Federal Briefs

A three-judge panel of the D.C. Circuit Court of Appeals upheld FERC Order 1000 after Oklahoma Gas & Electric and other utilities challenged the landmark rule’s elimination of incumbent transmission owners’ right of first refusal to develop transmission projects.

OG&E sued FERC in December 2014, arguing that when it agreed to join SPP, it gave up some transmission planning rights in return for the right of first refusal. The utility said FERC couldn’t meet a higher legal burden to negate that part of the membership agreement, which predated Order 1000.

The utility has not yet decided whether it will appeal the decision to the full court. SPP supported OG&E’s case, which was also joined by Southwestern Public Service, ITC Great Plains, Xcel Energy Services, Mid-Kansas Electric and Sunflower Electric Power.

More: The Oklahoman

GAO Audit: DOE not Protecting Whistle-blowers

The Department of Energy has failed to protect whistle-blowers at its nuclear plants from retaliation, a Government Accountability Office audit found.

The report said the department has issued only two violation notices in the past 20 years against contractors who created chilled work environments at nuclear sites. Employees who try to use the department’s whistle-blower protection program find it difficult to navigate without legal help, the report says.

The report was requested in 2014 by three Democratic senators in response to reports of retaliation against whistle-blowers at the Hanford nuclear reservation in Washington state. The audit broadened to the handling of 87 contractor employee complaints at 10 of the department’s largest nuclear facilities.

More: McClatchyDC

FERC Allows BG&E to Recover $1.2M from Scrapped MAPP

Baltimore Gas and Electric may recover nearly $1.2 million it spent on the Mid-Atlantic Power Pathway (MAPP) project, which was canceled by the PJM Board of Managers in 2012, under a settlement between the company and the Maryland Public Service commission that FERC approved earlier this month.

The MAPP involved a 230-mile 500-kV transmission line from Virginia to New Jersey intended to “relieve load deliverability criteria violations” expected to occur on the Delmarva Peninsula. In canceling the project, PJM said that its “reliability drivers no longer existed.”

FERC had granted BGE incentives effective May 29, 2009, allowing it to recover costs if the project were abandoned. The commission has previously approved settlements between others state regulators and utilities that had contributed to the project.

More: ER15-2331

Entergy Asks NRC for More Time for Upgrades

Entergy has asked the Nuclear Regulatory Commission for more time to meet post-Fukushima upgrade requirements at its Pilgrim Nuclear Power Station in Massachusetts, which is set to close by June 2019.

The company asked for a deadline of Dec. 31, 2019, in order to avoid making permanent modifications before the closure. Instead, it wants to use a FLEX strategy, so called because it uses portable equipment.

“The plant does have a limited operational timeframe going forward, but our mandate is to make sure that the public is going to be adequately protected,” NRC spokesman Neil Sheehan said.

More: CapeCod.com

FERC Gives Go Ahead for Bosher Dam Study in Va.

FERC has approved an application to conduct a feasibility study for an 8-MW hydro facility outside of Richmond, Va., at the existing Bosher Dam on the James River. The proposed project would use the existing 12-foot-high dam and create a 1,000-acre impoundment area, with new intakes, a new tailrace and four 2-MW turbines, along with a new powerhouse and substation.

The Richmond Department of Public Works, along with the James River Association and others, questioned the need for the facility during the public comment period, but FERC said the feasibility study was necessary to determine the validity of any opposition concerns.

The project is being proposed by Energy Resources USA.

More: GenerationHub.com

Pipeline Projects Get Positive Draft EIS

Two jointly proposed pipeline projects to move Marcellus and Utica shale gas in Ohio to the Midwest and Canada received a favorable draft environmental impact statement from FERC.

DTE Energy and Spectra Energy’s 260-mile Nexus Gas Transmission pipeline would move 1.5 Bcf/d. It is being developed along with the Texas Eastern Appalachian Lease project, which would expand Spectra subsidiary Texas Eastern Transmission’s system by 950,000 dekatherms/day to accommodate the new pipeline.

FERC noted some “adverse environmental impacts, but impacts would be reduced to less-than-significant levels” with mitigation efforts. Public comment is open until Aug. 29. The commission said the final EIS should be ready by Nov. 30.

More: Natural Gas Intelligence

DOE Approves $15M for Algae-Based Fuels Efforts

The Department of Energy is providing $15 million for algae-based biofuel projects in California and Florida. The grants are aimed at furthering the commercialization of biofuels as a renewable, affordable fossil fuel replacement, it said.

Three companies and their research partners will receive the funds. Global Algae Innovations in California is working on cultivation and preprocessing technology to produce algal oil. MicroBio Engineering, also based in California, is researching wastewater treatment and carbon-dioxide mitigation to produce useable oils. Finally, Florida-based Algenol Biotech is working to devise ways to use cyanobacteria to produce algal oil.

More: Biofuels International

House Passes Funding Bill For Interior Department, EPA

The House passed a $32.1 billion funding bill for the Interior Department and EPA, about $1 billion less than what the Obama administration requested, and a $64 million cut over current spending levels. The bill includes a number of riders intended to block EPA water, power plant and coal mining regulations.

“There is a great deal of concern over the number of regulatory actions being pursued by the EPA in the absence of legislation and without clear congressional direction,” Rep. Ken Cavert (R-Calif.) said. “For this reason, the bill includes a number of provisions to stop unnecessary and damaging regulatory overreach by the agency.”

The bill passed 231-196, with most Democrats opposing it. The White House has threatened to veto it.

More: The Hill; House Appropriations Committee

Report: Green Energy Funding Down 23% from Last Year

A report by Bloomberg New Energy Finance shows that renewable energy funding has fallen 23% for the first six months of the year compared to last year. It said investments globally were about $116.4 billion for the first half of the year. Second-quarter investments were $61.5 billion, 12% higher than the first quarter, but still 32% lower than the $90 billion for the same period last year.

