Page 1556 – RTO Insider

May 5, 2015January 21, 2024

SPP Board Rejects Short-Term Study; Impact on Quick-Start Units Debated

By Rich Heidorn Jr.

SPP’s Board of Directors rejected a recommendation to create a short-term reliability unit commitment (RUC) study as part of the intra-day RUC process (Revision Request 49).

The study would provide results for 15-minute intervals, allowing operators to make unit commitments with more granularity than the current one-hour study. SPP staff said it would reduce the number of real-time manual commitments.

The study won the backing of the Markets and Operations Policy Committee last month but ran into stiff opposition last week from representatives of Golden Spread Electric Cooperative and Nebraska Public Power District, who said they feared the new tool might exacerbate losses they are suffering as a result of SPP’s dispatch of their quick-start units.

The quick-start units, which cost at least twice as much as regular combustion turbines, can be at full capacity in five minutes or less.

Golden Spread said that SPP should first fix its real-time balancing market software so that it recognizes quick-start resources as always “online” and available to the market. When the units are dispatched manually by operators through the RUC process instead of economic dispatch, they cannot set prices in the real-time market.

“So they just get the market price — which normally is much lower than the actual price — and need to be made whole,” Ron Thompson of Nebraska Public Power District said in written comments on the proposal. “If there is [an] issue and the unit does not perform as intended, the ‘make whole’ payment may be less or potentially not occur and the unit owner will be subject to much higher operating cost than what the market paid.”

At times, Golden Spread’s quick-start 168-MW Antelope units near Abernathy, Texas, are covering half of SPP’s regulation, Mike Wise, Golden Spread’s senior vice president of commercial operation and transmission, told the committee.

Wise said starts for the 18 Wärtsilä reciprocating engines at Antelope increased to almost 13,000 between March 1 and Dec. 3, 2014, compared with about 3,000 starts during the same time period in 2013, before the start of the Integrated Marketplace, a four-fold increase. About 41% of the starts in 2015 resulted from RUC instructions by SPP operators.

“They shouldn’t be getting RUC’ed at all,” Wise said. “They should be dispatched by the day-ahead or real-time market.”

Wise said SPP should create a ramping product to create the proper economic signals for quick-start and other fast-ramping resources. “This market should have a ramping product that is the envy of the country. We have got the wind resources that are the envy of the country,” Wise said. The short-term study “is not the answer. The ramping product that we are working on is the answer.”

One director asked about deferring to the new tool until the ramping product is developed. “I don’t want to make a bad situation worse,” he said.

Richard Dillon, director of market design, said it will likely be months before there is a proposed ramping product for members to consider and that once approved, it will take considerable software development to implement.

Chief Operating Officer Carl Monroe said the tool would automate “something we’re already doing manually. It doesn’t change [Golden Spread’s] situation at all.”

With the rejection, the measure was returned to the MOPC.

May 4, 2015

Supreme Court Agrees to Hear Demand Response Appeal

By Rich Heidorn Jr.

WASHINGTON — The U.S. Supreme Court said Monday it will reconsider the D.C. Circuit Court of Appeals decision threatening the Federal Energy Regulatory Commission’s authority over demand response.

The court made its decision after a conference Friday on FERC’s petition for a writ of certiorari.

The court agreed to consider two questions:

Whether FERC “reasonably concluded that it has authority under the Federal Power Act, 16 U. S. C. 791a et seq., to regulate the rules used by operators of wholesale electricity markets to pay for reductions in electricity consumption and to recoup those payments through adjustments to wholesale rates.
“Whether the Court of Appeals erred in holding that the rule issued by [FERC] is arbitrary and capricious.”

A ruling is expected in about 12 months, following briefs this fall and oral arguments in the fall or next spring.

Retail, not Wholesale

Last May, the D.C. Circuit vacated FERC Order 745, which set rules for compensating DR in RTO energy markets. The court said DR is a retail product and thus subject to state, not federal, jurisdiction (Electric Power Supply Association v. Federal Energy Regulatory Commission).

FERC’s 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. (See FERC Files EPSA DR Appeal with Supreme Court.)

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.

Opponents’ Brief

In a brief opposing the petition, attorneys for the Electric Power Supply Association and others said that those supporting review had provided “no compelling basis” for reconsidering the appellate ruling.

