The Federal Energy Regulatory Commission on Friday granted PJM’s request to increase the cost-based energy offer cap to $1,800/MWh through March.
“We find that PJM has demonstrated that the current offer cap of $1,000/MWh in PJM is unjust and unreasonable for the winter months,” FERC said in its order, which became effective immediately (EL15-31). PJM had requested the Tariff revision go into effect Jan. 9.
Any cost-based offer, regardless of fuel type, will be eligible to set the LMP, the ruling said, rejecting a request by the Independent Market Monitor that it be restricted to natural gas.
“We find that restricting the proposal to natural gas costs alone would be unduly preferential to those sellers whose electricity is from natural gas-fired generation,” the order said.
Meanwhile, the commission said, it is “exploring potential improvements to market design and operational practices in order to ensure appropriate price formation in energy and ancillary service markets operated by ISOs/RTOs, which involved four staff papers and a series of workshops.”
The order included a request for comments as FERC seeks information on possible alternative offer caps and how it can mitigate seams issues among neighboring RTOs. (See PJM Seeking RTO Consensus on Offer Cap Increase.)
Responding to critics’ concerns, the commission said, “While PJM’s proposal may exacerbate seams issues by creating an incentive for external resources to attempt to sell into PJM when energy prices exceed $1,000/MWh, PJM is proposing only a short-term, temporary change applicable over the next few months.”
FERC also dismissed protesters’ assertions that the waiver would invite unsupported market-based offers above the $1,000/MWh cap.
“PJM’s proposal also provides additional protection to customers by requiring that market sellers provide cost justification for all bids above $1,000/MWh according to PJM’s cost development guidelines, in order to set the LMP,” it said.
Furthermore, it noted, “As we found in the February 2014 Waiver Order, allowing these offers to set LMP promotes efficient resource selection and sends clear market signals so that resource costs are reflected in transparent market prices.”
PJM’s proposal will allow generators to recover “justifiable costs” more than $1,800 through make-whole payments, but such offers would not set prices for other market participants.
The issue arose after a spike in gas prices last January pushed some generators’ costs to more than $1,000. At the time, FERC granted PJM’s request for a waiver from the cap to allow some gas-fired generators to cover their costs.
Because the proposal’s wording did not put a time limit on the price cap hike, FERC is requiring PJM to submit a filing by Feb. 27 to remove the waiver effective April 1. Because that change is ministerial, FERC said it will not entertain protests.
FERC also declined to establish hearing procedures, as some had requested. It also denied PJM Load Group’s motion for extension, saying that “the current situation requires immediate relief.” (See PJM Offer Cap Proposal Sparks Opposition.)
In addition, it disagreed with the Load Group that the proposal would result in retroactive ratemaking.
“The Tariff provisions revise offers solely in the energy market and are prospective, as of the date of this order. They, therefore, have no retroactive effect on past offers or energy prices,” the order said.
PJM’s Section 206 filing seeking the higher cap came after stakeholders failed over eight months to reach consensus on changes to the current $1,000/MWh cap. (See Last-Ditch Effort to Break PJM Offer Cap Deadlock Fails.)
The Federal Energy Regulatory Commission yesterday asked the Supreme Court to overturn an appellate court ruling voiding its authority to regulate the rules used by RTOs to pay for demand response, a day after PJM filed a contingency plan for including DR in its upcoming capacity auction.
The 59-page petition for a writ of certiorari, filed by attorneys for FERC and the U.S. Department of Justice, said the D.C. Circuit Court of Appeals erred in its May 23 ruling (Electric Power Supply Association v. Federal Energy Regulatory Commission) that FERC lacked authority under the Federal Power Act to issue Order 745. The order requires RTOs to pay DR providers the same way they pay generators in energy markets — through LMPs.
“FERC’s conclusion that it has the authority [and the responsibility] to regulate the compensation paid by wholesale-market operators for demand-response commitments — and recouped in the wholesale rate set in the auction markets run by those operators — is the best and indeed only sensible reading of the statutory text,” FERC said.
The petition said the Supreme Court should take the case because of the growing importance of demand response.
“Even read most narrowly — as invalidating only FERC’s authority to regulate the level of compensation paid by wholesale-market operators to demand-response providers in energy markets — the decision … threatens significant damage to the nation’s wholesale-electricity markets,” FERC said.
FERC said its regulation of DR participation in wholesale markets “is essential to the commission fulfilling its statutory responsibility to ensure that [wholesale] rates are just and reasonable” and that the EPSA ruling also threatens the participation of DR in wholesale capacity markets.
“Because the court concluded categorically that ‘[d]emand response is part of the retail market,’ and determined that the FPA ‘unambiguously restricts FERC from regulating the retail market,’ its holding throws into serious question whether FERC may review any of the rules established by wholesale-market operators to govern demand-response participation — or perhaps even whether it has authority to permit the participation of demand-response providers in wholesale-electricity markets at all,” FERC said.
PJM Filing
On Wednesday, PJM submitted to FERC its contingency plan to incorporate DR in May’s Base Residual Auction if the Supreme Court rejects the petition and allows the ruling to stand (ER15-852).
General Counsel Vince Duane outlined the plan Dec. 18 to the Markets and Reliability Committee. (See PJM to File Post-EPSA Demand Response Contingency Plan with FERC.) It would allow a load-serving entity “or other wholesale entity” to submit demand-side bids — “wholesale load reductions” — causing PJM to procure less capacity in the BRA.
PJM requested a response from FERC by April 1. If the court agrees to hear the case, PJM would withdraw the filing.
Duane said last month that PJM can expect a decision on whether the court will take the case in March or April.
The New Jersey Board of Public Utilities staff has recommended approval of Exelon’s $6.8 billion acquisition of Pepco Holdings Inc. in a settlement that would give Atlantic City Electric customers $62 million in rate credits.
The settlement, announced yesterday, came as the board was holding public hearings on the merger. If approved by the BPU, Exelon would need only approval from regulators in Delaware, Maryland and D.C. for a deal that would result in a company with more than 8 million customers from Illinois to the Atlantic.
Pepco Holdings, headquartered in D.C., includes Atlantic City Electric, the Pepco utility serving the District, and Delmarva Power & Light, with customers in Delaware and Maryland.
The $62 million in rate credits amounts to $114 for each of Atlantic City Electric’s 544,000 customers. The settlement also includes:
An energy-efficiency program that would provide $15 million in energy savings over five years;
Promises to hire 60 union employees, protect wages and benefits and keep a headquarters at Mays Landing, N.J.; and
Charitable contributions equal to Atlantic City Electric’s $709,000 annual giving for 10 years.
