UPDATE: PJM Capacity Prices Up 37% to $165/MW-day

By Rich Heidorn Jr. and Suzanne Herel

PJM’s first auction under its new Capacity Performance rules saw prices rise 37% to $164.77/MW-day in most of the RTO, while the ComEd zone broke out at $215 and Eastern MAAC hit $225.42.

The Base Residual Auction procured 166,837 MW of capacity for delivery year 2018/19, giving the RTO a 19.8% reserve margin, well above the target of 15.7%.

Price Premiums

Capacity Performance resources, which represented more than 80% of capacity acquired, were priced at a $15/MW-day premium to base capacity in most of the RTO. In the winter-peaking PPL locational deliverability area (LDA), the premium was $90.

In the BGE and PEPCO LDAs, base demand response and energy efficiency priced at a discount of more than $100 compared with CP resources.

While CP resources are subject to stiff penalties for failure to perform during emergencies year-round, base capacity is only liable if it fails to perform during the summer peak period.

3 Exelon Nukes Fail to Clear

Clearing prices were generally in line with analysts’ expectations. But that was not enough for Exelon, which announced Monday that three of its nuclear plants — Quad Cities in Illinois, Oyster Creek in New Jersey and Three Mile Island in Pennsylvania — did not clear.

Oyster Creek is scheduled to be retired by 2019. Exelon said it expects to make a decision on retiring Quad Cities, which has lost about $300 million over the last six years, by September.

Spokesman Paul Elsberg declined to specify the price at which Exelon offered the three plants into the auction, citing “competitive reasons.” He said all of Exelon’s other nuclear plants in PJM cleared. That includes the Byron plant in Illinois, which the company says also has been losing money.

In last year’s auction, Oyster Creek, Byron and Quad Cities all failed to clear. But analysts said the company would earn almost $150 million more in capacity revenue from planning year 2017/18 than it would have if all of the company’s capacity had cleared because the additional supply would have reduced clearing prices. (See How Exelon Won by Losing.)

New Capacity

The auction, which ran from Aug. 10-14, also resulted in 3,500 MW of new capacity, most of it gas-fired, a decline from the 5,900 of new entry from last year’s auction.

Analysts cited higher interest rates, lower spark spreads and the short runway to the auction following FERC’s June order approving CP as reasons for the decline.

More than 4,100 MW of new capacity offered into the auction, all but 600 MW clearing. The new cleared capacity includes 2,919.3 MW from new gas-fired combined-cycle generators and combustion turbines, and 587.6 MW from uprates to existing units. EMAAC and MAAC each cleared 526.7 MW of new units, while the rest of the RTO cleared 1,865.9 MW of new generation.

Public Service Enterprise Group announced Monday that its planned 540-MW combined-cycle plant in Woodbridge, N.J., was the winner in EMAAC.

Analysts for UBS Global Research said the other new combined-cycle plants were likely in Ohio or West Virginia, where they can obtain gas from the Utica shale play. They cited four proposed plants that had been seeking financing: Moundsville, 550 MW in West Virginia; Advanced Power’s 700-MW unit in Carroll County, Ohio; Clean Energy Future’s 800-MW facility in Lordstown, Ohio; and the 550-MW NTE Energy unit in Middletown, Ohio.

Imports

Generation imports clearing rose to almost 4,700 MW, a slight increase over last year, when PJM imposed capacity import limits because of concerns that transmission constraints might prevent some external resources from being able to deliver power into the RTO.

Most of the imports clearing came from west of PJM and all met the requirements for exceptions to the import limits, meaning they will be paid the RTO clearing price. To qualify for the exception, they were required to have pseudo-ties allowing them to be treated as internal generation, subject to redispatch and locational pricing, have long-term firm transmission service and agree to abide by must-offer requirements.

Demand Response

Demand-side resources rebounded slightly following two straight years of decline from their peak for delivery year 2015/16.

More than 11,000 MW of demand response cleared, 1,484 of it CP — more annual DR than had ever cleared before, PJM said. Of 1,247 MW of energy efficiency cleared, 887 was CP. DR offers increased 3.4% from last year, with 95% clearing.

“That’s in the face of the uncertainty caused by the ongoing Supreme Court review of the EPSA case,” Stu Bresler, senior vice president for markets, said in a press conference late Friday. (See FERC Orders PJM to Include DR, EE in Transition Auctions.)

“I think we’ll see quite a bit of innovation at the DR level in order to figure out ways to aggregate resources and continue to participate and be Capacity Performance going forward,” Bresler added.

Demand response aggregator EnerNOC saw its stock rise 3.34% Monday to close at $8.35, after an intraday high of $8.71.

Renewables

Renewables with a nameplate capacity of more than 14,000 MW also cleared, including 6,600 MW of wind, 1,450 MW of it as CP.

About 857 MW of wind capacity offered into the auction — all of it clearing — an increase of almost 7% over last year. Based on wind’s 13% capacity factor, that translates to nameplate capacity of 6,594 MW.

Almost 184 MW of solar resources offered and cleared (484 MW of nameplate capacity at a 38% capacity factor), a jump of 58% from last year.

“An extremely small portion of that cleared as capacity performance, due, I would imagine to the risk of nonperformance in the winter months,” Bresler said.

Prices ‘as Expected’

Bresler said he was pleased that the RTO clearing price was in line with analysts’ expectations, saying it was an indicator of the “transparency” of the PJM market.

The $10.9 billion total cost of the capacity procured was a $3.4 billion increase over 2014 “right in the middle” of the $2 billion to $5 billion range PJM and the Market Monitor had predicted in a joint analysis, Bresler said.

Bresler acknowledged that the discount between CP and base capacity was generally smaller than the RTO and outside analysts had expected.

