the end of the MISO planning year. “MISO is not aware that any other market participants believe their circumstances would necessitate early retirement to comply with MISO’s tariff provisions,” the RTO said in a filing this summer.
Also protesting IPL’s request is NRG Power Marketing and GenOn Energy Management, providers of bilateral capacity. NRG said IPL “correctly” notes that there’s no guarantee that bilateral capacity will be available, but “it is highly likely that such capacity will be available on a bilateral basis — and at far less than the cost of new entry.”
NRG also contends that requiring IPL to pay the market price for capacity during a period of scarcity “should not be considered a ‘problem.’ It is the market at work.”
ISO-NE will be expanding the winter reliability program it began last winter with additional incentives for fuel purchases and new pricing flexibility for generators.
Nevertheless, the ISO “will be in a precarious operating position for the next several winters due to the natural gas pipeline constraints that have limited the delivery of fuel to natural gas-fired power generators at times, combined with recent and pending generator retirements,” ISO-NE spokeswoman Marcia Blomberg said.
Although new pipeline capacity has been added since last winter, the region is still vulnerable to constraints, the Federal Energy Regulatory Commission staff told the commission last week. “With no [additional] pipeline capacity planned until 2016, the region will need to rely on fuel diversity to meet the region’s energy needs,” staff said.
Increased Marcellus Shale production and a mild summer created some unusual dynamics, with prices at the Algonquin citygate near Boston below Henry Hub since April.
But fears of another polar vortex and low natural gas storage have caused an 82% jump in natural gas futures for January and February 2015 versus a year ago, with prices averaging $21/MMBtu, FERC’s Division of Energy Market Oversight (DEMO) said. “Futures are raised because they are taking into account what happened last winter — so they’ve added kind of an insurance premium,” said Christopher Ellsworth, a DEMO branch chief.
Those expectations have rippled into the electricity markets, with winter power futures up 84% to $184/MWh.
FERC Chairman Cheryl LaFleur said the increase in futures prices is “quite sobering.”
New England Model ‘Unsustainable’
Commissioner Tony Clark said the Northeast is the area of “greatest concern” in the nation. “Already we’re hearing about potential all-in retail rates in parts of New England of 25 cents a kWh,” he said. “It’s really not a supply problem. We have a rather severe infrastructure problem.”
Clark said New England’s regulatory model — a mix of retail choice and state central planning — may be “unworkable and unsustainable.”
In an Oct. 15 response to a letter to the commission from New Hampshire Sen. Jeanne Shaheen, Clark said he believes both the traditional vertically integrated model and fully restructured markets can be effective.
“The one regulatory model that does not appear to be working well is one in which a market is created to procure resources for unbundled utilities, but then the pricing signals in the market are undermined by policies designed to select energy resource mixes through legislative or regulatory planning,” he wrote.
Last Winter’s Experience
While New England did not set a new winter demand record last winter, the ISO had its share of white-knuckle moments as gas-starved combined-cycle plants dropped offline and reserve margins briefly fell below prescribed levels. Natural gas supply constraints last year were worse than expected and some generators experienced difficulties replenishing oil supplies.
The region’s heavy reliance on natural gas generation, coupled with a high heating demand for that fuel, meant that gas prices exceeded that of oil on 57% of winter days. During cold periods, oil units provided nearly one-fourth of the region’s power instead of the typical 1% average.
Winter reliability was also enhanced, according to FERC, by its August 2013 order that clarified the ISO-NE tariff to impose a strict performance obligation on capacity resources. FERC ruled that capacity resources may not take outages based on economic decisions not to procure fuel or fuel transportation.
Winter Outlook
In September, the Federal Energy Regulatory Commission approved New England’s plan for the coming winter (ER14-2407). It creates incentives for dual-fuel resources, offsets the carrying costs of unused fuel oil purchased by generators and provides compensation for demand response services.
“Based on preliminary review of submissions to participate in the program, the ISO is satisfied that the response will help improve fuel adequacy for the 2014/15 winter,” Blomberg said.
Blomberg said that 69 oil and dual-fuel units have indicated a willingness to stockpile oil for the winter and several other gas-fired generators told the ISO they will add dual-fuel capability by Dec. 1. Another eight units plan to contract for at least 1.5 Bcf of liquefied natural gas.