“Notwithstanding petitioners’ sky-is-falling assertions, the decision … does not have the kind of exceptional importance that warrants this court’s intervention,” it said.

“Instead, they merely disagree with a D.C. Circuit decision that correctly identified FERC’s rule for what it is: a clear intrusion on the states’ exclusive authority over retail sales, in a backdoor effort to overcome the states’ unwillingness to adopt a regime for retail rates that mirrors FERC’s preferred regime for wholesale rates.”

Order 745 required RTOs and ISOs to pay DR the same prices as generation. The opponents cited a comment by former FERC Chairman Jon Wellinghoff during a technical conference: “I have no assurances as to when the states will put dynamic retail prices with the controversies that are going on [and] all the political problems with getting those in place.”

In a reply brief on behalf of FERC, Solicitor General Donald Verrilli said Wellinghoff “was merely responding to the suggestion that wholesale demand response could impede efforts to develop retail-level demand response technology.”

“The purpose of the rule is to correct inefficiencies and improve pricing, reliability and competitive conditions in wholesale energy markets,” Verrilli wrote.

Arbitrary and Capricious

The opponents also said the petition was flawed because it did not ask the court to review the D.C. Circuit’s alternative holding that FERC’s final rule must be vacated as arbitrary and capricious even if it did not exceed FERC’s jurisdiction.

Verrilli noted that the D.C. Circuit’s primary holding barred the commission from reissuing the rule while the secondary holding would allow FERC to “repromulgate the rule with a response to the court’s holding on the payment formula, or could adjust the payment formula.”

The Supreme Court nevertheless took on that second question. It allotted one hour for a yet-to-be-scheduled oral argument.

At least four justices must agree to hear a case for the court to grant certiorari. The court said Justice Samuel Alito did not take part in the consideration of the petition.

PJM Capacity Auction will Include DR

PJM General Counsel Vince Duane said the court’s action means PJM will include DR in the 2018/19 Base Residual Auction. On April 24, FERC approved PJM’s request to delay the auction pending a ruling on the RTO’s Capacity Performance proposal. (See FERC OKs PJM Request to Delay Capacity Auction.)

“We will run a capacity auction either under the CP rules or under the old rules,” Duane said. “Despite that uncertainty, one thing that has become clear is that we will have DR participate, as it always has, as a supply-side resource.”

Duane said the granting of certiorari does not mean the court will ultimately overturn the D.C. Circuit ruling. Duane noted that the court ruled 7-2 April 21 to uphold the Ninth Circuit Court of Appeals in a case concerning FERC’s jurisdiction under the Natural Gas Act, ONEOK, Inc. v. Learjet, Inc.

“It seems hazardous to assume that because the court takes the case that it’s likely to overturn” EPSA, Duane said.

Duane said the way the court worded the first question it will consider suggests it will provide a definitive ruling on whether any limitations on FERC’s jurisdiction over DR in the energy market also apply to the capacity market.

Reaction

FERC Chairman Norman Bay praised the court’s action. “The integration of demand response is important to the nation’s competitive wholesale electricity markets and reliable electric service,” he said in a statement.

Wellinghoff, now a strategic advisor to the Advanced Energy Management Alliance, issued a statement expressing confidence that the Supreme Court will overturn the D.C. Circuit. “The lower court’s decision to vacate FERC Order 745 is inconsistent with the law and undermines the rights of customers to make smart choices about how they consume energy,” he said.

EPSA CEO John Shelk said the association “and its partners in the unprecedented coalition that successfully challenged FERC Order 745’s demand response provisions look forward to defending the D.C. Circuit’s well-reasoned decision in the Supreme Court.”

May 2, 2015

Appellate Court Rejects EPA Rule on Back-Up Generators

By Rich Heidorn Jr.

WASHINGTON — A federal appellate court Friday threw out the Environmental Protection Agency’s 2013 rule exempting diesel generators providing demand response from air emissions limits.

“Because EPA too cavalierly sidestepped its responsibility to address reasonable alternatives, its action was not rational and must, therefore, be set aside,” a three-judge panel of the D.C. Circuit Court of Appeals ruled unanimously in a challenge by Delaware environmental regulators.

At issue is an EPA rule that exempted reciprocating internal combustion engines providing “emergency demand response” from emissions limits for up to 100 hours each year. (National Emission Standards for Hazardous Air Pollutants for Reciprocating Internal Combustion Engines; New Source Performance Standards for Stationary Internal Combustion Engines, 78 Fed. Reg. 6,674, Jan. 20, 2013).

