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October 31, 2024

Revised Clean Power Plan Allows More Time, Sets Higher Targets

By Rich Heidorn Jr.

After sifting through 4.3 million comments and attending months of meetings with state regulators, utilities and RTO officials, the Environmental Protection Agency yesterday released a final Clean Power Plan that relaxes some controversial proposals while increasing its target for emission reductions.

As expected, EPA bowed to nearly universal opposition to a requirement that states meet interim goals as soon as 2020, replacing that with a 2022 target while leaving 2030 as the deadline for full compliance. As also expected, the rule incorporates a reliability “safety valve.”

At the same time, the Obama administration upped its ultimate target, saying it will require a 32% reduction in power plant CO2 emissions from 2005 levels, up from 30% in the draft rule.

EPA said it will permit all low-carbon resources, including renewables, energy efficiency, natural gas, nuclear and carbon capture and storage to have roles in compliance.

clean power plan
Natural gas generators will play a smaller role in replacing retiring coal plants under the final rule than EPA projected in its draft plan. Source: Duke Energy

But the final plan anticipates less switching from coal to natural gas and more reliance on — and incentives for — renewables. EPA projects renewables will account for 28% of generating capacity by 2030, up from 22% in the proposed rule, an increase of nearly one-third.

EPA said it increased renewables’ role in part because of the falling cost of solar and wind power and expectations of additional reductions in the future. The agency will seek to take advantage of those economics while offering pollution credits for states that add renewables before 2022, with similar incentives for those that make early energy efficiency investments in low-income communities.

Trading-Ready State Plans

In addition to delaying initial compliance by two years, EPA said the final rule also grants states more flexibility in meeting their targets, allowing them to develop trading-ready compliance plans for participating in emission credit markets with other states without the need for complicated interstate agreements.

State plans are due in September 2016, but states that need more time can make a preliminary filing and request extensions of up to two years for submitting a final plan.

Litigation Expected

EPA also released a federal implementation plan that it said can provide a model for states while also serving as a “backstop” for states that balk at compliance.

clean power plan
The solar industry says it offers a “50-state” solution to replacing coal-fired generation.

EPA will have to use that backstop if some states stand firm in their pledges to refuse to comply, as Senate Majority Leader Mitch McConnell, a Republican from coal-producing Kentucky, has urged. About two dozen states have indicated they may challenge the plan in court.

EPA, however, says that many states are already on the path to compliance, noting that all states have demand-side energy efficiency programs and all but 13 have renewable portfolio standards or goals. Half of the states have energy efficiency standards or goals.

“The idea of setting standards and cutting carbon pollution is not new. It’s not radical,” President Obama said at a White House ceremony announcing the plan. “What is new is that, starting today, Washington is starting to catch up with the vison of the rest of the country.”

Reliability ‘Safety Valve’

The rule seeks to ensure sufficient generation resources by requiring states to address grid reliability in their plans and includes a “safety valve” that could buy some retiring generators additional time to address any reliability concerns.

EPA noted that — unlike the Mercury and Air Toxics (MATS) rule — the Clean Power Plan does not impose plant-specific requirements, allowing states flexibility to “smooth out” their emission reductions over time and across sources.

International Audience

The Clean Power Plan is the latest of the Obama administration’s initiatives — which includes the controversial loan guarantees for clean energy technologies, a doubling of fuel economy standards for cars and light trucks, and a separate rule limiting emissions from new power plants — directed at climate change.

By now addressing power plant emissions — the largest source of greenhouse gases (32% of the U.S. total) — the Clean Power Plan will give the Obama administration a platform for urging other nations to cut their emissions at a United Nations climate change conference in Paris in December.

“I am convinced that no challenge poses a greater threat to our future and future generations than a changing climate,” Obama said in a 25-minute speech that was frequently interrupted by applause from supporters.

Obama also quoted the observation of Washington Gov. Jay Inslee: “We’re the first generation to feel the impact of climate change and the last generation that can do something about it.”

“We only get one planet,” Obama continued. “There’s no plan B.”

What Changed in the Final Rule?

The Environmental Protection Agency made a number of significant changes to the final Clean Power Plan based on feedback to the preliminary plan released last year. Here is a summary of the most important changes:

  • Sourcespecific CO2 emission performance rates: The plan uses two different CO2 emission rates to define the “best system of emission reduction” (BSER), one for coal-steam and oil-steam plants and a second for natural gas plants.
  • Rate and massbased state goals: The plan uses the CO2 performance rates to set both rate‐based (CO2 lbs/MWh) and mass‐based goals (total CO2 metric tons) for states. The draft rule used only rate-based targets; the mass-based targets were added to accommodate states that want to take part in emissions trading.
  • Energy efficiency building block eliminated: The final plan eliminates building block 4, relying on demand‐side energy efficiency, reportedly due to concerns it might be unenforceable: utilities can’t control their customers’ efficiency. “EPA nonetheless anticipates that, due to its low costs and potential in every state, demand‐side EE will be a significant component of state plans,” the agency said.
  • Refinements to the three remaining building blocks:
    • Building block 1: Improved efficiency at power plants. EPA originally proposed heat rate improvements of 6% for coal and oil generators, which industry officials said was unachievable. The final rule anticipates improvements of 2.1 to 4.3%, depending upon the region.
    • Building block 2: Shifting generation from higher emitting coal to lower emitting natural gas power plants. The final rule assumes natural gas plants will run at 75% of net summer capacity. The draft expected natural gas units to run at 70% of their nameplate capacity, a metric that many commenters said was incorrect because it doesn’t reflect real operating conditions.
    • Building block 3: Shifting generation to zeroemitting renewables. The final BSER analysis does not include existing or under‐construction nuclear power or existing utility‐scale renewable energy generation as part of building block 3. EPA expects a bigger role for renewables than originally proposed “based on up‐to-date information clearly demonstrating the lower cost and greater availability of clean generation than was evident at proposal. It takes into account recent reductions in the cost of clean energy technology, as well as projections of continuing cost reductions.” Generation from under‐construction nuclear facilities and nuclear plant uprates can still be incorporated into state plans and count towards compliance. “Nuclear power competes well under a mass‐based plan, as increased nuclear generation can mean that fossil fuel units are operating less and emitting fewer tons of CO2,” EPA said.
  • Grid reliability measures: States must show they have considered reliability in developing their compliance plans, “such as consultation with appropriate state reliability or planning agencies.” To address unexpected reliability concerns, states can amend their approved plans or seek temporary relief under a reliability safety valve.
  • Tradingready mechanisms: In response to concerns that requiring formal, up‐front agreements between states would deter use of trading as a compliance mechanism, the final rule allows states to design rate‐based or mass‐based trading-ready plans permitting individual power plants to use out‐of‐state reductions to achieve required CO2
  • Clean Energy Incentive Program: EPA will reward states making investments in renewable energy and demand‐side energy efficiency projects implemented in low‐income communities during 2020 and 2021 by awarding them emission rate credits (ERCs) or allowances.
  • Relaxed initial deadlines: The plan allows states a two‐year extension to submit compliance plans. By September 2016, states must submit either a final plan or an initial plan with a request for an extension to September 2018. Initial compliance goals will go into effect in 2022, not 2020.

Company Briefs

Well, that didn’t take long.

PeoplesGasSourcePeoplesThe new owner of Peoples Gas, WEC Energy Group, told the Illinois Commerce Commission that it has fired the contractor in charge of the natural gas main replacement project in Chicago — this after the project’s price has quadrupled to $8 billion.

WEC Energy Group, formed after Wisconsin Energy purchased People’s Gas parent Integrys Energy Group, said that Jacobs Engineering Group was no longer in charge of the accelerated gas main replacement project. It shouldn’t come as a surprise, though. One of the conditions the ICC placed on its approval of the acquisition was a promise that WEC take firm control of the problem-plagued project.

