Page 1449 – RTO Insider

April 25, 2016

FERC Orders Further Changes to NYISO RMR Rules

By William Opalka

FERC told NYISO last week that proposed changes to its rules for reliability-must-run generators are insufficient, ordering another compliance filing in 60 days.

FERC, NYISO, reliability-must-run agreements — Cayuga Plant *Source: Wikipedia*

In February 2015, the commission found NYISO’s Tariff unjust and unreasonable because it lacked rules governing the retention and compensation of generating units needed for reliability. FERC took action after several coal-fired and nuclear generators in western New York announced their closures and the ISO was unable over nearly four years to win stakeholder consensus regarding uniform compensation rules for RMR units. (See FERC Orders NYISO to Standardize RMR Terms in Tariff.)

On Thursday, the commission said the ISO’s revised rules complied only in part with its directive (ER16-120, EL 15-37).

The commission approved the ISO’s use of going-forward costs as a compensation mechanism for generators and its use of net present value to compare solutions to reliability concerns. But it rejected the ISO’s proposed role for the New York Public Service Commission, its cost allocation proposal and its plan for bidding RMR generators into capacity auctions.

‘Gap Solution’

NYISO proposed adding its RMR rules to its existing “gap solution” process. The gap solution is currently triggered when the ISO’s biennial reliability planning process determines that neither market-based nor regulated proposals will address a reliability need quickly enough, or if its Board of Directors — after consulting with state regulators — determines there is an imminent reliability threat.

Under the ISO’s proposal, it would solicit gap solution — generation, transmission or demand response — and market-based solution proposals when it identifies a reliability need that would result from a generator deactivation.

If there are no viable market-based solutions, the ISO would provide the PSC with a list of transmission and DR gap proposals. The ISO would enter into an RMR agreement only if there are no viable non-generation solutions or if the PSC does not select such a solution from the list provided by the ISO.

FERC said the ISO’s plan was inconsistent with Order 1000, improperly delegated authority to the PSC and could lead to inefficient transmission development.

The commission also rejected a proposal that generators provide 365 days’ notice before deactivation, more than doubling the 180 days required by the PSC. Generators had protested that the proposed notice period was “unreasonably long.”

FERC did not rule on the merits of the extended time frame but said it would address the timing issue after NYISO proposes Tariff amendments outside of the gap solution process. The commission further said it could not determine whether a generator should be compensated during the notice period and at what level.

Capacity Pricing

FERC also rejected the ISO’s proposed cost allocation for RMR generators and transmission gap solutions as inconsistent with Order 1000 and its plan to bid RMR generators into its capacity auction at prices above $0/kW-month. “It is more efficient for RMR generators to offer their [unforced capacity] at $0.00/kW-month as ‘price-takers,’” FERC said.

It accepted in part the ISO’s provisions to prevent generators from “toggling” between RMR compensation and market-based rates, requiring additional protections.

FERC also denied rehearing of a PSC complaint that FERC’s February 2015 order encroached on its jurisdiction. (See FERC Interfering with Reliability Order, NYPSC Says.)

April 25, 2016

FERC Open Meeting Briefs

WASHINGTON — A May 13 FERC technical conference reviewing generator interconnection procedures will include a discussion on the interconnection of energy storage resources (RM16-12, RM15-12).

FERC-commissioners-listen-to-National-Labs-presentations-content-web — FERC commissioners listen as representatives from the Energy Department’s National Laboratories give a presentation on grid modernization. © *RTO Insider.*

The tech conference was scheduled in response to a 2015 petition by the American Wind Energy Association to revise the commission’s pro forma large generator interconnection agreement. Other topics to be discussed include the current status of interconnection queues and transparency in the interconnection study process.

The conference was brought up by FERC Chairman Norman Bay during a presentation staff gave the commission at its open meeting last week on the data requests it sent six grid operators regarding their rules for energy storage participation in the wholesale markets. The storage issues slated for discussion at the conference are largely the same as those the RTOs will address in their responses to the data requests, which are due May 2. (See FERC to Examine RTO Roles for Energy Storage.)

“Energy storage is one of the big potential game changers in the energy industry,” Commissioner Tony Clark said. “This line of inquiry that we’re opening and the responses we’re going to get back I think are going to be tremendously important.”