The ISO also hopes to have 14 MW of DR, Blomberg said.
New England added about 200 MW of gas, biomass and solar since 2013. It expects almost 700 MW of new generation next year and another 300 in 2016, including more than 500 MW of natural gas.
At the same time, however, this year’s retirements of the Salem Harbor coal-fired generator and the Vermont Yankee nuclear plant will eliminate 1,300 MW of non-gas generation — more than the amount of capacity procured through last winter’s reliability program — and it will lose the 1,510-MW Brayton Point coal plant in 2017.
Retirements over the past year mean that gas-fired generation in New England has grown from approximately 44% of capacity in 2013 to 47% in 2014, according to FERC staff, who predicted increased prices and volatility.
Meanwhile, the use of backup oil generators has increased both emissions and costs. National Grid said last month that rates for its Massachusetts customers will increase by 37% over last winter’s as wholesale power prices have risen to the highest level in decades. NSTAR also expects to raise rates in the state, but the utility hasn’t said how much.
Plan for This Winter
The plan approved by FERC has six components:
Compensation for Unused Fuel:
Oil: Participants will be paid $18/barrel for carrying costs, price risk, availability cost and liquidity risk. The ISO plans to procure 3.5 million barrels of oil. Last year generators purchased 3 million barrels, 88% of which were burned.
LNG: Generators that contract for LNG will receive an end-of-season payment to offset the risk of unused LNG.
Dual-Fuel Incentives:
Natural gas-fired generators that commission or recommission dual-fuel capability will receive compensation to offset some of their costs. Eligibility is limited to generators that haven’t operated on oil since at least December 2011.
To allow more operational flexibility, dual-fuel resources won’t be required to demonstrate to the ISO’s Independent Market Monitor that it burned the fuel associated with its offer that cleared in the day-ahead market when fuel markets are volatile. However, the ISO will expand the scope of its audits of dual-fuel units.
DR: As in 2013/14, DR assets not otherwise participating in the wholesale markets or that have capacity in excess of obligations will receive both monthly payments for participating in the program and demand reduction payments based on the greater of either $250/MWh or the LMP of their zone. New this year:
The payment structure is modified to avoid double payments.
DR will be dispatchable up to 30 times this winter (six hours per dispatch), up from a maximum 10 dispatches last year (no more than two dispatches per day, with a minimum of four hours between each dispatch).
Participants will receive $1.80/kW-month rather than their “as bid” price.
A DR asset will lose its entire monthly payment if it fails to achieve at least 75% of its commitment for a month. (Last year’s underperformance penalty could have resulted in charges that exceeded assets’ program revenues.)
The DR program will be limited to 100 assets and 100 MW, down from last year’s cap of 200 assets. The ISO said the change will reduce administrative burdens and allow better estimation of maximum program costs.
Long-Term Plans
In approving New England’s plan for the coming winter, FERC ordered it to continue efforts to develop a long-term, market-based solution. ISO-NE on Wednesday filed a status report with FERC, stating the process will begin in November before the New England Power Pool Markets Committee.
ISO-NE expects to need some type of out-of-market program until 2018 when its Pay-for-Performance program to address the capacity market goes into effect. In that plan, the forward capacity market will have a two-settlement design, based on its actual performance during scarcity. Resources that perform poorly will cover their obligations through purchases from suppliers that perform well. The result will be payments from under-performing to over-performing resources.
A proposal by the six New England governors for a $3 billion taxpayer-supported pipeline transporting shale gas from Pennsylvania stalled in August due to cost concerns in Massachusetts. Gov. Deval Patrick temporarily suspended the state’s support of the pipeline after the state legislature failed to act on another major infrastructure project: additional transmission lines to import Canadian hydropower. The project would be funded through a tariff on ratepayer bills and supported by long-term power-purchase contracts.
Without clear support from Massachusetts, neither infrastructure project would be viable.
Kerri Fox of BBVA, far right, talked about uncertainty in development and urged coordination between the states at the Quadrennial Energy Review. “I think one of the problems in this country has been the piecemeal approach. As we’ve done financings in various states it’s always different,” she said.
NEW YORK — Energy Secretary Ernest Moniz traveled to New York last week to get Wall Street’s perspective on challenges to financing electric transmission and other energy infrastructure.