“But given the fact that we’re heading to 100% Capacity Performance two auctions from now … I don’t think that that result is bad at all. In fact I think that it’s a good result because the vast majority of resources offered at CP and wanted to take on that performance requirement.”

ComEd Break Out

ComEd prices broke out from the rest of the RTO as a result of reduced transmission capacity into the zone from MISO to the west, Bresler said.

Bresler said the capacity emergency transfer limit (CETL) into the ComEd LDA was reduced by 25% from 2014 due to several factors, including changes in MISO’s transmission system west of the LDA and “many changes” in firm transmission service reservations into and out of PJM from MISO and other areas.

“The net results of those combinations of factors was that when we did the transfer analysis into the ComEd zone we hit constraints to the western side of the ComEd zone much sooner than we have in the past, which required us to funnel the imports in the analysis from just the eastern direction. …That meant we hit a binding transmission limit for the transfers at a lower level.”

Consumer Reaction

The ComEd increase did not go over well with the Citizens Utility Board, a Chicago-based consumer group.

“For the second time in less than a year, consumers in the state — first in central and southern Illinois and now in northern Illinois — face significantly higher electric bills because of a flawed power-pricing system,” said CUB Executive Director David Kolata, in a reference to MISO’s capacity auction results in April, which saw a nine-fold increase in Illinois. (See Ill. AG Joins Call for Changes to MISO Auction Rules.)

“Illinois’ electricity market is not working well for consumers. This price spike is one more red flag that the rules governing the capacity auction open the door for power generators like Exelon, NRG and Dynegy to make windfall profits.”

CUB estimates that a typical family in ComEd will pay $3 to $7 per month more as a result of the PJM capacity results.

Comparison to 2014 Results

In addition to the impact of the new CP requirements, PJM said the auction results reflected changes approved by FERC in November to the RTO’s variable resource requirement (VRR) curve shape and gross cost of new entry (CONE) values (ER14-2940).

In last year’s auction for delivery year 2017/18, annual resources cleared at $120/MW-day in most of PJM following rule changes that limited DR and generation imports. That represented a doubling of prices in Virginia, West Virginia, North Carolina and much of Ohio (from $59/MW-day in the 2013 BRA) and little change in MAAC and ATSI. The PSEG zone ($215/MW-day) was also flat.

Last year’s rebound in prices were still below the $136/MW-day for 2015/16 and the all-time high of $174 set for delivery year 2010/11.

PJM will conduct transitional auctions to integrate CP resources into years for which the BRAs have already have been held, with the 2016/17 auction on Aug. 26-27 and the 2017/18 on Sept. 3-4.

In developing the CP proposal, Bresler said PJM officials surveyed natural gas generators to determine the cost of adding dual fuel capability. Lack of gas was one of the problems that contributed to the extraordinarily high forced outage rates during the polar vortex of January 2014.

“And the answers that we received back centered right around $40 or so per megawatt-day,” Bresler said. “So the increase we saw from last year to this year of about $45/MW-day really [was] very consistent with what we expected.”

August 18, 2015

Northern Pass Opponents Want More of Line Buried

By William Opalka

Eversource Energy last week proposed burying 60 miles of its proposed Northern Pass power line from Canada, but some critics insist the entire route be underground. Others, including New Hampshire’s governor, say that while the revised route is an improvement, they are hopeful for a plan with even fewer visual impacts.

Eversource subsidiary Northern Pass Transmission had previously proposed burying 8 miles of the now 192-mile route, but the company bowed to pressure and removed above-ground lines through the White Mountain National Forest and other sensitive areas.

On Thursday, the Appalachian Mountain Club naturalists group, which has been a vocal critic, said it and its allies should take some credit for the “dramatic shift” but that Eversource could do more. “For years the company has claimed that burial of the line was technically impossible and prohibitively costly … So while we are glad to see this additional 52 miles of the project buried, the question remains: Why not all of it?”

Jack Savage, speaking for the Society for the Protection of New Hampshire Forests, said “Northern Pass deserves credit,” but more must be done.

“Given that the new technology is apparently allowing Northern Pass to propose burying another 52 miles without increasing the overall project cost of $1.4 billion, there would seem to be opportunity for more burial along roadways,” he added.

Eversource said it doesn’t need to make any more concessions.

“There are going to be folks who’ve ardently opposed this from the outset and perhaps are going to look at it as an opportunity,” Bill Quinlan, president of the utility’s New Hampshire operations, told the New Hampshire Union Leader on Wednesday. “They’re going to say, ‘We got them to move this far; we can get them to move further,’ and I think that’s unlikely.”

Political Leaders Split

Political leaders in the state are divided.

“I have made clear that if Northern Pass is to move forward, it must propose a project that protects our scenic views and treasured natural resources while also reducing energy costs for our families and businesses,” Democratic Gov. Maggie Hassan said in a statement. “This route is an improvement over the previous proposal.”

She said dialogue from the company must continue and include “further improvements.”

However, the change was enough to win the support of Charles Morse (R-Salem), president of the New Hampshire Senate. “The changes announced by Eversource represent a major improvement to the project and a great opportunity for our state, and I am pleased to be able to support the Northern Pass project as now revised,” Morse said.

Eversource says it will file plans in October with the New Hampshire Site Evaluation Committee, a panel including members of the Public Utilities Commission, other state officials and members of the public. The company hopes to start construction in 2017 and have the line in service in 2019.

Capacity Reduced

The decision to bury more of the line forced a reduction in its capacity from 1,200 MW to 1,000 MW.

northern pass — Revised path for Northern Pass shows buried sections in yellow.

Rerouting of the line makes it 5 miles longer, up from the original 187 miles that included underground lines only near the Canadian border. The additional underground miles would be buried along existing roads through the White Mountain National Forest, Franconia Notch and the Appalachian Trail.