“It is now looking almost certain that the global investment total for this year will fail to match 2015’s runaway record,” Michael Liebreich, chairman of the advisory board at BNEF, said in a statement accompanying the report.

More: USA TODAY

Cook Nuclear Plant Back Online After Steam Leak

Unit 2 at the Donald C. Cook nuclear plant in Berrien County, Mich., returned to service last week after being shut down for six days because of a steam leak.

Plant spokesman Bill Schalk attributed the July 6 steam line rupture to “vibration-induced metal fatigue” of an expansion joint. He said the rupture also damaged the wall of the turbine building.

Vendors fabricated new parts for the line and repaired it. The plant came back online July 12. The Nuclear Regulatory Commission says it will analyze the plant crew’s response to the incident.

More: The Herald-Palladium

TVA Closer to Taking Watts Bar Commercial

The first new U.S. nuclear plant to be built in two decades is closer to being deployed after the Tennessee Valley Authority last week completed a key performance test on the reactor.

The unit, which has been operating at 30% of its 1,150-MW capacity, was raised to 50% so operators could perform load rejection tests, in which power is rapidly lowered and raised to simulate a storm-induced loss of load or other accident.

“All of the tests went like clockwork,” a TVA spokesman said. The corporation expects to bring the Watts Bar Unit 2 to full power later this summer.

More: Times Free Press

July 18, 2016

PJM Plans for Changes in Tx Flows Without Con Ed-PSEG ‘Wheel’

By Rory D. Sweeney

Preparing for next year’s termination of the Con Ed-PSEG “wheel,” PJM is using a three-pronged approach to coordinate stakeholder efforts through its Operating, Markets Implementation and Planning committees.

Each committee received updates last week on Consolidated Edison’s decision not to renew the agreement, under which NYISO moves 1,000 MW from upstate generators through Public Service Electric and Gas facilities in northern New Jersey to serve Con Ed load in New York City.

Con Ed said it would not renew the agreement, which began in the 1970s, after receiving a $680 million bill for two transmission upgrades in PSE&G territory — cost allocations that Con Ed complained were unreasonable. (See Con Ed-PSEG ‘Wheel’ Ending Next Spring.)

Overview of PSE&G – ConEd 600 400 Contract (PJM) — PJM and NYISO are determining new protocols for three interconnection facilities (Waldwick, Goethals and Farragut) that, as of next year, will no longer carry 1,000 MW from upstate New York, through PJM and back into NYISO.

PJM assigned Con Ed $629 million of the costs of PSE&G’s $1.2 billion Bergen-Linden Corridor upgrade to address a short-circuit problem; PSE&G was allocated $52 million. Con Ed was also assigned $51 million of PSE&G’s $100 million Sewaren storm-hardening project.

The transmission contract for the wheel expires May 1. Con Ed informed the grid operators that it found cheaper alternatives.

PJM and NYISO are collaborating on a replacement protocol that maintains reliability and is mutually beneficial to both grid operators. The protocol will adhere to FERC’s open access rules and support any existing market-to-market exchanges, PJM said. It will utilize existing infrastructure and won’t address merchant facilities, they said.

The Impact of PARs

Several stakeholders expressed concern that PJM’s goal of “free-flowing ties” would be hampered by the eight phase angle regulators (PARs) that currently govern the direction of flows on lines connecting the RTO with NYISO. There are one each on the A, B and C lines that flow 1,000 MW from PSE&G into New York, three just south of Waldwick on the J and K lines that flow the 1,000 MW into PSEG from upstate and two on the Branchburg-Ramapo 5018 line.

One of PARs on the 5018 line owned by Con Ed failed in June, and it was unclear whether NYISO and Con Ed plan to replace it. Participants asked if the PARs could be removed. “I worry about PJM calling balls and strikes on market optimization,” said Ed Tatum, vice president of transmission for American Municipal Power.

Several participants questioned why the PARs must be kept at all. Speaking after the meeting, Mike Bryson, PJM’s vice president of operations, explained that NYISO has always had a philosophy of using control devices to manage congestion and loop flow.

‘Insider Information’

Other participants expressed concern that the discussions between PJM, NYISO, PSEG and Con Ed haven’t been transparent. Dave Pratzon of GT Power Group, which represents some generators, asked for confirmation that the discussions haven’t included any “insider information.”

Bryson said PJM has ensured that conversations never overstepped the rules. “When we approach that line, we back the parties away,” he said.

Wheel’s New Look

PJM officials said further detail wouldn’t be available until August’s MIC meeting because of the timeline required to approve changes to the PJM-NYISO joint operating agreement. A broader picture wouldn’t be available until September.

Tim Horger, manager of market simulation at PJM, said the New York interface will likely be changed to model what’s “actually going to happen in real time.”

Both NYISO and PJM ran independent studies to determine interchange flows unconstrained by PARs — what they called “natural flow.” The studies were based on a summer peak case and found that 32% would flow over the western ties that connect between the “Twin Tiers” of Pennsylvania and New York, while 68% would interchange between the eastern ties involved with the wheel.

PJM engineer Asanga Perera said that part of the wheel’s benefit today is that the 1,000 MW coming into New York City from New Jersey pushes back on bottlenecks north of the city so it doesn’t see additional congestion.

Cost Allocation

With Con Ed out of the picture, the $680 million in upgrade costs will be reallocated to the existing stakeholders based on guidance in PJM’s manuals, officials said.

In response to a request from Tatum, PJM Vice President of Planning Steve Herling said he would look into providing a document answering frequently asked questions about the change and any public documents that governed the decision-making process.