The response? Do more to get the state and federal governments aligned on policy and regulation. With Congress incapable of passing any legislation and coal states alienated by the Obama Administration’s carbon policies, that’s a tall order indeed. But since Moniz asked, they told him.
The session at New York University was the final public hearing outside Washington this year in the Obama Administration’s Quadrennial Energy Review. President Obama announced the initiative – an effort to coordinate energy policies among all federal agencies — in January.
Moniz said the administration will be seeking ways it can use its existing authority rather than seeking new legislation.
Moniz
He cited the Energy Department’s $1 million investment to help New Jersey Transit’s train system develop a microgrid, a project prompted by the outages caused by Superstorm Sandy. “It’s trying to look for leverage points even where we don’t have direct authority,” Moniz said.
A sampling of comments:
Despite “a surplus of capital today that is trying to get deployed,” said Kerri Fox, North American head of structured finance for BBVA, “there’s been a dearth of projects that are structured in a way that can be financed.” A lack of long-term contracts has made it difficult to obtain financing for transmission and storage projects, she said.
Fox said public-private partnerships (P3s), which have helped build infrastructure in Canada, could help finance interstate transmission. Alternatively, the administration could develop a “best practice” P3 that states could adopt.
“I think one of the problems in this country has been the piecemeal approach,” Fox said. “As we’ve done financings in various states it’s always different. I think the developers have a hard time knowing for sure that if they invest the money that there will actually be a transaction that comes out of it. My watch word would be simplicity and coordination across the states.”
John Lange, global head of Barclays Capital’s power and utilities group, agreed. “It’s pretty tough with 50 states, the [Department of Energy], the [Environmental Protection Agency], the [Federal Energy Regulatory Commission], for investors to understand where things are headed. If you can keep things coordinated and transparent … that will keep the cost of capital as low as possible.
“The market remains extremely global in terms of competition for capital. There is a lot of capital out there but everyone on the power utility and infrastructure side is comparing jurisdictions. They’re comparing regulatory regimes; they’re chasing the best returns.”
Lange also said many are skeptical of investing in renewables. “Costs [of renewables] have come down dramatically. But the reality is … a lot of the energy is coming from the traditional way — utility assets. We want to make sure we don’t get burned by putting money into those [investments] and not getting the right rate of return for the risk we thought we were taking.”
Stephen Zucchet, senior vice president of Borealis Infrastructure, an arm of the Ontario Municipal Employees Retirement System (OMERS), cited as a success story Texas’ Competitive Renewable Energy Zone (CREZ).
Seven transmission and distribution utilities are building the project, which will be able to carry 18,456 MW of wind power from West Texas to the state’s urban areas. “Today you have a $5 billion project that’s well on its way to being completed,” he said. “[It could be] a template.”
Humayun Tai, a partner in McKinsey’s energy practice, said as much as 25% of RTO interconnections are for remote renewables. “You have load pockets and you have investment pockets. Over time as those separate, meaning load grows in an area you didn’t expect, you get congestion. And we are behind on congestion spending.”
Duke Energy and Exelon should be among the companies barred from acquiring any generation divested by PPL as part of its spinoff plan, the Independent Market Monitor told the Federal Energy Regulatory Commission.
The IMM submitted a corrected list (EC14-112) to replace one that it said erroneously excluded the two companies and mistakenly included Edison International.
PPL and Riverstone Holdings announced in June they would join their generation businesses into a publicly traded independent power producer named Talen Energy. The new company would own 15,320 MW of capacity, including 12,000 MW in PJM.
In their application to FERC, the companies proposed selling about 1,300 MW of PJM generation to avoid market power complaints. The companies said that no company with more than 10% of PJM’s summer installed capacity — a group that includes Exelon, NRG Energy and PSEG — should be permitted to bid for the plants.
The IMM says those barred from purchasing the assets should also include American Electric Power, Calpine, Dominion Resources and FirstEnergy. (See Market Monitor on Talen Plan: Not So Fast.)
MISO is depending on its transmission system, better information about natural gas pipelines and voluntary demand reductions to meet peak loads over the next two winters.
MISO told the Federal Energy Regulatory Commission last month that its Central and North regions expect a 2.3-GW shortfall in 2016, with three of the six zones failing to meet target reserve margins. While the recently integrated South region shows a 2.5-GW surplus over the same period, transmission constraints will limit the ability of the short zones to import the ISO’s spare megawatts.