A draft environmental impact statement released by the U.S. Department of Energy last month said the cheapest alternative would also have the most visual impact on natural areas. (See Price Tag Likely to Rise for Northern Pass Transmission Line.)

The company said the price tag of the project will remain at about $1.4 billion. Spokesman Martin Murray said the Northern Pass will use HVDC Light technology from ABB that is cheaper and more efficient than conventional HVDC cable. Reducing the project’s capacity also keeps its cost stable, Murray added.

Eversource has said burying the entire route would double its cost and make it economically unfeasible. About 400 above-ground structures will be eliminated by the new plan, with 80% of the route along existing roads and company rights of way.

The company said the additional underground construction will result in the longest HVDC underground land cable installation in North America.

But that comes at a cost. According to the draft EIS, the “DOE has determined that extended burial of a transmission line with a capacity of 1,000 MW would be practical and technically feasible. The burial of a transmission line with a capacity of 1,200 MW for extended distances would not be feasible.”

The new underground route includes most of alternative 5c and elements of alternative 4c from the draft EIS.

The developers say the project, which they have dubbed the Forward New Hampshire Plan, will bring economic benefits of more than $3 billion to the state. Lower wholesale energy prices in the ISO-NE market are expected to save New Hampshire customers $80 million annually. Additionally, a 100-MW power purchase agreement with Hydro Québec is expected to reduce consumers’ yearly bills by another $10 million.

The line is projected to create 2,400 construction jobs and generate $30 million in annual tax revenue. The developers also have promised a $200 million Forward NH Fund to support initiatives in tourism, economic development, community investment and clean energy innovation.

August 18, 2015June 15, 2023

PJM Prices Down 31% from Record-Breaking 2014

By Rich Heidorn Jr.

PJM energy market prices were down almost 40% in the first half of 2015 compared with 2014, while capacity and transmission service charges rose by double digits, the Independent Market Monitor reported last week.

The load-weighted average real-time LMP, which hit $69.92/MWh in the first six months of 2014 — largely due to the record-breaking polar vortex in January — dropped to $42.30/MWh in 2015, the Monitor reported in its second-quarter State of the Market report.

Uplift charges dropped by $590.1 million (71%) in the first six months of 2015, while congestion costs were down $523.6 million (36%).

Auction revenue rights and financial transmission rights revenues offset 88% of congestion costs in the day-ahead energy market and the balancing energy market for the 2014/15 planning period.

Including capacity, transmission and other charges, prices were down almost 31%, from $88.90/MWh in 2014 to $61.61/MWh this year.

Withholding Concerns

The Monitor said prices reflected short-run marginal costs except during high demand hours in February 2015, which “raises concerns about economic withholding,” it said. The Monitor reported similar concerns for January 2014.

“Overall the market structure of the PJM aggregate energy market remains reasonably competitive for most hours, although the market structure during high demand hours remains a concern,” the report said.

“The performance of the PJM markets under high load conditions raised a number of concerns related to capacity market incentives, participant offer behavior in the energy market under tight market conditions, natural gas availability and pricing, demand response and interchange transactions.

“In particular, there are issues related to the ability to increase markups substantially in tight market conditions, to the uncertainties about the pricing and availability of natural gas, and to the lack of adequate incentives for unit owners to take all necessary actions to acquire fuel and generate power rather than take an outage.”

Net revenues were lower for all new entrant generation in the first six months of 2015 than in 2014. But net revenues for new entrant gas and coal units were generally higher in 2015 than in the first six months of every other year since 2009.

Coal Loses Generation Share; Solar up 30%

The RTO saw gas displacing coal, with coal-fired generation down 16% (to 39% of the total) and gas-fired generation up 29% (21% of the total). Solar net metering generation rose 30% to 262 GWh but remained only a flicker of the total (0.07%).

Recommendations

The report includes four new recommendations:

Energy Market: PJM should remove non-specific fuel types such as “other” or “co-fire other” from the list of fuel types associated with their price and cost schedules. The Monitor recommends that PJM require market participants to make available at least one cost schedule with the same fuel type and parameters as that of their offered price schedule. (Priority: Medium)
Demand Response: DR resources should be required to notify PJM of material changes affecting the capability of the resource to perform as registered. (Priority: Medium)
Ancillary Services: PJM should report the reason for every hour in which PJM dispatch increases day-ahead synchronized reserve megawatts. (Priority: Medium)
Planning: PJM should enhance the transparency and queue management process for merchant transmission investment to remove barriers to competition. (Priority: Medium). (See related story, PJM Monitor Asks FERC to Resolve TransSource Dispute.)

August 18, 2015June 15, 2023

John Citrolo, PSEG Stakeholder, Mourned at PJM

John C. Citrolo, markets director for PSEG Energy Resources and Trade and a regular attendee at PJM stakeholder meetings, died Aug. 2. PJM’s Market Implementation Committee marked his passing with a moment of silence at its meeting last week.

Known to his friends as “Jay,” the 49-year-old Citrolo lived in Southampton, N.J., with his wife Sandi and his dogs, Jada and Mya.

He was a graduate of Upsala College, where he played football, and earned a master’s degree in economics at Temple University. Prior to joining PSEG, his career in the power industry included jobs with the State of Delaware, Conectiv Energy, Calpine and Net2000. He was also the co-founder and co-owner of the Medford Gym in Medford, N.J.

Surviving, in addition to his wife, Sandra Grungo Citrolo, are his father, John Citrolo Sr.; his stepmother Sally; his sister, Mary E. “Betsy” Citrolo; mother- and father-in-law, Sandra and Burt Roff; as well as six nieces and nephews. His mother, Beverly Young, died in 2013.

Memorial contributions in John’s name can be made to Joe Joes Place, an animal rescue organization, at 7 Tidswell Ave., Medford, NJ 08055.