Rate Counsel Rejects Settlement
While the settlement with the BPU staff is a major step toward final approval in New Jersey, it was not signed by New Jersey’s consumer advocate, the Division of Rate Counsel.
Rate Counsel Stefanie Brand told a BPU evidentiary hearing yesterday that she did not sign the settlement because it includes no limit on the post-merger transition costs Atlantic City Electric can seek or any “stay out” — a period of time when the company is prevented from seeking a rate increase.
“Without express limitation on the level of post-merger transition costs recoverable by Atlantic in a future proceeding, costs associated with the merger — such as installing new computer systems or severance payments that would not have been incurred by Atlantic but for the merger — may be sought by the company in Atlantic’s next base rate case without limitation,” Brand said. “In other words, the $62 million of benefits to Atlantic’s customers may be offset or totally wiped out.”
Brand also criticized the settlement’s claims that it would require Exelon to improve Atlantic City Electric’s reliability performance.
The settlement says the company would forfeit 50 basis points in the next electric distribution base rate case filed after January 2021 if it fails to meet a System Average Interruption Frequency Index (SAIFI) of 1.05 interruptions per customer per year or a Customer Average Interruption Duration Index (CAIDI) not to exceed 100 minutes.
Brand said the thresholds represent no improvement over the commitments the company made in the Reliability Investment Program as part of its 2009 base rate case. Brand said the company already has met the 100-minute target and would likely meet the SAIFI goal before the program’s expiration in 2016.
Brand also said the “most favored nation” clause in the settlement — an assurance that New Jersey will benefit from any additional concessions achieved by states yet to approve the merger — was too narrow.
“The decision to approve the merger in New Jersey is not a slam dunk,” Bruce Burcat, executive director of the Mid Atlantic Renewable Energy Coalition (MAREC), said in an interview. “The board will now have to consider the concerns of the non-signing parties and decide whether to approve the joint stipulation.”
Burcat’s group didn’t oppose the settlement. In return, Burcat said, Exelon has agreed not to oppose MAREC’s request that the BPU open a docket to order Atlantic City Electric to use a competitive process for the procurement of a portion of its obligations under New Jersey’s Renewable Portfolio Standards.
Public Hearings Begin in Maryland
The announcement of the New Jersey settlement came the day after a public hearing on the merger in Maryland.
About 100 people attended a Public Service Commission hearing on the merger in Rockville Tuesday night, the first in a series of public-comment hearings before evidentiary hearings begin in late January.
The majority of the crowd either belonged to or were supportive of environmental groups Chesapeake Climate Action Network (CCAN) and 350 Montgomery County, and they cautioned the commission on Exelon’s record on renewable energy.
Many of the speakers said Exelon’s goal was to use Pepco’s ratepayers to subsidize its nuclear fleet, which has become unprofitable.
About 100 attended a Maryland Public Service Commission hearing on the Exelon-Pepco merger in Rockville Jan. 13.
Others, including County Councilmember Roger Berliner, did not take a position on the merger at the hearing. Instead they urged the commission to make Pepco open up its transmission line right-of-ways for recreational use, if it approved the deal. Some speakers were hiking and mountain biking enthusiasts who enjoyed open right-of-ways in the territory of Exelon subsidiary Baltimore Gas and Electric but lamented that their trails were interrupted in Pepco’s territory.
Those who spoke in support of the merger included the Montgomery County Chamber of Commerce, the Maryland Chamber of Commerce, the Hispanic Chamber of Commerce and the Salvation Army.
Exelon has offered $100 million in credits for customers in Maryland and other states, but the PSC’s staff has said it thinks $167 million would be a more appropriate offer. (See Exelon-Pepco Merger Faces Headwinds in Maryland.)
The state Office of People’s Counsel has already urged rejection of the deal, calling Exelon’s “purported benefits … either non-existent or woefully deficient.”
PJM’s Independent Market Monitor Joe Bowring told the PSC in a letter that the merger “raises potential vertical and horizontal market power issues,” repeating concerns he expressed to the Federal Energy Regulatory Commission.
Bowring recommended that FERC require the companies agree to remain in PJM and permit independent third-party interconnection studies. He said Exelon should agree to a review of ratings of all elements of the combined transmission systems and a regular process for reviewing and updating transmission limits. Despite Bowring’s comments, FERC approved the merger without conditions in November.
Hard Sell in D.C.
In D.C., where some public hearings have already been held, Exelon faces a hard sell.
People’s Counsel Sandra Mattavous-Frye urged the D.C. Public Service Commission to reject the merger. “The office’s painstaking, comprehensive review and analysis details how the Pepco/Exelon application fails to meet each of the commission’s seven public interest factors,” she said in a statement last month. “Overall, there are far too many risks for consumers and nothing but benefits for Pepco and Exelon.”
A coalition calling itself Power D.C. is also opposing the merger. Although Exelon has promised $14 million in incentives for the District, the coalition, which includes the Sierra Club, CCAN, D.C. Working Families and the D.C. Environmental Network, said the merger wouldn’t benefit ratepayers or businesses.
Delaware PSC Wants $63M
Exelon has offered $17 million in customer credits in Delaware, but a Delaware Public Service Commission consultant has said $62.9 million, or $100 per customer, would be a proper offer. Public hearings are scheduled for February there.
Delaware Public Advocate David L. Bonar said he didn’t expect a settlement in New Jersey so soon.
“I was somewhat surprised the BPU signed off on the agreement as quickly as they did, but not surprised that the New Jersey Rate Counsel declined,” he said.
Bonar said all parties are continuing to work toward a settlement in Delaware, but added, “We are not quite there yet. A merger worth billions of dollars can’t be taken lightly.”
He said his office is “not ready, at this time, to say it’s in the best interest of Delaware as presently constructed.”
Burcat said he didn’t think what happened in New Jersey, where ACE serves a minority of the state, will have an impact on the question in Delaware, Maryland or D.C.
“In the other jurisdictions, Exelon will end up controlling the vast majority of the service territories and will also end up serving most of the electricity load,” Burcat said. “Consequently, the ramifications of the merger in these jurisdictions are substantially higher.”
Exelon has repeatedly said the merger would be a good thing for all concerned. “We believe that the facts — which are available in the testimony we’ve filed with the commission and other information we have provided to the parties through the regulatory process — will show that this merger is in the public interest and will benefit customers and the community,” spokesman Paul Adams said last month.
Justice Department Review
RTO Insider reported last month that the U.S. Department of Justice is investigating the interconnection process in PJM’s MAAC sub-region as part of its anti-trust review of the merger. (See DOJ Probing Interconnection Process in Exelon-Pepco Merger.)
