MISO industrial customers will get a full hearing on their bid to reduce transmission rates by $327 million a year.
The Federal Energy Regulatory Commission Thursday ordered an evidentiary hearing on the industrials’ complaint that the 24 MISO transmission owners’ base return on equity (ROE) — 12.38% except for ATC, which has a base ROE of 12.2% — is unjust and unreasonable.
The complaint “raises issues of material fact that cannot be resolved based upon the record before us and that are more appropriately addressed in the hearing and settlement judge procedures,” the commission ruled (EL14-12).
The commission rejected an attempt by the transmission owners — including Ameren, Duke Energy and Entergy — to dismiss the complaint on procedural grounds.
FERC opened the door to fights over the maximum allowable ROE in June, when it changed the way it sets return on equity rates for electric utilities that’s now more akin to the process it uses for natural gas and oil pipelines. Ruling in a case involving New England transmission owners, FERC tentatively set the “zone of reasonableness” at 7.03-11.74%. (See related story, New England TOs to Pay Refunds in ROE Case.)
MISO’s industrial customers say the base ROE for MISO TOs should not exceed 9.15%, citing “significantly changed economic circumstances since the base ROEs were first established.”
The commission rejected the industrials’ challenge to the use of capital structures that include more than 50% common equity.
“Complainants have not demonstrated that MISO TOs, individually or collectively, do not meet the requirement of the commission[’s] three-part test, failure of which would call into question the justness and reasonableness of using their actual capital structures for ratemaking purposes.”
The plaintiffs are six groups of industrial customers, including Illinois Industrial Energy Consumers, Indiana Industrial Energy Consumers, Minnesota Large Industrial Group and Wisconsin Industrial Energy Group.
The Environmental Protection Agency’s proposed regulations on carbon emissions would increase electric bills and harm reliability, Virginia State Corporation Commission staff members said in comments filed last week.
SCC staff said EPA’s “arbitrary, capricious, unsupported and unlawful” plan could cost Dominion Virginia Power customers alone between $5.5 billion and $6 billion. “Contrary to [the EPA’s] claim that ‘rates will go up, but bills will go down,’ experience and costs in Virginia make it extremely unlikely that either electric rates or bills in Virginia will go down,” staff said.
The EPA’s proposed regulations, announced in June, call for a 30% reduction in carbon emissions from the country’s existing power plants’ 2005 levels by 2030, with individual targets for each state. (See Carbon Rule Falls Unevenly on PJM States.) Virginia would be required to reduce its generating plants’ emissions to 884 lbs./MWh by 2020 and to 810 lbs./MWh by 2030.
Stranded Investments
The EPA’s modeling predicts that Virginia utilities will have to retire 2,851 MW of fossil-fuel generation and build 351 MW of wind power before 2020, “a timeframe that compromises reliability,” staff said.
The retirements threaten “several billions of dollars of recent investments in existing coal-fired facilities in Virginia and West Virginia that Virginia ratepayers have only begun to pay off. Much of this investment has been constructed to comply with EPA consent decrees on which the ink is hardly dry,” staff wrote.
Staff also claims the regulation would impose more stringent emission requirements on existing generators than the EPA is requiring in a separate standard for new generation.
While existing plants in Virginia will eventually be limited to 810 lbs./MWh, new coal plants, built with the best available carbon-capture technology, are limited to 1,000-1,050 (depending on the size), while new natural gas plants are limited to 1,100.
“It would be hard to imagine the EPA advancing such a proposal in areas that are more familiar to everyday life,” SCC staff said. “Would it be rational to require the current owners of automobiles or lawnmowers throughout Virginia, for example, to meet an emission standard that is 26% more stringent than required for the production of new cars or lawnmowers that must use the best available technology?
“Turning regulation on its head in this way — requiring older, but still useful equipment to meet a standard that the EPA admits cannot be achieved even by entirely new equipment — is a recipe for stranding prior investments and requiring significant additional investment.”