The rule, which replaced a prior 15-hour exemption, noted that using such generators, which are typically powered by diesel fuel, “as part of emergency demand response programs can help prevent grid failure or blackouts.”

Erroneous Assumption

EPA said it loosened the rule based in part on PJM’s comments in a prior rulemaking indicating that resources needed to be available for a minimum of 60 hours annually to participate in the RTO’s emergency load response program.

That was an incorrect conclusion, the court ruled, noting that PJM had clarified in comments to EPA in 2012 that the 60-hour minimum does not apply to individual engines and that engines may be aggregated to meet the 60-hour requirement.

“EPA seems to have either intentionally discounted PJM’s later explanation of its requirement or simply confused the later comment for the earlier one,” the court said. “Another commenter brought the possible confusion to EPA’s attention, but EPA did not specifically respond, saying it considered demand-resource needs ‘in all areas of the country, not just PJM.’ And yet, EPA significantly grounded the 2013 rule in a PJM requirement that does not exist for individual engines.”

EPA had no immediate comment, saying it was still reviewing the court’s decision.

EPA issued the rule under sections 111 and 112 of the Clean Air Act. The Delaware Department of Natural Resources and Environmental Control filed a challenge complaining that emissions from emergency demand response programs significantly worsened ozone pollution in the state and alleging that at least 90% of the pollutants contributing to Delaware’s failure to comply with National Ambient Air Quality Standards come from pollutants transported from other states.

‘Opposite Effect’

Delaware and other challengers, including the Electric Power Supply Association and Calpine, said that demand response based on backup generators was hurting both the environment and grid reliability, counter to EPA’s arguments.

The court summarized the arguments: Because backup generators are exempt from emissions controls, they can underbid conventional generators in capacity markets, resulting in underinvestment by traditional generators, which undermines grid reliability. The reduced power supply increases the number of power emergencies, resulting in an increase in the use of “dirty” backup generators.

“In short, petitioners and the intervenor argue that instead of protecting the nation’s air resources and improving grid reliability as EPA claims, the 2013 rule has the opposite effect.”

PJM’s Independent Market Monitor was among the rule’s critics when it was proposed, telling EPA that the 100-hour exemption would distort both the capacity and energy markets.

“Some have asserted that an exemption for [backup] generators participating in demand-side response programs provides benefits to the organized wholesale electricity markets,” the Monitor wrote. “Those arguments have no merit. On the contrary, providing the exemption will have negative consequences for efficiency and reliability.”

In its comments to EPA, Calpine contended the proposed rule “would incentivize the procurement of diesel-fired [behind-the-meter] generators masquerading as ‘demand response’ in electricity capacity markets and thereby displace clean generating resources.”

Calpine said backup generators are not necessary for reliability in organized markets because “the market will simply procure other resources instead of [a behind-the-meter generator] that has not had to internalize the costs of emissions controls.”

An August 2012 report submitted to EPA by Northeast States for Coordinated Air Use Management, a non-profit association of air quality agencies, said that “demand response programs appear to be shifting a portion of overall electricity demand from traditional generating resources that supply the grid to more dispersed, unregulated diesel generators.”

The court also noted “evidence in the administrative record” that backup generators represent almost 15% of demand response in PJM. PJM officials could not be immediately reached for comment on the ruling.

‘Arbitrary and Capricious’

The court said the rule was arbitrary and capricious because EPA failed to respond to comments raising concerns about its impact on the grid or to those suggesting that the 100-hour limit was based on faulty evidence.

“EPA also did not consider the alternative of limiting the exception to parts of the country not served by organized capacity markets. We should further note that EPA did not obtain the views of [the Federal Energy Regulatory Commission} or [the North American Electric Reliability Corp.] on the reliability considerations upon which EPA based the exemption.”

The court also criticized EPA for providing contradictory answers when challenged. It said that the agency dismissed suggestions that it work with FERC on the reliability impact of the rule, contending that the rule’s purpose was to address emissions and that it was not its responsibility “to determine which resources are used for grid reliability.”

“EPA cannot have it both ways,” the court said. “It cannot simultaneously rely on reliability concerns and then brush off comments about those concerns as beyond its purview.”