July 18, 2016January 18, 2024

Mountain West RTO Could Pose Competition for CAISO

By Robert Mullin

An effort to create an organized electricity market is taking shape in the inland West even as CAISO continues to build the case for expanding its operations into the wider region.

The Mountain West Transmission Group — a partnership consisting of seven different transmission owning entities within the Western Interconnection, including the Western Area Power Administration’s Loveland Area Projects and Colorado River Storage Project — is exploring the benefits of implementing a common transmission tariff across multiple states and developing an organized market.

Mountain West issued a request for information in May to CAISO, MISO, PJM and SPP regarding tariff administration and market operator services — “one of multiple sources of information to assist the group in consideration of [a] path forward,” the group said. Proposals were due back to the group July 15.

The group’s footprint covers most of Colorado and Wyoming, along with smaller areas of Arizona, Montana, New Mexico and Utah.

WAPA operates 17,000 miles of transmission spanning 15 states, nearly 5,000 miles of which is located inside Mountain West.

Other members of the group include Basin Electric Power Cooperative, Black Hills, Colorado Springs Utilities, Platte River Power Authority, Xcel Energy’s Public Service Company of Colorado, and Tri-State Generation and Transmission, which together control about 11,000 miles of transmission.

WAPA’s expansive network — as well as its status as a federal power marketing agency (PMA) — makes Mountain West an appealing alternative for some industry participants wary of joining a market operated by CAISO and potentially dominated by California interests. (See related story, Study Touts Benefits of CAISO Expansion.)

Among the skeptics is Utah Associated Municipal Power Systems (UAMPS), which provides energy on a nonprofit basis to community-owned utilities in eight Western states.

CAISO “is not the only game in town,” UAMPS CEO Doug Hunter told Utah lawmakers during a July 13 hearing to discuss the legislature’s role in PacifiCorp’s proposed ISO membership.

Hunter encouraged legislators to look at WAPA’s footprint.

“It runs right through us,” he said. “It would be much better if the entire West had access to it.”

WAPA has said that joint tariffs and energy imbalance markets are among the topics “driving the energy future.”

The agency “recognizes the impact this has on our business and as an organization continues to pursue and develop collaborative paths forward to best benefit our customers,” it said. The agency provides power at relatively low cost to publicly owned utilities referred to as “preference” customers.

WAPA has said that it “is uniquely positioned to facilitate collaborative discussions with industry experts and customers about engagement and involvement in industry activities, such as regional transmission organizations and other market initiatives.” The agency has said its interest stems from its “significant transmission system,” the “expanding geographic scope of markets” and “increasingly limited trading partners.”

A centrally operated Mountain West market could boost trading activity in the region by eliminating the “pancaking” of transmission charges and facilitating a transition from contract path to flow-based transmission rights, which more closely matches scheduled transactions with actual power flows.

Mountain West says its members have achieved “significant success” with rate design and cost-shift mitigation, issues that have stymied previous efforts at developing a common tariff. The group has engaged The Brattle Group to perform a scoping study examining the potential benefits of a day-ahead electricity market.

Although the outcome of the effort is still unclear, the Mountain West entities plan to make a decision on a direction forward in the third quarter of 2017, after a stakeholder process. A common tariff — or broader organized market — could be implemented as early as 2018.

July 18, 2016

NYPSC Extends Comment Period on Nuclear Subsidy

By William Opalka

The New York Public Service Commission last week extended the comment period on a proposed multibillion-dollar nuclear power subsidy by four days, until Friday (15-E-0302).

The comment period on a July 8 staff proposal, providing subsidies for the upstate nuclear fleet for up to 12 years, was to have ended on Monday. Environmental groups, industrial customers and anti-nuclear activists had sought a 45-day comment period.

“These extensions are granted for the fair, orderly and efficient conduct of these proceedings,” the PSC said Friday.

Political and labor leaders and economic development proponents in the Finger Lakes region have embraced the proposed zero-emission credit for financially stressed nuclear power plants. It is part of the proposed Clean Energy Standard, which seeks to transition the state to 50% renewable energy by 2030.

But the ZEC proposal has been opposed by some environmental organizations.

“Staff’s earlier cost estimates for the nuclear tier ranged from $59 million to $658 million over the first seven years. Now, under the new proposal, staff estimates the first two years will cost nearly $1 billion. Over the life of the program, it could amount to over $7 billion,” the Alliance for a Green Economy wrote in its petition seeking an extension last week.

Nine Mile Point - NYPSC nuclear subsidy — Nine Mile Point Nuclear Plant

Exelon, which owns three nuclear plants on Lake Ontario, opposed any extension that would prevent the commission from voting on the proposal at its next scheduled meeting Aug. 1. It repeated its position last week that any delay jeopardized its attempt to schedule a $55 million refueling of its Nine Mile Point 1 reactor next spring. (See Exelon Threatens to Close Nine Mile Point 1.)

The company said it needs a signed contract guaranteeing the continued operation of Nine Mile Point by Sept. 30 to prevent the plant’s retirement.

The company also started a separate proceeding to obtain subsidies through a cost-based regulatory order in the event the CES did not get approved in time. That proceeding is pending.

Exelon also owns the R.E. Ginna plant, which also could close at the end of March when its reliability support services agreement with Rochester Gas & Electric expires, and is in negotiations to acquire Entergy’s James A. FitzPatrick plant. (See Entergy in Talks to Sell FitzPatrick to Exelon.)

July 18, 2016

State Briefs

Regulators OK APS Battery Storage Program

The Corporation Commission approved Arizona Public Service’s demand-side management plan, which includes $4 million to incentivize the use of battery storage systems for residential customers.

The plan’s aim is to reduce peak load on the utility’s distribution system and includes programs to encourage the use of smart thermostats, demand response, LED lighting and technologies that improve the efficiency of air conditioners.

