SPP MOPC OKs New Rules for Calculating Mitigated Offers

By Rich Heidorn Jr.

TULSA, Okla. — SPP’s Markets & Operations Policy Committee last week approved new rules on how mitigated offers will be calculated for generators that fail market power tests, choosing a solution that includes default values for variable operation and maintenance (VOM) costs.

It was the second time the group had approved new rules on mitigated offers. In December, the SPP Board of Directors rejected a proposal that had been approved by MOPC over the objections of the Market Monitoring Unit, saying it wanted a solution that had broader support.

The new proposal, which passed on a voice vote, did not win the MMU’s endorsement, however.

MMU Director Alan McQueen told MOPC that the revised proposal’s use of default VOM values was an improvement because it reduced ambiguity. He also praised the inclusion of an adder for frequently mitigated resources.

Too ‘Generic’

But he said he was concerned that the proposal “removes any reference to competitive levels,” replacing it with “variable O&M,” a term he said is too “generic” because it could refer to costs incurred over a decade. That does not conform to the Federal Energy Regulatory Commission’s mitigation premise that offers are “approximately equal to short-run marginal cost,” he said.

“It actually adds ambiguity back into the overall process that the Market Monitor is going to have to use,” he said.

McQueen said this would cause problems both when the MMU is reviewing offers from units that claim costs higher than those in the default schedule and when it and stakeholders conduct their annual review of the default levels.

SPP rules allow units found to have market power to submit market offers of up to 125% of the mitigated energy offer, which would be based in part on the VOM defaults. Thus a combined-cycle plant with a heat rate of 10 MMBtu/MWH that would be paid $41/MWh, including $6 in VOM based on the default table, could receive as much as $51.25/MWh, with an implied VOM of $16.

The ‘Next Enron’

“When is the next Enron going to be entering the SPP market?” McQueen asked. “Do you want them to be deciding what should be included in the reference level or do you want the Market Monitor, who’s listening to everybody who’s in the market?”

McQueen said that based on his discussions with generators, he believed 80% of them supported use of the defaults.

Richard Ross of American Electric Power disagreed. “I can add up fairly easily enough megawatts [opposing defaults] to figure out that it isn’t 80%.”

Nevertheless, Ross said AEP would support the new rules.

Jake Langthorn of Oklahoma Gas & Electric said he was disappointed that the default solution did not include compensation for maintenance obligations under long-term service agreements. “If the LTSAs were included, we wouldn’t have a beef with it,” he said.

Staff Supports

Although the solution did not have the unqualified support of members and the MMU, SPP Chief Operating Officer Carl Monroe said RTO staff supported the proposal because it resolved some of the longstanding disputes over VOM calculations.

Richard Dillon, SPP’s director of market design, noted that FERC’s recent State of the Markets report found the RTO’s day-ahead on-peak power price to be the second-lowest in the country last year at $40/MWh, higher than only the $39 at the Mid-Columbia pricing hub in the Pacific Northwest.

“That is a good indicator that even at 125% [of the mitigated offer] the competitive price is under market,” Dillon said.

“Columbia is all hydro. Being only behind a hydro system is a problem.”

April 21, 2015June 15, 2023

SPP Staff Plan on Kansas Transmission Project Fails to Win MOPC Endorsement

By Rich Heidorn Jr.

TULSA, Okla. — SPP staff’s recommendation that the RTO approve a 21-mile 115-kV line from Walkemeyer to North Liberal as part of a reliability solution in southwestern Kansas failed to win stakeholder endorsement last week.

Staff’s solution received almost 64% support from the Markets & Operations Policy Committee, falling short of the two-thirds needed to recommend it to the SPP board.

Staff considered three alternatives, two of which would have delayed the line indefinitely, instead relying on operating guides for Sunflower Electric Power’s 76-MW Cimarron River Station to provide relief from thermal or voltage violations.

Option 1 would add a new substation with a 345/115-kV transformer on the Hitchland–Finney 345-kV line and a new 1-mile 115 kV line from the substation to Walkemeyer at an estimated cost of $17.8 million. Cimarron would be dispatched for up to 58 MW when needed to avoid violations.

Staff’s suggestion, option 2, included the new substation and transformer but would add the Walkemeyer-North Liberal line for an additional $17.5 million, avoiding the need to rely on Cimarron for reliability.

Although option 2 had higher upfront costs, staff said it was about $1.4 million cheaper than option 1 on a net present value basis over 20 years ($68.9 million vs. $67.5 million).