“Reserve margins are tightening across the footprint, the result of aging infrastructure, environmental regulation, and decisions made by legislatures, utilities and regulators to diversify the generation fleet,” Eric Callisto, president of the Organization of MISO States (OMS) and a member of the Wisconsin Public Service Commission, told FERC. “The erosion of excess reserves understandably is of great concern to us all. And consistent with our relative roles in the industry, I believe there has been an appropriate response in the MISO footprint to this challenge.”
Some are skeptical of the forecasts, the result of a MISO survey of load-serving entities.
MISO officials had been warning last November that they faced a capacity shortfall of as much as 5 to 7 GW in 2016-17 due to the loss of coal-fired generation. In January, officials cut the forecast shortfall to 2 GW. In April, MISO told FERC it had reduced the projected shortfall further to 500 MW.
FERC Commissioner Philip Moeller noted that the projection assumed an increase in residential demand would be negated by a decline in industrial load. “If [industrial demand] turns around, as we hope it does, then your assumptions start getting shaken real quickly,” Moeller said.
Last Winter
Last winter was the coldest in two decades for many areas of MISO, with increased outages, record congestion and higher prices and uplift. Heating degree days rose 25% from the previous winter pushing average load was up 7%.
MISO set a new winter peak of 109.3 GW on Jan. 6, a 9% jump from the previous peak. The following day, MISO narrowly avoided having to shed load as it fell 1,900 MW short of operating reserves, leaving it with only 300 MW.
MISO’s Independent Market Monitor, Potomac Economics, said ISO operators were late to recognize the shortage and approved 700 MW in exports that began flowing at 7 a.m., 10 minutes before it fell into a shortage and 15 minutes before it declared a Maximum Generation Alert.
Prices
Day-ahead energy prices averaged $51.52/MWh for the winter, almost 80% higher than the previous year.
Fuel delivery problems and low storage levels led to extreme natural gas price volatility. Generating costs for gas units in the Midwest region were as much as 10 times that in the South, reflecting a disparity in gas costs. Natural gas prices at Chicago rose to $8.02/MMBtu, more than double the price a year earlier.
In late February, prices stayed above $10/MMBtu for 12 consecutive days. At the benchmark Henry Hub in Texas prices never rose above $8.
Midwest markets will have increased access to Marcellus and Utica gas by the end of 2014 with the addition of 425 MMcfd of pipeline capacity, FERC staff said in a presentation at the commission’s Oct. 16 meeting. As of Sept. 30, the price at Chicago was $3.93/MMBtu, up 5% from a year earlier.
Price volatility make whole payments, intended to encourage suppliers to follow dispatch instructions, rose steeply, with day-ahead payments rising four-fold to $40.3 million for the winter and real-time payments rising 57% to $3.2 million.
The cumulative outage rate was 9.5%, up from 7.3% in 2013/14 and 8.1% in 2012/13. Short-term forced outages, which the Monitor said can be an indicator of physical withholding, rose to 2.7% from 1.7%. The Monitor said it was investigating outages that contributed to shortages or severe congestion, as well as units that didn’t respond on Jan. 6 and 7.
Actions Taken
MISO spokeswoman Jennifer June Lay said the polar vortex “taught MISO and our member companies a number of lessons about how to maintain reliable operations as we face extreme cold weather.”
She highlighted several changes since last winter:
Voluntary Load Management reporting was implemented in July to provide MISO more accurate data. “MISO lacked a clear understanding of demand response availability on a consistent basis due to the seasonal variation in potential and poor visibility into voluntary load management activities,” Lay said.
A real-time display was added to the MISO control centers to show the status of the major pipelines in the MISO footprint. In addition, a gas pipeline notification page was added to the MISO website in August. It includes a list of critical pipeline notices impacting the MISO footprint with drill-down functionality to additional information, including a map of the affected pipelines and the generators they serve.
Lay said the ISO is also discussing potential initiatives to address fuel-supply issues for natural gas units, reduce outages and improve data collection on outages and derates.
MISO is also soliciting stakeholder feedback on a straw man proposal it presented in August to change the natural gas nomination schedule.