When the project was first unveiled in 2009, Peoples said the cost of replacing about 2,000 miles of pipe over 20 years would be about $2.2 billion. The ICC approved a customer surcharge to finance the replacements. The cost estimate then went up to $2.6 billion, and then $4.6 billion. When the ICC sought more information in June from Peoples’ management, top managers called before the commission were unable to provide any firm guidance. That management team has since largely been replaced.

More: Crain’s Chicago Business

Wildfires, Market Shifts Cutting Rail Traffic to Delaware Refinery

Delaware City Refinery (Source: PBF)The number of tank cars delivering crude to the Delaware City Refinery has been cut in half because of wildfires in the west and shifting markets, according to the refinery’s owner. The refinery received an average of about 125,000 barrels per day during the first quarter of the year, according to Tom Nimbley, CEO of PBF Energy, which owns the facility on the banks of the Delaware River near Delaware City. In the second quarter, that number dropped to about 60,000 barrels per day.

Nimbley said North American crude oil — the type it receives by rail from the Midwest and Canada — has become too expensive compared with crude it can receive by water from other sources. “Factoring in transportation costs, it is plainly evident that these barrels cannot find an economic home on the East Coast, or a lot of other places” at current price levels, Nimbley said during a conference call with analysts.

Nimbley said rail deliveries could continue to fade, to 45,000 to 50,000 barrels per day, if the same market conditions persist. “We buy our crude basically two to three months early, so the crude we’re running in the third quarter is based on prices that exist in the second quarter, and those prices did not support rail economics,” Nimbley said.

More: The News Journal

Elon Musk’s SolarCity now has 250,000 Customers

SolarCitySourceSolarCitySolarCity, the solar development and financing company run by Tesla CEO Elon Musk, reported strong results in its second-quarter earnings, saying it booked 395 MW of solar projects and installed 189 MW. That’s a healthy rise from the previous quarter, when the company booked 237 MW and installed 153 MW.

SolarCity also said it produced 1.25 TWh of energy in the quarter. Through the end of the quarter, the company had installed 1,418 MW, an increase of 86% over the same period in the previous year, and said it had a total of 262,495 customers. The company said favorable regulatory rulings in California and Arizona contributed to its success.

More: Greentech Media

Duke Energy Progress Completes NCEMPA Asset Purchase

RTO-Duke EnergyDuke Energy Progress has completed the purchase of North Carolina Eastern Municipal Power Agency’s generating assets for $1.25 billion. The purchase includes ownership of about 700 MW of generation at Brunswick Nuclear Plant Units 1 and 2 in Brunswick County, Mayo Plant in Person County, Roxboro Plant Unit 4 in Person County and the Harris Nuclear Plant in Wake County.

The sale gets NCEMPA out of the generation business. It has entered into a 30-year power purchase agreement with Duke.

More: Duke Energy

SunEdison: NASCAR’s Official Solar Partner

SunEdisonNASCARSourceSunEdisonSunEdison has been named the “Official Solar Energy Partner of NASCAR Green.” The partnership intends to build on the expanded use of solar technology at race-team shops and race tracks across the country.

“Our strategic partnership with SunEdison will help NASCAR further reduce the sport’s environmental impact and help continue to educate our fans on renewable energy,” said Steve Phelps, NASCAR’s chief marketing officer.

NASCAR says a study it commissioned in 2014 found that four out of five NASCAR fans believe the earth is going through a period of climate change, and that two out of three of those fans feel a personal responsibility to do something about it.

More: The St. Louis Post-Dispatch

Xcel Energy Supports Large-Scale Solar Projects

Fowke
Fowke

Xcel Energy CEO Ben Fowke said last week that the Minneapolis-based utility supports development of large, attractively priced solar power projects, but it will keep pushing to limit more costly rooftop and subscriber-based community solar gardens. Xcel recently won approval from Minnesota regulators to develop its first three utility-scale projects in the state, the largest of which will generate 100 MW.

Fowke said recent studies have confirmed that large solar development “is far more cost-effective for consumers than smaller applications” and solar policy needs to be based on “sound economics.”

“While solar gardens and rooftop solar have a place in our portfolio as an option for consumers, because they require heavy, heavy subsidization of non-participants, you’ll continue to see us advocate that the primary focus be utility-scale solar so that we can keep energy costs affordable for consumers,” Fowke said.

More: Minneapolis Star Tribune

AEP Texas Names New President, COO

Evans
Evans

American Electric Power has named Bruce Evans as the new president and chief operating officer of AEP Texas. He is replacing Wade Smith, who is now senior vice president of grid development for AEP Transmission. Evans was vice president of distribution operations for AEP Texas.

Evans has a bachelor’s degree in finance from Hardin Simmons University in Abilene and a master’s degree in finance from Dallas Baptist University. He also attended the Advanced Management Program at Harvard University. He has built his career in utilities, spending the first 21 years at West Texas Utilities, Central Power & Light, Central & South West and AEP. He was president and CEO of the former CPL from 1996 to 1998.

More: Alice Echo

Shell Starts First Arctic Well in Chukchi Sea

ShellSourceWikiAfter a failed attempt at Arctic exploration last year, Royal Dutch Shell plunged a drill bit into the mud at the floor of the Chukchi Sea. The exploratory well will be Shell’s first action in the search for oil reserves that may measure in the billions of barrels. And even as the first well was being drilled, protests against Shell’s Arctic explorations continued. The icebreaker Fennica — in Portland, Ore., for repairs after gashing open its hull — steamed past protesters on its way to join the rest of the marine drilling fleet.

Shell is betting big on this Chukchi Sea attempt, but it is racing the clock as winter is already starting to bear down on the drill site. A previous attempt had to be halted when an iceberg drifted toward a drill ship in 2012.

But Shell said it is committed to this year’s attempt, and for good reason. The Arctic prospect “has the potential to be multiple times larger than the largest prospects in the U.S. Gulf of Mexico, so it is huge,” CEO Ben van Beurden said. But its potential is also far off. “If, indeed, we do find oil, and if we find an acceptable path to develop it, it will start to produce in 2030,” he said.

More: Associated Press; FuelFix

EDP Renewables Planning to Build 250-MW Wind Farm in Maine

EDPRenewablesSouroceEDPEDP Renewables has applied to build a 119-turbine, 250-MW wind farm near Bridgewater, Maine. If the Spanish company’s first project in the state gains approval and is built, it will eclipse what is now the largest wind facility there, the 185-MW SunEdison wind farm now under construction near Bingham.

EDP is proposing to build a 50-mile transmission line to connect the project to the regional power grid. In order to quiet opposition, EDP has already promised up to $2 million in energy efficiency projects for area residents and businesses.

More: Bangor Daily News

Clean Line Energy Asks Missouri PSC to Reconsider Nixed Project

CleanLineSourceCleanLineClean Line Energy Partners is asking the Missouri Public Service Commission to give it another chance to get a permit to build a $2.2 billion transmission line that would run from Kansas wind farms to markets in the east. The PSC denied a permit to the Grain Belt Express project in July.

“The project is too important to Missouri’s energy future not to pursue,” a company official said. The transmission line would run from Dodge City, Kan., across Missouri, through Illinois, to a substation in Indiana. Three of the commission’s five members voted against the project, questioning whether the line was needed to help Missouri meet its renewable energy mandate by the 2021 deadline.

More: Kansas City Star

UIL Invests in Northeast Energy Direct Pipeline

UIL Holdings will invest $80 million in the Northeast Energy Direct natural gas transmission line project being proposed for New York, Massachusetts and New Hampshire. The investment will give UIL a 2.5% ownership stake in the pipeline project proposed by Kinder Morgan. Plans call for the natural gas transmission line to extend 188 miles from upstate New York, through western Massachusetts and southern New Hampshire, before terminating in Dracut, Mass.