Reliability Impact
SCC staff said that they analyzed Dominion’s 2013 integrated resource plan as a reference to estimate the cost of complying with the EPA’s rule. One of two scenarios in the IRP, the Fuel Diversity Plan, calls for the addition of a third unit at the utility’s North Anna nuclear plant. (See SCC: Dominion IRP Lacks Analysis of Nuclear Plans.)
This plan would allow the state to meet its 2030 goal, the SCC staff said, but they altered it to include 69 MW of wind generation and more coal plant retirements than originally called for to meet the interim 2020 goal.
“These retirements are of grave concern because the power plants involved are used today to ensure reliable service to Virginia customers, have years of useful life remaining and cannot be replaced overnight or without regard for impacts on the electric system,” staff said.
Staff said the regulations set “generic and unsupported expectations of levels” of renewable generation and energy efficiency that “are extremely ambitious, almost certainly unachievable and uneconomic under traditional standards.”
Enviros: SCC Staff ‘Playing Politics’
Several environmental groups, however, criticized SCC staff’s assertions as inaccurate.
“The SCC staff analysis is just plain wrong,” said Glen Besa, director of the Sierra Club’s Virginia Chapter. “They’re playing politics with climate change science and they have no business doing that, and they’re bringing discredit on the commission.”
“The SCC staff crossed the line in their hastily submitted comments to EPA and I think they’ll ultimately regret that mistake,” said Dawone Robinson, the Chesapeake Climate Action Network’s Virginia policy director. “I think they misread the rule.”
Specifically, Robinson questioned the use of Dominion’s Fuel Diversity Plan as a way to comply with the regulations.
“SCC staff seems to suggest that in order to comply with the Clean Power Plan, Virginia needs to invest in a third nuclear reactor at North Anna, and that simply isn’t the case,” Robinson said. “Additionally, many of the coal plant retirements and natural gas conversions that the SCC staff suggests will hamper the state … were proposed by the utility before the Clean Power Plan was even released.”
Robinson’s comments echo those made by Cale Jaffe, director of the Southern Environmental Law Center’s Virginia office, to The Richmond Times-Dispatch.
“It appears the staff has misread the rule,” Jaffe said. “Analyses that we have reviewed show that Virginia is already 80% of the way to meeting Virginia’s carbon pollution target under the Clean Power Plan.
“Almost all of those reductions are coming from coal plant retirements and natural gas conversions that the utilities put in place long before the Clean Power Plan was even released.”
The EPA, which will be accepting comments on the proposed rule through Dec. 1, will issue the final rule in June 2015.
Northern Indiana Public Service Co. has reached an agreement with environmentalists and consumer advocates on a new renewables tariff that will boost payments to small wind farms while cutting prices for solar power.
The pact on NIPSCO’s revised renewable feed-in tariff (FIT), filed Oct. 9 (Case #44393), awaits final approval from the Indiana Utility Regulatory Commission.
Wind power generators of up to 100 kW would receive $0.25/kWh, up from $0.17.
“The purchase price for small wind in [the original FIT] was too low and as a result, the available capacity was not used,” said Kerwin Olson, executive director of Indianapolis-based Citizens Action Coalition. “Expanding small wind is important, so increasing that price will hopefully drive investment in small wind in Indiana.”
The settlement decreases payment for solar power to $0.17/kWh from $0.30/kWh.
Olson said the decrease reflects the falling costs of solar panels while still providing the price support needed to continue solar’s expansion in NIPSCO’s territory. “Solar is not at grid parity yet in Indiana, so it needs a ‘leg up,’” he said.
Residential customers would pay about $1 per month for renewables under the revised tariff, an increase of about $0.25. “We feel that’s reasonable,” Olson said.
Not everyone got what they wanted. The CAC and the Hoosier chapter of the Sierra Club argued that the definition of “qualifying renewable energy power production facilities” under the FIT should exclude facilities fueled by organic waste biomass derived from forest thinning.
The groups also sought exclusion of some types of waste-to-energy facilities, over air and water pollution concerns.