National Labs Brief FERC on Grid Modernization

Representatives from the Department of Energy and its national laboratories said that increased communication and cooperation with FERC will be needed in order to help them in their efforts to modernize the grid.

These efforts — including integrating renewable energy resources and energy storage, and increasing protection against cyber threats — were detailed in a series of presentations at the commission’s open meeting last week. The integration of new technologies will result in a paradigm shift in how energy is generated and used, they said.

One of “the key trends and themes that we’re reinforcing is the evolution towards more distributed control,” said Jeff Dagle, chief electrical engineer at Pacific Northwest National Laboratory. “Historically, we’ve forecasted demand and dispatched supply. I think increasingly in the future, we’ll be forecasting supply and dispatching demand.”

Chuck Goldman, of the Lawrence Berkley National Laboratory, urged FERC to consider having its senior staff participate in the advisory committees on some of the labs’ projects. He also said the commission should “think about the kinds of [research and development] that might be appropriate for ISOs that’s in the public interest [and] that can deal with grid modernization issues.”

– Michael Brooks

April 25, 2016

FERC Rejects Rehearing on SPP-WAPA JOA

By Tom Kleckner

FERC last week accepted revisions to SPP’s joint operating agreement with Western Area Power Administration-Upper Great Plains Region (WAPA-UGP), denying rehearing and clarification requests by MISO and 23 of its transmission owners (EL12-60, ER12-1586).

The commission’s April 21 order granted SPP and the Integrated System’s request for clarification that the term “energy exchange” reflects their intent that the JOA does not affect the transmission rights or service of third parties.

MISO and its TOs had protested FERC’s September 2012 order accepting the JOA, which was filed in April 2012 as a precursor to the IS’ membership in SPP. They said part of the JOA would be “incompatible” with market-to-market coordination between MISO and SPP when the latter’s Integrated Marketplace began operating, and that the agreement equated to “assessing compensation for loop flow.”

FERC rejected both arguments. The IS, comprising WAPA-UGP, Basin Electric Power Cooperative and Heartland Consumers Power District, became full transmission-owning members of SPP in October.

The commission clarified that that sections 5.4-5.6 of the JOA are the parties’ method for addressing contract path capacity determinations. The commission affirmed its prior determination that the language does not violate market-to-market principles or constitute unauthorized loop flow compensation.

“As the commission stated elsewhere in the Sept. 18 order, sections 5.4-5.6 of the [WAPA-SPP] JOA do not govern loop flow; rather, loop flow is governed by the congestion management process.”

April 25, 2016

Utility-Solar Partnership Proposes Net Metering Overhaul

By William Opalka

New York utilities and three solar companies on Tuesday proposed a business model that they said would replace net metering and address cost-shifting concerns, a pact that could serve as a model nationally (15-E-0751).

The proposal was made in a proceeding of New York’s Reforming the Energy Vision initiative.

The Solar Progress Partnership includes Central Hudson Gas & Electric, Consolidated Edison, New York State Electric and Gas, National Grid, Orange and Rockland Utilities, Rochester Gas and Electric and the solar companies SolarCity, SunEdison and SunPower.

“At its core, the partnership’s proposal provides simplicity for customers, recognizes the locational value of clean [distributed energy resources] and attempts to resolve potential bill impacts, particularly to customers who are not participating in [net metering],” the filing states.

Under net metering, utilities pay for surplus power from rooftop solar systems. Utilities say this means ratepayers without solar systems are paying more than their share of grid costs. (In the Orange and Rockland service territory, customers are reimbursed at the NYISO day-ahead hourly price, which is the wholesale rate. Some other utilities pay at the retail rate.)

The proposal would preserve credits for residential rooftop solar systems. But it proposes a transition from the current net metering model that would begin in 2020 for larger projects. The filing recommends collecting a payment from solar developers for community and remote solar projects connected to the grid.

The proposal marks a potential cease-fire in the battles solar developers have fought with utilities in states across the country. In December, SolarCity announced it was ending operations in Nevada after regulators cut payments to rooftop panel owners.

News of the agreement appeared to cheer investors. SolarCity shares ended last week at $33.34, up 9% from the open Tuesday, while SunPower shares were up less than 1% at $21.66. SunEdison shares were trading at $0.34 Thursday — when the company announced it was seeking Chapter 11 bankruptcy protection — up 6% from Tuesday.