“Pairing advanced technology with customer education empowers our customers to have more control over their own energy use,” said Jim Wontor, the utility’s manager of demand-side management.

More: KJZZ; Arizona Public Service

CALIFORNIA

Brown Moves to Extend Cap-and-Trade

Gov. Jerry Brown’s administration last week moved to keep the state’s cap-and-trade program alive beyond its scheduled expiration in 2020. The Air Resources Board proposed a plan that would progressively decrease emissions caps until 2031 — to 40% below 1990 levels — and extend the carbon market to 2050.

Legislation to limit 2050 emissions to 80% below 1990 levels — and extend the market — stalled in the state’s lower house last year. While lawmakers have taken up a scaled-down version of the bill this year, passage is not ensured because of strong opposition. Brown is negotiating with oil companies who have criticized the cap-and-trade program.

More: Los Angeles Times

CAISO Solar Record Slips Past 8,000 MW

CAISO solar output hit a new record of 8,030 MW at 1:06 p.m. on July 12, exceeding year-ago levels by 2,000 MW and nearly doubling the peak in May 2014. Renewable portfolio standard resources together covered 29% of load during the ISO’s system peak later that day.

The state currently has about 8,600 MW of solar resources connected to the grid.

More: CAISO

CONNECTICUT

Report: State Energy Costs Highest in US

The state has the highest average energy costs in the nation, according to financial website WalletHub. The report says the average household in the state spends $400/month on energy.

The state ranked No. 3 for electricity costs, No. 3 for home heating oil costs, No. 11 for natural gas costs and No. 14 for gasoline costs, equating to average monthly costs of $155, $104, $44 and $100, respectively.

The state’s New England neighbors also ranked in the top five.

More: Hartford Courant

Green Bank’s Program Aids Energy Efficiency

The state’s Green Bank unveiled a new $800,000 grant program called Energy on the Line to assist manufacturers in using renewable energy and efficiency measures.

The program provides up to $50,000 in supplemental funding for projects. An $800,000 funding pool from the state Department of Economic and Community Development will be matched by more than $8 million in private-sector loan funds procured by the Green Bank.

Manufacturers interested in participating in the new grant program must apply by Sept. 16.

More: New Haven Register

MAINE

Governor Opposes Wind, Solar Projects

Gov. Paul LePage, speaking at a town hall in the Moosehead Lake region, said that area is not right for renewable energy development.

“Is there room for wind and solar?” the governor said. “Yes, in certain spots of the state. But I want to tell you Moosehead is not one of them.”

SunEdison is seeing opposition in the Greenville area to its proposed 26-turbine wind farm on Misery Ridge, near Moosehead Lake, but the project’s fate is uncertain since the company’s bankruptcy. Though the governor mentioned solar power, there are no such projects being proposed for the area.

More: Portland Press Herald

Largest Solar Farm in State Under Development

Ranger Solar is conducting an environmental assessment for a solar farm of up to 80 MW that could break ground in 2018.

The project would be the largest utility-scale solar farm in the state. A solar farm requires about 5 acres/MW, according to the developer. An exact number of panels that would be needed for the project is not yet known, but upward of 90,000 to 100,000 panels are likely.

Once a project plan is completed, Ranger Solar will bring it formally before the Farmington Board of Selectmen and the state Department of Environmental Protection.

More: Portland Press Herald

MICHIGAN

State Hires Two Firms For Pipeline Analysis

The state has hired two companies to analyze the financial impact of a hypothetical rupture of Enbridge’s underwater pipelines, collectively called Line 5, in the Straits of Mackinac and to explore potential alternatives to their route. Enbridge will pay $3.5 million for the studies but declined to oversee the work.

Det Norske Veritas will work on an analysis of the cleanup costs in the event of a rupture. Dynamic Risk Assessment Systems will look into alternatives for Line 5, which carries 23 million gallons of oil and LNG per day.

More: The Associated Press

Snyder Appoints Former BP Lobbyist to Head MDEQ

Gov. Rick Snyder has appointed a former BP lobbyist to head the state’s Department of Environmental Quality, sparking criticism from residents and environmentalists already galvanized over the Flint water crisis.

Heidi Grether, currently a deputy at the Agency for Energy, previously spent 21 years with BP in external communications, including managing the public response to the Deepwater Horizon oil spill. Former MDEQ chief Dan Wyant resigned in late December amid the Flint controversy.

“After the Flint water crisis clearly demonstrated there were cultural problems within the DEQ, this appointment is a concerning development,” said Lisa Wozniak, executive director of the Michigan League of Conservation Voters.

More: Detroit Free Press

MISSOURI

PSC: Grain Belt Express Must Wait 60 More Days

The Public Service Commission ruled that Clean Line Energy must wait another 60 days for its Grain Belt Express transmission line application to be considered for approval because the company did not provide adequate public notice when it made its filing.

The commission rejected the project a year ago in a 3-2 vote, but it said this latest delay was strictly procedural.

More: St. Louis Post-Dispatch

NEW HAMPSHIRE

Merrimack Valley Power Line Approved by State

The state Site Evaluation Committee approved an application from Eversource Energy and National Grid for construction of the Merrimack Valley Reliability Project, the first major upgrade to the electrical transmission system in 20 years.

The new 18-mile overhead transmission line will be built on an existing interstate right of way.

The application for the project was submitted in July 2015. Its cost is estimated at $125 million, and the utilities are evaluating construction bids.

More: New Hampshire Union Leader

NEW MEXICO

PRC Schedules Hearing on Facebook’s Planned Facility

The Public Regulation Commission unanimously agreed to hold an Aug. 9 hearing on Public Service Company of New Mexico’s request to provide renewable energy to a proposed data center for social media giant Facebook. If no comments are received by July 27, however, the commission may waive the hearing.