The FIT program is designed to incent customers who generate green electricity from solar, wind, biomass or new hydroelectric facilities. Facilities between 5 kW and 5 MW are eligible. Total capacity available under the FIT is capped at 30 MW.
Among those generally pleased with the settlement is Bio Town Ag, which operates the world’s largest on-farm anaerobic digester generating facilities with NIPSCO, according to Bio Town president Brian S. Furrer. Bio Town, in Reynolds, Ind., has sought multiple purchasers of electricity generated by methane from animal waste, including NIPSCO and other suppliers. The digester generation facility can produce 5 MW.
Also party to the FIT settlement with NIPSCO was the Indiana Distributed Energy Alliance and the Indiana Office of Utility Consumer Counselor.
NIPSCO officials were not immediately available for comment.
A new constructability review of proposed Artificial Island solutions revealed no significant differences in the permitting challenges between the northern and southern Delaware River crossings, PJM told the Transmission Expansion Advisory Committee Thursday.
A PJM consultant compared the permitting challenges between a proposed line crossing the southern part of the Delaware River to a line that runs from the island to Red Lion, Del. “Both will have significant permitting challenges,” said Paul McGlynn, general manager of system planning. “Neither one will be easy.”
McGlynn noted that although two of the four finalists bidding for the job has offered to cap their costs, none has offered a firm “fixed” cost. “They all have exclusions in what’s included and not included” under the cap, McGlynn said.
PJM is continuing its review of the proposals.
Planners Studying EPA Carbon Rule, Ill. Nuke Retirements
PJM staff is analyzing the potential impacts of the Environmental Protection Agency’s proposed carbon emissions rule in response to a request from the Organization of PJM States Inc. (OPSI).
In a letter to PJM CEO Terry Boston, OPSI said it would like the analyses based on several scenarios, including one that assumes a PJM-wide carbon price based on a “roll up” of EPA’s state emission targets and compliance with existing state energy efficiency and renewable portfolio standards. Other scenarios requested would include only renewable resources currently in the transmission queue or a 50% increase in natural gas costs.
Staff is conducting a production cost simulation and evaluating the reliability impacts from the potential loss of “at-risk” plants. Initial results are expected as soon as the end of the month.
Planners are also conducting an analysis of the potential loss of Exelon’s Byron, Quad Cities and Clinton nuclear plants at the request of the Illinois Commerce Commission. Exelon has said it may be forced to close some of its Illinois nuclear fleet because of low energy and capacity revenues. (See Exelon in Lobbying Push to Save Ill. Nukes.)
The ICC’s request asked PJM to calculate the potential impact on wholesale energy prices and the need for transmission improvements. Initial results are expected in mid-October.
The Operating Committee approved the following with little debate or opposition:
Transmission Owner Data Feed
Members agreed to Operating Agreement and manual changes to make it easier for transmission owners to access real-time generator data. The changes are intended to improve situational awareness and emergency response.
The Operating Agreement was revised to include a universal non-disclosure agreement, eliminating the need for a separate data confidentiality agreement.
Transmission owners will be able to obtain data from generators in their zone without justification. For generators outside its zone, the TO must confirm that the plant is in the current TO energy management system (EMS) model or will be included in an expanded model. (See Members to Consider Easier Sharing of Real-Time Generator Data.)
Manual 1: Control Center and Data Exchange Requirements
Members approved changes to Manual 1 to comply with a revised reliability standard given preliminary approval by the Federal Energy Regulatory Commission last month. COM-002-4 (Operating Personnel Communications Protocols) requires the use of a three-part communications process when issuing operating instructions. (See FERC Backs NERC, NAESB Standards.)
TO/TOP Matrix
Members approved version 8 of the Transmission Owner/Operator Matrix, an index between PJM manuals and NERC reliability standards.
Non-Voting Items
Eastern Interface Changes
The Eastern Transfer Interface definition will be revised, and its import capability increased, with the completion of the Susquehanna-Roseland 500-kV project.