“We’re working together to keep our state’s solar market vibrant while enabling us to maintain the robust power grid that solar energy requires, and in a way that is fair to all customers,” Con Edison CEO John McAvoy said in a joint statement.

SolarCity CEO Lyndon Rive also was conciliatory. “The deep institutional knowledge of these six utilities and the creative approach they are taking to the evolution of electricity is inspiring. Leaders like these will lay the foundation for the grid of the future.”

The partnership said the proposal came out of discussions facilitated by the Advanced Energy Economy Institute.

LMP+D+E

The proposal said it would use elements of a New York Public Service Commission staff white paper to transition to a compensation structure “that more closely aligns with the value the resources bring to the power system, including the wholesale power system (‘LMP’), the electric distribution system (‘D’) and to society at large (‘E’), which is generally the environmental benefit.”

Each community distributed generation (CDG) project would be assigned to a tranche that would establish a compensation rate and developer payments. “Each successive tranche would incorporate higher developer payments, gradually moving the total resource compensation rate to LMP+D+E,” the partnership said.

According to PSC data, the state has more than 3,100 MW net energy metering resources installed or in utilities’ interconnection queues. “These queues have more than doubled in the first three months of 2016,” the proposal said. “Much of this recent development activity has been configured as CDG projects.”

Barriers to Entry?

The plan would require developers to provide letters of credit, a condition that Karl Rábago, head of the Pace Energy and Climate Center, said bars small developers.

“In the early days of the Texas market deregulation, that’s really what shook out the smaller developers,” Rábago, a former Texas Public Utility Commissioner told Capital New York. “I don’t have a line of credit if I’m a small player.”

April 25, 2016

ERCOT Board of Directors Briefs

AUSTIN, Texas — ERCOT’s Independent Market Monitor said last week that negative prices are becoming less frequent and that they have virtually no impact on average energy prices, despite media attention given to them.

Steve Reedy, the IMM’s deputy director, told the Board of Directors during his regular update that while negative prices “are not a problem, they’re certainly something as an economist that interest me.”

Reedy said the Monitor saw “significant amounts” of negative pricing in ERCOT’s West zone — where most of the ISO’s 15,764 MW of wind capacity resides — during the first year of the nodal market, which went live in 2010. The completion of the $6.8 billion, 3,600-mile Competitive Renewable Energy Zone (CREZ) transmission buildout in February 2014 resolved most of the congestion issues.

“For the most part, we’ve seen [those prices] go away,” Reedy said. “We still have negative prices, but rather than being the norm early in the nodal market and in the zonal market, it’s now the exception.”

Reedy expressed mild frustration that a September Slate article detailing prices reaching as low as -$8.52/MWh led to a flurry of additional press coverage. He said the Sept. 13 event was typical of wind energy being offered into the market at off-peak hours.

Testing his hypothesis, Reedy asked Monitor staff to calculate negative prices’ effect on the ERCOT market by replacing every negative price with a zero.

The end result? An energy-weighted price of $26.78/MWh for 2015, virtually identical to the $26.77 average including the negative prices.

“It’s a late-night, early-morning phenomenon. It’s not an example of the CREZ being used up,” Reedy said. “It’s driven a lot of press, but it’s not had a major effect on the price.”

Ken-Anderson, PUCT at the ERCOT Board of Directors Meeting — Anderson © *RTO Insider*

Texas Public Utility Commissioner Ken Anderson asked whether ERCOT would be seeing the same behavior without the federal production tax credit, which is worth $23/MWh. “No, I don’t think that would be the case without the PTC,” Reedy told the commissioner.

“We’ve seen over the last five years that the west export capacity, due to CREZ, has expanded significantly,” he said. “Even with the growth of wind energy, we rarely get that crossover where [we end up with negative prices].”

Asked what was causing the low-priced energy, Reedy could only reply with anecdotal evidence, suggesting that some coal generators might be running overnight to reduce their fuel stockpiles, and that other market participants might be running units overnight to eliminate start-up risks.

Reedy also discussed the operating reserve demand curve (ORDC), a price adder created to reflect the value of reserves during high-load periods. ERCOT staff compiled stakeholder proposals for revising the ORDC in a white paper earlier this year, following Anderson’s call for a PUC review of it and its methodology. (See “State Regulators Seeking Answers to Summer Incident,” ERCOT: No Consensus on Operating Reserve Changes.)