Construction of the $3 billion project is expected to start in 2017, with the pipeline becoming operational in November 2018. Northeast Energy Direct is part of a larger, 412-mile project that would bring natural gas from the Marcellus Shale deposits of north-central Pennsylvania to the population centers in southern New England.

Michael West, a UIL spokesman, said the company’s deal with Kinder Morgan gives it the opportunity to purchase an even larger ownership stake in the transmission line project.

More: New Haven Register

SPP BoD/Members Committee Briefs

KANSAS CITY — SPP’s Board of Directors/Members Committee last week voted to approve moving the deadline for day-ahead market offers up 90 minutes to 9:30 a.m. CT following continued debate over costs and tradeoffs.

The Members Committee approved the motion 8-5, with six abstentions. The board vote is not public, but Chairman Jim Eckelberger took the somewhat unusual step of ensuring that the board and Members Committee quickly knew the motion had passed.

The measure passed the Markets and Operations Policy Committee and other stakeholder groups with similar splits. Some members questioned the expense and effort to implement a small change. Members from SPP’s northern footprint have complained that the adjustments do little to increase the knowledge of day-ahead prices. (See SPP Members Reluctantly OK Day-Ahead Change.)

The change is intended to comply with the Federal Energy Regulatory Commission’s Order 809, which moved the timely nomination cycle deadline for gas to 1 p.m. CT from 11:30 a.m. and added a third intraday nomination cycle.

Assuming FERC approval, SPP will post day-ahead results at 2 p.m. CT, up from 4 p.m. It also shortens the reoffer period to 45 minutes, with reliability unit commitment (RUC) offers due at 2:45 and results posted by 5:15.

SPP faces an Aug. 4 compliance filing deadline with FERC. “If we don’t pass this, we will have to say why we can’t comply,” Carl Monroe, SPP’s chief operating officer, said before the votes. “And I’m not sure I can defend that.”

SPP staff has estimated it will take $1.5 million and 14 months to implement the changes, which will require new software. Staff suggested including that work with the Enhanced Combined Cycle (ECC) project.

Bruce Rew, SPP’s vice president of operations, noted that both projects improve the market-clearing engine’s functionality. “We would be working both together in the same project, because both are focused on improving solution time,” Rew said.

Board Backs Change to ARR Allocations

The board also approved the MOPC’s recommendation to change the annual auction revenue rights allocation system capacity to better match the annual transmission congestion rights (TCR) auction and reduce underfunding.

The board agreed with the MOPC’s recommendation to change the percentage for ARR allocation from the original 60% of system capacity to 80% for the seasonal or shoulder months. The percentages are unchanged for June (100%) and July to September (90%).

Those pushing the 60% allocation for seasonal months said it was an aggressive number and would solve the TCR markets’ underfunding problem, but they recognized it would cause problems for some market participants.

“I think the members said at MOPC that by going down to 60%, you are masking all the other issues,” Xcel Energy’s Bill Grant said.

The revision will settle or convert all annual ARRs during the annual process. No ARRs would be carried forward, and infeasible TCRs would be reduced. All residual capacity would still be allocated and auctioned in monthly processes.

Out-of-Bandwidth Projects Ordered Re-Evaluated

Continuing a discussion that began at the MOPC meeting two weeks earlier, the board put seven over-budget transmission projects on hold, ordering them to be brought back to the board in January following “proper evaluations.”

The seven projects were initially estimated by a third-party consultant to cost $62.8 million as part of the 2015 Integrated Transmission Planning 10-Year Assessment (ITP10). After the projects’ notices to construct (NTCs) were issued, additional study by the members revealed the projects’ cost would come to $147.7 million. (See SPP Frustrated over Transmission Project Overruns.)

The projects were among those filtered out of the 30 committed projects resulting from the ITP10 and near-term planning processes. Only four projects came within a 30% variance “bandwidth,” with 23 exceeding that threshold and three projects coming in below.

spp

SPP staff brought seven of the largest above-estimate projects to MOPC, which recommended suspending NTCs for three of the projects and moving forward with the other four.

But the board overruled MOPC in ordering all seven restudied. NTCs are decisions for the board, Director Julian Brix said.

“The board giveth, the board taketh away,” he said. “There’s too much differentiation in these projects. This is about the board’s fiduciary responsibility.”

SPP Vice President of Engineering Lanny Nickell said his staff conducted interviews with the transmission owners granted NTCs. The feedback indicated material and labor costs were similar, but the third-party consultant had not taken into account individual design standards, rebuilding aging facilities, unforeseen substation work or building through wetlands or other sensitive areas.

“We didn’t ask the right questions,” Nickell said. “We didn’t have adequate information during the planning process.”

Nickell said transferring study responsibility to the third party, a compressed timeline and dealing with competitive information also contributed to the variances.

“The third party did a horrible job,” said Kelly Harrison, president of Westar Energy’s Prairie Wind Transmission. “All they had to do was ask. There wasn’t anything about the project that … we wouldn’t have shared with them.”

SPP was able to allay the concerns of American Electric Power and others that the re-evaluations would change the projects’ reliability or economic needs, and with it, cost allocations. Stuart Solomon, president of AEP’s Public Service Co. of Oklahoma, noted AEP is responsible for four of the seven projects, “all reliability rebuilds based on need.”

“I don’t feel the existence of the variance is a reason to suspend and re-study,” Solomon said during the discussion. He eventually supported the board’s decision, with the hopes SPP could “strive” for the October MOPC and board meetings.

Nickell said staff would be able to meet the board’s timeline, using detailed project proposals already in hand. AEP’s Linwood-South Shreveport 138-kV line rebuild has a 2017 need date, but Nickell said a mitigation plan is in place, should there be further delays.

No Raise in Administrative Fee Expected

Finance Committee Chairman Harry Skilton said the RTO expects its administrative fee for 2016 to be between 37 cents/MWh and 38 cents/MWh, consistent with the 2015 budget’s forecast.

The fee is currently 38.1 cents/MWh, having jumped about 15 cents since 2011 to pay for the Integrated Marketplace.

Skilton noted several factors that could affect the fee: 2015’s monthly peak loads, which are running 5% below 2014’s; the costs of complying with version 5 of the Critical Infrastructure Protection reliability standard; and the costs of improving combined-cycle functionality.

Date Change for Walkemeyer Project RFP

The board approved a staff recommendation to change a key date in its first competitive solicitation under Order 1000, the Walkemeyer-North Liberal project in Kansas.

General Counsel Paul Suskie said the change “mitigates a flaw in the process” by moving the “regulatory approval need date” eight months from the NTC’s issuance.

The SPP Tariff requires the need date be included in a competitive upgrade’s request for proposals to identify when an entity must have gained utility status in the state where the facility will be built. The change would meet a Kansas Corporation Commission statutory obligation to rule on such requests within 180 days of the initial filing and give the winning entity “reasonable time” to gain utility status in the state.

The board approved the 21-mile, 115-kV Walkemeyer project in April. The RFP was issued in May, with responses due Nov. 2. (See SPP Issues RFP for 115-kV Transmission Project.)

The original regulatory approval date was June 1, 2016. The board approval moves that date to Jan. 1, 2017. Changing the date gives RFP respondents sufficient time to finalize their work, Suskie said.

Suskie said staff would work with the Competitive Transmission Process Task Force to develop new policy setting to ensure future RFPs include a date that is reasonable and allows for the SPP process to work as designed.

New Member Process, Document Approved

The board approved a Strategic Planning Committee task force’s recommendations on improving the process of wooing prospective members to join the RTO.