More: Legacy.com

August 18, 2015June 15, 2023

PJM Opens Capacity Auction Under New Rules

By Rich Heidorn Jr.

PJM’s biggest news story of the year may well come Friday with the release of the results from last week’s capacity market auction.

The 2018/19 Base Residual Auction – the results of which are due Friday afternoon — will be the first under the new Capacity Performance rules approved by FERC in June. The rules increase incentives for high-performing resources and penalties for poor performers, largely eliminating force majeure provisions under a “no excuses” policy.

The auction, which ran from Aug. 10-14, was postponed from May due to delays in winning FERC approval.

The changes will be phased in beginning with the 2018/19 and 2019/20 delivery years, when PJM hopes to make at least 80% of its procurement CP resources, with the remainder “Base Capacity” subject to lower performance expectations. The transition will be complete for 2020/21, when PJM expects 100% of capacity to be CP.

FERC Approval

The commission approved PJM’s proposal by a 4-1 vote June 9, citing evidence of increased generator forced outage rates since 2007. (See FERC OKs PJM Capacity Performance: What You Need to Know.)

It accepted PJM’s prediction that resource performance will continue to worsen without changes, as the RTO sees much of its coal fleet retire, replaced largely by natural gas-fired generation. The majority rejected the arguments of opponents who said the changes were not necessary because generator performance improved last winter following more modest changes, including testing of seldom-used units.

Chairman Norman Bay dissented, saying the proposal will continue to allow generators to profit from poor performance while potentially saddling ratepayers with billions in excessive capacity costs annually.

Friction with Stakeholders

The ruling was followed by a testy, six-hour stakeholder meeting over CP manual changes June 18 that left some stakeholders complaining that the RTO had not thought through all the details. Criticism continued in July, as some members warned PJM officials that the way the RTO plans to calculate CP could lead generators to ignore dispatch instructions to avoid penalties. (See PJM Members: Capacity Performance Penalties May Hurt Dispatch Discipline.)

FERC issued a procedural order July 28 saying it needed more time to consider rehearing requests of its June 9 order from state regulators, consumer advocates, generators and the Independent Market Monitor.

Higher Costs

According to a cost-benefit analysis released in October by PJM and the Monitor, CP could cost ratepayers as much as $6 billion over the next four years, with long-term costs of as much as $700 million annually.

PJM says the increased performance will result in increased monthly capacity costs of about $2 to $3 per household beginning in 2018, assuming average winter and summer weather. In a year of extreme weather, officials say, it would result in net savings because the increased capacity costs will be more than offset by reduced energy costs.

For More Information

PJM’s Board of Managers filed the Capacity Performance proposal in December to increase the reliability expectations of capacity resources with a “no excuses” policy that would result in larger capacity payments and higher penalties for non-performance. (See What You Need to Know about PJM’s Capacity Performance Proposal.)

FERC’s June 9 order required several significant changes from PJM’s Capacity Performance proposal. (See What is Changing in PJM’s Proposal?)

August 18, 2015

PJM Monitor Asks FERC to Resolve TransSource Dispute

By Michael Brooks

PJM’s Independent Market Monitor has called on FERC to settle a dispute between PJM and a transmission developer, saying the RTO’s unwillingness to release relevant files is unfair to the developer and impeding the Monitor’s own attempts at resolution (EL15-79).

TransSource — not to be confused with Transource Energy, a partnership of American Electric Power and Great Plains Energy — asked FERC in June to order PJM to provide the company with data showing how the RTO calculated network upgrade costs in its system impact studies for several of its auction revenue rights requests. (See Transmission Developer: PJM TOs Inflating Upgrade Costs for ARRs.)

PJM responded by asking FERC to dismiss the complaint. The RTO insisted it had provided TransSource with all the relevant data, and that the specific files that the company is requesting were not used in the cost calculations. These files, called PLS.CADD, are held by transmission owners and are “highly confidential” according to PJM.

The Market Monitor told FERC in an Aug. 6 filing that it “is concerned that the primary defense raised by PJM is that the complainant does not have the facts sufficient to support its case, and that the claims amount to overly broad generalizations, when the complainant’s case is primarily based on TransSource’s claims that they have not been provided adequate facts to assess the determination to increase assigned costs to TransSource.”

TransSource maintains that under the PJM Tariff and the Federal Power Act, it has a right to the PLS.CADD files. While the Monitor did not comment on specific Tariff or legal provisions, it agreed that TransSource should have access to the files.

“The complaint does not request substantive relief, but only that what appear to be reasonable requests for additional information be answered before TransSource is required to make financial commitments that TransSource is not be able to make unless and until those question are answered,” the Monitor said. It also said the fact that the files are held by the TOs, and not PJM, “is a major obstacle to a resolution.”

The Monitor said it would prefer an administrative law judge to handle hearing or settlement proceedings. In a filing last week, TransSource said it supported this idea.

TransSource “persists in making overly broad and vague accusations such as PJM ‘refused’ to provide any data,” PJM said. “Such accusations deny the commission a true and accurate picture as to exactly what data and assumptions TransSource was denied.” PJM also said that it had informed the company that if PLS.CADD files had been used in the studies, then the RTO would have ordered their release.

PJM also argued that the company lacked evidence for its other accusations, including that transmission owners Public Service Electric and Gas, PPL, Jersey Central Power & Light and Delmarva Power & Light intentionally inflated the costs of the network upgrades to make it impossible for TransSource to secure funding for them.

August 18, 2015June 15, 2023

Company Briefs

SunEdison has sold Dominion Resources a 50% interest in its 420-MW Four Brothers solar project in Utah.