PNM submitted an application seeking expedited approval, without public comment or hearing, of a plan to provide 60 MW of solar or wind power. Facebook, which also is considering locating the site in Utah, wants the facility online by mid-2017 and has agreed to cover most of the costs of the power facility.

Facebook wants the center to run on 100% renewable energy, but it would still use traditional power plants as backup energy sources. As part of the deal, Facebook would require PNM to guarantee a fixed price on backup power for the first 10 years.

More: The Santa Fe New Mexican

NORTH CAROLINA

Regulators Set $98M Bond For Duke Plant Appeal

The Utilities Commission says two nonprofits must put up a $98 million bond to go forward with an appeal of a permit given for a new Duke Energy gas-fired power plant. The commission originally set the bond at $10 million, but an appellate court told it to recalculate the bond based on “competent evidence.”

The commission set the new amount based upon a 1965 state law and said it is designed to protect developers from costs associated with construction delays in the event they win a legal challenge. “The statute plainly places on the appealing party the financial risk of what potentially could be extensive additional costs,” the NCUC said in its order.

NC WARN and the Climate Times objected to the Buncombe County plant because it would use gas extracted using fracking. Duke had requested a $240 million bond, while the nonprofits said they were willing to put up $250. NC WARN’s director, Jim Warren, said it is not going to put up the bond. “We don’t have the money.”

More: News & Observer

NORTH DAKOTA

PSC Unanimously Approves Second Brady Wind Farm

The Public Service Commission unanimously approved the $250 million Brady Wind Energy Center II project, which will have 72 turbines and a capacity of 150 MW.

The project would double the potential capacity of Brady Wind, an indirect subsidiary of NextEra Energy Resources. The new facility will be located in Hettinger County, south of its sister project, approved last month, in Stark County.

Commissioner Brian Kalk said the approved siting permit includes strict turbine setbacks of 2,000 feet from homes in the project area and 2,640 feet from homes owned by those not participating in the project. He said the setbacks were negotiated based on county and PSC standards.

More: The Bismarck Tribune

PENNSYLVANIA

Company Could Pay $5M For Deceptive Pricing

Two administrative law judges are recommending that the Public Utility Commission fine Blue Pilot Energy $5 million for charging its variable-rate customers high prices during the polar vortex of 2014.

The judges found that the Las Vegas-based company did not provide accurate pricing information, charged prices that did not match its disclosure statement and falsely promised savings.

They also said that Blue Pilot did not comply with the state’s Telemarketer Registration Act. The company countered that the PUC is authorized only to enforce its own regulations, not the telemarketer law.

More: The Philadelphia Inquirer

TEXAS

Environmental Regulators Approve Controversial Mine Expansion

The Commission on Environmental Quality renewed and expanded a wastewater permit for Dos Republicas Coal Partnership, allowing the company to expand its current operations near the Mexican border and mine up to 6,300 acres for low-quality coal.

The mine’s opponents say the project will pollute the air and the Rio Grande, which is the area’s only source of water. Several Native American tribes have also argued that the mine threatens sacred ancestral ground and that they were never given proper notification about the company’s plans.

Dos Republicas is owned by Mexican companies and by the Plano-based North American Coal Corp. and its subsidiary Camino Real Fuels. Because the coal is categorized as too low-grade for use in the U.S., it’s shipped to Coahuila for use in Mexican plants.

More: The Texas Tribune

NRG, Denton Reach $3.7M Settlement over Rate Credits

The Denton City Council has approved a $3.7 million settlement reached between NRG Power Marketing and the city over money owed to ratepayers.

After the Texas Interconnection became deregulated in 2002, Denton Municipal Electric contracted with NRG to represent Denton at ERCOT until the city could begin buying and selling electricity directly in October 2014. Denton sued the company last year, alleging that NRG withheld credits from ratepayers.

The two parties were ordered into mediation, with Mayor Chris Watts personally assisting in the talks.

More: Denton Record-Chronicle

WISCONSIN

PSC Orders $16.5M Refund to WE Ratepayers

The Public Service Commission approved a $16.5 million refund to We Energies customers after the utility underestimated how falling fossil fuel prices would affect the cost of power. The refund will amount to about $5 for the average residential customer.

Four other state utilities — Wisconsin Power and Light, Madison Gas and Electric, Wisconsin Public Service and Northern States Power — will also issue refunds that range from $9.5 million to $16.5 million.

We Energies had asked the commission for a pass on issuing refunds, arguing that the money should be used to counteract future rate hikes, but consumer advocacy groups lobbied the PSC for immediate refunds.

More: Milwaukee Journal Sentinel; Wisconsin Public Radio

July 18, 2016

SPP Markets and Operations Policy Committee Briefs

RAPID CITY, S.D. — The SPP Markets and Operations Policy Committee last week refused to take action on American Electric Power and Oklahoma Gas & Electric’s revision request to remove the day-ahead limited must-offer.

Left to right: Monroe, Williams © RTO Insider — Left to right: Monroe, Williams © *RTO Insider*

The Market Working Group approved RR 125 last November but postponed moving it forward in December to allow further discussion on RR 135, which would revise physical withholding rules. It again failed to move the request forward in May on a tie vote (8-8, with one abstention).

“This is about the fourth or fifth bite at the apple others have tried with this issue,” Golden Spread Electric Cooperative’s Mike Wise said. “When we were designing the market, we debated this issue ad nauseam. I suggest we not change something that works right now.”

Wise said he agreed with the Market Monitoring Unit’s position of waiting to move forward with RR 125 until RR 135’s rules for physical holding have been completed. He suggested waiting for the enhanced combined cycle (ECC) project to go into effect next spring. The project — an effort to provide more sophisticated modeling that captures such plants’ flexibility — is being done in conjunction with changes to align the Integrated Marketplace’s day-ahead market with gas nominations.