Texas regulators are considering whether to artificially raise wholesale power prices, as ERCOT is seeing prices at 14-year lows. The PUCT met April 14 to consider the issue and will again discuss the topic May 4. Commission staff has issued a memo summarizing comments it has received from market participants.

[Editor’s Note: An earlier version of this article stated incorrectly that the white paper contained ERCOT staff’s recommended changes to the ORDC.]

Board Easily Passes LOC Revision

The board approved the Technical Advisory Committee’s recommended parameters for payments of lost opportunity costs to generators ordered to ramp down for grid reliability, with just two opposing votes and no discussion.

“No questions?” board Chair Craven Crowell asked the members, surveying the room. Addressing TAC Chair Randa Stephenson, he said, “Sounds like you did a good job on it then.”

“We worked hard,” Stephenson responded.

The board had remanded Nodal Protocol Revision Request (NPRR) 649 back to the TAC at its February meeting. Last month, the committee was able to reach agreement on one of three options, amending the language to reflect comments it received from the board. (See ERCOT Stakeholders Agree on Lost Opportunity Costs Rule.)

The Texas Office of Public Utility Counsel’s Tonya Baer (Residential Consumers) and the City of Dallas’ Nick Fehrenbach (Commercial Consumers) cast the two negative votes.

Stephenson, of the Lower Colorado River Authority, said the request’s original impact analysis of $100,000 to $150,000 had been reduced to the $50,000-$75,000 range, assuming high-dispatch limit (HDL) overrides remain at current levels. She said ERCOT has revised its procedures since Odessa-Ector Power Partners claimed its combined cycle plant had lost $300,000 because of three days of HDL overrides in November 2012 and only one HDL since last May.

“We anticipate costs to the load … when this does occur [again], it will be an uplift,” Stephenson said. She said the TAC will continue to monitor and report back on any uplifts.

The board also approved NPRR 745, which changes the emergency response service’s availability from an hourly to 15-minute interval evaluation and makes other minor changes.

ERCOT Net Above Budget, Despite Mild Weather

Bill-Magness,-ERCOT-CEO at the Board of Directors meeting — Magness © RTO Insider

ERCOT CEO Bill Magness told the board that 2016’s net revenues are $1.8 million above expected, despite system administration fees being $1.7 million under budget due to mild weather conditions. Timing differences kept spending $3.1 million under budget, he said in his report.

Pointing to an overhead screen filled with maps of Texas, Magness said, “That’s five different ways up there of saying it’s warm. The basic story is, we did have a pretty warm, pretty dry winter.”

Magness also reported that staff is testing an upgrade to ERCOT’s energy management system, which could go live as early as May 26. He noted the EMS is just one of several software systems scheduled to go live this year.

The CEO also mentioned ERCOT’s creation of the Grid Resilience Working Group, which will assess low-probability but “potentially high-impact” risks to the ISO’s system. Its first meeting is scheduled for April 26.

Bermudez, NPRRs Approved

The board re-elected unaffiliated Director Jorge Bermudez to a third and final term. His second term expires in June.

It also unanimously approved seven NPRRs and one change-request on its consent agenda:

NPRR 741: Clarifications to estimated aggregate liability (EAL) and total potential exposure (TPE) credit exposure calculations.
NPRR744: Reliability unit commitment trigger for the reliability deployment price adder and alignment with RUC settlement.
NPRR 746: Adjustments due to negative load.
NPRR 748: Revisions associated with NERC reliability standard COM-002-4 and other clarifications associated with dispatch instructions.
NPRR 749: Requires ERCOT to publish the cost of options for all outstanding congestion revenue rights within the CRR auction process.
NPRR 750: Clarifies the practice for setting telemetry when providing fast-responding regulation service.
SCR 787: Changes the net-dependable capability and reactive capability (NDCRC) application to provide historical generator information to all associated resource entities.

— Tom Kleckner

April 25, 2016

NIPSCO Settlement with Indiana Wind Farms Wins OK

By Amanda Durish Cook

FERC approved an uncontested partial settlement between Northern Indiana Public Service Co. and the owners of seven Indiana wind farms that contend the utility overcharged them for transmission upgrades.