Option 3, which would have relied solely on the Cimarron plant, had an NPV of $84 million and only “marginally” solved voltage violations, staff said.

Tom Hesterman of Sunflower said option 1 was the best choice, being a “statistical tie” with option 2 in NPV and having lower upfront costs.

Brian Gedrich of NextEra supported the 21-mile addition, saying “it could be the only competitive project” SPP approves in the current planning cycle.

The Cimarron plant has two natural gas-fired units: a 61-MW unit built in 1963 and a simple-cycle 15.5-MW combustion turbine added in 1967.

American Electric Power’s Richard Ross was skeptical of reliance on the aging plant, saying Sunflower was not obligated to keep it running if it requires costly repairs. He said he feared the unit could fail, necessitating the Walkemeyer-North Liberal project — but without the lead time necessary to open it to competitive bidding.

Sunflower’s Al Tamimi said the company invested heavily in the unit — adding a new cooling tower in 2014 — and had no plans to retire it. Southwestern Public Service’s phase shifter can maintain system reliability if the Cimarron plant is unavailable, Tamimi added.

“I just don’t think it’s appropriate for us to continue to rely on a unit we can’t rely on,” Ross insisted.

“That’s your opinion,” Tamimi responded. “You don’t know anything about the unit.”

“I do know that if the unit fails tomorrow and you don’t return it to service that … you’re going to turn around next year and put it right in the model as unavailable and the project … that we’re talking about here” will be required, Ross fired back. “And the difference will be whether or not you’ve pushed things out to where it’s not a competitive project.”

Antoine Lucas, director of planning, said staff would consider stakeholders’ comments before making its recommendation to the board.

April 21, 2015

PJM MRC/MC Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-9:20)

Members will be asked to endorse the following manual change:

A. Manual 14D: Generator Operational Requirements — Changes made to comply with a recent advisory from the North American Electric Reliability Corp. on generator governor frequency response.

3. ENERGY MARKET UPLIFT SENIOR TASK FORCE (9:20-9:40)

Members will be asked to approve revisions to rules developed by the Energy Market Uplift Senior Task Force regarding treatment of combustion turbine lost opportunity costs. Under the proposal, units with start-up and notification times of no more than two hours and minimum run times of two hours would be paid lost opportunity costs if they are not dispatched. Resources with real-time start-up and notification times or minimum run times of more than two hours will not receive lost opportunity payments unless PJM bars them from running in real time to avoid transmission overloads.

SPP said its integrated marketplace resulted in production cost savings in each of the last 12 months. (See “PJM: New Rule on Lost Opportunity Costs Would Exclude 1/5 CTs” in Operating Committee Briefs, April 14.)

4. RESIDENTIAL DR MEASUREMENT AND VERIFICATION (9:40-9:50)

Members will be asked to approve Tariff and manual revisions regarding residential demand response measurement and verification, which PJM plans to file in late April. The changes, endorsed at the Jan. 22 Members Committee meeting, have been updated to include an additional delivery year. (See “Sampling to be used for Measuring Residential DR” in MRC/MC Briefs, Nov. 25.)

5. TARIFF HARMONIZATION SENIOR TASK FORCE (9:50-10)

Members will be asked to OK the draft charter of the group, formed to address inconsistencies and discrepancies in PJM’s governing documents. (See Task Force Proposed to Resolve Inconsistencies in PJM Governing Documents.)

6. GENERATOR OFFER FLEXIBILITY (10-10:15)

Members will be asked to endorse a problem statement and issue charge by Calpine seeking to allow more flexible market offers for physical generating resources. PJM is the only U.S. RTO that does not allow generators to vary their cost- or market-based offers hourly. This problem statement would consider allowing generators to revise their offers hourly to reflect changes in gas prices. (See PJM May Consider Hourly Pricing for Generators.)

7. REGIONAL PLANNING PROCESS SENIOR TASK FORCE (10:15-10:25)

On first reading, members will be asked to approve a recommendation directing the Planning Committee to develop guidelines for considering generation interconnection projects as drivers under the multi-driver transmission project approach. The committee also will be asked to place the task force on hiatus, available to be returned to operation if needed based on future rulings by the Federal Energy Regulatory Commission.

Members Committee

CONSENT AGENDA (12:05-12:10)

B. Members will be asked to approve proposed minor “non-substantial” provisions regarding financial transmission rights’ auction clearing deadlines and trading periods.