“We should wait until the enhanced combined cycle [project’s completion] next spring, and then move forward,” he said. “It will remove the difficult decision and guessing about which mode of combined cycle operation the market needs, and remove some of those concerns dealing with the physical withholding in the market.”

“I haven’t heard enough about why it’s so important to remove the limited must-offer provision,” Midwest Energy’s Bill Dowling said. “I haven’t heard enough about the benefits [of] moving forward without knowing what the next steps are.”

RR 125 was a result of the Market Monitoring Unit’s recommendations to improve the Integrated Marketplace. It was designed to run in parallel with another revision request that would revise physical-withholding rules.

“We focus on the market power of units and the specific impact of units on the market,” MMU Director Alan McQueen said. “From a market monitoring perspective, physical withholding is the issue that’s a concern to us. I believe there’s value in coupling these things together and think about it in the way FERC’s going to look at it.”

The MOPC passed three revision request brought up individually, though each received a handful of opposing votes and abstentions.

RR 2, which predates SPP’s new revision request process, gives market participants the option of submitting interchange data in five-minute or hourly intervals. Participants were previously prohibited from submitting the data in five-minute intervals.

“As I understand it, the functionality won’t be used by the entire footprint for a long time,” said OG&E’s Greg McAuley, who cast one of four opposing votes against the measure. “Our MWG rep told me no single market participant intends to use this functionality. If we’re not going to consistently use it, why are we even talking about it?”

McAuley also questioned the estimated $50,000 cost of implementing RR 153, which would eliminate market participants’ need to make two separate submissions for a single intraday change.

Under current protocols, resource offers roll forward hour-to-hour, which can cause problems when intraday changes only meant to apply to the current day carry forward to subsequent days.

“It sounds like a software problem,” Kansas Power Pool’s Larry Holloway said. “If the software isn’t doing what it’s supposed to, isn’t there some sort of maintenance that occurs before [a revision request] comes to MOPC?”

“It’s a very fine nuance in the protocols,” said American Electric Power’s Richard Ross, who chairs the MWG. “I thought it was the software at first, too, but as we dug into it, there’s a very fine, quirky, strange reading of the protocols. We’re changing the protocols and the Tariff to make sure we get exactly what we want.”

SPP MOPC Meeting © RTO Insider — SPP MOPC meeting © *RTO Insider*

Another request approved by the MOPC, RR 167, would avoid Tariff violations resulting from the incorrect submission of annual revenue rights or transmission congestion rights. It is expected to cost $134,000.

“What’s the saying? ‘Sooner or later, it becomes real money,’” McAuley said. “We’re nickel and diming ourselves to death.”

Ross said the MWG has passed or is working on nine improvements to the Integrated Marketplace at a combined cost of about $11.4 million. The bulk of that total — $9.2 million — is linked to the ECC project.

Revision Requests Approved

The MOPC approved nine revision requests on its consent agenda:

BPWG-RR 88, modifying the time of day when unscheduled firm transmission is released for sale as hourly, non-firm transmission service for the next day from noon (CT) to 10 a.m. The change will allow coordination of next-day scheduling with the Western Electricity Coordinating Council.
MWG-RR 7 MPRR155, revising instructions for dispatching generators out of merit order into two categories: reliability issues and emergency conditions.
MWG-RR 161, changing the method for calculating make-whole payments for multi-configuration combined cycle resources; the new rules allow use of a netting approach in calculating the commitment-level costs eligible for recovery.
MWG-RR 165, removing references to the retired Mitigated Offer Task Force from the Tariff’s Appendix G.
MWG-RR 166, removing references from the protocols and Tariff to the interim transmission congestion rights process developed for the transition into the Integrated Marketplace.
MWG-RR 169, changes reliability unit commitment calculations from evaluating megawatts needed hourly to those needed for each dispatch interval.
ORWG-RR 159, moves requirements regarding the outage-coordination function into SPP Operating Criteria Appendix OP-2 “Outage Coordination Methodology,” eliminating redundant language elsewhere.
RTWG-RR 160, clarifying the Integrated Transmission Planning manual to note which generation interconnections and associated upgrades are required to be modeled in ITP assessments.
RTWG 163, correcting Tariff language to specify the ITP manual includes references to requirements.

Working Group Closes 5 of 9 MMU Market Recommendations

AEP’s Ross briefed the committee on the MWG’s progress in implementing the market monitor’s recommended improvements to the Integrated Marketplace. The recommendations were a result of the July 2015 State of the Market report, which covered the markets’ first year of operation.

Four of the MMU’s nine recommendations are considered closed, having been addressed by revision requests:

Not subjecting quick-start resources to reliability unit commitment and not providing make-whole payments for resources dispatched in the real-time balancing market;
Reducing available financial transmission rights to minimize over-allocations when not supported by day-ahead congestion revenues;
Improving transmission-outage reporting in the FTR process; and
Automating the bidding process for transmission congestion rights to prevent ongoing Tariff violations.

The MMU withdrew a fifth recommendation, related to market power mitigation conduct thresholds. The monitor said it had observed lower-than-expected mitigation levels during the Integrated Marketplace’s second year of operation.

Ross said a task force has been formed to address ramp-constrained shortage pricing, which the MMU suggested should be priced the same as operating-reserve capacity shortages.

SPP RE Selects New Trustee Candidates

The Regional Entity’s trustees have worked with a search firm to select two candidates as new trustees: Mark Maher, who retired as the WECC’s CEO, and retired NYISO CEO Steve Whitley. SPP’s Members Committee will vote on their nominations during the July board meeting.