The definition, currently comprised of five paths, will be expanded to include the Lackawanna-Hopatcong line. The new definition will change the distribution factors for some generators and increase import capability to the east.
The revision won’t have an impact until the Lackawanna-Hopatcong line goes in service. Completion of the line is expected about June 2015.
Warren Pricing Interface Expanded
PJM has added the Four Mile Junction-Corry East 115-kV line to the definition of the Warren pricing interface. The interface was created last month to set LMPs when operators take actions to address voltage issues in the Warren, Pa., area. The Warren interface, which is within the larger Seneca interface created in February, is effective until further notice.
Renewable Integration Study Recommendations
Members of the Intermittent Resources Task Force compiled a to-do list for the RTO as a result of the PJM Renewable Integration Study. The study found that PJM could get 30% of its generation capacity from wind and solar power without harming reliability but that coal and combined-cycle generators would face reduced run times and lower energy prices. (See Renewables Study Has Bad News for Coal, Gas Generators.)
PJM’s consultant on the study identified seven recommendations and topics for future study, but a survey of task force members indicated interest in pursuing only three. They would like PJM to:
Explore the reasons for ramping constraints on specific units and identify methods for improving performance. This would require approval of a problem statement.
Consider the impact of reduced energy market revenues for conventional generators in future capacity market discussions.
Investigate how wind and solar plants could contribute to frequency response. The Planning Committee last week approved an initiative on this issue based on the recommendation of its Enhanced Inverter subgroup. (See related story in Planning Committee Briefs.)
The Market Implementation Committee approved new rules to reduce uplift and ensure energy prices better reflect operator actions, including a more flexible version of the short-term fix approved by stakeholders in May.
The rules would increase synchronized and primary reserve requirements under emergency conditions (Hot and Cold Weather alerts, Maximum Emergency Generation Alerts) when additional intraday resources are scheduled.
The volume added to reserves would be based on the Eco Max rating of the resources committed as opposed to the static 1,300-MW adder included in the short-term fix, which expired in September. (See PJM Reserve Proposal Gets OK for Trial Run.)
PJM’s proposal won 84% support, and it will be the primary proposal considered by the Markets and Reliability Committee Oct. 30. A proposal from the PJM Industrial Customer Coalition that added a transition mechanism won 61% and will be considered by the MRC if the primary motion fails to win a two-thirds, sector-weighted vote. A proposal from the Independent Market Monitor failed with only 30%.
Separately, 87% of the MIC also approved PJM’s proposal to set limits on interchange during emergency conditions. The limit would be used when operators have made firm resource commitments and anticipated interchange schedules are sufficient to meet projected load for the hour.
Spot imports and hourly non-firm point-to-point transactions submitted after the cap is implemented would be blocked once net interchange reaches the limit. Schedules with firm or network-designated transmission service would not be curtailed.
The change is intended to prevent markets and operations from being whipsawed by large swings in imports.
A competing proposal by the IMM fell short at 23%.
Residential Demand Response
Members approved rules that would allow use of statistical sampling to calculate the performance of residential demand response resources providing synchronized reserves. The sampling would apply to direct load control resources without meters reporting data hourly or in shorter intervals.
The sampling would replace outdated studies such as the Deemed Savings Estimate Report, which is based on data from 2001–2005 from zones in Maryland and New Jersey. Since then, PJM’s footprint has grown to include Kentucky and Chicago, and air conditioners and other appliances have become much more efficient.
Sampling is a way to improve accuracy without the cost of installing one-minute meters on every participating household, PJM said.
If approved by the MRC, the rule would take effect June 1, 2015, with a transition mechanism for resources that cannot meet new requirements for delivery years 2016 through 2018.
Replacement Capacity Transactions
Members approved a problem statement from Citigroup Energy to consider changes to the timing for recording replacement capacity transactions.
Under current rules, Citigroup’s Barry Trayers said, the transactions can’t be submitted to PJM until after the third incremental auction, a rule he called “overkill and overly conservative.”