Exelon said yesterday that the Justice Department’s review period expired Dec. 22, meaning the Hart-Scott-Rodino Antitrust Improvements Act no longer precludes completion of the merger.
“Exelon and PHI will continue to work cooperatively with the DOJ until it advises them that it has concluded its evaluation of the merger,” Exelon said.
Michael Brooks contributed to this article.
[Editor’s Note: An earlier version of this article incorrectly said the Maryland Public Service Commission had sought $167 million in concessions from Exelon. That recommendation was by the PSC’s staff.]
American Electric Power has hired investment bank Goldman Sachs to investigate the sale of its merchant generation fleet in Ohio and Indiana, both coal- and natural gas-fired.
TheStreet, which first reported the news, said the plants — with a combined capacity of about 8,000 MW — could fetch $2.8 billion to $3.6 billion, based on a price of $350 to $450 per kilowatt. AEP officials confirmed hiring Goldman Sachs but said no decisions have been made.
Melissa McHenry, an AEP spokeswoman, identified the nine plants as:
Gavin – 2,665 MW
Cardinal Unit 1 – 595 MW
Conesville Units 5 & 6 – 810 MW
Waterford – 840 MW
Darby – 507 MW
Conesville Unit 4 – 339 MW
Zimmer – 330 MW
Stuart – 603 MW
Lawrenceburg – 1,186 MW
All of the plants are in Ohio except for Lawrenceburg, which is in Indiana. They represent a total of 7,875 MW.
The news isn’t exactly unexpected. AEP officials have been saying for the past several months that such a deal could be in the company’s future.
AEP Ohio President Pablo Vegas told Columbus Business First in an interview late last year that the plants in question are struggling to remain profitable.
“Those power plants that are on the economic bubble today are essentially coal plants and nuclear plants,” Vegas said. “They’re struggling in the PJM market to cover their fixed costs.”
AEP has gone before the Public Utilities Commission of Ohio seeking long-term guaranteed rates for some of its largest plants in an effort to remain competitive. (See AEP Seeks State Backing for Aging Ohio Coal Plant.)
If PUCO doesn’t rule in AEP’s favor, this could be the backup plan.
Other companies have taken steps to reduce their exposure to the volatility in merchant generation.
Duke Energy exited the field, selling its interest in 11 plants in Ohio, Pennsylvania and Illinois and its retail energy business for $2.8 billion to Dynegy. PPL is in the process of spinning off its generation in a joint venture with Riverstone Holdings.
Two New England utilities that had power purchase agreements with the Cape Wind Associates’ offshore project have terminated the contracts, leaving the project’s future in doubt.
National Grid and NSTAR, a unit of Northeast Utilities, said the 468-MW project off the coast of Cape Cod failed to meet deadlines to secure financing and begin construction by Dec. 31. The developer of the $2.6 billion project could have extended the deadline if it had put up financial collateral, the utilities said. Both utilities terminated their PPAs with the developer on Jan. 6.
National Grid had a 2010 agreement for 50% of the project’s output, while NSTAR was contracted for 27.5% as part of its merger settlement in 2012 with Northeast Utilities. Both PPAs were for 15 years.
“We do not regard these PPA terminations as valid due to the force majeure provision of the contracts that extends the milestone dates,” Cape Wind said in a statement. The developer cites delays caused by “relentless litigation” by project opponents as the primary reason it has been unable to meet the deadline, a contingency it says is included in the utility contracts.
National Grid said that it “is disappointed that Cape Wind has been unable to meet its commitments under the contract, resulting in yesterday’s termination of the power purchase agreement.”
The Alliance to Protect Nantucket Sound, which has been fighting the project for 14 years, hailed the contracts’ termination.
“The decision by NSTAR and National Grid to end their contracts with Cape Wind is a fatal or near-fatal blow to this expensive and outdated project. It’s very bad news for Cape Wind, but very good news for Massachusetts ratepayers, who will save billions of dollars in electric bills,” it said.
The Alliance has on its board fossil fuel magnate Bill Koch. By Cape Wind’s count, the alliance has initiated more than 20 lawsuits seeking to stop Cape Wind. None, so far, have been successful.
The Interior Department’s Bureau of Ocean Energy Management issued a commercial lease in 2010 for the project, which the alliance now says should be revoked.
Opponents’ efforts to block the project based on its above-market power prices have also failed. The NSTAR PPA established a base price equal to $187/MWh.
Even before the latest round of bad news, Cape Wind seemed to have lost its position as the first offshore wind development on the East Coast.
Deepwater Wind in Rhode Island has assumed the lead, promising “steel in the water” by this summer.
Its 30-MW Block Island Wind Farm is to be located about three miles off the coast of Block Island, R.I., and is fully permitted. The Block Island project has a PPA with National Grid that includes a fixed price of 24.4 cents/kWh with an annual 3.5% escalator.
The pilot project is a precursor of the planned 1,000-MW Deepwater Wind Energy Center, located off the coasts of Massachusetts and Rhode Island.
Last year, Deepwater Wind signed contracts with Alstom as its turbine supplier and long-term maintenance and service provider.
Legislators May Be Waiting for Quinn to Leave Before Bill is Sent
Quinn
Commonwealth Edison and Ameren stand to win an important victory in their attempts to get continued authorization to charge customers for smart grid improvements.
The state legislature easily passed a bill in December allowing the utilities to continue smart grid improvements. But legislative leaders are possibly waiting for Gov. Pat Quinn to leave office before they send the bill to be signed. Quinn, a Democrat who has made no secret of his thorny relationship with utility companies, vetoed a 2013 smart grid bill.“They’re waiting for me to leave,” Quinn told the Chicago Tribune. His Republican successor, Gov.-elect Bruce Rauner, is expected to be more receptive to the legislation. A new General Assembly gets sworn in on Wednesday, so Rauner has a two-day window to sign the measure.
Pence Suggests Utilities Set Own Energy Efficiency Goals
Pence
Gov. Mike Pence is proposing a policy that would allow electric utilities to determine their own energy efficiency goals, replacing mandated targets that the state Senate dismantled last year.
Pence’s proposal, which would require utilities to file energy efficiency plans every three years, would replace a 2009 law that set a 2% reduction in electricity use by 2019. That act was undone last year under a bill that became law without Pence’s signature.
Gov. Scott Walker declared a precautionary energy emergency last week after a key propane pipeline experienced supply interruptions.
The emergency proclamation provides extended operation hours to truckers to make up for delivery delays caused by the Mid-America East Blue Pipeline, which delivers propane to wholesale consumers in Iowa, Illinois and Wisconsin. Officials said the pipeline problem was expected to be quickly fixed.
