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, 2015June 15, 2023

PJM Considering Change to Day-Ahead Deadlines in Response to FERC Gas Schedule Order

By William Opalka, Chris O’Malley and Rich Heidorn Jr.

PJM is considering changing its day-ahead market schedule in response to the Federal Energy Regulatory Commission’s April 16 ruling revising the interstate gas nomination timeline.

Other RTOs’ reactions varied, with ISO-NE saying it has no plans to change its schedule and NYISO looking to respond to its neighbors. MISO stakeholders will discuss the issue Friday, while an SPP task force is expected to make recommendations on any changes by July.

FERC moved the timely nomination cycle deadline for scheduling gas transportation from 11:30 a.m. to 1 p.m. CT (12:30 p.m. to 2 p.m. ET). It also added a third intraday nomination cycle (RM14-2). (See FERC Approves Final Rule on Gas-Electric Coordination.)

In response, PJM is considering moving up its day-ahead schedule by three hours, Adam Keech, senior director of market operations, told the Markets and Reliability Committee on Thursday.

PJM’s day-ahead market results currently are published at 4 p.m. ET, which would not provide enough time for selected generators to purchase gas, Keech said.

PJM is proposing that day-ahead offers close at 9:30 a.m. ET, with results published no later than 1 p.m. That would allow at least one hour for gas generators selected to run the next day to purchase fuel before the timely nomination cycle deadline.

The rebid period and reliability unit commitment (RUC) also would be moved up, running from 1 p.m. to 4:30 p.m., with results published by 6 p.m., allowing at least one hour for gas nominations before the evening nomination cycle deadline, which FERC left unchanged.

The changes would condense the day-ahead market solution window to 3.5 hours.

Joe Wadsworth of Vitol asked if PJM would be coordinating its changes with neighboring regions. He said moving PJM’s day-ahead deadline to 9:30 a.m. could inhibit trading with NYISO, which publishes its day-ahead results at about 9:30 a.m. That could hurt day-ahead convergence along the NYISO-PJM seam, he said.

Wadsworth said PJM also needs to consider that liquidity in the next-day gas markets sometimes doesn’t occur until after 10 a.m. on high gas-demand days. In such circumstances, there may be little or no natural gas price transparency prior to PJM’s day-ahead market bid deadline, he said.

Ed Tatum of Old Dominion Electric Cooperative suggested PJM coordinate the changes through the ISO/RTO Council and consider changing the start of the electric day.

Keech said FERC’s order neither mandates nor precludes changes to the electric day.

Keech’s comments came during a first read of a proposed problem statement to respond to the FERC order. Although the initiative won’t come up for a vote until the May 28 MRC meeting, PJM will conduct an educational session following the May 6 Market Implementation Committee meeting.

PJM and other regions must make compliance filings — adjusting their tariffs to comply with the final rule or explaining how their current rules are compliant — by July 23.

NYISO

“Because electricity markets are interdependent, the NYISO’s response to FERC’s order will need to account for its neighbors’ compliance efforts,” NYISO spokesman David Flanagan said. “If no changes are determined to be necessary, FERC’s decision will provide New York generators an additional hour-and-a-half to nominate the gas they require following the posting of the NYISO’s day-ahead market. FERC’s order also will increase the gas procurement flexibility available to New York generators that participate in the NYISO’s real-time market.”

MISO

MISO spokesman Andy Schonert said the RTO is “working internally and with stakeholders to figure out how we will respond to FERC’s order.” The Electric and Natural Gas Coordination Task Force will discuss the issue in a meeting May 1.

SPP

SPP spokesman Tom Kleckner said the RTO’s Gas Electric Coordination Task Force discussed the FERC ruling at a meeting Thursday and will be making a recommendation to SPP’s Board of Directors at the board’s July meeting.

“The [task force] is evaluating what changes can be made to the day-ahead and reliability unit commitment timelines,” Kleckner said. “It will be up to our stakeholders to make any changes to our timeline that are presented to the board.”

ISO-NE

ISO-NE, which shifted its day-ahead market schedule two years ago to align with the natural gas trading day, believes it is already in compliance with the FERC rule, spokeswoman Marcia Blomberg said.