In reversing the 100-hour exemption, the court said EPA can file a motion requesting either that the current standards remain in place or that it be allowed time to develop interim standards “if vacating these portions of the 2013 rule will cause administrative or other difficulties.”

May 1, 2015

Eversource: Northern Pass Delayed Until ’19; Earnings Up

Eversource Energy said Wednesday that its proposed Northern Pass transmission project won’t be operational until the first half of 2019.

The company had previously said the 187-mile, 1,200-MW line would be delivering Canadian hydropower to the New England energy market by 2018.

The delay is due to the longer-than-expected release of a U.S. Department of Energy draft environmental impact statement, Eversource officials said during the company’s earnings call. The statement had been expected in April, but the company is now expecting its release by June or July.

Approvals are expected in late 2016, with construction beginning shortly thereafter and expected to take about two years. However, even if the project maintains its construction schedule, line testing could not take place during the winter of 2018-2019 and would be delayed until spring, officials said.

Q1 Earnings Up

Eversource reported first-quarter earnings of $253.3 million ($0.80/share), compared with $236 million ($0.74/share) a year ago. These figures include integration costs of $4 million in 2015 and $5.8 million in 2014 related to the merger of Northeast Utilities and NSTAR. Excluding those costs, Eversource earned $257.3 million ($0.81/share) versus $241.8 million ($0.76/share).

The legal name change of Northeast Utilities to Eversource Energy was approved at the company’s 2015 annual shareholders meeting on April 29. Its stock started trading on the New York Stock Exchange under the ES ticker symbol in February. The company also reported that Standard & Poor’s upgraded its corporate credit rating to A.

— William Opalka

May 1, 2015June 15, 2023

Strong PECO Performance Helps Exelon’s Earnings

By Suzanne Herel

Exelon said Wednesday that first-quarter profit exceeded expectations, in part due to strong performances by PECO, Baltimore Gas and Electric and Constellation Energy.

The company reported earnings of $693 million ($0.80/share) compared with $90 million ($0.10/share) a year earlier. Excluding certain items, the company delivered a per-share profit of 71 cents, compared with 62 cents the same time last year.

Exelon said its earnings benefited from fewer storms and more hot days for PECO, its generation-to-load-matching strategy, the $60 million acquisition of Integrys, increased rates at BGE and the Department of Energy’s cancellation of spent nuclear fuel disposal fees.

These factors were partially offset by some nuclear outages; lower profit at Commonwealth Edison, where heating degree days and electric deliveries fell; higher operating and maintenance costs for contracting; interest expenses; and the termination of interest rate swaps.

Exelon’s generation segment — which includes its retail suppliers and Constellation, which sells to both wholesale and retail customers — saw a profit of $443 million, compared with a year-earlier loss of $185 million.

In a conference call with analysts, CEO Christopher Crane said he was hopeful that an Exelon-backed bill designed to support some of the company’s underperforming nuclear reactors would clear the Illinois legislature this session. (See Exelon-Backed Bill Proposes Surcharge to Fund Illinois Nukes.)

He also was optimistic that the company’s proposed $6.8 billion takeover of Pepco Holdings Inc. would clear the final regulatory hurdles in Maryland and D.C., and close late in the second quarter or the third quarter of this year. (See Deadline Looms for Decision in Exelon-Pepco Deal.)

He dismissed rumors that Maryland Gov. Larry Hogan opposed the merger, saying, “The governor has stayed neutral since he says he’s come in late to the process.” Crane said Hogan had penned a letter to the state Public Service Commission saying he was neither for nor against the transaction.

Crane said he expects the company to receive a decision from the Maryland PSC by May 15.

Chief Financial Officer Jack Thayer said that should regulators reject the deal or place such onerous conditions on it that it no longer was viable, Exelon would use the money to “fund growth at the business or return value to shareholders through other means.”

April 30, 2015June 15, 2023

MISO Company Q1 2015 Earnings Roundup: Week of April 28

NiSource’s net income rose nearly 1% in the first quarter, to $268.4 million from $266.2 million a year earlier, the company announced Thursday.

The Merrillville, Ind.-based energy provider said that quarterly revenue fell 7%, to $2.15 billion from $2.32 billion, in the same quarter of last year.

Most of the decline occurred in its electric utility business, where revenue slumped 12% to $394.7 million. The company’s gas distribution business revenues dropped 11% to $1.08 billion, but gas transport and storage revenue rose nearly 9% to $628 million, thanks to growth in shale gas projects.