State to Argue Before SCOTUS on Gas Supplier Anti-Trust Case
Lawyers representing the state will appear before the U.S. Supreme Court this week to defend the right of states to intervene in antitrust matters involving natural gas companies.
The case, ONEOK v. Learjet, pits a natural gas supplier against large consumers. The consumers, led by Learjet, said that ONEOK, a wholesale gas provider based in Tulsa, Okla., charged artificially high fuel prices. ONEOK argued its prices are regulated by the Federal Energy Regulatory Commission, not state agencies. ONEOK’s appeals made it to the Supreme Court.
Although not parties to the original case, Kansas and 20 other states filed amicus briefs defending the rights of individual states to exercise their own consumer protection laws in the matter. “I’m encouraged that the Supreme Court granted us time for oral argument, and we will vigorously defend Kansas consumer-protection laws from the federal administration’s power-grab,” state Attorney General Derek Schmidt said.
PSC Member Angelle Raises More than $1.5 Million for Gubernatorial Bid
Scott Angelle, a member of the Public Service Commission who is running for governor this year, has already raised $1.5 million to fund his campaign.
Angelle will face fellow Republicans U.S. Sen. David Vitter and Lt. Gov. Jay Dardenne, and Democrat state Rep. John Bel Edwards, in the Oct. 24 primary. Under Louisiana’s system, all candidates appear on the same ballot, and voters may vote for any candidate, regardless of party affiliation. If no candidate receives a majority of the vote during the primary, a runoff election will be held on Nov. 21 between the top two primary candidates.
State Department of Environment Opens Fracking Comment Period
The state Department of the Environment has opened a 30-day public comment period on proposed rules allowing hydraulic fracturing and natural gas development.
Gov. Martin O’Malley, in one of his final acts before leaving office, signed legislation allowing fracking in western Maryland. The rules contain a requirement other states have not included: permit applicants must produce a five-year comprehensive gas development plan. Gov.-elect Larry Hogan has promised to move swiftly to approve the rules after taking office Jan. 21.
Hogan Names Department Heads for Natural Resources, Environment
Hogan
Incoming Gov. Larry Hogan appointed Charles Evans Jr. as the secretary of the Department of Natural Resources and Ben Grumbles as the Department of the Environment secretary.
Grumbles is a former assistant administrator at the federal Environmental Protection Agency under President George W. Bush and was involved in developing federal policy on hydraulic fracturing. Evans was assistant secretary of the state Department of Natural Resources under former Gov. Robert Ehrlich.
Sandpiper Pipeline Hearing Draws 500 Supporters and Opponents
The Public Utilities Commission conducted the third of five hearings last week on a proposed $2.6 billion pipeline that would transport crude oil from the Bakken fields through northern Minnesota. The hearing drew about 500 people.
The PUC will determine whether the Enbridge Energy project goes forward. The 612-mile pipeline would connect the Bakken fields in North Dakota to an Enbridge hub in Clearbrook and a Great Lakes terminal in Superior, Wis.
One woman said she was opposed to the pipeline out of fear that a spill “could, in an instant, destroy the reasons we are here.” Others, such as a surveyor, said the pipeline could help boost the economy. The PUC is expected to issue a ruling in June.
Two utilities – Kansas City Power and Light and The Empire District Electric Co. – have asked the Public Service Commission to increase the monthly fixed-charge portion of customers’ bills. Fixed charges are typically used for infrastructure costs.
KCP&L is asking for an increase from $9 to $25. Empire is seeking a boost from $12.52 to $18.75. KCP&L said it needs the increase to pay for transmission and distribution system improvements. Empire said the hike is needed to balance the company’s fixed and variable costs for electricity, which it said are “out of whack.”
The Public Service Commission heard from Ameren Missouri customers who are upset that the utility has filed for its sixth rate increase since 2006.
The company is seeking an increase of $264 million, about 10%. The PSC staff has recommended it get only $113 million, or about a 4% increase. Since 2007, Ameren rates have risen more than 40%. The company filed the request in July. The PSC is expected to rule in May.
More: St. Louis Post-Dispatch
NEBRASKA
State Supreme Court Throws Out Keystone Pipeline Challenge
The state Supreme Court decision on Friday removed a major hurdle for TransCanada’s Keystone XL Pipeline.
The justices ruled 4-3 that a lower court correctly decided that a 2012 eminent domain law giving the governor the power to approve major oil pipeline projects was unconstitutional. But the state constitution requires five of the Supreme Court’s seven members to rule a law unconstitutional. The 4-3 Supreme Court ruling thus, under state law, voids the lower court’s ruling. “The legislation must stand by default,” the justices’ decision said.
It was an important win for the proposed $7 billion, 1,179-mile pipeline that is to run from Canada to the Gulf Coast. President Obama has vowed to veto Keystone legislation, but the White House has frequently hinged its opposition to the uncertainty of the Nebraska legal challenge. The court ruling came hours before the U.S. House of Representatives approved the pipeline in a crucial vote. The Senate vote is scheduled for Jan. 20.
Third-Party Provider Settles for $2.1 million in Bait-and-Switch
A third-party electricity provider accused of failing to live up to promises of guaranteed savings for customers has settled with state authorities for $2.1 million.
The Board of Public Utilities, the Division of Consumer Affairs and the state Attorney General’s Office alleged that HIKO Energy promised savings to customers to switch but charged them even more than the default utility rate when prices surged during last year’s frigid winter.
As part of the settlement, the energy supplier company will refund $1.82 million to customers. Similar complaints against two other third-party suppliers, Systrum Energy and Palmco Power, are pending.
Administrative Law Judge Says JCP&L Should Cut Rates by $107.5 Million
A state administrative law judge has recommended that Jersey Central Power & Light reduce its rates by $107.5 million. The state Division of Rate Counsel, which requested the review in 2011, called the recommended rate cut “unprecedented.”
The agency, which represents consumers in rate cases, had argued that the FirstEnergy utility had earned too much since its last rate case in 2005. It sought a decrease of more than $190 million. The staff of the Board of Public Utilities had urged for a $169.8 million cut.
JCP&L said it will dispute Judge Richard McGill’s findings. “Today’s decision does not reflect costs incurred by the company since 2011, [which include] JCP&L’s investment of more than $400 million to improve reliability across its service territory and the $580 million spent to rebuild the system following Superstorm Sandy,” spokesman Ron Morano said in a statement.
Commissioner Karen L. Montoya was elected chairman, and Commissioner Lynda Lovejoy elected vice chairwoman, of the Public Regulation Commission last week. The five-member commission oversees New Mexico’s utilities, telecommunications carriers and trucking industry.