“However, we are very disappointed at the decision not to change the gas day,” Blomberg said. “We continue to believe it would have been a material improvement to reliability. Without the change, obtaining fuel in order to meet their obligations will be more challenging for generators during upcoming winters. We are supportive of the change to the timely nomination cycle, which will help owners of gas-fired generators incrementally by improving their ability to timely nominate and schedule gas.”

April 28, 2015

PJM Members Tighten Lost Opportunity Cost Rules; Tech-Specific Eligibility Retained

By Suzanne Herel

WILMINGTON, Del. — PJM stakeholders last week approved tighter rules on generator lost opportunity costs but rejected a proposal to limit eligibility to the most flexible combustion units.

The rules concern compensation for combustion turbines that are scheduled in the day-ahead energy market but not committed in real time.

The vote by the Markets and Reliability Committee on Thursday was a partial setback for PJM and Independent Market Monitor Joe Bowring, who said current rules provide incentives for units to offer and clear in the day-ahead market but not in the real-time market.

PJM and the Monitor won a change preventing combustion turbines from receiving start-up and no-load costs when they do not run in real time — correcting what Bowring called “an algebra mistake” that resulted in generators receiving payments for costs they did not incur.

The change — including no-load and start-up costs as avoided costs in LOC calculations — was a reform the Monitor had sought since 2012. PJM has estimated the change could reduce LOC payments by about $40 million annually.

‘2×2’ Rule Rejected

The Energy Market Uplift Senior Task Force also had approved a proposal that would have allowed only the most flexible “2×2” CTs — those with start-up plus notification times and minimum run times of two hours or less — to receive lost opportunity costs if they are not dispatched in real time after clearing the day-ahead market.

Resources with start-up plus notification times or minimum run times of more than two hours would not have received lost opportunity payments unless PJM barred them from running in real time to avoid transmission overloads or other reliability problems.

But the task force’s proposal received less than 60% support in a sector-weighted vote of the MRC, short of the two-thirds minimum for passage.

An alternate motion that retained the current technology-specific LOC eligibility rules — combustion turbines and combined-cycle plants operating in simple-cycle mode — was then approved with nearly 92% support and a round of applause.

The MRC last month tabled the task force’s proposal, sending it back for more discussion, after some members, including Ed Tatum of Old Dominion Electric Cooperative (ODEC), complained that the 2×2 requirement was too restrictive. (See PJM Tables Rule Change on CT LOCs.)

Several proposed amendments emerged from the task force’s April 17 meeting: one by Dominion Resources, allowing for start-up costs to be paid if a unit operates in real time at PJM’s direction during any portion of its “temporally contiguous” commitment period; one from PJM clarifying the definition of “temporally contiguous”; and one from ODEC that would have extended LOC eligibility to 2×5 units with minimum run times of up to five hours.

Economic Choice

“We believe units with greater than a two-hour minimum run time are valuable to dispatch,” Tatum said. “We should be making decisions on units’ capability and not on an algorithm’s limitations.” (See PJM: New Rule on Lost Opportunity Costs Would Exclude 1/5 CTs.)

Bowring disagreed. “I don’t agree there is any physical basis for any minimum run time. It’s not required by manufacturers … it’s typically an economic choice,” he said. “I would suggest, if anything, that two hours is too long, not too short.”

Bowring added, “Part of the reason we got into this problem in the first place is PJM wasn’t really looking out four or five hours. Five hours is nowhere near flexible.”

Neither amendment by Dominion nor ODEC was cleared as “friendly,” so membership voted on the main EMUSTF proposal, which failed.

Susan Bruce of the PJM Industrial Customers Coalition then made what became the winning proposal, suggesting that the language regarding LOC eligibility be returned to the status quo and considered for approval along with Dominion’s amendment and PJM’s definitional clarification.

“My understanding is that [the 2×2 issue] was a bit of a surprise to some people,” she said. “That will move us past this issue.”

PJM’s Adam Keech, director of wholesale market operations, said that regardless of a mandated minimum run time, PJM will be making procedural changes “because we think we can do better,” noting that the RTO paid $25 million in lost opportunity costs in February. “We’re going to look at less flexible CTs, with lead times eight to 10 hours, and run them more often,” he said.