— Suzanne Herel

April 21, 2015

FERC Rejects New England Power Tx Tariff

By William Opalka

The Federal Energy Regulatory Commission on Thursday rejected tariff revisions submitted by New England Power, saying they would allow the company to exceed the commission’s limits on transmission returns on equity (ER15-418).

In Opinion 531, FERC last year ordered that the New England Transmission Owners’ total ROE, including base rate and incentives, could not exceed 11.74%, the top of the “zone of reasonableness.” (See FERC Splits over ROE.)

As a result, New England Power was required to revise the tariff governing the transmission facilities of its affiliates, Massachusetts Electric and Narragansett Electric, which it operates as a single integrated system.

But FERC ruled that the revisions the company filed would have improperly allowed it to earn returns of more than 11.74% on some of its assets as long as the average ROE was below the cap.

The commission said the company’s language “relies on the same interpretation of the term ‘total ROE’ that the New England Transmission Owners presented on rehearing in the Opinion No. 531 proceeding. The commission rejected that interpretation in Opinion No. 531-B, and we do so here for the same reasons.”

The commission also ordered the use of data from calendar year 2013, rather than 2012, to calculate the estimated decrease in revenues resulting from New England Power’s tariff revisions. The company had calculated a $2.2 million rate decrease if 2012 was used as the test year, and nearly a $2.3 million decrease based on data for 2013.

April 21, 2015June 15, 2023

SPP Markets Operations Policy Committee Briefs

SPP said its integrated marketplace produced net savings of about $210 million in the first year after combining 16 balancing authorities into the marketplace.

Over the rolling 12-month period ending in March, the market produced gross benefits of $430 million, or $210 million after accounting for $170 million in historical savings and $50 million in annual cost. That analysis excludes March 2013, the first month of the transition, when the RTO operated with higher unit commitments than required.

SPP-MISO Market-to-Market Showing Results

SPP’s market-to-market initiative with MISO, which began last month, is paying dividends, SPP’s Bruce Rew told members. Rew said there was activity on all but two days in March, with daily settlements ranging from $2,000 to more than $1 million.

Rew said the two RTOs are working to address “oscillation” at some locations, where congestion returns almost immediately after being relieved.

“It’s working,” he said. “It needs some improvements and we’re working closely with MISO to do that.”

Proposal on Disqualifying Regulation Resources Remanded

The Markets & Operations Policy Committee remanded Revision Request 33 to the Market Working Group. The request would allow SPP to disqualify resources from participation in the regulation market for poor performance.

Bill Grant of Southwest Public Service Co. said he was concerned that the rule was overly strict and that its requirement that resources respond within four seconds would result in the unnecessary disqualification of many resources.

“You’re already financially incented to respond. So we’re questioning the need for disqualification altogether,” he said. “… If we’re going to start disqualifying people over four-second deployments, people need to understand that because most people’s [energy management system] might not respond in four seconds.”

Staff said SPP’s intent is to improve the response of the poorest-performing “outliers.” Staffers said they have never disqualified a resource.

Members approved RR44 and RR45, which add details on how SPP calculates regulation resources’ actual mileage for settlement purposes.

Members OK Short-Term Unit Commitment Study

Members approved RR49, which would create a short-term reliability unit commitment (RUC) study as part of the intra-day RUC process. The study will provide results for 15-minute intervals, allowing operators to make unit commitments with more granularity than the current one-hour study. It is expected to reduce the number of real-time manual commitments.

Delays on Z2 Credit Fix Spark Frustration

Members expressed frustration with SPP’s slow progress in creating a process for properly crediting and billing transmission customers for system upgrades under Tariff attachment Z2. Repeated delays in the project led SPP to reorganize the staff team handling it. SPP’s software vendor is now projecting completion of the project by June 2016.

The project has proven more complex than originally expected because of the need to avoid over-compensating project sponsors, and to include a way to “claw back” revenues from members who owe SPP money for other reasons. Accounting for transfers of reservations has also proven a challenge.

“I have been dealing with this issue for so many years,” said Steve Gaw, representing The Wind Coalition. “I don’t know how many years ago we were being told that it would be fixed ‘next quarter.’

“I don’t have any more faith in the dates,” he continued. “I just don’t know when there’s going to be accountability [to the] folks who have been owed money for all of this time.”

Monroe acknowledged the frustration. “We’re playing with the hand we’ve been dealt,” he said.

2016 ITPNT Scope Approved

MOPC approved the scope of the 2016 Integrated Transmission Planning Near-Term (ITPNT), including the automatic recommendation of the notices to construct from the Consolidated Balancing Authority scenario.