Montoya, an Albuquerque native who joined the PRC in 2013, previously served as the Bernalillo County assessor. Lovejoy, a former Democratic state senator, was appointed to the PRC in 2007.
Hearings Start on PNM’s Plan to Shutter Part of San Juan Station
Public Service Company of New Mexico’s plans to shut down two units of the coal-fired San Juan Generating Station has sparked a spirited two-week hearing before the Public Regulation Commission. The two units produce 838 MW of the plant’s 1,701-MW total.
The commission is reviewing PNM’s plan to replace the power with a mix purchased on the wholesale market. PNM has said the replacement power would cost about $6.8 billion for 20 years, most of which would be recovered by boosting customer rates. Environmental groups and members of the Navajo Nation said the decreased emissions are a good first step. But Navajo Nation President Ben Shelly said he is also concerned about the possible negative economic effects of the closure.
PNM says that retiring the two units would cut plant emissions by 50% and help it meet federal emissions mandates. It also says the retirements would save the company $780 million.
Regulators Rule Against Utilities, Keep Solar Payment Structure
The Utilities Commission has decided that the pricing structure for power produced by solar facilities is fine the way it is, declining a request from Duke Energy and other utilities to potentially reduce payments to independent power producers.
The utilities had asked the commission to reduce the cutoff point for standard contracts from the current 5 MW to 100 kW. If that change were made, utilities would be able to negotiate separate supply contracts from generators of more than 100 kW. Solar providers sought to boost the limit to 10 MW, saying it would incentivize the renewable industry.
DOT Says Fracking Would Cause Millions in Road Damage
The Department of Transportation says increased traffic from natural gas development, which could start as early as this spring in North Carolina, could cause millions of dollars of damage to roads and bridges.
After studying shale gas operations in Pennsylvania, DOT analysts estimated that each fracking operation could require up to 1,600 trucks to deliver sand, water and equipment. The result: an uptick in maintenance and repair costs to roads and bridges that could approach $11 million.
“The volume of traffic can and does cause significant damage to secondary roads over a relatively short period of time,” the report says. “The majority of this traffic occurs over a period of six weeks.” DOT officials have proposed requiring drilling operators to put up multi-million dollar bonds to cover highway repairs.
Andre Porter, the current director of the state’s Department of Commerce, has applied to rejoin the Public Utilities Commission, where he previously served for two years.
“I’d like to return to the PUCO because there is complex and important work to be done,” Porter wrote on his application. Porter, a Republican, is seeking the seat currently held by Steve Lesser, the lone Democrat on the five-member commission. Lesser has also applied for re-appointment.
A special panel will select four finalists out of the 16 applicants, and Gov. John Kasich will make the final choice, which must then be approved by the state Senate. Porter served on PUCO from 2011 to 2013, when Kasich appointed him to the Commerce Department position.
Earthquakes Increase 5-Fold in 2014; Drilling and Injection Could be to Blame
The domestic oil and gas boom is shaking up more than the energy markets. The number of earthquakes quintupled in Oklahoma last year compared to 2013, and geologists say the likely cause is the high volume of wastewater being injected into underground wells approved by the Environmental Protection Agency.
The state experienced 564 earthquakes of magnitude 3.0 or greater in 2014, compared to 100 for the same period last year. Between 1975 and 2008, the state reported between one and three quakes of magnitude 3.0 or greater a year.
Most seismic activity appears to be linked to underground injection control, the practice of pumping wastewater into deep, isolated rock formations. The bonanza in oil and gas production from shale has produced a boom in wastewater from hydraulic fracturing. In many states, injection wells are the preferred disposal method for the liquids. The U.S. Geological Survey said in a report last year that injection wells were a “likely contributing factor” to the tremors.
OCC Member to Temporarily Serve as Admin. Director
Corporation Commission member Bob Anthony, the nation’s longest-serving utility commissioner, will temporarily fill in as the commission’s director of administration.
Anthony, who was first elected to the commission in 1988 and has served six times as the OCC’s chairman, said the commission will seek a permanent director after its third member, Todd Hiett, takes office this month.
The director’s position became vacant following the departure of Lori Wrotenbery, who announced in October that she would be leaving for family reasons.
Media Asking Supreme Court to Force PUC to Open PPL Outage Records
Two news organizations are asking the state Supreme Court to force the Public Utilities Commission to release documents related to an investigation into alleged favoritism in PPL Utilities’ storm response.
The PUC cited the Allentown utility for accelerating the repair of an unnamed customer during a 2011 storm, and PPL paid a $60,000 settlement. The Morning Call and the Wilkes-Barre Times requested that the PUC identify the customer. The state Office of Open Records agreed with the news organizations. But the PUC and PPL appealed the decision, and the Commonwealth Court ordered that the records stay closed. A coalition of Pennsylvania media organizations wants the Supreme Court to overturn that ruling.
“In this case, the system failed to serve the public’s right to information to which it was fundamentally entitled,” said David M. Erdman, The Morning Call‘s editor and vice president. “Our coalition is strongly affirming the public’s right by speaking with one voice in our petition to the Supreme Court.”
PUC to Allow TransCanada to Argue for Lapsed Permit
TransCanada, builder of the proposed Keystone XL Pipeline, should be allowed to try to convince regulators that a construction permit issued in 2010 is still valid, the Public Utilities Commission ruled last week. State law calls for projects to get recertified if the permits are more than four years old and construction hasn’t begun.
The Yankton Sioux and Rosebud Sioux tribes had sought to dismiss TransCanada’s application, saying that changes to the pipeline plan since the permit was issued should force the company to start the process again. “At best,” said Commission Chairman Gary Hanson, “the tribes’ motion is premature. Under South Dakota law, the applicant has a right to a hearing.”
Dominion Resources Suing Landowners who Denied Property Access for Surveys
Process servers in Nelson and Augusta counties are expected to be busy this week serving notices to landowners who have denied access to pipeline surveyors working for Dominion Resources.
Dominion and other companies who want to build a natural gas pipeline through Virginia filed 20 suits in Nelson County and 27 in Augusta County, arguing that utilities are allowed to survey private property for prospective projects. The companies are building a 550-mile Atlantic Coast Pipeline to deliver shale gas from West Virginia to North Carolina.
Public Comment Session for Badger-Coulee Project Ends
State utility regulators have closed the public comment session for the proposed Badger-Coulee transmission line, and technical hearings are to start this week. The Public Service Commission will determine whether the project, part of a larger transmission line known as CapX2020, is in the public interest.