Because the less flexible units will retain their LOC eligibility, committing them in real time will ensure they are paid based on LMPs instead of being compensated via uplift.

Because the day-ahead payments to the units are a sunk cost, the less flexible units in many cases become essentially a “free resource” to PJM operators, Bowring explained.

After the meeting, Tatum said he was pleased with the vote. “We’re good for now — until the next shoe drops,” he said.

April 28, 2015June 15, 2023

ISO-NE May Delay DR Integration into Markets

By William Opalka

ISO-NE is considering delaying full integration of demand response into its markets by a year due to uncertainty about the Federal Energy Regulatory Commission’s authority over the resource.

A 33-page Markets Committee contingency plan released April 17 suggests not implementing DR until 2018 because of the time needed to develop procedures once the issue is resolved.

The U.S. Supreme Court was scheduled to consider FERC’s appeal of the D.C. Circuit Court of Appeals decision threatening the agency’s jurisdiction at its conference Friday. But no decision was announced Monday and the court said no news is likely for at least a week.

The D.C. Circuit vacated FERC Order 745, which set rules for compensating DR in RTO energy markets, saying the commission had intruded on state jurisdiction (Electric Power Supply Association v. Federal Energy Regulatory Commission). There is disagreement over whether the ruling also voids FERC jurisdiction over DR in the capacity and ancillary services markets. FERC filed its appeal with the Supreme Court in January. (See FERC Files EPSA DR Appeal with Supreme Court.)

“Without direction from the U.S. Supreme Court and the FERC, the region’s next steps are uncertain,” according to ISO-NE’s plan. “Possible scenarios range from maintaining an approach that is fairly consistent with the status quo, to allowing demand response participation solely in the capacity and ancillary services markets, or to removing demand resources from the supply-side of the wholesale market platform altogether.”

If the Supreme Court grants FERC’s request for a writ of certiorari, ISO-NE said, a ruling is not likely before mid-2016. Then FERC must interpret how the court’s direction impacts the integration of DR in wholesale markets.

“In addition to the potentially protracted legal process in this case, it is also unclear how narrowly or broadly the decision in EPSA will be interpreted — primarily by the commission, but potentially by the U.S. Supreme Court as well,” the plan says.

ISO-NE had planned to implement full integration of DR into the energy and reserves markets by June 1, 2017, a transition it says will require at least two years of modifications to its software and system infrastructure.

“The ISO would be at least one year into the project to meet the June 1, 2017, implementation date before knowing the Supreme Court’s ultimate decision,” the plan says. “And for all of the time, money and effort expended up to that point, the Supreme Court may nevertheless uphold the D.C. Circuit’s previous ruling. Substantial resources will be wasted if the ISO moves forward to fully integrate demand response into the energy and reserves market by June 1, 2017, and the Supreme Court ultimately upholds EPSA.”

The Markets Committee will discuss the issue when it meets May 5-6.

FERC last month rejected as premature PJM’s contingency plan to include demand response in its capacity auctions in the event the EPSA ruling is allowed to stand. (See FERC: PJM Demand Response Stop-gap Measure ‘Premature’.)

April 28, 2015January 3, 2024

State Briefs

Dynegy CEO: Exelon Bill Endangers Jobs, Plants

Legislation proposed by Exelon that would impose a customer surcharge to provide more revenue for its Illinois nuclear fleet would put jobs at risk at competing coal-fired power plants, Dynegy CEO Bob Flexon said. “It’ll have a severe economic impact on jobs downstate,” he told Crain’s Chicago Business, placing Dynegy’s plants “more at risk for shutdown.”

“What I would like the Legislature to avoid is disrupting the market by introducing a subsidy for one generator at the expense of other generators,” he said. (See Exelon-Backed Bill Proposes Surcharge to Fund Illinois Nukes.)

More: Crain’s Chicago Business

INDIANA

Small Railroad Wants to be Heard in IPL Fuel Switch

Indianapolis Power & Light wants to switch its Harding Street plant from coal to natural gas. Cleaner fuel, more modern plant, better reliability, right? Who would complain?

Well, the small railroad that last year delivered 1 million tons of coal to the plant might. The Indiana Utility Regulatory Commission has recognized Indiana Rail Road Company to be an intervenor in the case. “This conversion will have a substantial, adverse financial impact,” the company wrote. The status as intervenor will allow it to cross-examine IPL witnesses. The rail company has not said whether it will try to stop the fuel conversion.