The 2016 ITPNT’s primary focus is to identify solutions required to address potential reliability problems under normal conditions (no contingency) and (N-1) scenarios. It will include modeling of the system through 2020.

It will also reflect improved dispatch of wind resources and include the Integrated System — the Western Area Power Administration Upper Great Plains, Basin Electric Power Cooperative and Heartland Consumers Power District — as SPP members. (See Spurned by Entergy, SPP Expands in Great Plains.)

Keystone Pipeline Would Add SPP Loads

The controversial Keystone XL pipeline would add at least 400 MW of load to SPP based on its use of about 20 pumping stations at 20 to 25 MW each, said Jay Caspary, SPP director of research, development and special studies.

Caspary said those loads, in addition to unserved loads in New Mexico and Kansas, helped justify the Notices to Construct that SPP has issued.

Bary Warren of Empire District Electric said SPP should be wary of overestimating loads, saying that gas and oil producers have recently announced 30 to 50% cuts in capital spending due to falling oil prices.

“The projects are probably needed,” he said. “The question is when are they needed? Should they be competitively bid? … At what voltage?”

Charters Approved

The committee approved the charter of the newly formed Stakeholder Prioritization Task Force and approved a revised charter for the Transmission Planning Improvement Task Force with no substantive changes.

MOPC also approved a change in the charter of the Transmission Working Group, allowing an increase in its membership from 20 to 24. Two of the seats will be assigned to representatives of WAPA-UGP and Basin Electric. Existing SPP members will be able to apply for one of the additional two seats on the working group.

Chief Operating Officer Carl Monroe said other committees may see similar increases in their membership to accommodate the new members.

The new charter also updates the group’s scope to include:

Changes to the SPP portion of North American Electric Reliability Corp. flowgates;
Reviewing and developing rating criteria, including minimum design standards;
Reviewing and approving study information for interconnections; and
Reviewing technical and reliability aspects of all policies, business practices, study scopes, SPP criteria changes and tariff changes.

Regional Allocation Review Delayed

Members approved delaying the regional cost allocation review until new models are developed for the 2017 Integrated Transmission Plan 10-Year Assessment. This would delay completion of the RCAR II analysis until July 2016.

Members were concerned with proceeding with the models being used in the 2015 ITP10, which are about two years old and do not include Kansas City Power and Light’s January decision to stop burning coal at its Montrose power plant in Clinton. The company plans to close or convert one of its units to natural gas by 2016 and make similar decisions on the remaining two units by 2021.

SPP, which completed its last cost allocation review in 2013, is required to conduct such reviews every three years.

— Rich Heidorn Jr.

April 21, 2015June 15, 2023

FERC Upholds VEPCO Obligation to Purchase Solar Energy from Small QFs

The Federal Energy Regulatory Commission last week denied a request by Virginia Electric and Power Co. to terminate its obligation to purchase electricity from nine North Carolina solar facilities. The facilities, owned by Community Energy Solar, each have a net capacity of 4.99 MW.

VEPCO had filed the request last October.

In 2008, FERC terminated VEPCO’s obligation to purchase energy from qualifying facilities (QFs) larger than 20 MW in its service territory, with the presumption that such facilities have nondiscriminatory access to the PJM markets.

At the same time, FERC created the presumption that smaller qualifying facilities did not have the same access to the markets because of their size. The commission placed the burden of proof on utilities seeking to terminate agreements to show otherwise.

“We find that the nine Community Energy QFs established legally enforceable obligations under [the Public Utilities Regulatory Policies Act] prior to VEPCO’s filing of its application to terminate its mandatory purchase obligation for those QFs, and we therefore deny VEPCO’s application,” FERC said in its April 16 ruling (QM15-1-000).

— Suzanne Herel

April 21, 2015June 15, 2023

FERC Clarifies NYISO ICAP Market Power Mitigation Order

By William Opalka

The Federal Energy Regulatory Commission on Thursday clarified unresolved issues from a previous order on the installed capacity market in New York that have been pending for nearly three years (EL11-42).

In it, FERC accepted NYISO’s filings in response to the June 22, 2012, order, which directed the ISO to clarify how the mitigation exemption test and offer floor calculations are implemented. The commission had found merit in a complaint by NRG Energy and several other generators that NYISO’s implementation of the buyer-side mitigation rules lacked transparency.

NYISO said the 2012 order was unclear with respect to the comparison made between the default offer floor and unit net cost of new entry in determining the offer floor. FERC said NYISO’s interpretation is correct, in that the value for unit net CONE to be used should be only the first-year value of the three-year average of annual unit net CONE.