Under the terms of the joint venture, Dominion will invest about $500 million to get 50% of the project equity and 99% of the federal and state tax benefits. SunEdison has secured necessary funding to complete the rest of the estimated $650 million facility. It is scheduled to be operating by mid-2016.

The project’s output is under contract with a 20-year power purchase agreement with Berkshire Hathaway Energy’s subsidiary PacifiCorp.

More: SunEdison; SeeNews Renewables

Overbuilt, We Energies Seeks to Sell Excess Capacity Elsewhere in Wisconsin

We Energies wants Wisconsin regulators to force two other utilities in the state to buy its excess power rather than building new gas-fired generating plants for $1.2 billion.

One of the utilities in need of new generation, Alliant Energy’s Wisconsin Power & Light, has applied for state approval to build a $750 million natural gas-fired plant in Beloit. Alliant said We Energies and its parent, WEC Energy Group, should have submitted its plan earlier and WEC now seeks to force a process in which it would be sole bidder to supply Alliant. The other utility seeking to build new generation is Wisconsin Public Service, which is owned by WEC.

We Energies said selling power to Alliant and WPS would allow the neighboring utilities to avoid the cost of construction and could provide We Energies customers some rate relief by selling excess power. The state Citizens Utility Board and the Wisconsin Industrial Energy Group issued a joint statement saying the proposal was worth considering.

More: Milwaukee Journal Sentinel

Ameren Withdraws Application for 2nd Callaway Nuclear Reactor

Ameren has withdrawn its application from the Nuclear Regulatory Commission for a second reactor at its Callaway Energy Center plant in Callaway County, Mo., after years of delay.

Ameren said its decision to abandon the project was based on its assessment of long-term capacity needs, declining costs of alternative generating technologies and the regulatory framework in Missouri. CEO Warner Baxter told analysts during the company’s second-quarter earnings call that it continues “to believe nuclear power must be an important clean energy source for our company and country.” Callaway was recently granted a 20-year license extension.

Ameren first filed its application for a second unit in 2008. The company teamed with Westinghouse in 2012 for a small modular nuclear reactor that would be about a fourth of the size of a conventional plant. After being passed over twice for federal grants, Ameren said it was “stepping back” from the project at the end of 2013.

More: St. Louis Post-Dispatch

Minnesota Co-ops Combine to Acquire Alliant Territory

Nobles Cooperative Electric, Federated Rural Electric and 10 other electric distribution cooperatives completed their acquisition of Alliant Energy’s electric service territory in southern Minnesota.

The acquisition transfers about 43,000 Minnesota Alliant Energy accounts to local electric cooperatives. According to Rick Burud, general manager of both Nobles Cooperative and Federated Rural, the transfer is a first of its kind. “It is a very unique situation for electric cooperatives to have the opportunity to purchase service territory from investor-owned utilities,” he said.

In 2013, the 12 cooperatives formed Southern Minnesota Energy Cooperative as the single point of contact for the purchase of electric service territory from Alliant. The acquisition process was approved by the Minnesota Public Utilities Commission, Iowa Utilities Board and FERC.

More: Daily Globe

ERCOT Names Bill Magness as Next President, CEO

ERCOT’s Board of Directors selected general counsel Bill Magness to become the RTO’s next president and CEO. Magness, who is also currently senior vice president for governance, risk and compliance, will succeed Trip Doggett, who announced in June he plans to retire next year as president and chief executive. Doggett has been CEO since 2010.

“Bill’s leadership skills, as well as his significant executive experience at ERCOT, have positioned him to successfully lead ERCOT through an era of evolving changes in the energy industry,” ERCOT Board Chair Craven Crowell said. “He also understands the importance of — and is committed to — strong working relationships with stakeholders, the Public Utility Commission of Texas and the Texas Legislature.”

More: Houston Chronicle

World-Renowned Auction Expert Joins ERCOT’s Board of Directors

ERCOT approved Peter Cramton as the new independent member of its Board of Directors. An economics professor at the University of Maryland at College Park and a widely recognized expert in energy auctions, Cramton succeeds Michehl Gent, whose third and final term concluded in May.

The ISO said Cramton has played a lead role in the design and implementation of electricity and gas auctions in North America, South America and Europe since 2001. Cramton also chairs Market Design Inc., an economics consultancy that focuses on the design of auction and matching markets. “Peter is a pioneer in his field, and we are delighted to welcome him to ERCOT’s Board of Directors,” ERCOT Board Chair Craven Crowell said in a press release.

The Public Utility Commission of Texas, which oversees ERCOT, approved Cramton’s appointment to the board. State law mandates the board include five unaffiliated members, from which the chair and vice-chair are chosen.

More: ERCOT

Four Corners Resumes Operation Following Bomb Scare

Operations returned to normal at New Mexico’s Four Corners Power Plant last week following the discovery of three suspicious devices in one of the plant’s three active units.

An FBI spokesman said the three devices, each a steel pipe with its ends capped, were hollow and did not contain explosive material. The devices’ discovery Aug. 3 led to an evacuation of all plant personnel. Operations did not resume until the following day.

The FBI said there was no indication the devices were related to explosions at two Las Cruces churches Aug. 2.

More: The Daily Times

Tres Amigas Posts $8.2M for PNM Tx Upgrades

Tres Amigas: Cancelled SPP Agreement ‘Not Significant’.)

CFO Russ Stidolph told Curry County, N.M., commissioners Aug. 4 that Tres Amigas has posted $8.2 million in collateral to begin making necessary upgrades for the Public Service Company of New Mexico grid.

Stidolph said Tres Amigas is working with land owners to acquire rights of way. He said he expects “significant progress” to be made with land owners in the next months.

More: Clovis News Journal

Arkansas Co-op Subsidiary to Add Solar

Arkansas Electric Cooperatives Inc. announced Aug. 12 that its Today’s Power subsidiary has reached an agreement to provide a 1-MW solar array for Tri-County Electric Cooperative of Hooker, Okla. The facility is projected to generate more than 50 million kWh over its 25-year useful life.