More: The Indianapolis Star

KENTUCKY

Landfill Project Will Generate Electricity from Methane Gas

The East Kentucky Power Cooperative plans to begin construction next month on a landfill-gas power plant after receiving approval from the Kentucky Public Service Commission.

The facility at the Glasgow Regional Landfill, which will generate electricity from methane gas produced from buried trash, could be operating by September. Other landfills in the state have embarked on such projects over the past decade.

EKPC, comprised of 16 owner-member distribution cooperatives, will purchase the methane gas from the city-owned landfill, and Farmers Rural Electric Cooperative Corp. will buy the electricity produced from the facility.

More: Glasgow Daily Times

MARYLAND

Hogan to Sign Bill Opening Transmission Construction to Non-Incumbents

Gov. Larry Hogan is scheduled to sign a bill Tuesday opening transmission construction to non-incumbent transmission developers.

Senate Bill 460 authorizes persons other than “electric companies” to obtain a certificate of public convenience and necessity (CPCN) to build overhead transmission at or above 69 kV and to obtain land access through condemnation proceedings. Under current law, that authority was limited to existing electric distribution companies — companies already delivering power to retail customers. The bill allows a transmission developer with a regionally cost-allocated project to obtain a CPCN if the Public Service Commission finds the permit is in the best interest of state residents.

The bill was backed by LS Power and NextEra Energy, two competitive developers seeking to gain business as a result of the Federal Energy Regulatory Commission’s Order 1000, which eliminated incumbent transmission developers’ federal rights of first refusal (ROFR). Order 1000 does not bar state ROFR preferences, but FERC Chairman Norman Bay has suggested such laws may be unconstitutional. (See FERC Rejects Rehearing Request on SPP Order 1000 Filing.)

More: Md. Department of Legislative Services

MICHIGAN

Democrats Propose Bill to Double Renewable Standards

While Republicans in Lansing are looking to gut or abandon the state’s renewable energy standard, Democrats are seeking passage of a bill that would double the clean energy standards. The bill, “Power Michigan’s Future,” was introduced last week and now heads for Republican-controlled committees.

The legislation would double the renewable portfolio standard, to 20% by 2022, while also increasing energy efficiency standards to 2% of a utility’s annual sales by 2019.

More: Midwest Energy News

Detroit Zoo Energy Plans: 400 Tons of Animal Manure

The Detroit Zoo is raising funds for a proposed power generator that would be fueled from something it has plenty of: animal manure. It is using an online crowdsourcing site – Patronicity.com – to help it obtain $55,000 in funds to match an offer by the Michigan Economic Development Corporation.

The zoo wants to build a biodigester that would capture methane from the manure to generate both heat and power for the zoo’s 18,000-squre-foot Ruth Roby Glancy Animal Health Complex. The zoo estimates it could save between $70,000 and $80,000 a year in energy costs. “The biodigester will turn one of our most abundant resources – manure – into energy, and represents a significant step on our green journey,” said Detroit Zoological Society CEO Ron Kagan.

More: MLive

NEBRASKA

Wind Energy Credit Bill Advances in Legislature

A bill that would create a wind energy tax credit moved forward last week with a 25-3 vote in the Senate. The bill would provide for a 1-cent tax credit per KWh of power produced. The credit would decline by a tenth of a cent every two years, and then end after 10 years. The federal wind energy tax credit, which expired last year, was 2.3 cents per KWh.

The bill’s sponsor, Sen. Jeremy Nordquist of Omaha, said the wind industry is ready to step in to replace production that will be lost from coal-fired plants being forced into retirement by federal emissions standards. The state has a high amount of potential wind energy, but ranked only 18^th in the nation in production while neighbor Iowa was first.

Iowa is one of six states with state production tax credits, according to a report last year by the Iowa Department of Revenue. “We need to be in the game,” Nordquist said. “Right now, without a [state] production tax credit, we are not in that game.”