NiSource, the parent of Northern Indiana Public Service Co., said it is on track for a planned July 1 separation of its Columbia Pipeline Group into a publicly traded company. It will trade on the New York Stock Exchange as CPGX.

Entergy Q1 Profits Bruised by Wholesale Unit

Strong electricity demand by Entergy’s industrial customers in the first quarter was offset by a decline in its wholesale commodities unit, resulting in a 26% decrease in quarterly profit, the company announced Tuesday.

The New Orleans-based generator earned net income of $298.1 million ($1.65/share) in the first quarter versus $401.2 million ($2.24/share) for the same period last year. Quarterly operating revenue fell 9% to $2.92 billion.

Entergy cited the “Industrial Renaissance” in the Gulf region for the seventh-straight quarter of industrial sales growth. That boosted consolidated net income of the utility segment by 11% to $223.4 million. Entergy cited industrial growth in persuading MISO to approve a $187 million out-of-cycle project to beef up its transmission system near Lake Charles, La. (See Entergy Out-of-Cycle Requests Win MISO Board OK.)

Entergy’s wholesale commodities segment saw a steep decline in the first quarter, with net income falling to $123 million compared to $242 million in 2014 — a decrease of nearly 50%. The company cited several factors, including the shutdown of the Vermont Yankee nuclear plant at the end of 2014 and lower wholesale power prices.

CEO Leo Denault said Entergy is proceeding with $8 billion in capital spending over the next three years, including additional peaking units in the Lake Charles area.

He also said new ratemaking legislation in states such as Arkansas should provide a more favorable regulatory climate for recovering costs.

Denault also said that during Entergy’s first year as a member of MISO, the company’s customers have benefited from $240 million in energy-related savings, “exceeding expectations.”

Weather, Higher Expenses Nibble at Alliant Energy Earnings

Alliant Energy’s first-quarter profit dropped nearly 11% as a warmer winter brought lower electricity and gas sales.

The Madison-based energy company said it earned a profit of $99.2 million ($0.87/share) in the quarter, including a 4-cent weather benefit.

But that was significantly lower than the 12-cent benefit during the colder first quarter of 2014, when the company earned $110.6 million ($0.97/share), Alliant CEO Patricia Kampling said.

Higher electric transmission service expenses at Wisconsin Power and Light and retail electric customer billing credits at Interstate Power and Light also crimped results.

Revenues fell 6% to $897.4 million.

— Chris O’Malley

April 29, 2015

UPDATE: Incoming PJM CEO Ott Expects Challenges from an Industry in Transition

By Suzanne Herel

Incoming PJM President and CEO Andy Ott said Wednesday that the biggest issues facing the RTO are a “substantial swap” in fuel from coal to natural gas, increasing gas-electric coordination and the rise of distributed energy.

“We have an industry in transition,” Ott said. “We’re seeing a tremendous amount of coal resources retiring.”

Managing that evolution, he said, will be a major focus when he assumes the top spot this fall, as Terry Boston steps into a coaching role and retires on Dec. 31 after eight years running the RTO. (See PJM CEO Boston to Retire.)

Boston concurred: “We have seen the largest and fastest fuel change in the history of the world,” he said. “It took a lot longer to go from wood to coal than to go from coal to natural gas.”

Ott, an 18-year PJM veteran who currently holds the role of executive vice president of markets, was named Boston’s successor Wednesday. They spoke in an afternoon press conference.

Cost Allocation Challenges

The changing industry poses another challenge, Ott said: cost allocation of new transmission projects and operational changes.

“As we look at some of the impacts of those changes on the power system operation, one of the things we saw with the polar vortex, for example, was a very big, big shift in the cost or the price of reserves — we call it market uplift. One of the challenges the stakeholders face is dealing with some of these very difficult issues of cost allocation brought on by these changes.” (See FERC OKs $1,800 Offer Cap in PJM.)

The issue likely will be addressed in market rules and Tariff provisions, he said.

Boston also identified demand response as an industry concern waiting to be resolved by the Supreme Court. (See FERC Files EPSA DR Appeal with Supreme Court.)

“One of the challenges Andy may have is if the DR goes from wholesale market to retail control, how do we involve the 14 public service commissions’ stake in planning what DR will be in the future?”