NIPSCO - FERC - Indiana wind farms - Meadow Lake Wind Farm (Meadow Lake Wind Farm) — Meadow Lake Wind Farm *Source: Meadow Lake Wind Farm*

The April 21 order (EL14-66-003) resolves issues related to NIPSCO’s 138-kV transmission upgrade funded by the Meadow Lake and Fowler Ridge wind farms. Under the settlement, the utility will pay $400,000 to Meadow Lake and $450,000 to Fowler Ridge to withdraw their complaint.

E.ON Climate & Renewables North America filed the original complaint against NIPSCO in 2014, objecting to the multiplier rate used in two transmission upgrade agreements with its Pioneer Trail and Settlers Trail wind farms. FERC later that year ruled that the multiplier was unreasonable and instructed the two companies to enter into settlement proceedings to determine a new rate (EL14-66).

Meadow Lake and Fowler Ridge filed a similar action after the ruling. NIPSCO charged their facilities and several other wind farms $35.8 million to cover 35 years of operating costs on top of the $50.4 million to build transmission. (See NIPSCO Blows Back at Wind Farm Complaints.)

FERC’s acceptance of the partial settlement also closes out Meadow Lake and Fowler Ridge’s request for rehearing in E.ON’s complaint (EL14-66-002).

April 25, 2016

SPP News Roundup from FERC Open Meeting

FERC denied reconsideration of a 2012 ruling that granted in part Exelon Wind’s petition for a declaratory order, but it once again declined to initiate an enforcement action against the Public Utility Commission of Texas (EL12-80).

The owner of several qualifying facilities under the Public Utility Regulatory Policies Act, Exelon Wind had protested that a PUCT order approving Southwestern Public Service’s treatment of QF energy purchases violated PURPA.

While rejecting the request for an enforcement action, FERC’s 2012 order concluded that the PUCT’s approval of avoided cost rates linked to the locational imbalance price (LIP) at a QF’s node in the SPP Energy Imbalance Service market was inconsistent with PURPA.

The PUCT, Occidental Permian and SPS parent Xcel Energy filed requests for reconsideration in September 2012, saying the revised methodology for calculating avoided costs approved by FERC was inconsistent with PURPA.

FERC said the PUCT’s reliance on SPP’s LIP to calculate avoided costs was moot, as the RTO replaced the Energy Imbalance Market with the Integrated Marketplace, which relies on LMPs, in March 2014. The Texas commission has approved SPS’s request to substitute LMP for LIP in calculating avoided costs. “Accordingly, we find that the issue of whether LIP may be used to calculate avoided costs has been overtaken by events,” FERC said.

SPP-IS Partial Settlement Offer Accepted

The commission accepted a partial settlement on behalf of SPP, the Western Area Power Administration-Upper Great Plains Region (Western-UGP), Missouri River Energy Services and the Municipal Energy Agency of Nebraska, resolving issues over the October integration into SPP of Western-UGP, Basin Electric Power Cooperative and the Heartland Consumers Power District as transmission-owning members (ER14-2850, ER14-2851).

The Nebraska MEA had intervened in SPP’s original September 2014 filing, raising concerns about seams issues resulting from the decision of the Integrated System’s entities (Western-UGP, Basin and Heartland) to become SPP members.

Missouri River Energy Services (MRES) asked FERC for relief from marginal loss and marginal congestion payments associated with the exercise of its transmission rights. Basin Electric and Heartland also requested such “carve out” treatment. FERC found the concerns to be of “material fact” best addressed through hearing and settlement judge procedures.

The parties to the settlement agreed to forego a full evidentiary hearing before an administrative law judge and brief the issue directly to the commission, using stipulated facts, legal precedent and pleadings previously filed with the commission addressing carve-out treatment under the SPP Tariff.

FERC Accepts Termination of Northwestern-So. Montana Interconnection Pact

FERC accepted NorthWestern Corp.’s termination of a large generator interconnection agreement with Southern Montana Electric Generation and Transmission Cooperative, saying NorthWestern does not have to make further reimbursements to the co-op for network upgrade costs (ER16-763).

The 2011 agreement governed the interconnection with Southern Montana’s Highwood Generating Station, which the co-op decommissioned, dismantled and sold for parts in June 2014.

Northwestern filed a termination notice in January, asking for confirmation that it would not be required to pay $5.84 million in unreimbursed upgrade costs and interest.