More: Omaha World-Herald

NEW JERSEY

BPU Investigating JCP&L’s Operations, May Order Audit

The Board of Public Utilities has ordered its staff to examine Jersey Central Power & Light’s operations, finances and customer service, and indicated that the initial probe could extend into a full audit. The team conducting the probe is expected to report back to the board by its next meeting in May.

JCP&L has been the target of frequent criticism for its outages. The FirstEnergy subsidiary was handed a blow earlier this year when the BPU signed off on a rate case that reduced revenue by $115 million.

While JCP&L has upgraded substations to improve reliability, regulators have said the company is still under the microscope. “Even today, there lingering concerns about operations and management of the company,” said BPU President Richard Mroz.

More: NJSpotlight

Three N.J. Utilities Issue RFPs To Increase Solar Certificates

While not ready to build their own solar facilities, three utilities in New Jersey are seeking power purchase agreements with solar generators for about 80 MW of solar capacity. Atlantic City Electric, Jersey Central Power & Light and Rockland Electric Company are looking to secure Solar Renewable Energy Certificates to satisfy state mandates.

The three-year SREC program, certified by the Board of Public Utility’s Office of Clean Energy, awards one SREC for each MWh of solar generation. ACE is looking for 23 credits, JCP&L is in the market for 52 credits and Rockland needs 4.5 credits.

More: PV Magazine

NEW MEXICO

PRC Nixes Public Service’s Plan To Shutter San Juan Unit

The Public Regulation Commission’s refusal to allow Public Service Co. of New Mexico to shut down one half of its coal-fired San Juan Generating Station to meet federal emissions standards could spell trouble for the plant’s future, according to the company.

Public Service wants to retire two of the plant’s four units, and install emissions controls on the other two. While the hearing examiner agreed to closing the units, he nixed the company’s proposal to absorb 132 MW of excess coal capacity in one of the remaining two units. The company said its plan is necessary because some of the plant’s co-owners will pull out in 2017.

“The consequences of such a decision will likely lead to a collapse of the restructuring of the San Juan ownership interests … and ultimately endanger continued operations at San Juan,” the company wrote in a filing last week. If Public Service has to find outside sources for the lost generation, rates could increase for customers, it said.

More: Albuquerque Journal

NEW YORK

Anti-Fracking Report Due Out Soon

A several-thousand-page document that will lay out the rationale for prohibiting hydraulic fracturing will be released soon, state Environmental Conservation Commissioner Joseph Martens said. The Supplemental Generic Environmental Impact Statement will end seven years of study that paves the way for Martens to issue an order preventing large-scale fracking.

In December, Martens said he would move to prohibit high-volume fracking “at this time” after state Acting Health Commissioner Howard Zucker issued a report recommending against proceeding, citing concerns about health risks and gaps in science.

To formalize a ban, the state Department of Environmental Conservation has to complete the environmental impact statement. State law mandates the document must be available for public review for at least 10 days before Martens issues a “findings statement,” the legal document that would finalize the state’s decision.

Poughkeepsie Journal

Caithness Long Island Says 2nd Plant Could Save $192 Million a Year

Caithness Long Island Energy, which already operates a 350-MW plant in the center of Long Island, released a study that says construction of a second plant could lower regional energy costs up to $192 million a year.

The company said its proposed 750-MW Caithness II plant in Yaphank would also decrease the island’s dependence on power imports and on older plants. The company released the report after PSEG Long Island, operator of the local distribution company, announced that no new sources of power were necessary until 2024.

Caithness President Ross Ain called PSEG’s analysis “one-dimensional” and said it didn’t take into account other savings from both the proposed plant and from Caithness I. PSEG Long Island’s parent company also produces power that would be in competition with the Caithness project.

More: Newsday

NORTH CAROLINA

Most Wells Near Duke Ash Ponds Show Contamination

State environmental regulators issued health warnings after some tests of private water wells near Duke Energy’s coal ash ponds showed contamination. The Department of Environment and Natural Resources said that 87 of 117 test results mailed recently to property owners cited contamination that exceeded state water safety standards.

The state indicated that the water would pass federal standards for municipal water supplies. Nevertheless, the state included warnings not to use the water for drinking or cooking.