FERC also:

Confirmed NYISO’s method of adjusting the offer floor for inflation.
Ordered NYISO to change how it adjusts unit net CONE for inflation.
Affirmed its finding that NYISO has justified its use of natural gas futures prices and historical prices in its net CONE calculations.
Ordered NYISO to incorporate language allowing the Market Monitoring Unit to consider all factors relevant to mitigation exemption and offer floor determinations in its reports reviewing whether the ISO’s mitigation and exemption determinations were conducted in accordance with its Market Administration and Control Area Services Tariff.

FERC also ruled Thursday in a case related to the ICAP, in which Astoria Generating and TC Ravenswood had alleged that NYISO’s buyer-side market mitigation provisions were improperly administered (EL11-50). The order generally denied rehearing, but it ordered the ISO to use the Astoria II plant’s actual cost of capital in its mitigation exemption determination.

April 21, 2015June 15, 2023

FERC Denies Rehearing Requests on NYISO Order 1000 Compliance Filing

By William Opalka

The Federal Energy Regulatory Commission accepted most of NYISO’s and New York Transmission Owners’ second compliance filing for Order 1000 while denying multiple requests for rehearing (ER13-102).

The parties have 30 days to submit a further compliance filing.

FERC denied LS Power’s request for rehearing, saying that cost-effectiveness is appropriately assessed in NYISO’s proposed evaluation process.

The commission previously expressed concern that NYISO’s regional cost allocation method for public policy transmission projects could cause unnecessary delays for transmission developers seeking regional cost allocation. FERC accepted the ISO’s proposal that the process for deciding the cost allocation method run in parallel with state siting proceedings.

FERC also:

Accepted NYISO’s revisions clarifying how it will review transmission owners’ local transmission plans to determine whether alternative transmission solutions might meet reliability needs. FERC noted that NYISO and the Long Island Power Authority have agreed to tariff revisions that allow LIPA to determine whether “a proposed transmission need driven by public policy requirements requires a physical modification to transmission facilities located solely within the Long Island Transmission District, while also allowing the New York [Public Service] Commission to determine that a transmission need driven by public policy requirements identified by LIPA is a regional transmission need driven by public policy requirements.”
Accepted NYISO revisions on who may qualify as an approved transmission developer. A prospective transmission developer will be allowed to submit a detailed plan for financing, developing, constructing, operating and maintaining a transmission facility. The ISO may require information about transmission facilities that the prospective developer has already constructed.
Ordered NYISO to treat whether or not a nonincumbent developer has received its siting permits and other authorizations under New York state law as just one factor in the ISO’s selection process.
Ordered revisions to clarify that only disputes within the New York PSC’s sole jurisdiction may be subject to judicial review in state courts.

April 21, 2015

Consumers Energy, Wolverine Power OK’d to Reclassify Facilities as Transmission Assets

By Chris O’Malley

The Federal Energy Regulatory Commission on Thursday approved requests by two Michigan electric utilities to reclassify a number of distribution facilities as transmission assets within MISO.

FERC granted requests by Consumers Energy (ER15-910) and Wolverine Power Supply Cooperative (ER15-976). Consumers initially filed its reclassification request with the Michigan Public Service Commission, which last October approved a settlement (U-17598) between the utilities and Michigan Electric Transmission Co. (METC). The PSC approved a settlement over Wolverine’s reclassification of the assets from “excluded transmission” to “included transmission” in January (U-17742).

Consumers transferred its transmission assets in 2001 to then-subsidiary METC. A year later, it sold METC to another company, which sold it to current owner ITC Holdings.

In 2012, however, ReliabilityFirst Corp. informed Consumers that its audit had determined that a small set of the company’s distribution facilities were actually transmission facilities.

Consumers said its own analysis confirmed RFC’s findings and identified other assets that it said were similarly misclassified.

In total, Consumers said, the facilities to be reclassified have a net value of $34 million, representing 1.32% of Consumers’ distribution plant. They include equipment in 69 substations on 138-kV transmission lines, 65 138-kV line segments and six substations connecting those lines to Consumers’ bulk power substations.

Consumers noted that FERC previously stated that the 100-kV threshold has been among the factors in determining whether an asset is part of the bulk electric system.

Consumers plans to sign the MISO Transmission Owners Agreement and will join the Michigan Joint Zone, under MISO Rate Schedule 11. FERC also ordered Wolverine to include its reclassified facilities in the Michigan Joint Zone.