The board first added several modifications to those offered the previous day by the Regional State Committee to a document outlining triggering mechanisms for when communication and work-group processes to be followed during negotiations with prospective members would apply.

The task force report notes that SPP’s staff “remains solely responsible for the direct negotiations with the prospective member” while stakeholders provide input on policy and changes to the governing documents.

SPP Seeks Larger Board

CEO Nick Brown said SPP has filed with FERC modifications to the bylaws that would allow up to three additional directors. He said the Corporate Governance Committee will be evaluating the results of an RFP to conduct a search for board candidates, the first such search SPP has conducted in seven years. The committee will discuss the issue further during its Aug. 27 meeting.

Competitive Tx Task Force Extended

The board approved extending the Competitive Transmission Process Task Force’s charter through 2016 and endorsed the group’s Load Responsible Entity concept. Golden Spread Electric Cooperative’s Mike Wise, chair of the Strategic Planning Committee, said the task force intends to bring a “full package” of recommended improvements to the MOPC in January. (See “Load Responsibility White Paper” in SPP Strategic Planning Committee Briefs, July 20.)

Two New Members

SPP welcomed its two newest members during the meeting: the Tri-State Generation and Transmission Association and Harlan Municipal Utilities. The additions increase SPP’s membership ranks to 92.

Tri-State Generation is a wholesale electric power supplier owned by the 44 electric cooperatives that it serves. The association generates and transmits electricity to its member systems throughout a 200,000-square-mile service territory across Colorado, Nebraska, New Mexico and Wyoming.

Harlan provides electricity, gas, water and telecommunications to a city of more than 5,100 in southwestern Iowa.

Special Guest

FERC Commissioner Cheryl LaFleur was among those sitting in the board’s inner circle. “I’m here to listen,” said LaFleur, who was in the area for Clean Power Plan-related hearings.

— Tom Kleckner

Dynegy: Complaints about MISO Auction ‘Fatal’

By Chris O’Malley

Dynegy told federal regulators last week they should reject complaints over its bidding in MISO’s capacity auction last April, saying the challenges suffer from a “fatal” procedural flaw.

In May, the Illinois Attorney General and Public Citizen filed complaints asking the Federal Energy Regulatory Commission to investigate Dynegy’s behavior in the Planning Resource Auction, which resulted in a nine-fold price increase for Zone 4 (EL15-70). Several other market participants, including Southwestern Electric Cooperative, also have filed protests over the results.

Dynegy, which has the commanding share of capacity in Zone 4, has previously denied there was any manipulation or underlying flaws in the MISO auction. (See Dynegy: No Evidence of Misconduct in Auction.)

In a July 30 filing, Dynegy said efforts by Illinois Attorney General Lisa Madigan to retroactively change the results of the auction “run squarely afoul” of previous FERC decisions.

Precedent Cited

The company cited a 2008 challenge by the Maryland Public Service Commission over PJM capacity auction results. The commission ruled that it would not invalidate results of completed capacity auctions that were conducted in accordance with approved market mitigation measures and were deemed by an independent market monitor to be competitive.

“So too here: because the complainants in these cases have not alleged that MISO violated its Tariff, and because [MISO Market Monitor David Patton] has confirmed that the results of the [auction] were competitive, the complainants’ challenges to those rules fail as a matter of policy,” Dynegy told FERC.

Dynegy said that although the attorney general wants the auction retroactively invalidated, “it never alleges, much less substantiates, any violation of the MISO Tariff.”

The company also said that Southwestern, which filed a complaint alleging that the auction results were unreasonable, also fails to show that MISO violated its Tariff.

“The complainants’ failure to clear that hurdle was fatal from the outset. Their more recent continued silence on the point only serves to underscore that failure,” Dynegy told FERC.

Changes to MISO Auction Sought

Last month Madigan joined industrial consumers and Southwestern in calling for changes to MISO’s capacity auction rules. (See Illinois Attorney General Joins Call for Changes to MISO Auction Rules.)

NYPSC Outlines Reforming the Energy Vision Changes

By William Opalka and Rich Heidorn Jr.

New York regulators last week began to sketch out the details of their ambitious Reforming the Energy Vision (REV) initiative with a white paper on rate design that seeks to upend business models that have been in place for more than a century and establish the state as a leader in the shift to distributed energy resources (DER).

The New York Public Service Commission staff straw proposal is intended to address the “discontinuity” between traditional cost-of-service regulation and the “multi-sided” market envisioned in Reforming the Energy Vision, with customers that are also producers and utilities that also serve as “platforms” for vendors offering services that help consumers reduce or time-shift their energy use.

That means utilities will see less of their earnings from centralized generation and returns on capital investments and more on service revenue and incentives tied to energy reductions, reducing transaction costs and increasing the volumes of DER, such as rooftop solar, microgrids and storage.

“The ratemaking paradigm must create alternatives to the current financial and institutional incentives and provide opportunities for utilities to earn from activities that achieve their service obligations in a manner that supports reductions in the total customer bill,” the paper says.

“The intent of REV is to harness markets to achieve innovative and cost-effective solutions, with utilities facilitating those markets both in their system planning and in day-to-day operations. Financial incentives and economic signals must be in alignment with this goal.”

reforming the energy vision

In February, the PSC issued its “Track 1” order that created a framework for the shift from centralized generation to a customer-centric market that encourages adoption of clean distributed energy resources. The commission said that business as usual is no longer a viable option for utilities in meeting their statutory responsibilities to New Yorkers. (See New York PSC Bars Utility Ownership of Distributed Energy Resources.)

Last week’s white paper will be the foundation for an anticipated “Track 2” order on ratemaking changes. “Track 2 looks closely at how we’re going to align the utility investment earning capacity with customer value,” Anthony Belsito, a policy advisor for the PSC, told the Infocast New York Reforming the Energy Vision Summit last week. (See related story, Public Helping Drive New York REV Agenda.)

Gradualism

The paper said that changes to rate design formulas must not cause large, sudden increases in customer bills. And this “gradualism” should also apply to industries such as solar and energy efficiency providers, it said. “Any changes affecting these industries should provide ample time for businesses to adapt and plan for new forms of opportunity.

“For the same reason, rate design changes should be oriented toward investments going forward, versus investments already made. To the extent possible, customer investments already made under assumptions of a program such as [net energy metering (NEM)] should not be disrupted.”

The report says concerns about the impact of NEM on utility earnings are “inconsequential” at current penetration levels.

“Input from the DER industry makes clear that the simplicity and predictability of NEM is very important in engaging customers and providing certainty to investors. Staff does not believe that there is any value in changing NEM for mass-market customers with on-site [distributed generation] at this time.”

Granularity vs. Simplicity

One of the challenges observed by the PSC is the conflict between increasing granularity in cost allocation and maintaining simplicity in billing, particularly for residential customers. That, the staff said, is where aggregators can play an important role. “Customers themselves may not need to see complex rates if a service provider or aggregator sees and manages complexity for them,” it said.

LMP+D

The paper proposes a new method for calculating the value of DER: adding a distribution component (“D”) to the wholesale LMP pricing (location-based marginal price of energy, as New York refers to it).

“The current convention of crediting at the average retail rate may be either too little or too much based on the nature of the resource and its location,” the paper says.

reforming the energy vision
Click to zoom.

The value of D can include load reduction, frequency regulation, reactive power, line-loss avoidance and resilience.

The PSC plans to develop ways to calculate LMP+D in proceedings involving utilities and DER providers. Staff called for the state’s utilities to adopt software to determine distribution-level marginal costs.

LMP+D can incent net-metered facilities to install smart inverters that can increase the amount of solar generation that can safely be interconnected to a circuit. Staff said the commission should consider requiring smart inverters on future net-metered projects.