Lawmaker: UP Needs Plants, Not Transmission Upgrades
Dianda
State Rep. Scott Dianda thinks utilities should build new power plants to replace retiring generators in the remote Upper Peninsula, rather than bringing in power over new transmission lines.
Dianda introduced a resolution encouraging the build-out of new power plants to serve the Upper Peninsula, saying it would be more cost-effective than transmission lines. Dianda pointed to the imminent retirement of a 450-MW We Energies plant at Presque Isle as evidence of the need for new generation. The aging coal plant remains operating under an order from MISO, which determined the plant had to stay online to preserve system reliability.
BPU Orders Third-Party Suppliers Provide Simpler Offer Details
The Board of Public Utilities ordered third-party electricity suppliers to explain their offers to consumers in plain language. The order was a response to a flood of complaints from customers who were hit with large bills last winter.
Suppliers now are required to clearly tell consumers if they are getting a fixed rate or a variable rate. Many customers said they were unaware of provisions in their contracts that pegged their electric bills to natural gas prices, which soared during the winter. The changes are to go into effect next month.
“This is really an evolving process,’’ BPU Commissioner Joseph Fiordaliso said. “It is important the industry become involved in the educational process. We didn’t expect this sustained cold.’’
No Need for NCUC Hearing for New Plant, Owners Say
The developers of a new, 475-MW natural gas plant have asked the Utilities Commission to expedite approval of the project because it is unopposed.
NTE Carolinas wants to build a one-on-one combined-cycle plant called the Kings Mountain project in Cleveland County. It has already won approval from NCUC staff. There have been no opposition filings to the project since it was announced in June. If approved, NTE said construction would begin in June of 2015 and operations would start in March of 2018.
The University of North Carolina is putting together a panel of experts to review Duke Energy’s plans and procedures to close its ash ponds and dumps across the nation, part of an effort to hold the company accountable after a devastating ash spill in the Dan River earlier this year.
The National Ash Management Advisory Board will be chaired by UNC professor John Daniels, an environmental engineer known for reuse of waste materials. The board, which is funded by Duke, will provide guidance to the Duke team overseeing the ash disposal plan. Duke has 33 impoundment ponds and dumps throughout the state holding fly ash from coal-fired generation stations.
Sunoco’s Mariner East Pipeline Given Utility Status by PUC
The Public Utility Commission rejected an advisory opinion and reaffirmed public utility status for Sunoco Logistics Partners and its proposed pipeline, Mariner East. The PUC sent the issue back to administrative law judges to examine Sunoco’s request for a zoning exemption to construct buildings around valve control and pump stations along the 300-mile pipeline.
Sunoco Pipeline is repurposing an existing pipeline to move Marcellus Shale liquefied natural gas to a terminal near Philadelphia, a process that requires new pump and valve control stations on the 83-year-old pipeline. Sunoco had asked that the pump stations be exempt from local zoning restrictions. Some landowners and local governments had hoped to impede the project through zoning hearings.
Two PUC administrative law judges recommended rejecting Sunoco’s status as a public utility, which is the basis for obtaining the local zoning exemptions, but the PUC said the pipeline company qualifies.
“Sunoco’s amended petitions adequately plead sufficient facts for the commission to find that it is both a ‘public utility’ and a ‘public utility corporation,’” the commission wrote in a 4-1 ruling.
The Department of Environmental Protection is seeking a $4.5 million fine against a Pittsburgh natural gas producer for allowing fracking wastewater to leak from impoundments. If the fine is upheld, it would be a record for the state.
The DEP charged that EQT allowed a “major pollution incident” in 2012 in Tioga County. It said EQT first noticed a possible leak in April, but the company said it discovered the leak in May and that it took steps to contain it and dispose of contaminated soil. The DEP, however, said the spill continued to cause problems and that water was still being collected at the site.
Other drillers have faced DEP fines for similar issues. In September, Range Resources agreed to pay a $4.15 million fine related to wastewater contamination.
The State Corporation Commission last week approved the merger between Exelon and Pepco Holdings Inc., one more hurdle crossed for the $6.8 billion deal. The approval was needed because Pepco and one of its subsidiaries, Delmarva Power and Light, have some transmission facilities in Virginia.
The merger still needs regulatory approval from Maryland, D.C., New Jersey and Delaware, as well as the Federal Energy Regulatory Commission. Pepco stockholders approved the merger on Sept. 23.