Ratepayer Implications Minimal

Consumers said the reclassification will benefit consumers by placing the transmission assets under “the functional control” of MISO. Becoming a transmission owner will allow it to more fully participate in the RTO, Consumers said.

Consumers said the increased costs of the reclassification are negligible, with an incremental revenue requirement of about $50,000, or .001% of Consumers’ $3.9 billion base rate revenue.

The utility noted that some of the assets are used to provide wholesale distribution service. “To avoid a potential double recovery, Consumers will remove the applicable assets from the wholesale distribution service rate and include them instead under its forthcoming transmission rates under the MISO Tariff.”

Wolverine also said a portion of its reclassified assets are also used to provide wholesale distribution service. To avoid a double recovery, Wolverine said it will coordinate with MISO to separately submit a filing to terminate its wholesale distribution service rate with the Zeeland Board of Public Works.

Wolverine said the net plant value of its updated list of included transmission facilities is $249.91 million, or an increase of nearly $16 million.

Tom King, Wolverine’s director of regulation and policy, told RTO Insider that the co-op is still calculating the impact of the change but expects the reclassification to be positive for its members.

Consumers officials could not be reached for comment.

April 21, 2015January 3, 2024

Company Briefs

The Tennessee Valley Authority has purchased a 700-MW gas-fired combined-cycle plant in Ackerman, Miss., from Quantum Choctaw Power. The plant is a two-one-one configuration and is the sixth combined-cycle plant TVA has purchased or built since 2007. TVA said in February, when it announced board approval of the purchase, that it would pay $340 million for the plant. The authority is retiring many of its coal units and either building or purchasing gas-fired generation in an attempt to meet emissions mandates.

Quantum Choctaw was owned by Quantum Utility Generation, an independent power producer that has coal- and gas-fired plants in Florida, Virginia and Mississippi, a solar project in Guam, and wind energy projects in Connecticut, Pennsylvania, Maine and Minnesota.

More: The Chattanoogan

TVA Has No Plans to Restart Construction of Bellefonte

The Tennessee Valley Authority’s 20-year plan for electricity generation sees the possibility of uprates at existing, operating nuclear stations and probably more natural gas and renewable generation, but its dormant Bellefonte nuclear plant doesn’t fit into any of those plans. The authority’s draft integrated resource plan is the subject of public hearings before it goes to the TVA board for a final vote in August.

Construction of the Bellefonte plant began near Hollywood, Ala., in 1974, but was abandoned in the 1980s after an investment of about $4.5 billion. The authority voted to restart construction of the plant in 2011, but that plan was killed in the face of slumping power demand the next year. The authority decided to go ahead with plans to complete Watts Bar Unit 2, another reactor that had been started in the previous century and then stopped. It is currently scheduled to go online by the end of this year.

More: Huntsville Times

National Grid Starts Construction on Advanced-Technology Solar Project

National Grid is starting construction of a 650-kW solar facility in Massachusetts that will test advanced technology ahead of the company’s plan to build 16 MW of solar generation in 19 sites in that state. The pilot project will test the use of new inverters, a vital component of the process of feeding solar energy into the grid. The move is part of the utility’s effort to contribute to the state’s goal of having 1,600 MW of solar by 2020. Much of the company’s efforts so far have been on connecting third-party solar generation to the grid, although it has solar generating facilities in five Massachusetts towns.

More: FierceEnergy

AWEA: Wind Industry Added 23,000 Jobs in 2014

The wind industry added 23,000 jobs in 2014, raising the total to 73,000 positions, according to the American Wind Energy Association. In its 2014 report, AWEA said 12,700 MW of wind projects were under construction as this year began. “These results show that extending the Production Tax Credit for wind power in 2013 was good for business in America,” AWEA CEO Tom Kiernan said. “We’ve got a mainstream, Made-in-the-USA product that supports jobs in every state and is gaining momentum. With a more predictable policy, we can add more jobs and keep this American success story going.”

More: PennEnergy

FirstEnergy’s Beaver Valley Loses Unit to Bad Pump Bearing

One of the reactors at FirstEnergy’s Beaver Valley nuclear station near Shippingport, Pa., went offline Wednesday when a pump supplying non-radioactive water to the steam generators shut down, probably due to a bad bearing. One of the two pumps serving Unit 1 showed signs of failing, and workers shut the reactor down at about 4 a.m. Repairs will take several days, a company spokeswoman said Thursday. Company officials said the other pump could serve the reactor at only 50% capacity.