“I have contracts sitting on the shelf and have a fear about not submitting them at the right time and causing all kinds of havoc,” he said. Trayers explained his concern after the meeting. “If I forget to submit the replacement capacity, I have an obligation to perform which I won’t realize I have because, in my books, I am flat and have no obligations. But in PJM’s eyes I will have separate long and short positions. It is just an accident waiting to happen and can so easily be fixed by just accepting the transactions,” he said.
Trayers said the current rule is intended to ensure the replacement capacity exists. But he said suppliers of replacement capacity must show they have the capacity available before PJM will accept it in an incremental auction.
Trayers said he didn’t seek both changes initially because the first was a “much cleaner argument.”
Subcommittee Rejects Temporary Credit Change for Virtuals
The Credit Subcommittee voted down a proposal to change credit requirements for virtual transactions in January and February 2015, Chief Financial Officer Suzanne Daugherty told the MIC.
Members approved a problem statement last month at the request of Twin Cities Power, which said the change was needed because extreme conditions last winter would otherwise result in much higher reference prices and credit requirements next winter. Credit requirements for increment offers and decrement bids are based on nodal reference prices.
Public Service Enterprise Group is again looking for a merger partner.
The Street reported last week that the New Jersey company was outbid for Pepco Holdings Inc. by Exelon. Quoting unnamed sources, it said PSEG later approached PPL about a merger but was rebuffed.
PSEG’s leadership is frustrated that it has been unable to get a deal done, one source said. Unfortunately, according to the source, “their peer group is getting smaller and smaller so the question becomes: who is left for them to merge with?” A proposed merger between PSEG and Exelon was scrapped in 2006. The report listed several other possible candidates for PSEG, including Consolidated Edison, FirstEnergy, Dominion Resources and American Electric Power.
FirstEnergy and American Electric Power are seeking Ohio ratepayer subsidies for their aging coal-fired power plants.
FE is trying any way it can to improve its finances, according to a report by the Institute for Energy Economics and Financial Analysis. The company is “turning to regulatory capture and ratepayer bailouts as it struggles to reverse a deepening spiral of debt service and revenue declines.” The report blames much of the company’s problems on its acquisition of Allegheny Power and an ill-fated gamble on coal-fired generation.
It said FE’s investments started losing their luster as natural gas prices fell and alternative energy sources gained market momentum. In response, according to the IEEFA, FE turned to federal subsidies and lobbying efforts at the state level. The company is pushing for guaranteed income at its merchant plants, a request currently before the Public Utilities Commission of Ohio.
Meanwhile, AEP has asked PUCO to allow it to charge ratepayers for the cost of running its plants if market prices are too low. It would mean a monthly charge of about $2 per household if approved. AEP says that ratepayers would eventually see savings within 10 years.
AEP identified four plants that require the subsidies to keep operating: the 1,149-MW Conesville plant, the 600-MW Stuart plant, the 592-MW Cardinal plant and the 330-MW Zimmer plant.
Environmentalists are opposed to the schemes. “Your family shouldn’t have to pay more for dirty energy from outdated coal plants,” says one of the Sierra Club’s media campaigns.
Dominion Midstream Partners, the Dominion subsidiary created to own and operate the Cove Point LNG facility on the Chesapeake Bay, launched an initial public offering to raise $350 million.
Cove Point, an existing liquefied natural gas import plant, recently received Federal Energy Regulatory Commission approval to construct a liquefaction and export plant on the site. The $3.8 billion plant is scheduled to be in operation by June 2017. In addition to the plant, Dominion Midstream will own 136 miles of natural gas pipeline linking the plant to interstate pipelines.
The IPO is for 17.5 million shares, representing about 27.4% of Dominion Midstream, which will list under the ticker DM. Shares are expected to be priced in the range of $19 to $21. Underwriters will have an option to buy an additional 2.65 million shares at the IPO price.