Exelon is promising reliability improvements for all Pepco territories, as well as a $100 million customer benefit fund that can be applied toward rate credits, energy-efficiency programs and assistance programs. Exelon is also promising to contribute $50 million to charitable organizations in Pepco territories.
McAuliffe’s Energy Plan Has Something for Everyone
McAuliffe
Gov. Terry McAuliffe’s new energy plan casts a wide net, promising support for renewables, new traditional energy projects, coal exports and infrastructure investment. The state rolls out an energy plan every four years.
The plan calls for easing restrictions on solar development and boosting renewable energy. Virginia now only counts about 6% renewables as part of its generation mix, most of that hydro. The plan also calls for a revenue-sharing plan for any gas and oil extracted from offshore development, as well as additional incentives to develop wind energy.
Recognizing that domestic demand is declining for the state’s coal resources, the plan calls for increasing exports of coal and coal technology.
The plan drew initial praise from industry and environmentalists. “We appreciate and agree with the governor’s commitment to an all-of-the-above energy strategy and his recognition of the need for new energy infrastructure investments,” Dominion spokesman David Botkin said. The Sierra Club’s Virginia chapter saw “a lot of good stuff in this plan on efficiency, offshore wind and solar,” according to chapter Director Glen Besa.
The state is looking for ways to deal with tight budgets and has hit upon a new one.
Last week, the state opened bids to drill under a 14-mile section of its portion of the Ohio River. Officials from the Department of Commerce say that allowing drilling on state land and now under a state-controlled river would generate $17.8 million in up-front payments, plus royalties.
Until horizontal drilling methods were improved, such extraction wasn’t feasible. But now, allowing fracking under rivers “creates what could be a substantial revenue stream at a time when budgets are very tight,” according to Commerce Secretary Keith Burdette. State officials said other river tracts could be next.
AEP to Transfer Partial Ownership of Mitchell to Wheeling Power
American Electric Power, consumer groups and energy-efficiency advocates have reached an agreement that will let the company transfer half ownership of the 1,600-MW Mitchell Power Plant to subsidiary Wheeling Power.
According to a filing with the Public Service Commission that outlines the terms of the agreement, Wheeling would pay about 82.5% for half of the interest in the plant, with the final payment set in 2020. The agreement, if approved by the PSC, would leave state rate payers responsible for half of what had been a merchant plant, leaving them open to some market risk.
AEP wanted to transfer ownership to a regulated utility in order to obtain rate guarantees. An attempt to transfer partial ownership to Appalachian Power, which is regulated by the Virginia State Corporation Commission, was turned down by Virginia regulators.
To make the deal more palatable for consumer groups and energy-efficiency advocates, AEP promised to bulk up its annual spending on energy-efficiency programs from $1.8 million to $10 million. The company will also issue RFPs for any new generation it may need in the future. This would encourage participation by renewable-energy producers, offsetting criticism that AEP’s generation mix consists of too much coal.
Constellation Energy and demand side management specialist Comverge said last week they are combining their demand response businesses for commercial and industrial customers.
The announcement came the day before PJM proposed ways for demand response to comply with an appellate court ruling in the Electric Power Supply Association’s (EPSA) challenge of the Federal Energy Regulatory Commission’s Order 745. (See related story, Awaiting FERC Action, PJM Floats ‘Trial Balloon’ on DR Post-EPSA.)
Despite the uncertainty following the EPSA decision, Constellation and Comverge said they believe there is still gold to be mined in the DR market.
The two companies said the new combined business will be operated as a standalone company, with Constellation taking a minority stake and private equity investment firm H.I.G. Capital holding the majority. Terms of the agreement were not released. Comverge, which went public in 2007, was acquired by H.I.G. for $49 million in 2012.
Comverge and Constellation officials said the name of the new company will be announced after the closing of the transaction.
Scale
Comverge CEO Gregory Dukat said the new company’s “size, focus and years of expertise helping C&I [commercial and industrial] customers successfully participate in demand response programs make it a formidable presence in the market.”
Mark Huston, president of Constellation Retail, said DR customers will “benefit from a company solely dedicated to DR products and services.”
Comverge has more than 5.5 million energy management devices in the field and thousands of C&I customers. They also brought more than 1 million residential customers into various DR programs. It has absorbed other demand response businesses, including Enerwise Global Technologies, which it acquired in 2007 for $75 million.