The $580 million line would deliver wind energy from Minnesota and Iowa to markets in the east. Opponents of the line, mostly landowners whose rights of way could be taken through eminent domain, say the demand for the electricity just isn’t there. Builders ATC and Xcel say the line is needed to improve system reliability and to deliver cheaper power to consumers.
Pallister Calls for Change to Bipole III Route for Savings
Conservative Leader Brian Pallister said last week that changing the route of the proposed $4.6 billion Bipole III transmission line to the east side of Lake Manitoba from the west side would reduce costs. The ruling New Democratic Party has endorsed the longer and more expensive western route to avoid a sensitive boreal forest that is a proposed UNESCO World Heritage site.
“This is an opportunity to reset the debate on the most important project currently being undertaken by Manitoba Hydro and the province,” he said. “We demand the next potential premier tell Manitobans if they will take steps to keep Manitobans’ Hydro bills low.”
The transmission project, proposed in 2010, would deliver power from northern hydroelectric plants to customers in the south of the province.
Market Monitors Joe Bowring (PJM, left) and David Patton (MISO, ISO-NE and NYISO).
WASHINGTON — The RTO stakeholder process came under fire last week as financial traders said it was being used to quash competition and a leading economist blamed it for slowing market reforms.
The setting was a Federal Energy Regulatory Commission technical conference, part of the commission’s Section 206 inquiry into PJM’s treatment of financial transactions (EL14-37).
Section 206 Inquiry
FERC opened the 206 case in August, ruling that PJM may be improperly discriminating in its disparate treatment of virtual transactions. While incremental offers (INCs) and decrement bids (DECs) are charged uplift and subject to the financial transmission rights forfeiture rule, up-to-congestion bids (UTCs) are exempt from both.
UTC trading volumes have dropped by about 80% since Sept. 8 — the date from which FERC said any uplift ultimately assigned to UTCs will be applied. (See PJM Traders Continue to Shun UTCs on Uplift Fears.)
PJM Market Monitor Joe Bowring and David Patton, Monitor for MISO, ISO-NE and NYISO, were among 11 panelists who spoke during the all-day session Jan. 7. They were joined by economists and representatives of several financial trading firms critical of PJM’s rules and Bowring’s interpretation of them. Commissioner Philip Moeller sat in for the afternoon session but asked no questions.
Bowring often found himself alone in defending his views. At one point, Patton waded into a debate between Bowring and Inertia Power’s Noha Sidhom over whether PJM’s enforcement method presumes collusion. After beginning by offering himself as a mediator in the disagreement, Patton ended by criticizing PJM’s method as “arbitrary and capricious.”
“If that’s mediation,” Bowring responded dryly, “I’d hate to see him take a side.”
2013 Tariff Revisions
In 2013, PJM proposed Tariff and Operating Agreement changes to redefine UTCs as virtual transactions and make them subject to FTR forfeitures (ER13-1654). The RTO said the change was justified by the evolution of UTCs from a congestion hedge for physical transactions to a purely financial product.
That didn’t go far enough for FERC, which said it had concerns about differences in the way PJM planned to apply the rule. The commission also questioned why PJM was not assessing UTC uplift charges even though the RTO believes the transactions contribute to uplift.
Last week’s conference featured debates over the similarities between UTCs and paired INCs and DECs, the need for the forfeiture rule, the impact of the decline in UTC trading and the ability to assess market players’ contribution to uplift.
William Hogan, research director of the Harvard Electricity Policy Group and an intellectual forefather of current RTO market designs, was highly critical of FERC for not asserting more leadership.
“I think FERC is not doing its job in setting priorities and … forcing these processes to create efficient markets,” he said. “And it’s deferring too much to stakeholder processes and bottom-up, consensus agreement. It’s a big mistake and it’s hurting us more and more.”
Anticompetitive Motives Alleged
Two panelists accused Bowring and large market participants of having ulterior motives in assigning fees to financial traders.
Sidhom said UTCs cannot bear uplift charges because their profit margins are thinner than those of INCs and DECs. The Monitor’s motive “is to kill the UTC product,” she said.
Wesley Allen of Red Wolf Energy Trading said the cost allocation resulting from PJM’s stakeholder process is akin to Microsoft assigning costs to Apple, with the large utility holding companies using their domination of the stakeholder process to crush competition from small financial traders.
“When it comes to allocation of costs, a Fortune 500 company can allocate some of their costs to another market participant and simultaneously eliminate their competition,” Allen said.
“The stakeholder process is not there to come up with the best results for the market,” he said. “The stakeholder process is about people — Fortune 500 companies largely, who control the voting — managing their costs as best they can. Eliminating their competition as best they can.”
Although the holding companies must select membership in a single sector for sector-weighted votes in PJM’s most senior committees, they have multiple subsidiaries that vote in the lower committees in several different sectors.
PJM, he said, is returning to its monopolistic past. “We’re getting there through the allocation of fees,” he said.
FTR Forfeiture Rule’s Genesis
PJM moved swiftly to implement the FTR forfeiture rule in December 2000, filing it for FERC approval just two weeks after discovering that some traders were using INCs and DECs to create artificial congestion.
The traders were using radial paths — ones designed for future growth, which have few or no network connections. “They would increase or decrease congestion to increase FTR revenues in locations where we never saw congestion before,” said Stu Bresler, PJM vice president of market operations. The traders didn’t mind losing some money on the virtual trades because they were making more on the artificially created congestion.
“It is about manipulation,” Bowring told the conference.
Traders: ‘Worst-Case’ Selection Unfair
Under the rule, traders of INCs and DECs forfeit profits on FTRs when their virtual trades increase congestion and day-ahead/real-time price divergence. PJM identifies offending trades by first screening for those deemed to be “at or near” the constrained FTR paths. Then it determines whether the participant’s FTR profits are likely to have increased as a result of the virtual transactions by determining whether the day-ahead congestion revenues on the FTR paths increased relative to real-time revenues.
To estimate the effect of a transaction on flows, PJM must identify both the source and sink buses of the transaction. But because INCs and DECs have only one bus, PJM must select a second bus to complete the analysis.
For the second bus, PJM uses what it deems the “worst-case” bus to determine the potential impact of the trade on the FTR path. The worst-case bus is the one that has the highest net distribution factor — the percentage of the total energy of the transaction that flows on the FTR path. Trades with distribution factors of 75% or higher are deemed “at or near” the constrained FTR paths. (The worst-case identification is not necessary for UTCs, which have explicit sources and sinks.)
Harry Singh of J. Aron and Co. told the conference that PJM’s method is unfair. “Power doesn’t sink at the worst-case connection,” he said.