Ott was thought to be one of two likely in-house candidates. Both he and Executive Vice President for Operations Mike Kormos frequently represent PJM before the Federal Energy Regulatory Commission and in industry forums.

“Andy is recognized internationally as a power industry leader and expert,” said PJM Board Chairman Howard Schneider. “The board and I are confident that Andy will ensure the continued collaboration, trust and exceptional performance for which PJM is known and that he shares our commitment to reliable grid operations, fair and efficient wholesale markets and robust transmission planning.”

Core Mission Unchanged

Said Ott: “I can assure everyone that our core mission will be unchanged and that we will maintain open communications and the collaborative, productive relationships with members and stakeholders which are crucial to PJM’s success.

“One of the strengths that Terry has fostered here at PJM is our industry leadership and our collaboration with stakeholders and states and FERC. I will promote that type of collaboration and continue it as we move forward.” (See Retiring PJM CEO Boston Lauded for Efficiency Improvements, Management Style.)

Ott called PJM an industry leader in innovating technical systems and a competitive market environment. “We will continue to lead there,” he said.

Boston said the men would make a decision sometime in the early fall as to when Ott officially will take the helm, but it likely will be in October or November.

“Andy has a lot of roadwork to do with all the commissioners and the CEOs of the major companies we serve,” Boston said.

Asked to look back on the highlights of his tenure, Boston noted the replacement of about 26,000 MW of coal for natural gas, experiencing three “one-in-100-year” weather events and advancing billions of dollars in projects to storm-harden the grid.

Ott has extensive experience in energy market restructuring. Prior to joining PJM, he worked for GPU Inc. in transmission planning and operations.

Currently, he provides executive oversight of the PJM Market Operations, Market Strategy, Member Training, State Relations, Customer Relations and Performance Compliance divisions. He was responsible for implementing the PJM wholesale electricity markets.

He is a board member of both PJM Technologies and PJM Environmental Information Services. He also serves on the board of directors of the Association of Power Exchanges and chairs the CIGRE (International Council on Large Electric Systems) Study Committee C5 on Electricity Markets and Regulation.

He received his bachelor’s in electrical engineering from Pennsylvania State University and his master’s in applied statistics from Villanova University. Ott is an Institute of Electrical and Electronics Engineers fellow.

As for what’s next for Boston, the native Tennessean said he and his wife, Brenda, intend to move into their son Brian’s condo in Hawaii for the winter after he graduates with a doctorate in geophysics from the University of Hawaii.

Boston is also looking to serve on a couple of boards of directors, potentially a utility and a high-tech company, he said, noting that he wrote his graduate thesis on the optimization of energy storage.

April 28, 2015

Michigan OKs Wisconsin Energy-Integrys Merger

By Chris O’Malley

Michigan regulators on Thursday approved Wisconsin Energy Corp.’s $9.1 billion acquisition of Illinois-based Integrys Energy — with the condition that the merged companies continue to operate the Presque Isle Power Plant in Michigan’s Upper Peninsula.

The approval of the Michigan Public Service Commission comes less than a month after the Federal Energy Regulatory Commission granted its OK (EC14-126).

The deal also requires the approval of state regulators in Illinois, Minnesota and Wisconsin.

Gov. Rick Snyder and other Michigan officials initially opposed the merger, in part because Wisconsin Energy had agreed to keep Presque Isle open under a system support resource agreement with MISO.

The aging generating plant had lost its major mine customers, and keeping it open under an SSR would have resulted in hefty rate increases for Upper Peninsula customers. Presque Isle recently wooed back former mine customers.

In exchange for approving the merger, the Michigan Public Service Commission won a commitment from Wisconsin Energy not to enter into a Presque Isle SSR with MISO before the end of 2019 or a new “clean energy” plant goes into service in the Upper Peninsula.

Wisconsin Energy also agreed to continue making any capital investments needed to continue operations of Presque Isle until the end of 2019 or the new plant begins commercial operations. The plant could retire earlier if Wisconsin Energy’s WEPCo subsidiary and the mines served by Presque Isle come to an agreement.

Other terms include a pledge by Wisconsin Electric not to increase retail rates for Michigan customers as a result of special contracts between Wisconsin Electric and mines in the area.

It appears the biggest hurdle for Wisconsin Energy and Integrys to clear is in Wisconsin, where consumer groups have demanded that the Milwaukee-based utility provide guarantees of monetary savings from the merger.