Southern Montana and Beartooth Electric Cooperative — a Southern Montana member that advanced a portion of the funds for the network upgrades — protested the filing, saying they were entitled to refunds. FERC found for NorthWestern, saying a transmission operator “has no further obligation to reimburse the interconnection customer for its upfront payment if the generating facility ceases commercial operation before the interconnection customer has been completely reimbursed.”

FERC Denies a Waiver

FERC denied Montana-Dakota Utilities’s (MDU) request for a waiver of SPP Tariff charges assessed to pay the commission’s annual fees (ER16-866).

MDU made the request in February, saying the charges were the same as those paid to MISO for serving the same transmission load. SPP agreed not to oppose the waiver request if its FERC assessment calculation did not include Montana-Dakota’s transmission service.

But the commission likened MDU’s situation to that in which two or more transmission operators transmit power “sequentially” over long distances, one after the other. In that case, the commission said, “each RTO public utility or individual public utility will be assessed an annual charge based on its respective transmission of such electric energy.”

– Tom Kleckner

April 25, 2016

Federal Briefs

As the Paris Agreement on climate change was being signed on Earth Day, scientists and media outlets sounded a steady drumbeat of sobering climate change news.

According to studies, the first three months of 2016 have been the hottest ever recorded, Australia’s Great Barrier Reef is slowly being bleached to death and Greenland’s ice sheet is melting faster than scientists have ever seen. “The strongest hurricane on record for both the Northern and Southern Hemisphere, unprecedented continuing drought in California, the warmest start to a year that we’ve ever seen, on the heels of what was the warmest full year on record for the globe,” said Michael Mann, a Pennsylvania State University climate scientist.

The climate agreement, signed by officials from 174 countries, is a pledge to cut greenhouse gas emissions and slow the warming of the planet.

More: The Washington Post

Secretary Moniz Disputes ‘War on Coal’ by Obama

Energy Secretary Ernest Moniz said the Obama administration has not declared war on coal, as many critics say, but is committed to using innovation to breathe continued life into the fuel.

“Make no bones about it,” he said, “we start with the assertion, the commitment, that we are talking about a progressively lower carbon future. But we have not abandoned coal as part of that future.”

Moniz was speaking at a University of Kentucky forum focused on energy innovation. He noted the administration’s investment of billions of dollars for research on carbon capture and storage, including $6.5 billion in tax credits for the technology. If the administration wanted to kill off coal as a fuel, he said, “we wouldn’t have put $6 billion into CCS.”

More: Lexington Herald-Leader

Virginia Officials Ask FERC to Reject Pipeline Route

The Augusta County Board of Supervisors asked FERC to reject an alternate route for the $5 billion, 550-mile Atlantic Coast Pipeline, saying the proposed pipeline would have a negative impact on the county.

The developers of the proposed pipeline, designed to bring natural gas from Appalachian shale plays, had already shifted the route to avoid going through the Monongahela and George Washington National Forests. But Carolyn Bragg, the August County board chair, says the new route goes through land with protected conservation easements, and near protected water sources. In a letter addressed to “Chairman” Cheryl LaFleur, Bragg also complained that no public hearings for the new routes had been held.

A spokesman for Dominion Resources, the pipeline’s developer, said the route has already been changed several times after consultation with the U.S. Forest Service.

More: The News Virginian

Army Still Undecided on Dominion Tx Project

The U.S. Army Corps of Engineers said it believes the need still exists for a 500-kV transmission line by Dominion Virginia Power despite contrary research by opponents, but it isn’t yet prepared to approve a plan to build the line, which would cross over the James River.

Dominion says it needs to import power to areas that were formerly served by two units at its now-retired Yorktown generating station. Consultants for the National Parks Conservation Association have concluded that the line isn’t necessary.

The corps has called for more study before making a decision.

More: The Virginia Gazette

Lower Wind Speeds Slow Wind Power Growth in US

Wind generation grew by only 5.1% in the U.S. in 2015, the smallest annual increase since 1999, due primarily to a change in weather patterns in the West, according to the Energy Information Administration.

Those same weather patterns, however, resulted in higher average winds in the central part of the country, pushing up wind generation totals in the heartland.

Construction of new wind farms continues apace. Wind capacity grew 12.9%, a greater growth rate than the two previous years, with 8.1 GW installed. The agency said wind is projected to supply more than 5% of U.S. electricity generation in 2016.