While the valuation of DER should vary by location, the paper says, customer charges should remain indifferent to location.

Customers participating in a utility demand response program or exporting power to the grid should receive compensation based on LMP+D, staff said.

Customers who supply only a portion of their electricity and do not participate in a utility program would receive no significant credits from their utilities. “In this circumstance, even when the ‘value of D’ as a service to the grid can be calculated, the reduction of the customer’s bill should continue to be based on the average cost of service. That is, NEM as it is currently constructed should remain applicable.”

Reforming the Energy Vision Rate Design

The paper proposes several additional changes:

  • Demand Charges — The paper proposes “for comment and further development” the concept of replacing part of the kilowatt-hour and fixed customer charges with a peak-coincident demand charge. “Because long-run distribution marginal costs are driven by coincident peak on a circuit-by-circuit basis, customers’ usage at system peak provides the most accurate measure of system costs. And, unlike fixed customer charges, peak demand can be managed by customers via DR, energy efficiency and/or DG,” staff said. Fixed customer charges should reflect only the costs of distribution that do not vary with customer demand.

“This change is not proposed as a mere reallocation of costs among customers,” the paper said. “It is proposed as part of a broader strategy to reduce long-term system infrastructure needs, encourage the optimal development of DER, discourage uneconomic bypass of the distribution system and maintain affordable rates for all customers.”

  • Time-of-Use Rates — The paper says utilities should develop time-of-use rate demonstration projects and offer technologies that have been shown to increase peak reduction savings, such as in-home displays, “energy orbs” and programmable and communicating thermostats. The paper cites studies showing TOU rates resulting in peak reductions as high as 47%. “Peak load reduction impacts are seen to increase as the peak to off-peak price ratio in TOU rates increases,” it added.
  • Smart Home Rate — The PSC said early-adopter consumers should be able to opt in to new rate structures. “A gradual approach to changes in mass-market rates should not prevent customers who are willing and able to begin participating in energy markets as active consumers from doing so.”
  • C&I Rate Design — While rates for commercial and industrial customers are more advanced than for mass-market customers, the report calls for additional improvements, saying demand rates should be more precise and reflect the time of energy use. “Current non-coincident demand rates can have the effect of inhibiting a customer from shifting load to off-peak times,” it says. “For example, a customer investing in storage to purchase off-peak power and utilize it at peak times might face an increased demand charge due to the shift in usage to the off-peak time.”

It called for utilities to examine their C/I rates and propose improvements in their next rate filing.

  • Standby Service Tariffs — Standby rates, which apply to large customers that generate much of their power on-site and use the distribution grid as a backup, can be another barrier to DER. The PSC recently expanded an exemption from standby rates for four years while it studies rate design changes. Standby rates are related to net metering and to the general rate design issue of fixed versus variable rates, the report notes. “In each case, the responsibility of a customer for the cost of the customer’s reliance on the distribution grid is at issue,” the staff said. “The cost of remaining connected to the grid should generally be lower than the cost of building redundancy and independence into a self-generation system.”

SPP Regional State Committee Briefs

KANSAS CITY — SPP General Counsel Paul Suskie briefed the Regional State Committee last week on several seams and interregional issues. At times, however, he could say little.

Stressing the confidentiality of settlement negotiations with MISO over its use of a 1,000-MW contract path between its North and South regions, Suskie said, “I can say all parties are extremely close to a settlement. Hopefully, that will be resolved in the near future.”

Suskie said settlement negotiations also are ongoing with five seams neighbors who were among those intervening or filing protests with the Federal Energy Regulatory Commission regarding Tariff and bylaw changes to accommodate the Integrated System: Missouri River Energy Services, Montana Dakota Utilities, Municipal Energy Agency of Nebraska, Montana Consumers Council and Otter Tail Power.

spp
SaskPower assets (click to zoom).

Suskie said the issues are not a roadblock to the Integrated System’s incorporation. “If these negotiations aren’t resolved, they will simply be referred to hearing,” he said.

With the Integrated System’s full incorporation, SPP will create a northern seam in North Dakota. Suskie said the interconnection will be limited, consisting of a 230-kV line with Saskatchewan utility SaskPower. SaskPower will be SPP’s first international market participant.

Interregional Projects

Suskie also briefed the committee on SPP’s interregional projects with MISO. The projects, all recommended for approval by a joint SPP-MISO study, include construction of a 345-kV line between Nebraska and Kansas, a series reactor on a 115-kV line in northeast Louisiana, and the rebuild of a 138-kV line south from Shreveport to Wallace Lake.

The projects are now going through each RTO’s regional-review process; SPP completed its in time for the April board meeting. The largest, the 78-mile, 345-kV Elm Creek-NSUB construction project, has an estimated cost of $140.6 million. Because SPP will receive 80% of the project’s benefit, Suskie said, it will pick up 80% of the costs, which will be allocated under the RTO’s highway/byway allocation process. (See 3 MISO-SPP Transmission Projects Move Forward.)

Integrated Marketplace Performing Well

Bruce Rew, SPP’s vice president of operations, delivered a one-year update on the Integrated Marketplace, saying its system availability has exceeded expectations, with the real-time balancing market successfully solving 99.95% of all its five-minute intervals.

He said the market had been delayed from posting just twice — once in June 2014 due to a modeling issue and again in December when a software problem affected participants’ ability to submit offers.

SPP’s balancing authority has maintained compliance with North American Electric Reliability Corp. standards, Rew said, and capacity overage has been reduced from the previous energy imbalance service (EIS) market. The EIS market’s final two months, January and February 2014, averaged more than 6,000 MW of un-dispatched capacity. The Integrated Marketplace has exceed 3,500 MW just once.

The Integrated Marketplace went online with 103 market participants. There are now 148 participants, with 98 classified as financial-only and 50 as asset-owning. The EIS market, by contrast, had only 50 participants.

SPP is currently testing improvements to its market-clearing engine performance and day-ahead reliability unit commitment process.

Bylaws, Waiver Request

The RSC also accepted recommended changes to its bylaws, reviewed updates from the July Markets and Operations Policy Committee meeting and approved SPP’s recommendation to reject Kansas City Power and Light’s waiver request to revise a transformer’s voltage level for cost-allocation purposes.

— Tom Kleckner

State Briefs

Superior Court Directs Suit Against Delmarva to PSC

A class-action challenge to Delmarva Power and Light will be heard by the Public Service Commission after a Superior Court judge ruled that the court doesn’t have jurisdiction. William Whipple III filed the case against the state’s largest utility, arguing that its Bloom Energy Servers program consumes more natural gas than Delaware’s Coastal Zone Act allows. The result, Whipple said, is higher, rather than lower, bills for customers.

But Superior Court President Judge Jan Jurden said the issue comes under the state’s Qualified Fuel Cell Project tariff, which is overseen by the Public Service Commission. The Bloom Energy fuel cell program is partially subsidized by Delmarva customers.

“Plaintiff’s claim for ‘unjust or unreasonable rates’ is a challenge to the QFCP tariff, a regulatory policy which falls within the PSC’s exclusive jurisdiction,” she ruled.

More: Delaware Law Weekly

ILLINOIS

New Calculator Helps Residents Shop for Cheaper Power

Residents have a new free calculator at their disposal to help them save money in the electric market.

The Citizens Utility Board created the CUB Power Deal Calculator to help residents learn what they would pay with an alternative electric supplier compared with their regulated utility, Commonwealth Edison or Ameren.

From 2010 to 2013, when ComEd was locked into higher-priced contracts, it was simpler for consumers to find better deals. Now, however, the last of those contracts has expired.