AECI, a utility service cooperative owned by 17 Arkansas electric cooperatives, launched Today’s Power in February to provide renewable energy solutions, energy efficiency programs and emergency backup generators for large commercial, industrial or utility customers. Today’s Power has an exclusive distribution agreement to promote and sell tenKsolar products in Arkansas, Tennessee, Mississippi, Louisiana, Oklahoma and Missouri.

More: Arkansas Business

Construction Begins on 300-MW SunEdison Texas Wind Farm

SunEdison Making $2B Bet on Wind in Midwest, Canada.)

South Plains II is expected to generate 1,200 GWh of energy each year, enough to power more than 90,000 homes and avoid the emission of 2 billion pounds of carbon dioxide. Hewlett-Packard plans to purchase 112 MW of the project’s capacity to power its Texas-based data centers. The remaining 188 MW of capacity will be sold to an affiliate of Citigroup, which is financing the project.

More: SunEdison

Hunt Family Buys EFH’s Oncor for $19 Billion

Hunt Consolidated Energy agreed to pay $19 billion for the transmission business Oncor, the jewel of Energy Future Holdings. Energy Future is selling Oncor as part of its bankruptcy proceeding.

Energy Future, formerly TXU, selected Hunt Consolidated among many other offers. Hunt Consolidated has been in the energy business in Texas for more than 80 years.

As part of the bankruptcy restructuring, Energy Future will spin out its competitive businesses — TXU Energy and Luminant — and turn over Oncor to Hunt Consolidated, which will manage the company out of the current Dallas headquarters. The deal still needs several legal and regulatory approvals. Oncor has more than 3 million customers in North and West Texas.

More: Texas Lawyer; Dallas Business Journal

FirstEnergy Announces Corporate Promotions

FirstEnergy has expanded the roles of several corporate executives in an effort to “support the company’s focus on customer service and cost management.”

Among those promoted are James Lash, president of FirstEnergy Generation, who will also serve as executive vice president of FirstEnergy. CFO James F. Pearson will see a bump up from senior vice president to executive vice president. Charles Lasky, vice president of fossil fleet operations, will shift to the human resources department as a senior vice president.

FirstEnergy also filled several vacant positions. Trent Smith, vice president of sales and marketing for FirstEnergy Solutions, will serve as supply chain vice president for the parent company, filling a void left by Gary Benz, who was named senior vice president of strategy in June. Gary Grant will take over as vice president of customer service at FirstEnergy Utilities, replacing Ronald Green, who is retiring after 38 years with the company.

More: FirstEnergy

Talen to Spend $100M to Add Gas to Brunner Island

The coal-fired Brunner Island power plant in York County, Pa., will soon be burning natural gas to help power its three generators.

New owner Talen Energy says it will spend $100 million to convert the plant to dual fuel, which includes building a 3-mile pipeline to tap into an interstate line. A Talen spokesman said the plant would still burn coal, but he could not say how much power would be generated by either fuel.

While Brunner Island is often listed among the dirtiest plants in the U.S., Talen said the plan isn’t being driven by the Environmental Protection Agency’s Clean Power Plan or any other environmental regulations. “The real driver behind this project is the long-term sustainability of that plant and 200 jobs,” spokesman Todd Martin said. The project is expected to be completed by spring 2017.

More: LancasterOnline

Bechtel Breaks Ground on Natural Gas Plant in Virginia

Construction company Bechtel is building a natural gas-fired plant in Leesburg, Va., which will generate enough power for 800,000 homes in Virginia and D.C.

The Stonewall Energy Center is expected to cost about $800 million and be completed by mid-2017. Bechtel has sold its interest in the project to Panda Power Funds, now the plant’s sole owner. A Panda Power spokesman said no new pipelines or transmission lines will be needed and that the plant will use the latest emissions-controlling technology.

More: The Washington Post

AEP Promotes Haynes to SVP of Strategic Initiatives

American Electric Power has promoted Stephan Haynes, vice president of strategic initiatives, to senior vice president of strategic initiatives. Haynes will continue his role as chief risk officer.

“Steve and his team have done an incredible job identifying, analyzing and developing mitigation strategies for risk events that could impact AEP,” CFO Brian Tierney said “He also has helped the company evaluate strategic opportunities to grow our business and to move our transmission joint ventures forward.”

Haynes has a bachelor’s in business systems analysis from Harding University and an MBA from Ohio State.

More: AEP

Dispute’s Resolution Sets Up Closure of New Mexico Plant’s Units

Public Service Company of New Mexico and four other parties signed an agreement to end their dispute over the future of the coal-fired San Juan Generating Station in northwestern New Mexico. The settlement potentially paves the way for the state Public Regulation Commission to approve PNM’s plan to shut down two of the power plant’s four generating units to meet federal haze regulations.

Environmental, clean energy and consumer organizations had opposed PNM’s proposals for San Juan, largely because the utility and its parent firm, PNM Resources, wanted to acquire 197 MW of excess coal generation that will be left behind in one of the two remaining generators. The new accord ends that opposition, allowing PNM to take ownership of the additional 197 MW to keep San Juan’s two remaining units fully operational.

The agreement must still be reviewed in a public hearing, now scheduled for Sept. 30, before the PRC makes a final decision.

More: The Albuquerque Journal

El Paso Electric Seeks Rate Hikes in Texas, NM

El Paso Electric has filed a rate increase request with the Public Utility Commission of Texas on Aug. 10 that would add $8.41 to an average residential customer’s monthly bill. The new rates would go into effect Sept. 14, although EPE said a months-long rate case might delay imposition of the increase until the second quarter of 2016.