Inertia Power’s Sidhom also was critical. By using the worst-case bus, PJM is often attributing to one trader the actions of another, she said.
“The fundamental flaw is taking another person’s transmission into consideration,” she said. “Don’t have a rule that I can’t screen for.”
Referring to calls to extend the rule to UTCs, she asked: “Do we want to take a flawed rule and apply it to another transaction?”
The financial traders found support from Patton and Bresler.
“PJM’s opinion at this point is that we probably went too far with that,” Bresler said, “because we’re evaluating one participant’s activity against somebody else’s, of which assumedly they don’t have knowledge.”
Patton said using the worst-case bus leads to one of two results. “It’s either irrelevant or it’s leading you potentially to a bad decision,” Patton said.
But Bowring was unyielding, saying it is better to err on the side of over-enforcement rather than under-enforcement.
“The consequences of over-mitigation are very small,” he said. “The consequences of under-mitigation are very large.”
Bowring also insisted the rule is more efficient than a case-by-case review.
Bowring has recommended modifying the rule by evaluating traders’ portfolios. He also favors applying the rule to UTCs and counterflow FTRs in addition to the prevailing-flow FTRs now covered.
Bresler said there is no need to subject counterflow FTRs to the rule. “It’s much more difficult to manipulate through counterflows,” he said. He said he has concerns that a portfolio approach would result in false positives — “catching too many fish in the net.”
No Forfeiture Rule in Other RTOs
Unlike PJM, NYISO, ERCOT and MISO do not have a forfeiture rule, and ISO-NE has one that Patton said is never applied. “Whenever we’ve looked at it we’ve found the costs outweigh the benefits,” he said. The fact that it took FERC several years to act against Louis Dreyfus Energy Services for using virtual trades to boost its FTR revenues “illustrates it’s hard to develop a bright-line test,” he said.
Patton said generic market manipulation rules provide sufficient protection against gaming of FTRs. The scheme, he said, is easy to spot. “I’m not worried about the bank robber who comes wandering in without a mask on and stands in front of the security camera. And that’s effectively the people who would be caught by this rule.”
Bresler said PJM favors replacing the worst-case test with the use of a load-weighted reference bus for INCs and generation-weighted reference for DECs.
Sidhom said she supported such a change. “We’re not that far apart on the forfeiture rule,” she said. “I really don’t know if we need wholesale changes here.”
Assessing UTCs for Uplift
The other major issue at the conference was whether UTCs should be assessed uplift charges. Bowring believes they should, saying the disparity in treatment is a major reason why UTC trading volumes have increased in recent years while INC and DEC trading has declined.
Stephanie Staska, chief risk officer for Twin Cities Power Holdings, said no virtual trades should be assessed for uplift related to “deviations,” a term she notes is not defined in the PJM Tariff.
Based on the dictionary definition — “an action different from what is usual or expected” — uplift is properly charged to those whose real-time physical positions differ from their day-ahead positions, such as load that is under- or over-forecast and generation and demand response that fails to meet the scheduled output.
In contrast, Staska said, traders entering into financial contracts receive both a day-ahead and a real-time position that cannot be cancelled or altered after the day-ahead market closes.
Bowring disagreed, saying virtuals affect dispatch and commitment decisions. The Monitor said UTCs were responsible for 64% of the deviations corresponding to negative balancing congestion in 2013 and INCs and DECs added another 24%.
Bowring said virtuals’ uplift “allocation should be reduced … but there’s no reason to exempt anyone, including UTCs.”
Bowring said billing UTCs $0.57 to $0.65 per megawatt-hour would allow PJM to cut uplift charges on INCs and DECs by more than 80% and by more than half for day-ahead load.
PJM Charges Higher than Other RTOs
PJM’s current uplift charges are more than three times those in MISO, CAISO and ERCOT, according to a summary compiled by Allen, who said PJM has rejected traders’ request for a cost causation study.
Harvard’s Hogan said attempting to assess cost causality on uplift results in circular logic.
He recommends day-ahead transactions be exempt from uplift. Instead, he said, uplift should be allocated to real-time transactions with the lowest demand elasticity. “Then spread it wide” so the charges are small, he said.
PJM and Bowring are working on a joint proposal on uplift that they will present to the RTO’s Energy Market Uplift Senior Task Force, said Adam Keech, director of wholesale market operations. “Hopefully that can garner some support” among stakeholders, he said.
Fixed Fee
Keech said the task force’s consideration of replacing the current uplift formulas with a fixed fee was abandoned for lack of support.
“A fixed rate is simple. It’s also wrong,” Bowring said. “Every day it’s wrong.”
Abram Klein of Appian Way Energy Partners said a fixed fee is “not a horrible outcome. … That’s a proposal we could ultimately live with.”
Impact of Drop in UTC Trading
The panelists also sparred on the impact the drop in UTC trading since September has had on uplift and price convergence.
Scott Holladay, senior economist for Yes Energy, said the “before/after” analyses conducted by PJM and Bowring overlooked the fact that PJM’s load curves dropped as summer turned to fall. Holladay said his own analysis, which controlled for seasonality, showed that the decline in UTCs has resulted in a drop in price convergence and increased uplift. Allen said that Holladay’s analysis indicates the loss of UTCs has resulted in $1.2 billion in “increased inefficiency.”
Bowring said the $1.2 billion figure “has no basis in fact.”
Keech also rejected Holladay’s conclusion, saying uplift was at “historically low” levels since March 2014, averaging $30 million a month less than in 2013, thanks in part to a mild summer and low fuel prices. “I don’t want people saying that we took UTCs out of the market and uplift went up. That is not the case.”
It was difficult to determine the impact of the drop in UTCs, Keech said. “It’s not really clear that price convergence has gotten better or worse.”
Keech also said assigning cost causation “is extremely difficult.”
“We haven’t done a cost-causation analysis because frankly we haven’t defined what that term even means in the context of this discussion,” he said.
PSEG Nuclear says some of the proposed transmission fixes for Artificial Island would pose risks to the Salem and Hope Creek nuclear plants, above.
PJM planners won’t be ready after all to recommend a stability fix for New Jersey’s Artificial Island in time for the Board of Managers’ regular meeting in February.
The winner of a contentious battle among four project applicants was expected to be announced at a special Jan. 25 meeting of the Transmission Expansion Advisory Committee.
But at the TEAC meeting last week, Paul McGlynn, general manager of system planning, said staff is working with consultants and industry experts to further study aspects of the proposals for the island, home to the Salem-Hope Creek nuclear complex.
“We have a consultant who’s been looking at sub-synchronous resonance issues for us,” he said, referring to a piece of Dominion Resources’ plan to combine thyristor-controlled series compensation (TCSC) technology with static VAR compensators (SVCs) to ensure stability.