Among those groups insisting on concessions are the Wisconsin Paper Council, Wisconsin Industrial Energy Group and retail customer group Citizens Utility Board, reports the Milwaukee Journal Sentinel.

Wisconsin Energy is the parent of electric utility We Energies. Integrys owns Wisconsin Public Service Corp. and Michigan Gas Utilities Corp

April 28, 2015June 15, 2023

Company Briefs

Regulators in Maryland and D.C., the last holdouts to Exelon’s proposed $6.8 billion acquisition of Pepco Holdings Inc., have completed evidentiary hearings and are expected to rule on the deal by May 8 and May 13, respectively. Approval would create the Mid-Atlantic’s largest electric and gas utility.

Opposition in D.C. continues to mount, with two more of the District’s Advisory Neighborhood Commissions last week signing resolutions against the merger, tipping the resistance among those 40 groups to more than half. None of the ANCs have come out in support of the takeover, despite being approached by Exelon. The District’s Office of People’s Counsel and three members of the D.C. Council also oppose the deal. (See Deadline Looms in Exelon-Pepco Deal.)

Meanwhile, Exelon has pulled its advertising supporting the merger in Maryland and D.C., prompting some to wonder if that means the company has concluded the acquisition is a done deal. “The decision to discontinue ads in Maryland and D.C. is completely unrelated to any anticipated action the Maryland PSC may or may not take in coming weeks with regard to the merger,” Exelon spokesman Paul Adams said. “The ads have run for several weeks, and we believe they have been effective in educating people about the benefits of the merger.”

More: The Sentinel

Half of U.S. Fracking Companies Will be Gone By End of Year

The slumping price of U.S. oil and gas will halve the number of hydraulic fracturing companies, according to an industry executive’s prediction. Rob Fulks with Weatherford International, one of the larger fracking-service companies, predicts that the number of fracking companies will fall from 41 to just 20 by the end of the year, either through acquisitions or closures.

Speaking at the IHS Cera Week conference in Houston, Fulks said low energy prices are causing a decline in demand for drilling services. Some consolidation moves are already apparent, he said, pointing at Halliburton Co.’s acquisition of Baker Hughes Inc. in a $34.6 billion deal announced in November.

More: Bloomberg News

Dominion Backing Away From Offshore Wind Pilot Program

Unexpectedly high costs have Dominion Virginia Power rethinking its offshore wind pilot program.

The company obtained the permits, did the site test work, drew up plans and sent out bid requests. It figured it would cost about $230 million to erect two wind turbines off Virginia Beach. But the bids came back at between $375 million and $400 million. Now, a Dominion spokesman said the pilot program is on hold, while the company and its partners research other ways of building the project.

More: Virginian-Pilot

Alliant Taking Steps to Prevent More Eagle Deaths

A month after an eagle was electrocuted on one of its power lines, Alliant Energy is installing equipment aimed at preventing more avian injuries. In March, the body of a dead eagle was found beneath one of its lines near the town of Harper, Iowa.

While birds can perch on one charged wire without risk, Alliant is installing plastic insulation on some wires to decrease the likelihood of a bird contacting two charged wires at once. Work crews are also installing triangular plastic devices on the crossarms to discourage birds from perching.

Birdwatcher say hundreds of eagles congregate in the area, where there is a proliferation of hog farms.

More: The Gazette

Alevo Makes First Sale of 2-MW GridBank Battery System

Alevo Group says it signed its first sales contract on its 2-MW GridBank battery system. The company said it will sell three units to an unidentified buyer. In February, the company and Customized Energy Solutions announced they would provide 200 MWs of merchant storage capacity to regional transmission operators, half of it to PJM.

More: Charlotte Business Journal

RGGI Auctions Provided $2.9 Billion Returns

The nine states of the Regional Greenhouse Gas Initiative (RGGI) say they generated $2.9 billion in savings through 2013. A report by RGGI shows the CO2 allowances auctions provided lifetime energy bill savings to more than 3.7 million participating households and 17,800 businesses.

More than $1 billion in RGGI auction proceeds were invested in programs including energy efficiency, clean and renewable energy, greenhouse gas abatement and direct bill assistance. Energy efficiency continued to receive the largest share of investments.

Over their lifetime, the investments are projected to save more than 48.7 million BTU of fossil fuels and 11.5 million MWh of electricity, avoiding the release of about 10 million short tons of carbon pollution.