EPE filed a separate rate case with the New Mexico Public Regulation Commission in May, asking for about $8.6 million that would result in a 9% increase to the average monthly residential bill for its customers in that state. Any approved increase in New Mexico would go into effect in 2016, officials said.

Utility officials said they are seeking to recover some of their infrastructure costs for the El Paso Montana Power Station and its transmission lines and a new operations center. The first two generating units at the Montana station cost about $206 million, with another $20 million for the transmission lines and $40 million for the operations center.

More: El Paso Times

August 18, 2015June 15, 2023

Northeast on Way to Compliance with Clean Power Plan

By William Opalka

When the Clean Power Plan was released last year, New York’s grid operator was concerned with its impact despite the state’s membership in a regional carbon trading regime.

Reliance on coal generation had threated reliability, in the view of NYISO, so changes needed to be made, even though New York had cut emissions by 39% from 2000 levels. (See NYISO: EPA Clean Power Plan Threatens Reliability for New York City.)

Changes made in the final plan based on input from grid operators — combined with a more pronounced shift toward gas generation and renewables in New York as new power plants move closer to completion and the state has committed another $1.5 billion for clean energy over the next decade — seem to have allayed those fears.

“Based on our initial review, it appears EPA responded positively to major concerns regarding reliability in the draft rule, and that the final rule is generally favorable to New York,” NYISO spokesman David Flanagan said.

EPA also added a reliability safety valve and a requirement that states seek grid operators’ reliability assessments on their implementation plans.

“A reliability safety valve will allow a state to propose a modified emission standard for an affected generator for a temporary period of time to address an unforeseen emergency situation that threatens reliability,” Flanagan said.

In June, the state committed to reducing all greenhouse gas emissions by 40% from 1990 levels, cutting energy consumption in buildings by 23% from 2012 levels and getting half of the state’s energy from renewable sources.

While New York is ahead of most other states, it will have to make decisions on retirements of aging, fossil fuel plants and the future of the Indian Point nuclear facility.

New England

The New England states — members of the Regional Greenhouse Gas Initiative, along with New York — are generally well ahead of the targets set in the Clean Power Plan, in some cases by several years. EPA has recognized RGGI as a model compliance tool.

Connecticut, Massachusetts and New Hampshire have less stringent goals for the 2022 interim period, reflecting what EPA calls a “smoother glide path.” However, those states have more stringent goals by 2030 compared to other states.

Connecticut’s interim goal is 899 lbs/MWh and its 2030 goal is 786 lbs/MWh; Massachusetts is at 956 and 824, respectively; Rhode Island, 877 and 771; and New Hampshire comes in at 1,006 and 858.

Maine no longer has any of the coal-burning power plants considered the primary target of the emissions reductions. Under the goals, Maine would have to reduce its carbon dioxide emissions per megawatt-hour of electricity by 10.8% by the year 2030.

Vermont is one of three states, along with Alaska and Hawaii, exempted from the rules. Vermont’s largest source of electricity is hydropower imported from Canada. The Green Mountain State has some in-state dams and two wood-burning power generators.

The Union of Concerned Scientists issued a report last week that said the Northeast states are among 20 states that have made commitments (including carbon caps, coal plant closures and mandatory renewable electricity and energy efficiency standards) that put them more than halfway toward meeting their 2030 targets. Sixteen states are likely to surpass the targets, the group said.

August 18, 2015June 15, 2023

FERC OKs Expansion of SPP Board

FERC last week approved bylaw changes allowing SPP to add up to three seats to the RTO’s Board of Directors.

The revisions also incorporate corresponding modifications to quorum and voting requirements, effective Aug. 15.

spp — SPP President Nick Brown and Board Chair Jim Eckelberger.

SPP’s board is currently comprised of seven independent directors, including President Nick Brown. The RTO says expanding its board to up to 10 persons would “foster a measure of flexibility” and further director succession planning, “with due consideration given to director tenure, knowledge sharing and risk management.”

SPP’s Corporate Governance Committee recommended the revisions in April, when they were approved by the Members Committee.

Brown said last month the governance committee will be evaluating the results of a solicitation 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.

— Tom Kleckner

August 18, 2015

PJM Operating Committee Briefs

VALLEY FORGE, Pa., — PJM will continue the generator testing begun last winter with only minor changes after members rejected proposals to expand the program.

More than 62% of more than 130 stakeholders who responded to a poll said they preferred continuing the program — begun last winter in response to the high number of generator outages during the 2014 polar vortex — with only minor changes, PJM’s David Schweizer told the Operating Committee last week.

The proposal included only minor changes requiring generators to submit a primary and alternate date for the exercise; submit results of the exercise to PJM; and report completion of the cold weather preparation checklist through eDART. Manual 14D: Generator Operational Requirements also will be revised to clarify combined-cycle offers for generators exercising one combustion turbine on alternate fuel.

Members rejected three other options that would have made larger changes to the program, including option 2, which would not compensate Capacity Performance resources for participating after the winter 2015/2016. It received only 42% support.

Option 3, which received 34% support, would have expanded the exercise period -– currently the month of December -– to Nov. 1 through Jan. 15; increased the maximum temperature to 40 F from 35 F in the southern zones; and increased the maximum test allowed daily from 1,000 MW to 1,200 MW. It also would have included a reevaluation of the program after winter 2015/16 to determine whether it should be continued.

Option 4, a combination of options 2 and 3, also received 34% support.

The testing, which cost about $7 million last year, was credited with improving generator performance during the winter of 2014/15. (See Why Did PJM Grid Fare Better This Winter?)

PJM Seeks to Eliminate Disconnect on Metering Requirements

PJM plans to modify Manual 1: Control Center and Data Exchange Requirements to “close the gap” between PJM requirements and generator practices regarding metering.