The model was roundly criticized by Dominion’s competitors: LS Power, Transource and Public Service Electric & Gas.
PSE&G’s sister company, PSEG Nuclear, which operates the nuclear plants, last month called on PJM’s Board of Managers to reject using what it called unproven technology.
McGlynn said staff also is looking at the impact of installing fiber optic ground wire for shorter clearing times. That might reduce the size of the SVC, or supplant the need for one at all.
“We’ve actually got a lot of work going on,” said Steve Herling, vice president of planning.
After the meeting, Herling said he expected to have a recommendation ready to present to the TEAC next month. Discussions are underway to call a special meeting of the Board of Managers in March.
All of the potential solutions involve new transmission lines connecting Artificial Island to Delaware. LS Power and Transource have proposed a southern crossing of the Delaware River. Dominion and PSE&G offered a northern route with an overhead crossing. McGlynn has said that either path is expected to face permitting challenges.
LS Power’s proposal includes both overhead and submarine options for the river crossing, each of which would carry a binding cost cap of $146 million.
Transource has emphasized its 50-50 partnership with Pepco Holdings Inc. and said its submarine proposal will have the easiest time obtaining permitting.
Ronnie Bailey, manager of transmission planning for Dominion, stressed among his proposal’s advantages a 36- to 48-month turnaround time.
PJM planners had recommended PSE&G’s selection for the project but re-engaged the other three companies after being widely criticized this summer by environmentalists, New Jersey officials and spurned bidders. (See PJM Puts the Brakes on Artificial Island Selection.)
In an interview last week, Herling said none of the contestants had threatened a lawsuit, and that the delay was simply the result of PJM wanting to conduct a thorough review.
The project is PJM’s first under the Federal Energy Regulatory Commission’s Order 1000, which opens up transmission line projects to non-incumbent companies.
Northeast Utilities, the holding company that operates six electric and gas distribution companies in three New England states, has announced a top-to-bottom rebranding by changing its name to Eversource Energy.
The corporate parent, with headquarters in Boston and Hartford, Conn., will use the name for itself and each of its units: NSTAR Electric, NSTAR Gas and Western Massachusetts Electric Co. in Massachusetts; Public Service Company of New Hampshire (PSNH); and Connecticut Light and Power and Yankee Gas Services in Connecticut.
The new name becomes effective on Feb. 2 and the company has requested its ticker on the New York Stock Exchange be changed to ES on Feb. 19.
“Energy is what brings us all together, and Eversource reflects the one-company focus we have been driving for the last few years,” Northeast Utilities CEO Tom May said in a statement. “Consolidating our brand was the obvious next step for us as we continually strive to improve energy delivery and customer service to our 3.6 million electricity and natural gas customers across the region.”
The Northeast Utilities name dates back to 1965, when CL&P, Hartford Electric Light and WMECo merged. NU acquired PSNH in 1992. According to the PSNH website, that company became the first investor-owned utility to go bankrupt since the Great Depression. PSNH spent the 1980s fending off financial crises precipitated by cost overruns, delays and opposition related to the Seabrook nuclear plant.
The biggest step in the makeover occurred in 2012 with the merger of Hartford-based NU with NSTAR, of Boston. The proposed pairing was announced in late 2010. During regulatory review, the new company pledged to maintain dual headquarters in its host cities. NU, with about 2.4 million customers, was twice the size of NSTAR with its 1.2 million customers.
Included in the merger was a negotiated settlement in Massachusetts for NSTAR to purchase electricity from the proposed Cape Wind project. NSTAR had committed to buy 27.5% of the 468-MW project’s output under a 15-year power purchase agreement. That project is now imperiled as NU and National Grid, another New England utility with a PPA with Cape Wind, have terminated the agreements due to the wind farm’s failure to meet contract benchmarks. (See related story, Terminated PPA Imperils First Offshore Wind Project.)
At the time of the merger announcement, the two companies were planning a joint venture to import Canadian hydropower into New England. The $1.4 billion Northern Pass transmission line in northern New Hampshire is now a wholly owned subsidiary of NU Transmission Ventures. The 186-mile line would bring 1,200 MW of electricity produced by Hydro-Quebec in Canada into the New England power market.
Although the project would use 147 miles of existing rights-of-way, it is mired in controversy because of the need to cross the White Mountain National Forest and its visual impact on other federal and state nature preserves.
Northern Pass requires a Presidential Permit from the Department of Energy because it crosses an international border.
The merger was almost derailed by criticism over CL&P’s response to Hurricane Irene and Superstorm Sandy in 2011. The Connecticut Public Utilities Regulatory Authority penalized the company by reducing its allowed return on equity by 0.15% for a year.
The financial markets seem to have shrugged off the controversies. NU stock ended 2014 at $53.52, up about 26% for the year above its 2013 close of $42.39.
The Federal Energy Regulatory Commission has accepted a request by MISO transmission owners to implement a 50-basis-point adder as an incentive for RTO membership.
But the commission suspended the adder (ER15-358) from being applied until TOs demonstrate that their base return on equity is reasonable based on an updated discount cash flow analysis. The resulting ROE, including the adder, must be within the 7.03% to 11.74% “zone of reasonableness” the commission set in June in a case involving New England TOs.
Last fall, MISO industrial customers filed a complaint contending that the TOs’ current base return on equity — 12.38% except for American Transmission Co. — is too high (EL14-12).
The industrials argued the base ROE for TOs should not exceed 9.15%, citing changes in financial markets. The lower rate would reduce transmission rates by $327 million, industrials say.
TOs filed for the adder request on Nov. 6, in what industrials countered was an attempt to claw back some of the revenue TOs might lose if unsuccessful in the base ROE challenge.
Industrials have argued that TOs don’t need an incentive to remain in MISO and that granting the adder would not benefit the reliability, coordination or operation of transmission facilities.
In its ruling, FERC said industrials and other opponents of the adder failed to provide evidence for that argument.
“We reiterate that the basis for the incentive adder is a recognition of the benefits that flow from membership in an RTO, ISO or other commission-approved transmission organization, and that continuing membership is generally voluntary,” FERC said.
The MISO industrial customers include the Illinois Industrial Energy Consumers, Indiana Industrial Energy Consumers, Minnesota Large Industrial Group and Wisconsin Industrial Energy Group.
The TOs consist of 24 companies, including Ameren, ATC, Entergy, Indianapolis Power & Light and Northern States Power.
vestment bank Goldman Sachs to investigate the sale of its merchant generation fleet in Ohio and Indiana, both coal- and natural gas-fired.