Maher and Whitley would join incumbents Dave Christiano and Gerry Burrows. Christiano replaced John Meyer as the trustees’ chairman earlier this year, when Meyer resigned to join Western Interconnection reliability coordinator Peak Reliability.

RE General Manager Ron Ciesiel told the MOPC the trustees approved the entity’s $10.9 million budget for 2017 and its business plan during their June meeting.

Ciesiel said the RE continues to see a downward trend in standards violations and vegetation contacts. He reported just two regional events during the second quarter, an outage and a 30-minute partial loss of monitoring at a control center.

The RE is conducting its first Critical Infrastructure Protection v.6 audit this month. Ciesiel said a FERC-led CIP compliance audit is expected next year, as the SPP footprint was not selected for an audit this year.

Recommendation: Retire Task Force, Create New Working Group

The MOPC unanimously approved the Capacity Margin Task Force’s recommendation that it and the Generation Working Group retire and be replaced by a Supply Adequacy Working Group. The new working group would also assume fuel supply work now performed by the Gas Electric Coordination Task Force.

The CMTF held its last meeting June 30, when it finalized a charter for the new working group. It also reviewed its final deliverable, a resource adequacy workbook that combines the data needed for complying with NERC standards with those needed to validate SPP’s planning reserve margin. Chairman Tom Hestermann, of Sunflower Electric Power, said many of the task force’s members will transition to the new group.

The task force was created in 2014 to update SPP’s capacity margin requirements and methodology. Its work resulted in the RTO’s first reduction in its planning reserve margin since 1998 and a package of policies defining a load-responsible entity and its obligations. The task force also drafted a planning-reserve assurance policy and conducted a deliverability study. (See “Lowered Reserve Margin Promises $86M in Annual Savings,” SPP Board of Directors Briefs.)

Study Scopes Approved

The MOPC unanimously approved study scopes and revisions for a pair of studies, the Variable-Generation Integration study and the 2017 Integrated Transmission Plan’s 2017 Near-Term assessment.

The variable-generation study will include stability and frequency-response analyses with wind resources representing 30%, 45% and 60% of total SPP generation. SPP’s peak wind penetration record is 49.17%, and staff has said it expects to see levels approaching 60%.

Asked whether the task force is trying to determine when the 60% figure will be reached, SPP’s Casey Cathey, manager of operations analysis and support, said, “Sixty percent is a good level [to measure], because we have to add wind [generation] to get to that level. …The real issue, based on our footprint and our models, is will we see such penetration?”

Cathey said he is interested in determining whether there will be any voltage issues, saying, “We have to make sure that, given how we work the market, including dispatchable wind, whether we can maintain nominal voltage levels.”

The study will also analyze a potential five-minute ramping product.

The 2017 ITPNT’s scope was revised to include additional NERC transmission system planning performance (TPL-001-4) contingencies. Members also approved a modification to the 2017 ITPNT’s scenario 5, which sets all wind generation and reservations between companies to maximum firm service, as allowed on a pro rata basis. The modification aligns with the TPITF’s white paper, which assumed long-term firm transmission-service usage levels and conventional renewable resource output levels.

Regional Cost Allocation Review Approved

Members approved the Regional Allocation Review Task Force’s second regional cost allocation review of SPP’s regional- and zonal-allocation methodologies (RCAR II). There was one dissent.

The report’s 10 recommendations included proposed Tariff revisions and a proposal to incorporate its lessons learned in future assessments of the SPP highway/ byway methodology.

RCAR II identified the City Utilities of Springfield zone as SPP’s only deficient zone, with a benefit-cost ratio of 0.59, below the 0.8 threshold. Future transmission and seams studies with MISO and Associated Electric Cooperative Inc. are expected to help address the deficiencies. If not, a high-priority study for the area remains an option.

Two other zones (the Omaha Public Power District and Empire District Electric) are above the 0.8 cost-benefit threshold but below 1.0, requiring the RCAR II’s analysis be considered in future transmission plans.

The task force shared its report Monday with the Regional State Committee. Stakeholders will be able to provide their input through Aug. 5 for a lessons-learned report.

– Tom Kleckner

July 18, 2016

NYPSC Declares Moratorium on Low-Income Sign-ups

By William Opalka

The New York Public Service Commission on Thursday declared a moratorium on energy marketers signing up low-income customers, citing the inability of stakeholders to agree on consumer protection reforms (12-M-0476, et al.).

Zibelman © RTO Insider - NYPSC Declares Moratorium on ESCO Low-Income Sign-ups — Zibelman © *RTO Insider*

The commission voted 3-1 to impose the moratorium, which takes effect in 60 days.

The PSC ordered a stakeholder collaborative after its February 2015 order requiring energy service companies to guarantee that low-income consumers enrolled in utility assistance programs will pay no more under an ESCO contract than they would have as a full-service utility customer. (Alternatively, the ESCO must provide the customer with value-added products or services that do “not dilute the effectiveness of the financial assistance programs.”)

The collaborative, which included ESCOs, low-income advocates, utilities and regulators, was unable to reach a consensus that would have satisfied the aims of the order.

Commissioner Diane Burman opposed the moratorium. “The statements in the conclusion [of the order] seem to [be] more in the nature of an advocacy, rather than in a reasonable balancing of the issues that we’re supposed to deal with as regulators,” she said.

Burman said the collaborative’s report showed that some ESCOs were willing to offer savings but that the “pathway” for further discussion was cut off by the moratorium.

PSC Chair Audrey Zibelman said that the first imperative was to “do no harm” while the commission dealt with further enhancing consumer protections.