A June report by the Commerce Commission’s Office of Retail Market Development indicated that ComEd is likely the best deal in the current market. The ICC report found that over the last year, those who got their power from ComEd saved $73 million compared with customers who signed up with an alternative electric supplier.

The calculator can be used for individual plans or deals negotiated by communities.

More: Rock River Times

MASSACHUSETTS

Gov. Baker Poised to Introduce Solar Bill

Baker
Baker

Gov. Charlie Baker said last week that his administration is ready to introduce legislation that is expected to address caps on solar power net metering, a hot issue in the state these days. Baker and state officials offered few details of the proposed legislation, saying only that it would build “upon the success and continued growth of Massachusetts’ solar industry while ensuring a long-term, sustainable solar program that facilitates industry growth, minimizes ratepayer impact and achieves our goal of 1,600 MW by 2020.”

The promise of further legislation comes after the Senate approved a bill that raises the solar power net metering cap to 1,600 MW. But the bill was criticized by an industrial users group. Associated Industries of Massachusetts said it would provide a subsidy that “could add as much as $600 million to the electric bills of Massachusetts consumers, businesses and institutions.” The group said the bill benefits only those who are able to install solar facilities, at the expense of those who can’t.

More: MassLive

MINNESOTA

PUC Approves $125 Million Upgrade to Crude Pipeline

MinnesotaPpinebendRefinerySourcePinebendThe Public Utilities Commission approved a $125 million upgrade to a crude oil pipeline that serves two refineries in Minneapolis. Minnesota Pipe Line asked for approval to build six new pump stations and to upgrade others along the 305-mile pipeline. The upgrades will more than double the pipeline’s capacity to 350,000 barrels per day.

Minnesota Pipe Line is co-owned by Flint Hills Resources, owner of Rosemount’s Pine Bend refinery; Northern Tier Energy, which owns the St. Paul Park refinery; and a third investor. The pipeline is operated by Koch Pipeline — like Flint Hills Resources, a unit of Koch Industries.

More: Star Tribune

NEW JERSEY

Small Hole Found, Filled in Protective Wall at Hope Creek

HopeCreekSourceWikiWorkers discovered a small hole in a protective wall at the Hope Creek nuclear plant last week, but the reactor — stored in a separate structure — was not compromised, according to PSEG Nuclear.

The 1-inch hole was noticed by workers about 2 p.m. Tuesday and was sealed within two hours. The opening was found inside a closed auxiliary building and did not open into the environment, the utility said. It said that the primary containment containing the reactor core and major safety systems were unaffected, and that operations were uninterrupted.

PSEG Nuclear spokesman Joe Delmar said the hole apparently dated to the original construction when concrete was formed and poured. “There are more than 100 of these holes. All of the other holes were filled with grout/filler material,” he said. “There is no evidence that there was grout/filler in this hole. We continue to investigate and determine if it may have been filled at one time and not refilled.”

More: The News Journal

NORTH CAROLINA

Report: Geothermal Industry Growing in State

NorthCarolinaSustainableSourceNCSEAA report just released by the North Carolina Sustainable Energy Association shows that geothermal energy is a growing industry in the state, generating $143 million in revenue in 2014 and accounting for about 3% of the state’s clean energy income. It says that since the North Carolina Renewable Energy Investment Tax Credit was extended to geothermal installations in 2009, more than 10,500 units have been shipped to the state.

The report also said that because of uncertainty surrounding the survival of the tax credit, geothermal installation growth stagnated in 2014. According to a survey conducted by the NCSEA, the tax credit was the single most important consideration among those who decided to install geothermal systems, with 92% of respondents saying it was a determining factor.

“Energy efficiency is the low cost, least risk resource and [geothermal heat pumps] are the most energy-efficient technology for satisfying the thermal loads of homes and buildings,” said Robert Rust, territory manager for WaterFurnace International.

More: North Carolina Sustainable Energy Association

NORTH DAKOTA

172-MW Wind Project Considered Again by PSC

A wind farm originally proposed by a California company whose ownership was transferred to a North Dakota firm is again up for consideration before the Public Service Commission. The Antelope Hills Wind Project, a $240 million, 172-MW wind facility, originally received a permit in December. Ownership transferred to SUNE North Dakota Holdings in April, and the company has to reapply for approval. A hearing is set for September to consider the project.

The wind farm would be constructed on 22,000 acres near Beulah. While the project still calls for 85 turbines, the location of some of the turbines has changed.

More: Bismarck Tribune

OHIO

Utilities Push Back on Net Metering

FirstEnergy and American Electric Power are challenging how much they must pay solar owners for excess power and how much of it they are required to buy back, now that there are nearly 1,600 solar arrays operating in the state.

The Public Utilities Commission is considering revising its January 2014 ruling limiting net metering to 120% of a user’s average monthly demand over the previous three years.

The two utilities also have taken their challenge to the state Supreme Court, but the court is waiting to rule until the commission reconsiders its position.

More: The Plain Dealer

FirstEnergy CEO Wants State Power Industry Re-regulated

RTO-FirstEnergyFirstEnergy CEO Chuck Jones would support state re-regulation of the electric utility industry “in a heartbeat,” he told The Plain Dealer. That’s after FirstEnergy fought seven years ago to have the industry deregulated, with electricity rates set by wholesale markets without influence from the state.

“I think it makes sense. I am trying to save a company,” he said.

In 2008, FirstEnergy was poised to prosper from coal-fired plants that provided some of the cheapest power in the state. Now, Jones said, FirstEnergy may not survive if it can’t convince the Public Utilities Commission to force ratepayers to cover the full cost of electricity from two of its huge coal and nuclear plants.

More: The Plain Dealer

PENNSYVLANIA

Talen Reaches Proposed Settlement on Coal Ash Spill

MartinsCreekSourcePPLTalen Energy, the company formed by the spinoff of PPL’s generation assets, has reached a tentative $1.3 million agreement with the Department of Environmental Protection that would cover damage caused by a 2005 coal ash spill at the Martins Creek Steam Electric Station. In August 2005, part of a retaining wall burst at a settling basin at the coal-fired plant, releasing about 100 million gallons of fly ash and water into fields and into the Oughoughton Creek and the Delaware River.

The settlement, which still needs to be approved by DEP after public comment, would result in Talen paying $1.3 million to settle all natural resource damage claims from the spill. PPL, then the owner of the plant, spent $37 million on the cleanup, including a $1.5 million civil settlement.

The coal units at the plant were retired in 2007. Talen Energy now operates three oil and natural gas units generating 1,700 MW at the site.

More: Lehigh Valley Live; Pennsylvania Department of Environmental Protection

RHODE ISLAND

First Offshore Wind Foundation Laid

DeepwaterWindSourceDeepwaterThe first 440-ton steel foundation of the nation’s first offshore wind farm rising from the Atlantic Ocean was lowered from an enormous crane in about 100 feet of water off Block Island. The project that developer Deepwater Wind is building points the way toward a clean energy future for the country, U.S. Interior Secretary Sally Jewell said.

“A place like Block Island, which could only burn dirty diesel fuel, now will have the opportunity for clean, renewable energy,” Jewell said as she stood at the bow of a ferry as it rocked in the swells off the tiny island. She was accompanied to the site of the five-turbine wind farm, about three miles southeast of Block Island, by Gov. Gina Raimondo, the state’s congressional delegation, and other public officials.

More: Providence Journal

VERMONT

Family Seeking Approval for Large-Scale Wind Project

A local family is gathering data with an eye toward developing a seven-turbine wind project on a ridge in Swanton.

The Belisle family is working with Vermont Environmental Research Associates to put together the plan before applying to the state for permission to build. The family has said it would like to begin construction by the end of 2016. When completed, according to Martha Staskus of Vermont Environmental Research, the 20-MW Swanton Wind farm would produce enough energy to power about 7,800 households.