Jason Cigarran, Comverge’s vice president of marketing and communications, said that because the new company will be taking what had been Comverge’s C&I customers, the rest of Comverge will now concentrate on residential and small business exclusively. He declined to say how many megawatts of DR the company has under its control.
Constellation’s retail businesses serve more than 100,000 commercial customers and more than 1 million residential customers. It purchased CPower, which managed 850 MW of DR capacity, in 2010. Constellation said it controlled 1,300 MW of DR as of the end of 2013.
Competition
The merger will give the combined company more scale to compete against publicly traded EnerNOC, which has between 24,000 and 27,000 MW of peak load management. According to a recent Securities and Exchange Commission filing, EnerNOC had $22.1 million in revenue in 2013, about 45% of that from the PJM market.
NRG Energy is also moving into the market in a larger way and now has about 2,000 MW of demand management load under its control.
Some analysts say that the increased competition in the DR market is putting pressure on prices. The loss of the guaranteed prices that had been afforded by FERC’s Order 745 may also slow some of the demand response market, they say. A study by Greentech Media predicted the loss of Order 745 will reduce the annual growth rate of the DR industry from 8% to 4.9% through 2023. (See Appeals Court Snuffs Hope for FERC Demand Response Jurisdiction.)
Exelon, which last month announced it would spend $500 million to build two natural gas-fired generating stations in Texas, is selling two other gas plants in Texas and Utah.
An Exelon spokesman confirmed the pending sales last week but declined to give sales prices.
Exelon is selling its five-unit, natural gas-fired peaking plant near West Valley City, Utah, to Wayzata Investment Partners. The 185-MW plant went into operation in 2001 and was folded into Exelon’s fleet in the 2012 merger with Constellation Energy. Investment news service The Street, citing unnamed sources, estimated the price at between $74 million and $93 million.
Starwood Energy Group is buying the second Exelon plant, the Quail Run Generating Station near Odessa, Texas. It is a six-unit, 488-MW natural gas-fired combined-cycle plant. The first section of the plant went online in 2007 with the second section going operational a year later.
It too came with the Constellation merger. Constellation acquired it in 2010 for $365 million.
Exelon Generation spokesman Jimmy Porch said the company expects to close on both in the fourth quarter of this year.
Wayzata did not issue any announcements about the purchase agreement. The company describes itself on its Web site as a private equity firm “that specializes in purchasing distressed companies and assets with various strategies to profitably turn them around in partnership with new or existing management.”
The company, headquartered in Wayzata, Minn., has purchased power plants before. It bought Guadalupe Power, a 1,070-MW plant in Guadalupe County, Texas, in 2011, selling it to Calpine in February.
Starwood has numerous holdings in natural gas and renewable generation and transmission. It also declined to give a purchase price.
Exelon has made steady investments in its generation footprint in Texas, starting when it bought the Handley and Mountain Creek generating stations from then-TXU for $443 million in 2002. Exelon also built a gas-fired plant to serve industrial users near Houston called ExTex Laporte.
Last month, it announced it was building two 1,000-MW gas-fired combined-cycle plants, one each at its existing plants at Wolf Hollow, near Fort Worth, and Colorado Bend, southwest of Houston. That would bring the company’s Texas fleet to about 5,500 MW after the sale of Quail Run.
Porch said Exelon had not intended to sell Quail Run but that it “received attractive unsolicited bids” for the plant. “All decisions were founded on optimizing Exelon’s generation mix,” he said.
He said Exelon remains committed to being a player in the ERCOT market.
“Exelon’s decision to build two new natural gas power plants in Texas is part of our ongoing growth strategy and will allow the company to offer more low-carbon electricity to the growing Texas energy market,” Porch said. “Texas is an important area for growth for Exelon because of the increasing demand for electricity in the state and excellent market conditions.”
He wouldn’t say if there are any other deals afloat. “Exelon continually evaluates all opportunities to add value for our shareholders, including M&A,” he said. “However, we don’t comment on rumors about specific M&A activity.”
PJM will forgo $10.2 million in balancing operating reserve (BOR) charges resulting from transactions that two trading companies characterized as internal bilateral transactions (IBTs) under a settlement approved by the Federal Energy Regulatory Commission.