More: PennEnergy

FE Delays Bruce Mansfield Decision Because of Possible PJM Auction Delay

FirstEnergy has decided to put off a final decision on whether to invest in a dewatering facility for coal ash control at its Bruce Mansfield coal-fired power plant until it knows when PJM’s annual capacity auction will be held. The company wants to see if the plant would clear the auction before deciding whether to invest in the dewatering facility. PJM has asked FERC for permission to delay the annual action, usually held in May, pending final commission rulings on its Capacity Performance proposal. FirstEnergy says it will now make the decision sometime this summer.

More: Pittsburgh Business Times

FirstEnergy Closes 3 Ohio Coal Plants

FirstEnergy, saying it was better to retire aging coal plants than retrofit them to make them conform to emissions mandates, has closed three coal-fired plants in Ohio.

The Ashtabula plant on the shores of Lake Erie, Lake Shore and Eastlake plants, all in northern Ohio, were shuttered last week. They were part of a list of nine the company announced in 2012 it would be retiring. Six of those nine have been decommissioned already. These are the last of that original list. The retirement of the final three was delayed until improvements could be made to transmission lines to accommodate the transmission of power in the absence of those plants. That work was completed at the cost of about $263 million, company spokeswoman Stephanie Walton said.

“There will be a period of shutdown activity, then the plant will be put into a safe and environmentally secure mode,” Walton said, describing the process for the Ashtabula plant.

More: Star Beacon

PPL Retiree Loses Bid to Have NRC Review Nuke Transfer Decision

The Nuclear Regulatory Commission has denied a request made by a former PPL employee to have the commission review its decision to transfer the operating licenses for the company’s sole nuclear plant to a projected merchant generation spinoff. Douglas B. Ritter asked the commission to hear arguments on the transfer, which the commission just formally approved.

PPL and assets associated with Riverstone Holdings are spinning off and forming Talen Energy. Ritter had raised questions about the Susquehanna nuclear plant’s operation under the new ownership, and about the plant’s decommissioning funds and waste storage. The commission based its decision on the lack of “admissible contention” in Ritter’s request.

“I’m disappointed that those issues have not been addressed publicly by the NRC,” said Ritter, who worked for 34 years at PPL and lives about four miles from the plant. “I feel like we the public are being kept in the dark by the NRC, but that’s big business, I guess.”

PPL said it expects to close on the Talen arrangement by the end of the second quarter.

More: The Morning Call

PPL Montana to Sell Retired Plant, Equipment

PPL Montana announced that it wants to sell the land, buildings and equipment of its retired J.E. Corette Steam Electric Station. The 153-MW plant, on 74 acres along the Yellowstone River near Billings, was built in 1968 and shut down last month. The company said its decision to retire the plant was based on the high cost of upgrades that would have been necessary to make it comply with emissions rules.

More: Great Falls Tribune

NextEra to Build 81-MW Solar Plant in Arkansas

NextEra Energy Resources is building an 81-MW solar plant in Arkansas County, Ark. The facility, in the Grand Prairie region of the county, will be the largest solar facility in the state. Entergy Arkansas has signed a 20-year power purchase agreement to buy the plant’s electricity, and a new substation will be constructed to transmit the power to Entergy Arkansas’ system. NextEra has applied with the state Public Service Commission to gain approval for the plant. Entergy and NextEra said the plant will be operational by mid-2019.

More: Entergy

ATC Names Mike Rowe as New CEO

Mike Rowe, an expert in asset management and construction, has been named the new CEO of American Transmission Co. Rowe will be taking the position of John Procario, who has headed up ATC since 2009. Procario announced his plans to retire last year.

Rowe has been with the Pewaukee, Wis.-based company for the past eight years, where he started as the vice president of construction, and later moved on to head the Asset Management, System Operations and Transmission Planning departments. He was promoted to executive vice president and chief operating officer in 2012. Before coming to ATC, Rowe was director of Engineering & Asset Management for Kansas City Power & Light. Before that, he spent 22 years with Commonwealth Edison in Chicago.

More: American Transmission Co.

NRG Pumps More Capital into Residential Solar

While many utilities are fighting the expansion of residential solar through challenges in state legislatures, NRG Energy is doubling down on its investment in that area. Having already fielded a company that specializes in home solar installations, NRG Home Solar, the energy giant announced it is pumping yet more money into the business. The company and its investment arm, NRG Yield, have formed a partnership that will invest up to $150 million in cash into Home Solar.