PJM’s Ryan Nice presented the OC with a first read on a problem statement to create a task force to draft new manual language. “Some of these gaps are pretty extensive,” Nice said.

Nice said the revised manual will clearly delineate requirements for monitoring and control metering used by PJM’s state estimator and revenue metering used in settlements.

“This is the raw data” for settlements and operations, Nice said. “So it really behooves everyone to pay attention to this.”

Members should send the names of those interested in joining the task force to ryan.nice@pjm.com.

PJM Moves to Tighten Training, Certification Requirements

The System Operations Subcommittee will consider ways to increase compliance with PJM training and certification requirements under an issue charge approved by the OC.

The SOS will only suggest changes to section 3.3 of Manual 40: Certification and Training Requirements, which deals with compliance, and not to the actual requirements, as detailed in section 3.2, said Glen Boyle, manager of system operator training. The subcommittee’s work will also not deal with North American Electric Reliability Corp. requirements, Boyle said.

PJM has been tracking non-compliance among several generation dispatchers, demand response providers and energy storage device operators for months and the situation has not improved. The subcommittee will “look for options to get these companies back into compliance,” Boyle said. (See “Generators’ Non-Compliance Continues” in PJM Operating Committee Briefs, June 15, 2015.)

PJM also briefed members on other changes to Manual 40. The changes, intended to clarify PJM’s processes, will be brought to a vote at the next OC meeting.

Closed-Loop Interface Set for Dominion Chesapeake

PJM last week declared a closed-loop interface near Norfolk, Va., in the Dominion zone to address voltage or thermal problems that could result from an N-1-1 contingency during transmission upgrades expected to be completed by the end of the year.

pjm — The DOM-CHES closed-loop interface near Norfolk, Va. (in blue), was created to address voltage or thermal problems that could result from an N-1-1 contingency during transmission upgrades expected to be completed by the end of the year.

The interface, effective Aug. 14, will allow the RTO to set sub-zonal real-time prices for load management or generation during high load conditions or emergency transmission outages in the Dominion Chesapeake area, protecting the load pocket. The interface would be modeled for the day-ahead market but not for financial transmission rights.

Bath County SPS Extended for Cloverdale-Lexington Outage

PJM will extend the Bath County special protection scheme (SPS) during an outage required for upgrades to the Cloverdale-Lexington 500-kV tie line between the Dominion and American Electric Power zones.

The line is expected to be out of service from January through June 2016 during a reconductoring project and again from mid-September 2016 through mid-October 2016 for replacement of the Cloverdale transformers. The SPS will address the loss of one of six generators in Bath County and potential congestion on a 138-kV line as a result of the outage.

The SPS was initiated in September 2014 for the Dooms-Lexington 500-kV project, which is expected to be complete by the end of 2015.

PJM and Dominion will consider extending the SPS beyond 2016 to address other pending upgrades in the western Virginia area, PJM’s Liem Hoang told the OC.

Behind-the-Meter Initiative Yields 1,000 MW

PJM has identified about 1,000 MW of behind-the-meter generation as a result of an initiative following the September 2013 heat wave that caused two days of load shedding.

PJM was forced to cut power to 44,000 customers in southern Michigan, northern Ohio and northwest Pennsylvania as temperatures unexpectedly hit the mid-90s and the RTO found itself without enough generation during the fall maintenance period.

A third day of load sheds was avoided after the city of Sturgis, Mich., provided 8 MW of relief through conservation and its behind-the-meter generator. PJM had not been aware of the generator before the emergency. (See Heat Wave To-Do List Grows Longer.)

“If we had seen that [generation] early, we have indications that [Sturgis] would have been happy to come on to avoid having to shed load,” PJM Vice President of Operations Mike Bryson told the OC.

As a result of the incident, PJM began seeking information on other behind-the-meter generation in February. The project identified the nearest Bulk Electric System substations, so that operators can conduct distribution factor studies to determine how effective they would be in addressing constraints.

PJM’s Joe Mulhern said any relief from the generators would come on a voluntary basis because the RTO’s current rules provide no way to compel or compensate them. Such generators are eligible for energy market and ancillary service revenues, however.

Bryson said PJM will have to discuss the issue with each of its 14 states individually because of varying jurisdictional rules.

“We would be open to any of these kinds of discussions with them,” Bryson said.

PJM to Tighten Long-Term Transmission Outage Rules

PJM plans to revise its rules regarding long-term transmission outages in order to protect FTR revenues.

The current rules in Manual 3: Transmission Operations require transmission owners to submit any outages longer than 30 days by Feb. 1 so that they can be accounted for in the annual FTR auction.

But Simon Tam told the OC that some TOs have submitted two or more consecutive outages of less than 30 days at the same location and were not covered by the requirement. “Sometimes they’re not able to project every single piece of work they need to do … and need to extend the outage,” he said in a second briefing to the Market Implementation Committee.

Under the new rules, which will be added to the manual during a scheduled revision this fall, PJM will evaluate outages exceeding 30 days on the same line or transformer within an eight-month time span. If the outage causes a shortfall in FTR revenue, PJM will require the TO to reschedule it or pay for the congestion it causes, Tam said. The plan will be phased in over a year for TOs unable to meet the Feb. 1, 2016, implementation.

PPL’s Frank “Chip” Richardson expressed concern with the change at the MIC briefing, saying it could delay upgrades needed for the reliability of the system. He added that TOs have no way to recover congestion costs they might be assessed.

“We’re not going down the road of wanting TOs to pay for congestion,” Tam responded. “The intent is for the TO to do a little more advanced planning.”

If the upgrade in question is critical and should not be delayed, PJM can declare an emergency and the TO can complete the upgrade without a congestion charge, Tam said.

— Rich Heidorn Jr. and Michael Brooks