More: RGGI

TVA Shutting Coal Units, But Wants to Stay in Steam Business

TVAJohnsonvilleSourceTVA — Johnsonville Fossil Plant (Source TVA)

The Tennessee Valley Authority said it wants to install a heat recovery steam generator on one of the 20 gas-fired combustion turbines at the Johnsonville Fossil Plant in Tennessee to provide steam to an adjacent titanium dioxide manufacturer. TVA is retiring the coal-fired units at the Johnsonville plants by the end of 2017, but wants to continue selling steam to the factory. It has prepared a draft environmental study supporting the plan.

More: Chattanooga Times-Free Press

April 28, 2015June 15, 2023

Bid for Generator Price Flexibility Draws Debate Over 10% Adder

By Suzanne Herel and Rich Heidorn Jr.

WILMINGTON, Del. — Calpine won stakeholder approval for an initiative that could give generators more flexibility in pricing following an unusually lengthy debate before the Markets and Reliability Committee Thursday.

Dave Pratzon, representing Calpine, presented a problem statement and issue charge arguing that permitting generators to revise their offers hourly to reflect changes in gas prices would result in reduced risk premiums, benefiting consumers.

But some stakeholders questioned the scope of the problem statement, saying it should also include language calling for reconsideration of the 10% adder that generators are allowed to include in their cost-based offers. The adders provide a cushion against uncertainties, including fuel prices and heat rates that can vary with temperatures and plant loading. Hourly pricing would reduce the fuel price risk, they reason, reducing the need for the adder’s price cushion.

Walter Hall, representing the Maryland Public Service Commission, said the PSC would oppose the problem statement if it did not include a reconsideration of the adder. PJM and the Independent Market Monitor also backed inclusion of the adder in the problem statement.

Challenge Reaching Consensus?

“I don’t want to set this group up to fail,” said PJM Executive Vice President for Operations Mike Kormos, referring to the senior task force expected to be assigned to study the problem and recommend a solution. “It may be difficult to reach consensus without this issue. We think this is an important issue.”

“Clearly it’s related,” said Market Monitor Joe Bowring. “It doesn’t make any sense [to exclude it]. I think it’s avoiding something that’s really obvious.”

But Pratzon rejected Hall’s request to include the adder as a “friendly” amendment. Pratzon said he wanted to avoid “scope creep” and was not authorized by his client to broaden the initiative. He suggested the adder be addressed separately by the Cost Development Subcommittee.

Jason Cox of Dynegy came to Pratzon’s aid, saying, “I’m concerned that Calpine’s problem statement is being hijacked.”

“This issue is very narrow,” he added, saying hourly pricing would reduce the use of the adder. He said those concerned about the adder should propose their own problem statement.

The problem statement was approved by voice vote with two votes against it.

PJM Stands Alone

Pratzon introduced the proposal to the MRC in March, saying PJM is the only organized market in the U.S. that does not allow generators to vary their offers hourly. (See PJM May Consider Hourly Pricing for Generators.)

As approved, the initiative would also permit consideration of more flexible offers by energy storage and price-based demand side response. Market power protections were also added to the scope.

Pratzon said the issue gained urgency because the Federal Energy Regulatory Commission had declined earlier this month to change the start of the gas day, a blow to efforts to improve gas-electric coordination. (See related story, PJM Considering Change to DA Deadlines in Response to FERC Order on Gas Schedule.)

John Farber of the Delaware Public Service Commission and Ruth Price of the Delaware Public Advocate’s office pressed Pratzon for how the change to hourly pricing would benefit ratepayers.

Pratzon noted that a 50-cent per MMBtu difference in the price of gas translates to a difference of $3.50/MWh. With hourly generator offers, he said, the price will “be lower some hours, higher some hours. But overall it will be better.”

The Adder’s Role

Although the adder was not included in the problem statement, Kormos said it would be included in the educational portion of the task force’s work. “I’m finding it hard to understand how that couldn’t be permitted,” he said.

According to the Market Monitor, the adder was included in the definition of cost-based offers in 1999, based on the uncertainty of calculating the hourly operating costs of combustion turbines under changing ambient conditions. However, in docket (EL15-31) — in which PJM proposed limiting the adder to the $100 for offers exceeding $1,000/MWh — generators argued that the adder also provided protection against gas-price volatility.