More: Energy Information Administration

US NatGas Production Continues to Climb

U.S. natural gas production hit a record high of 79 Bcfd in 2015, up about 5% from the previous year, despite continued low prices for the fuel, according to the Energy Information Administration. While production dipped in much of the U.S. gas fields, increased production in five states — Pennsylvania, Ohio, West Virginia, Oklahoma and North Dakota — more than made up for any decrease.

Pennsylvania’s growth rate slowed from the previous year — dropping from 2.6 Bcfd in new production in 2014 to 1.5 Bcfd of new production. But it still reported the fastest-growing production rate in the nation.

More: Energy Information Administration

DOE Tasked to Study Albedo Modification

The U.S. Senate wants the Department of Energy to study the value of using reflected sunlight to fight global warming.

A proposed spending bill would fund the department with an undetermined amount of money to examine whether climate change trends could be reduced by increasing the amount of sunlight reflected from the Earth’s surface back into space.

Harvard University scientist David Keith was promoting the study on reflectivity. “Ignorance is not a good basis for making decisions, so learning more about this is extremely valuable even if we find out that it will never work,” he said.

More: Science

Army Ammo Base Switching From Coal to Natural Gas

The Army is building a $60 million, natural gas-fired generating plant to replace a 77-year-old coal-fired unit at its Radford Army Ammunition Plant. The announcement came a day after protesters gathered outside U.S. Rep. Morgan Griffith’s Christiansburg, Va., office to protest the open burning of hazardous waste at the plant.

The Army pointed to its switch to natural gas from coal as an example of its commitment to the environment. It also said it recently received $7 million to design and build an enclosed incinerator and close the open-burn unit.

“We absolutely take our obligation to the environment very seriously,” said Lt. Col. Alicia Masson, the base commander.

More: The Roanoke Times

Environmental Groups Sue Four Corners Plant

A coalition of environmental groups and the Navajo tribe last week announced it had formally filed suit against the U.S. government for extending operations at a New Mexico coal plant and its associated mine.

The suit was filed in the U.S. District Court for Arizona against the Interior Department’s Office of Surface Mining and U.S. Fish and Wildlife Service, among others, over a July decision to allow the Four Corners Power Plant and Navajo Mine to operate until 2041. The 52-year-old power plant and coal mine is in the Navajo Nation, about 15 miles southwest of Farmington, and operated by Arizona Public Service.

The owners plan to shut three of five generation units, reducing its capacity from 2,100 MW to 1,540 MW. Opposition groups argue that the 25-year extension did not take into account the assessment of clean energy alternatives and environmental risks. The groups also cite the recent string of bankruptcies, shutdowns and regulations facing the coal industry.

More: The Durango Herald

Spurned in ND, Nuke Waste Firm Looks to SD

A group sponsoring a federal study to explore for an underground nuclear waste storage site is scouting potential properties in South Dakota after North Dakota rejected a plan to study sites there.

Battelle Memorial Institute, the nonprofit research firm behind the Department of Energy project, has planned two public meetings in Spink County to explain the exploration.

Battelle says its deep borehole test will not involve any radioactive waste. Its purpose is to find deep underground rock layers that may be suitable for the storage of nuclear waste in the future.

More: The Associated Press

April 25, 2016

District, OPC Ask PSC to Reconsider Exelon-PHI Merger

By Suzanne Herel

The D.C. Office of the People’s Counsel and the district government asked the Public Service Commission Friday to reconsider its March 23 approval of Exelon’s $6.8 billion acquisition of Pepco Holdings Inc., saying the commission’s rewrite of settlement terms was improper.

Friday was the deadline for the nine parties to the case to request such reconsideration. Aside from OPC Sandra Mattavous-Frye and D.C. Government, the only qualified party to do so was Grid 2.0, which advocates for distributed generation. (See Grid 2.0 Asks DC PSC to Reconsider Merger Approval.)

Exelon and Pepco didn’t wait for the deadline, closing the merger the day of the PSC’s approval. (See Exelon Closes Pepco Merger Following OK from DC PSC.) Last week, Pepco asked Maryland regulators for a 10% rate increase for most of its customers.

Mattavous-Frye said the decision was important for future cases. In her application, she asked that the PSC reopen the record and allow all parties to comment or reject Exelon and Pepco’s unilateral request for adoption of new merger terms as being “procedurally improper.”