PJM, which contended DC Energy and Scylla Energy mischaracterized the transactions to avoid paying the charges, collected $38.8 million in retroactive payments from the companies after it found in 2011 that the trades did not involve the physical transfer of energy and could not be classified as IBTs under PJM’s Tariff. Unlike increment offers (INCs) and decrement bids (DECs), IBTs are not subject to BOR charges.
Under the settlement, PJM will retain the money it has already collected while dropping its claim to the remaining $10.2 million. The companies, meanwhile, will withdraw their petition to the D.C. Circuit Court of Appeals to review FERC’s March 2012 order that forced the companies to pay the charges.
PJM and the companies said they settled “in order to bring certainty to the marketplace and avoid the costs, risks and uncertainties of continued litigation.”
‘Nonsense’
PJM’s Independent Market Monitor, however, said “the argument that the settlement brings certainty to the marketplace is nonsense.” The monitor said the settlement means that PJM members will not receive $10.2 million to which FERC has found they are entitled. It also said, however, that “more than $10.2 million is at stake in this proceeding. Full enforcement of the commission’s orders is important to discourage inappropriate market behavior.”
FERC ruled that the settlement doesn’t change the commission’s interpretation of PJM’s rules concerning IBTs. “PJM market participants, therefore, remain on notice that IBTs may not be used to avoid deviation charges,” FERC said.
While pondering the biggest change in the capacity market since its inception, PJM is hoping that testing of little-used generating units will ensure they are available if cold weather strains its reserve margin.
Last winter, the RTO saw as much as 22% of its generation on the disabled list as it set new winter peak records. Officials had to admit afterward that they had mistakenly assumed that natural gas plants’ outage rates would be randomly distributed rather than correlated with cold weather and pipeline problems.
The record-setting cold pushed PJM’s load-weighted LMP to $126.80, more than three times the price in January 2012. Operators had to resort to demand response and a voltage reduction to avoid shedding load. The new winter peak of 141,500 MW exceeded the Feb. 5, 2007, mark by nearly 5,000 MW.
It was a humbling experience for an organization long held out as the gold standard among grid operators.
To improve operations in the interim, PJM stakeholders embarked on initiatives in at least five committees and task forces. Earlier this month, the Operating Committee approved plans for voluntary generator testing, while the Market Implementation Committee approved rules to reduce uplift and ensure energy prices better reflect operator actions. (See MIC Briefs)
PJM hopes to test up to 1,000 MW of generation on each of 20 days in December 2014. The tests would be limited to generators that haven’t run in the prior eight weeks and days when temperatures are below 35 degrees Fahrenheit.
The OC also endorsed manual changes to ensure generators keep their operating parameters (e.g., notification times, dual-fuel capability and availability, fuel inventories, resource limitations) updated in eMkt.
PJM officials also have taken steps to improve communication with pipelines, transmission owners and neighboring reliability coordinators.
PJM will enter the winter with 183,000 MW of installed capacity, almost 50,000 more than the projected 50/50 winter peak of 133,510 MW. It will also benefit from transmission upgrades in Pennsylvania, New Jersey, Ohio and Maryland.
The RTO will conduct a fuel inventory survey in November and a dispatcher training webinar covering the changes in December. An emergency procedures drill is scheduled for Nov. 17.
“Based on forecasts, we expect to have adequate power supplies for the winter,” PJM spokesman Ray Dotter told RTO Insider. “We’ve learned from last January’s cold weather and we’re working with our members to improve the availability of generation over the long term.”
“We didn’t have a reliability problem last year. I’m not expecting to have one this year as well,” Executive Vice President for Operations Mike Kormos told the Organization of PJM States annual meeting last week.
One item that remains unresolved on PJM’s to-do list is a potential increase in the $1,000/MWh offer cap. None of three proposals considered by the Markets and Reliability Committee last month could muster a two-thirds majority. (See Members Deadlock on Change to $1,000 Offer Cap.)
Gas and electric futures prices are up sharply, Federal Energy Regulatory Commission staff said in a briefing last week. As of Oct. 1, the average of January and February 2015 contracts at Transco Zone 6 non-NY was $9/MMBtu, almost double last winter. Electricity futures at the PJM Western hub were up 62% to $73/MWh.