In addition to gathering technical information for a feasibility study, the Belisle family is reaching out to neighbors and other community members to hear their concerns.

The project, however, is already facing some opposition. “The state has done absolutely nothing to recognize that this type of development causes tremendous harm to the environment and to the health and welfare of people living around the mountains,” said Annette Smith of the Danby-based group Vermonters for a Clean Environment. As a result of some complaints, a test tower is already being taken down.

More: Rutland Herald; Associated Press

Siting Task Force Studies Solar Growth

A panel created by the Legislature to study the growth of solar power in the state will meet for the first time this week. The Solar Siting Task Force was charged with reviewing the design, location and regulation of solar electric generation facilities, and is due to report back to lawmakers in January with recommendations.

A new renewable energy law established the 10-member panel and set a requirement that 55% of the power sold by energy companies come from renewable sources by 2017 and 75% by 2032. The state has a broader goal of getting 90% of its energy from renewable sources by 2050.

The task force is made up of state and utility officials, a landscape professional and a member of the general public. It is responsible for addressing concerns raised by some municipalities and others about the fast growth of solar power projects in the state.

More: Burlington Free Press

Study Quantifies Solar Energy’s Benefits

VermontAcadiaCenterSourceAcadiaA recent study by the Acadia Center says the value of solar power to the grid — and to ratepayers connected to the grid — ranges from 19 to 23 cents/kWh, with additional societal values of 7 cents/kWh.

“Solar generation is a valuable local energy resource that provides significant benefits to ratepayers,” said Ellen Hawes, Acadia’s senior analyst for energy systems and carbon markets. The study said solar provides value to the electric grid by reducing energy demand, providing power during peak periods and avoiding generation and related emissions costs incurred by conventional power plants. The study suggests the overall grid value of solar is the sum total of those various benefits.

In addition to the value that solar provides to the grid, Acadia’s study found that it provides broader societal benefits, including environmental gains from reducing greenhouse gas emissions and other pollutants.

FERC Denies Shetek Wind Reinstatement Request

By Chris O’Malley

The Federal Energy Regulatory Commission last week denied a request to reinstate a generator interconnection agreement terminated by MISO last year after a wind developer failed to make milestone payments.

The commission denied Shetek Wind’s request to rehear an order it issued last October accepting MISO’s termination of the GIA (ER14-2681).

That agreement, which included transmission owner Northern States Power, provided up to 146.6 MW of interconnection service to Northern States’ Garvin, Minn., substation.

In October, FERC found that Shetek failed to meet milestone payments under the GIA and that extending the milestones without assurance that the developer would meet its obligations would present “harm to lower-queued interconnection customers in the form of uncertainty, cascading restudies and shifted costs necessitated if the project were to be removed from the queue at a later date.”

Northern States parent Xcel Energy said that since signing the agreement in 2007, Shetek had made no progress toward development.

Shetek’s plan was to install up to 60 turbines near Tracy, Minn. In 2006, the developer reported that it had raised $470,000 in equity from almost 40 landowner-investors in the project’s targeted area.

The company was seeking an extension of time to make progress payments and argued that Northern States breached its obligations to act in good faith.

Shetek said FERC’s decision last year was not in the public interest because termination would frustrate Minnesota’s interest in supporting community-based projects.

But FERC noted that both the state’s Public Utilities Commission and its Court of Appeals found that Xcel was not required to give special consideration to the project.

Company Q2 2015 Earnings Roundup

amerenAmeren reported last week that earnings were flat in the second quarter, largely on milder temperatures that reduced demand for electricity.

The St. Louis-based company earned $150 million ($0.61/share) compared with $149 million ($0.61/share) in the same period last year. Operating revenues were $1.40 billion versus $1.42 billion last year.

Ameren said its results were buoyed by earnings from investment in electric transmission and delivery infrastructure, along with a lower tax rate.

The company raised its full-year earnings-per-share guidance slightly, to $2.48 to $2.68 from $2.45 to $2.65.

— Chris O’Malley

Lower Revenues Dim CMS Energy Profits in Q2

CMS Energy LogoSecond-quarter net income for CMS Energy fell 19% on a 8% decline in revenue, the company reported last week.

The Jackson, Mich.-based parent of Consumers Energy earned $67 million ($0.25/share) compared with $83 million ($0.30/share) during the second quarter of last year. Revenue was down to $1.35 billion, from $1.47 billion a year earlier.

Nevertheless, CMS reaffirmed its 2015 earnings-per-share guidance of $1.86 to $1.89, consistent with its goal of 5 to 7% annual adjusted EPS growth.

President and CEO John Russell said CMS is still on track to retire its seven oldest coal plants — amounting to one-third of its coal fleet — by next April. The units being shuttered are an average of 60 years old and will be replaced by gas-fired units.

Russell also said CMS will proceed with its first-ever utility-scale solar generating station. The 10-MW demonstration project will be evaluated for the potential of additional utility-scale units in Michigan.

— Chris O’Malley

Unfavorable Weather Cited in DTE Earnings Drop

dteDTE Energy’s second-quarter profits fell 12% on increased costs and unfavorable weather.

The Detroit-based company posted net income of $109 million ($0.61/share) compared with $124 million ($0.70/share) in the same quarter last year.

Operating earnings in DTE’s electric segment were down by $18 million, while the gas utility segment recorded a $3 million decline. Operating revenue for the company fell 15%, to $2.27 billion.

During a conference call, executives cited strong growth in the gas storage and pipeline business and in energy trading. As a result, DTE raised its 2015 operating EPS guidance to $4.54 to $4.90, from $4.48 to $4.72.

— Chris O’Malley

Eversource Q2 Earnings Jump 63%

eversourceEversource Energy said last week that the company’s second-quarter profits this year increased by nearly 63%, from $127.4 million ($0.40/share) in 2014 to $207.5 million ($0.65/share).

“We had an excellent first half of 2015, with financial performance consistent with our targeted 6 to 8% long-term earnings growth rate and our 2015 projected earnings of $2.75 to $2.90 per share,” Eversource CEO Thomas May said in a statement.

The company also said it is reviewing the recent Department of Energy draft Environmental Impact Statement for its Northern Pass transmission project. (See Price Tag Likely to Rise for Northern Pass Transmission Line.)

“We don’t believe it poses any unanticipated challenges to the construction of the project,” said Lee Olivier, executive vice president of enterprise strategy and business development. He added that plans for site approval will be filed with state officials in “early to mid-fall,” with review taking about one year.

— William Opalka

Exelon: Quad Cities Decision as Soon as September; Awaiting Pepco Decision from DC

earningsExelon CEO Chris Crane told analysts during the company’s quarterly earnings conference call that if Illinois legislators fail to pass a law that would essentially guarantee profits for its nuclear plants, the company may be forced to close its Quad Cities generator, with a decision coming as soon as September.

Crane and other company officials have long said that three of its six nuclear stations in Illinois are losing money on the wholesale market, primarily because low natural gas prices are pushing wholesale power prices down.

Even anticipated revenue boosts from PJM’s Capacity Performance program “will not be enough to keep all the units economically viable,” Crane said. The decision on whether to keep its Clinton nuclear station open — which bids into MISO and therefore is governed by different rules — won’t be made until the first months of next year.

“We don’t take the decision lightly,” Crane said. “We understand the effect that we have on the communities and potential effect on employees, but this has been a long-term issue that we’ve been evaluating and trying to come to a resolution [on], and we’re staying within the timeline.”

Exelon reported second-quarter earnings of $508 million ($0.59/share) compared with $440 million ($0.51/share) this time last year.

The company said profit rose due to higher sales and a hedging-related gain. Crane also credited strong financial performance by Exelon Generation.