“I strongly believe that the manner in which the decision was reached was legally flawed,” she said. “If the flaws in this order are not corrected, it will erode the trust and confidence of consumers and all parties that practice before the commission.”

The D.C. government, in a filing submitted by Attorney General Karl Racine, said, “By unilaterally modifying the terms of the non-unanimous settlement agreement and approving the terms of the revised non-unanimous settlement agreement as a resolution on the merits, the commission committed a series of procedural and substantive errors that require it to reconsider and vacate Order No. 18148.

“The order will have a chilling effect on future settlement negotiations because parties will fear that, in agreeing to proposed settlement terms, they run the risk of the commission proposing and approving alternative settlement terms without the parties’ consent.”

If the PSC does not reconsider and vacate the order, it should reject the merger or approve the non-unanimous settlement agreement subject to “such additional terms as the commission determines will satisfy the public interest,” the filing said.

Mattavous Fry Source DC PSC, DC OPC — Mattavous Fry *Source DC OPC*

Mattavous-Frye and the government opposed the initial merger proposal, which the commission rejected last August. They signed on to a later settlement brokered by Mayor Muriel Bowser’s office in October. District officials withdrew their support after two of three PSC commissioners revised that settlement, saying the changes substantially weakened protections for ratepayers.

If the commission stands by its decision, parties may seek relief from the D.C. Circuit Court of Appeals.

April 25, 2016

FERC Orders Changes to MISO-PJM Interregional Planning

By Suzanne Herel

FERC last week ordered MISO and PJM to make changes in their interregional transmission planning process, granting in part a 2013 complaint by Northern Indiana Public Service Co. (EL13-88).

NIPSCO, which operates on the seams of the RTOs, pointed to “significant congestion costs [and] operating issues” along the seam and noted that no transmission project had ever been approved under the RTOs’ joint operating agreement.

The company said that although market-to-market redispatch had helped day-to-day operations, the RTOs had not developed solutions to long-standing congested flowgates. It proposed several changes that it said would incent cross-border transmission projects. (See FERC Considering NIPSCO Proposals on PJM-MISO Seam.)

First, it recommended the RTOs run their cross-border transmission planning process at the same time as their regional transmission planning cycles, rather than after them.

FERC said it agreed with NIPSCO that the existing open-ended planning process can delay the “identification, analysis and potential approval of beneficial interregional economic transmission projects.”

The commission gave MISO and PJM 60 days to revise the JOA “to include timely, specific deadlines for each step in the coordinated system plan study process” and establish a deadline for how much time it should take from proposal to approval.

“We also find that … it is unclear how the coordinated system plan study in the JOA interacts and aligns with the [MISO Transmission Expansion Plan] and the [PJM Regional Transmission Expansion Plan],” FERC ruled. “A clear process laid out in the JOA may resolve these disagreements and help provide a consistent understanding of the process for all stakeholders.”

FERC denied NIPSCO’s request that the MTEP, RTEP and JOA processes follow a common timeline. But it asked MISO and PJM to submit an informational filing within 120 days describing how it could do so and what impacts that would have on the RTOs’ planning process as well as interregional coordination with neighboring regions.

The commission also denied NIPSCO’s suggestion that MISO and PJM be required to conduct a coordinated system planning study on a regular basis. Requiring that “even when the RTOs’ annual review of transmission issues finds it unnecessary would not be an efficient use of MISO’s, PJM’s and stakeholders’ time and resources,” FERC said.

NIPSCO also recommended that the RTOs develop a single model using the same assumptions in the cross-border transmission process. FERC rejected that suggestion but directed MISO and PJM to “explore the potential use of a joint model with the same assumptions and criteria” and submit an informational report on the issue.

Finally, NIPSCO asked that the RTOs use a common set of criteria in evaluating cross-border efficiency projects.

FERC agreed with NIPSCO that the current cost and voltage thresholds can remove from consideration certain projects that could benefit both regions. It ordered MISO to reduce its minimum voltage threshold for interregional economic transmission projects from 345 kV to 100 kV and eliminate the $5 million cost threshold for such projects. (See PJM, MISO to Scrap $20M Threshold for Joint Tx Projects.)

It also ordered the removal of the requirement for a third, separate benefit-cost analysis for the combined regions.