“With the completion of this partnership between the companies, we initiate a new phase in the growth strategy of the NRG Home business unit and NRG Yield,” says David Crane, CEO of NRG and chairman and CEO of NRG Yield.

More: Solar Industry

MYR Group Buys Eversource’s Transmission and Distribution Co.

MYR Group is buying E.S. Boulos, Eversource Energy’s electrical contractor that specializes in transmission, distribution and substation design and construction. ESB is headquartered in Westbrook, Maine. It was purchased by Eversource in 2001 and operated as a non-regulated company. Industry reports say the Illinois-based MYR is paying $11.4 million for the company.

More: Virtual Strategy

Millstone Nuke Worker Says He Was Fired for Reporting Co-worker’s Drug Use

A worker at Dominion Resources’ Millstone nuclear station in Connecticut told Nuclear Regulatory Commission officials that he was fired in retaliation for reporting a co-worker’s narcotic use. “I got fired for bringing up a safety issue, and you, the NRC, need to support me,” Stephen Lavoie said during the agency’s annual meeting with the Connecticut Nuclear Energy Advisory Council. NRC officials promised to look into Lavoie’s allegation. But Millstone spokesman Ken Holt said Lavoie was laid off because the demand for insulation workers had dropped. An independent investigator looked into Lavoie’s claim and found nothing to substantiate it, Holt said.

More: The Day; CBS Connecticut

Dominion Boosts Solar Fleet with Purchase of 20-MW Georgia Facility

Dominion Resources has purchased a 20-MW solar facility in Georgia, bringing the total amount of solar generation in its stable to 364 MW at sites throughout the U.S. Dominion paid an undisclosed amount for the Richland Solar Center in Twiggs County, Ga., from HelioSage Energy. It also secured a 20-year power purchase agreement with Georgia Power. David A. Christian, CEO of Dominion Generation, said the company wants to have 625 MW of contracted solar generation by the end of 2016. Dominion has set a goal of developing up to 400 MW of solar generation in Virginia alone by 2020.

More: Atlanta Business Journal; Street Insider

EPRI Names Gil Quiniones New Board Chairman

The Electric Power Research Institute has elected Gil Quiniones chairman of its Board of Directors. Quiniones is president and CEO of the New York Power Authority, the nation’s largest state-owned electric utility. Current board member Patricia Vincent-Collawn, CEO of PNM Resources, was elected vice chair. Five new members were also elected: Lisa Johnson, CEO of Seminole Electric Coop.; Warner Baxter, CEO of Ameren; Mark McCullough, executive vice president of generation at American Electric Power; William Spence, CEO of PPL; and Dr. Seok Cho, CEO of Korea Hydro and Nuclear Power.

More: EPRI

Investor in McClendon Firm Settles Chesapeake Claim for $25M

Energy & Minerals Group has settled a trade secrets lawsuit by paying Chesapeake Energy $25 million. Chesapeake claimed that former CEO Aubrey McClendon stole trade secrets from Chesapeake when he left to form his own firm, American Energy Partners. EMG is a major investor in American Energy Partners.

EMG had earlier described the claims against McClendon as meritless and has invested nearly $3 billion in McClendon-directed ventures. Chesapeake claimed that the information was used to acquire Utica Shale field drilling rights. The settlement releases one of American Energy Partners’ affiliates, American Energy-Utica, harmless in exchange for the $25 million and drilling rights to 6,000 acres.

The full terms of the settlement remain confidential, but the settlement size says a lot, one expert says. “Nobody settles a lawsuit by paying $25 million and signing over 6,000 acres of valuable oil and gas leases unless they are at least a little bit troubled by what they have learned,” said Erik Gordon, a professor at the University of Michigan.

More: Reuters

Dynegy CEO Says Coal Plants Ready to Meet Emissions Regs

Dynegy CEO Robert Flexon said in an interview last week with Bloomberg News that its coal-fired generation fleet is ready to meet the looming increased emissions rules. While other companies, such as American Electric Power, are retiring aging units, Dynegy has gone on a buying spree of coal-fired generation or already retired aging plants in advance of the Environmental Protection Agency’s Mercury and Air Toxics Standards implementation.

“Coal accounts for 48% of Dynegy’s generating capacity of 25,758 MW, which is enough to power 21 million homes,” Flexon said. “All of the plants are compliant with the MATS rules and the EPA’s cross-state pollution regulations that started to get implemented this year,” he said.

He also said he expects PJM to receive approval to delay its annual capacity auction while Capacity Performance rules are finalized.

More: Bloomberg News

Compiled by Ted Caddell