While the tests have not yet shown a direct link between the coal ash ponds and the contaminants, many of the contaminants were those often found in coal ash, such as toxic heavy metals. Duke said it believes the high levels of contaminants are naturally occurring. “Based on the test results we’re reviewed thus far, we have no indication that Duke Energy plant operations have influenced neighbors’ well water,” the company said.

More: The Charlotte Observer

Officials Approve Offshore Seismic Surveys With Some Caveats

The state Division of Coastal Management gave the go-ahead for seismic surveys off the North Carolina coast by two oil and gas exploration companies.

Although Spectrum Geo Inc. and GX Technology now have state permits, they still need approval from the Bureau of Ocean Energy Management and the National Marine Fisheries Service. The state division also set other conditions, such as conducting the surveys at times that don’t conflict with recreational fishing tournaments, avoiding certain protected habitats, and following federal mitigation methods to reduce or eliminate impacts to marine life.

More: Carteret County News-Times

Attempt to Scale Back RPS Foiled by House Vote

A House committee voted against an attempt to roll back renewable portfolio standards. House Bill 681 would have allowed utilities to freeze the amount of renewable energy they procure at 6% for the next three years. The current Renewable Energy and Energy Efficiency Portfolio Standard requires utilities to obtain 12.5% of their energy from renewable sources by 2021. The bill was defeated in committee 15-14.

More: WRAL

Duke Energy Moves Ahead With N.C. Solar Construction

Duke Energy is on track to complete three more utility-scale solar projects by the end of the year as part of a $500 million investment in North Carolina solar: the 65-MW Warsaw facility in Duplin County; 40-MW Elm City plant in Wilson County; and the 23-MW Fayetteville Solar Facility in Bladen County.

Duke is also building a 13-MW solar plant at Marine Corps Base Camp Lejeune. The company said last week that it will employ more than 900 workers on the plants at the peak of construction.

More: The Charlotte Observer, Duke Energy

PENNSYLVANIA

PUC Gives Initial Approval To New AEPS Regulations

The Public Utility Commission voted unanimously to revise the state’s Alternative Energy Portfolio Standards with new rules for net metering customers. The rules would allow “customer-generators” to produce up to 200% of their annual power needs, receiving retail prices for any excess they sell to the grid. The rules also would reduce PUC deadlines for approving net metering applicants.

Final approval is pending a comments session. The AEPS requires distribution companies and generation suppliers to source 18% of electricity from alternative sources by 2021.

More: The Philadelphia Inquirer, PUC

FirstEnergy’s Bruce Mansfield Plant Tagged with Notice of Violation

The Department of Environmental Protection issued a notice of violation to FirstEnergy Corp. for emissions at its Bruce Mansfield coal-fired plant in Shippingport. The DEP said that the plant’s Unit 2 stack exceeded emissions limits earlier this month. The NOV did not identify the emissions.

Workers at the plant found a leak in a duct and repaired it, a plant spokeswoman said. A DEP spokesman said union employees at the plant brought the issue to the attention of state regulators, and that “served as a way to gets us out there.”

More: Pittsburgh Post-Gazette

VIRGINIA

Dominion to Close All Ash Ponds in Virginia

Dominion Virginia Power said it will be closing all ash ponds at its Virginia power plants. The announcement came following the finalization of coal-ash disposal rules by the Environmental Protection Agency.

Virginia is the northern neighbor of North Carolina, which has been the scene of coal-ash legal action and legislation following a massive spill of toxic coal ash from a retired Duke Energy plant on the border of the two states. Dominion said it would close coal ponds at its Chesterfield Power Station near Richmond, the Bremo Power Station in Fluvanna County, the Chesapeake Energy Center in Chesapeake and the Possum Point Power Station in Prince William County.

The company said the ponds would be drained and sealed with a liner that would covered with a 2-foot layer of earth.