Crane also said the company is prepared to quickly finalize its $6.8 million acquisition of Pepco Holdings Inc., pending approval by regulators in D.C. As the company awaits the ruling, expected late this month, it extended the deal’s termination date from July 29 to Oct. 29.

Pepco’s second-quarter earnings were flat compared with the same period in 2014, with net income of $53 million ($0.21/share).

“Increased operation and maintenance costs, primarily driven by the implementation of a new customer information system, impacted second-quarter results,” CEO Joseph Rigby said.

— Suzanne Herel

FirstEnergy Beats Expectations

RTO-FirstEnergyFirstEnergy beat its own expectations, reporting second-quarter net income of $187 million ($0.44/share) compared with $64 million ($0.16/share) for the same period last year, despite the fact that the company’s revenues stayed flat at $3.5 billion, the company said.

“We remain focused on implementing our regulated growth initiatives and our Cash Flow Improvement Project, which was launched in April,” CEO Charles Jones said in a statement. “I’m pleased that the opportunities we have identified as part of that project are expected to result in cash savings of $240 million by 2017, exceeding our original targets.”

Operating earnings for the Akron, Ohio, company’s regulated distribution business were flat compared with the same period last year, as the benefit of higher distribution revenues and approved rate cases was offset by higher operating expenses and a higher effective income tax rate.

The regulated transmission business saw higher transmission revenues, in part related to the company’s Energizing the Future plan to upgrade its grid.

The company’s competitive energy services benefited from lower operating expenses and a slightly higher commodity margin compared with last year.

— Suzanne Herel

PPL Posts Loss After Talen Spinoff

FERC Gives Conditional OK to Talen Energy.)

The company said the loss reflected a $1 billion hit from discontinued operations of the competitive supply business.

For the same period last year, PPL had reported net income of $229 million ($0.34/share).

Not taking into consideration the spinoff and some other accounting items, the utility reported second-quarter earnings of $329 million ($0.49/share), an 11% increase from adjusted earnings of $296 million ($0.44/share) for the same period in 2014.

The company also narrowed its 2015 forecast range from ongoing operations to $2.15 to $2.25 per share and increased its quarterly common stock dividend to $0.3775/share.

“Based on the strong performance of PPL’s seven regulated utility businesses in both the U.S. and the U.K., the continued rate base growth from our significant infrastructure investment and our solid business plan to grow earnings per share, we are increasing the midpoint of our 2015 earnings forecast,” CEO William H. Spence said in a statement.

“The new PPL Corp. — with its strong growth profile, a solid dividend and diverse mix of holdings — is a unique and very compelling investment option in the U.S. utility sector,” he said.

— Suzanne Herel

PSEG Q2 Earnings Up 62%

psegPublic Service Enterprise Group on Friday reported second-quarter net income of $345 million ($0.68/share) compared with $212 million ($0.42/share) for the same period in 2014.

“Our businesses performed well. [Public Service Electric & Gas’] expanded investment program is successfully translating into improvements in customer satisfaction at the same time operational improvements at PSEG Power supported increased output,” CEO Ralph Izzo said in a statement.

Operating earnings for PSE&G rose to $167 million ($0.33/share) from $151 million ($0.30/share) this time last year. The company attributed the boost to an expansion of its capital program, warmer-than-normal temperatures and a recovering economy.

Meanwhile, PSEG Power reported operating earnings of $110 million ($0.22/share) compared with $87 million ($0.17/share) this time last year.

The company said the results reflect improvement in operations of its nuclear and fossil fuel generating facilities, higher prices on its hedged energy output and a drop in the cost of its gas supply.

— Suzanne Herel

WEC Energy Group Erases $0.24/Share on Integrys costs

WECEnergySourceWECCosts related to its June acquisition of Integrys Energy put the squeeze on WEC Energy Group’s second-quarter profits.

Milwaukee-based WEC earned $80.9 million ($0.35/share), a 39% decline from $133 million ($1.04/share) in the second quarter of 2014. Excluding the acquisition costs, which cut EPS by $0.24, WEC would have reported EPS of $0.59.

Like many northern utilities, a cooler-than-normal June crimped electricity revenues. Operating revenues declined to $991.2 million from $1.04 billion last year.

WEC’s results do not yet include the financial performance of Integrys or its subsidiaries.

— Chris O’Malley

Xcel Reports Flat Earnings for Q2

RTO-XcelXcel Energy reported flat profits for the second-quarter, with earnings of $197 million ($0.39/share), compared with $195 million ($0.39/share) for the same period last year.

Minneapolis-based Xcel said the results were generally in line with expectations. Though the company missed analysts’ estimates by $0.01/share, it reaffirmed its full-year earnings-per-share guidance of $2 to $2.15.

Xcel blamed unfavorable weather conditions that affected customers’ heating and cooling costs and adjustments to a rate request in Minnesota.

Second-quarter electric margins increased due to new rates and riders in various jurisdictions and a lower Public Service Company of Colorado earnings test refund. Xcel said that increase was offset by higher depreciation, a lower allowance for construction funds and higher property taxes, operating and maintenance expenses and interest charges.

Xcel’s Monticello nuclear plant is operating at full capacity, having received final Nuclear Regulatory Commission approval. The facility was uprated to 671 MW from 600 MW in 2013, at a cost of $748 million (a $0.16/share hit to profits). Xcel said its Cherokee combined-cycle plant in Colorado completed its first-fire during the quarter and is on budget and on time.

— Tom Kleckner

PJM, Pipelines Pledge Increased Cooperation to Boost Reliability

By Suzanne Herel

PJM and nine interstate pipelines have signed an information-sharing agreement to improve the reliability and flexibility of natural gas supplies for the RTO’s generators.

The Memorandum of Understanding spells out in detail the kind of non-public information PJM and the pipelines will share as permitted by PJM’s Tariff and the Federal Energy Regulatory Commission’s Order 787. (See FERC Rejects Bid to Broaden Scope of Gas-Electric Info Sharing.)

The pipelines said they are willing to sign contracts to “firm up” services for generators that do not have primary firm service. The MOU notes that the pipelines may require additional facilities to provide firm service.

Each of the pipelines will provide PJM a description of services they are offering to generators that could satisfy the RTO’s Capacity Performance requirements. They also agreed to provide PJM a summary of services that have been requested by generators and the status of those requests. PJM may share any information obtained under the MOU with the Independent Market Monitor.

In return, PJM will provide the pipelines with performance requirements for gas-fired generators serving as capacity resources, including a demonstration of access to firm gas during the peak hours of the electric day and evidence of hourly flexibility — ensuring that generators will not seek compensation due to an inability to procure gas outside the normal scheduling window.

“This agreement sets the stage for greater coordination between electric generators and the natural gas pipeline industry,” said PJM Chief Operations Officer Mike Kormos in a statement. “As electricity-generating facilities increasingly turn to natural gas, it is important that we all communicate clearly to assure reliable service.”

“Continued dialogue will result in more informed decisions by the PJM market participants that operate and rely upon gas-fired electric generators,” said Don Santa, CEO of the Interstate Natural Gas Association of America.

According to data from the U.S. Department of Energy, natural gas surpassed coal as the country’s top source of electric power generation for the first time in April.

The country’s historic fuel shift was the topic of this year’s PJM Grid 20/20. (See PJM Grid 20/20: Who Will Build the Pipelines?)

The pipelines signing the MOU are Dominion Cove Point LNG; Dominion Transmission; Columbia Gas Transmission; National Fuel Gas Supply; Natural Gas Pipeline Co. of America; Tennessee Gas Pipeline; Texas Eastern Transmission; Texas Gas Transmission; and Transcontinental Gas Pipe Line.

The agreement will run through June 2016, after which it will continue on a month-to-month basis unless terminated by the parties.