Protesters gathered outside Dominion’s Cove Point LNG plant just days after the Federal Energy Regulatory Commission approved plans to build a $3.8 million export facility at the site in Maryland. Construction is expected to begin immediately.
Protesters vowed the fight was not over, despite FERC approval. “It’s not a done deal; it’s merely the beginning of a new chapter,” one demonstrator said. Mike Tidwell, Chesapeake Climate Action Network director, faulted FERC’s review as “secretive and detached” and said the regulatory approval process was “rigged.” Another environmental group, EarthJustice, has promised to appeal FERC’s ruling.
FE Wants to Allow Industrials to Opt Out of Energy Efficiency
FirstEnergy wants to allow its Ohio industrial customers to opt out of state-mandated energy-efficiency programs in the first big challenge to the state’s efficiency laws since legislators passed a law in June freezing the five-year-old program while it is under review. That law also allows utilities to amend programs.
FirstEnergy executive William Ridmann said the energy-efficiency mandates cost businesses and consumers about $1 billion in temporary rate increases and said efficiency efforts should be “customer driven.” If the Public Utilities Commission of Ohio approves FirstEnergy’s plan, its largest customers could drop out of programs as early as Jan. 1.
TVA Refuels Browns Ferry 1, Oldest Reactor in Fleet
The Tennessee Valley Authority powered down its oldest nuclear reactor last week for refueling.
Unit 1 at the Browns Ferry Nuclear Plant should remain down for refueling and maintenance for about a month, TVA said. An estimated 2,250 workers will be involved in the outage. The reactor, located on the Tennessee River near Athens, Ala., went into service in 1974.
The Nuclear Regulatory Commission in 2006 extended the operating licenses for all three Browns Ferry reactors for 20 years.
A new wind farm that already has a 20-year contract with Microsoft is under construction about 60 miles outside of Chicago.
EDF Renewable Energy, a subsidiary of the French Electricite de France, owns 96% of the Pilot Hill Wind Project on the border of Kankakee and Iroquois counties. The plant’s output is under contract to Microsoft, which has an energy-gobbling data center near Chicago. EDF says the plant should be in operation by next year.
Court Rules Even Non-Customers Must Pay for AEP Shortfall
The Ohio Supreme Court decided that customers who switched from American Electric Power to third-party suppliers must help the utility to pay a $36 million transmission shortfall.
The ruling upholds a 2012 decision by the Public Utilities Commission of Ohio that said all AEP customers would foot the bill for interstate delivery of electricity. An industrial users group had challenged the PUCO ruling.
PPL Energy Plus, the retail marketing subsidiary of PPL, was awarded a three-year contract to supply electricity to federal prisons, hospitals and office buildings in central and eastern Pennsylvania. The contract requires 10% of the electricity to be from renewable sources.
Commonwealth Edison launched its Peak Time Savings program last week, enabling customers to get credit for reducing their energy consumption during peak hours.
The Chicago utility is installing 4 million smart meters over the next four years, allowing customers to earn $1 credits for each kilowatt hour shaved during peak hours. The conservation events typically occur three to five afternoons during the summer.
The program is available only to customers who have ComEd as their energy delivery provider, who are not currently participating in the company’s air-conditioning-cycling program and are not net metering customers.
Entergy Asks to Consolidate Its Louisiana Utilities
Entergy Louisiana and Entergy Gulf States Louisiana are asking the Louisiana Public Service Commission for permission to consolidate into one entity.
Entergy officials say it would help the companies make more infrastructure investments and ultimately benefit customers. The region is experiencing increased economic growth, and the companies expect an increase of up to 1,900 MW of industrial load by 2019. The company says consolidation could produce up to $128 million in customer benefits.
NRG Energy, expanding its residential solar business, paid an undisclosed sum for Pure Energies Group, a solar installer with headquarters in Toronto and San Francisco. NRG bought Roof Diagnostics Solar in April and acquired GoalZero, a portable power generator, in August. A recent report ranked NRG as the sixth-largest U.S. residential solar installer.
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.”