More: The Roanoke Times

McAuliffe Signs Clean Energy Bills on Earth Day

Gov. Terry McAuliffe signed several bills aimed at encouraging clean energy production, energy efficiency and jobs production:

- - HB 2267/ SB 1099: A bill creating the Virginia Solar Development Authority, which aims to spur construction of solar facilities;
  - HB 1950/ SB1395: Doubles allowable generation capacity of a solar net energy metering facility;
  - HB 2237: Authorizes utility cost recovery for construction or purchase of a solar facility with capacity over 1MW and establishes that 500MW of solar generation are in the public interest;
  - SB 1331: Clarifies how costs are evaluated by the State Corporation Commission to increase approval of natural gas energy efficiency programs;
  - HB 1446 /SB 801: Expands the Property Assessed Clean Energy (PACE) program, which creates loan programs for localities to finance energy efficiency projects on commercial buildings using private capital; and
  - HB 1843/ SB 1037: Extends $500 per job Green Jobs Tax Credit for three years to July 1, 2018

Some environmentalists applauded the move, but said more action is needed. “The fact that we’re celebrating Earth Day by witnessing several pieces of clean energy legislation get signed into law is proof of the growing movement in Virginia demanding solutions to climate change,” said Dawone Robinson of the Chesapeake Climate Action Network.

“Virginia currently has only 11 MW of solar installed, and that figure is embarrassingly low, especially compared to our neighbors. Virginia has as much or more solar potential than Maryland and North Carolina, yet those states have more than 200 MW and 950 MW of solar currently installed respectively thanks to much stronger state policies.”

More: Gov. McAuliffe, Chesapeake Climate Action Network

WISCONSIN

Contested Transmission Line Gains PSC Approval

The Public Service Commission last week approved the Badger-Coulee transmission project, and now land agents are fanning out to acquire the easements upon which it will be built. The 345-kV, $580 million line is a joint venture of Xcel Energy and American Transmission Co.

With the PSC’s approval, the companies received permission to pass the cost of the line on to consumers across the Midwest. The line is part of a larger project, the CapX2020, which will run across Minnesota and Wisconsin.

Construction work on that line is already underway. ATC and Xcel say the lines will provide a way to deliver cheaper wind-generated power to consumers.

More: Lacrosse Tribune

Alliant to Build $750 Million Gas-fired Plant in Wisconsin

Alliant Energy Corp. is seeking authority to build a $750 million combined cycle gas plant in Wisconsin, its first application for new generation since regulators rejected its 2008 proposal to build a coal-fired plant. The company is also proposing to build a new 2-MW, $9 million solar facility next to the gas plant.

The solar facility, if approved and constructed, would be the second largest in the state. The proposed gas-fired plant would be rated at about 700 MW. The proposal for the new complex coincides with Alliant’s plans to retire a coal-fired facility in Cassville, Wis. and coal boilers in Sheboygan to comply with an environmental settlement reached with federal regulators several years ago.

More: Journal Sentinel

April 28, 2015

PJM Markets and Reliability Committee Members Committee Briefs

The Markets and Reliability Committee approved Tariff and manual revisions regarding PJM’s use of sampling to measure and verify residential demand response.

The new measurement method was originally endorsed at the Jan. 22 Members Committee meeting. Thursday’s vote approved the inclusion of an additional transition year because of delays in filing the new method with the Federal Energy Regulatory Commission.

PJM now expects to make the filing in late April. (See “Sampling to be used for Measuring Residential DR” in MRC/MC Briefs, Nov. 25, 2014.)

Tariff Harmonization Senior Task Force Charter Approved

The MRC approved the draft charter of the Tariff Harmonization Senior Task Force, formed to address inconsistencies and discrepancies in PJM’s governing documents. There was one abstention and one vote against the measure. (See Task Force Proposed to Resolve Inconsistencies in PJM Governing Documents.)

Regional Planning Process Senior Task Force Placed on Hiatus

On first reading, MRC members approved the Regional Planning Process Senior Task Force’s recommendation directing the Planning Committee to develop guidelines for considering generation interconnection projects as drivers under the multi-driver transmission project approach.

The MRC also agreed to place the task force on hiatus, available to be returned to operation if needed based on future rulings by FERC.

Manual Change Endorsed

The MRC approved changes in Manual 14D: Generator Operational Requirements to reflect a recent advisory from the North American Electric Reliability Corp. on generator frequency response requirements. PJM sent Generator Operators a survey regarding governor dead band settings, droop setting and mode of operation on April 3. PJM will compile the responses, due June 3, and share the data with NERC.

FTR Auction Clearing Deadlines, Trading Periods Approved

The Members Committee approved minor “non-substantial” provisions regarding financial transmission rights’ auction clearing deadlines and trading periods.