“The record is clear that low-income customers have not benefited from electric and gas supply services from ESCOs when that’s all that’s being purchased. The commission is taking steps to ensure energy affordability for low-income customers,” Zibelman said in a statement. “Unless and until these guarantees can be made, it is critical that we ensure that low-income customers are not paying any more than necessary for gas and electricity. We challenged the competitive retailers to look for ways to guarantee savings at or below the cost of utility-supplied power and gas.”

The action follows a PSC order in February 2016 that mandated savings for most retail customers. That order has been challenged by retail energy marketers. (See Court Delays New York ‘Guaranteed Savings’ Rules.)

The PSC estimates that there are more than 400,000 low-income customers served by ESCOs. Low-income customers represent about 25% of all electric customers in the state.

Customers currently served by an ESCO will revert to the host utility’s default service when their contract expires. The moratorium will last until the commission determines it can be lifted, the order states.

The Retail Energy Supply Association said it was reviewing the order with its members and legal counsel.

“If maintained, the moratorium would prevent low-income customers from accessing fixed-price energy offers that provide price certainty when compared to New York utilities’ monthly variable rates,” spokesman Bryan Lee said in a statement. “This is a benefit that is of particular value to consumers on fixed or limited incomes. By way of this order the commission has taken away the low-income consumer’s ability to enter into fixed rates just before the potentially volatile winter months when we know from experience that utility default rates can fluctuate widely in response to extreme weather.”

July 18, 2016

SPP, MISO Narrow Joint Study’s Scope

SPP’s Seams Steering Committee can expect to soon see a final scope of the next planned joint transmission study with MISO.

Adam Bell, SPP’s interregional coordinator, told the committee July 8 that the two RTOs have not nailed down the scope, but that it may not be limited to the Dakotas’ seam with the Western Area Power Administration, as MISO would prefer. The two grid operators agreed May 31 to take a “targeted” look at the newly created seam. (See “SPP, MISO Agree to Conduct ‘Targeted’ Joint Tx Study,” SPP Seams Steering Committee Briefs.)

“The scope will leverage some of the work we’ve done regionally,” Bell said.

The study is planned for completion in the first quarter of 2017.

SPP staff also told stakeholders it had filed an out-of-time intervention in an interregional planning dispute between MISO and PJM, as approved by the committee in June (EL13-88). (See “Committee Recommends SPP Intervene in FERC’s NIPSCO Docket,” SPP Seams Steering Committee Briefs.)

Staff said a MISO compliance filing removed several limitations that hampered efforts to resolve SPP-MISO seams issues, including the 345-kV and $5 million cost thresholds.

Committee Chairman Paul Malone, of the Nebraska Public Power District, reminded the committee that MISO believes the docket only applies to the MISO-PJM seam. “Why shouldn’t these same principles apply to the MISO-SPP seam?” he asked.

– Tom Kleckner

July 18, 2016

Del. Lawmakers Resolve to Fight Artificial Island Cost Allocation

The Delaware General Assembly has passed a resolution opposing PJM’s cost allocation for the Artificial Island project and creating a seven-member Cost Equity Committee to follow the issue through a planned rehearing at FERC.

Senate Concurrent Resolution 90 takes the place of a resolution approved by the state’s House of Representatives urging the Department of Natural Resources and Environmental Control to deny any easement request related to the project under the current cost allocation method. (See Del. Lawmakers Try to Block Artificial Island Plan; Project Still on Track.)

The Delaware Public Service Commission estimates that under the PJM transmission owners’ distribution factor cost allocation method (DFAX), about $354 million of the projected $410.5 million project cost will be assigned to customers in the Delmarva transmission zone, while the area stands to receive only 10% of its benefits. Following a January technical conference, FERC approved the Artificial Island project’s cost allocation on April 22. On June 21, it agreed to a rehearing. (See FERC Taking a Second Look at Cost Allocation for 2 PJM Projects.)

In addition to giving the new committee the authority to intervene in the rehearing, the measure also grants the group permission to be involved in any related court proceedings.

State and federal legislators representing Delaware, Gov. Jack Markell of Delaware, Maryland Gov. Larry Hogan and various agencies representing Delmarva ratepayers have bombarded FERC and the PJM Board of Managers with letters criticizing the cost allocation. (See Stakeholders Ask FERC to Rehear Cost Allocation Order.)

The upgrade to the New Jersey complex that houses the Salem and Hope Creek nuclear reactors involves sinking a new 230-kV transmission line under the Delaware River to Delaware.

— Suzanne Herel

July 18, 2016

UPDATED: LIPA Delays Vote on Offshore Wind Project; 90-MW Project Would be Largest in US

By Ted Caddell

The Long Island Power Authority on Wednesday delayed approving a proposed 90-MW offshore wind farm off the coast of Montauk, N.Y., that would be the largest such project in the U.S.

LIPA executives had expected an easy approval vote from its board of trustees, but they delayed the vote at the request of the New York State Energy Research and Development Authority, which also has a wind farm planned for off the Long Island coast.

The authority “has asked for a brief delay of the LIPA board vote so the project can be examined in the broader context of the Offshore Wind Master Plan, the development of which [NYSERDA] is leading for the State,” NYSERDA spokeswoman Dayle E. Zatlin said.

“The Master Plan and its forthcoming draft blueprint will inform decisions about the best way to manage this valuable resource in an environmentally responsible way and in order to obtain the lowest achievable offshore wind electricity cost for New Yorkers.”

That “blueprint,” she said, should be completed in a few weeks. “Together, these efforts are part of New York’s intent to foster greater renewable energy production, including offshore wind, on Long Island and throughout the state.”

A LIPA spokesman said a few week’s delay in the vote should have no impact on the Montauk project. “We’ve been talking off-shore wind for about 11 years on our island so the few weeks delay, in context, is not a deal breaker.”

LIPA has selected Deepwater Wind, which is already building a 30-MW project off Block Island, R.I., to develop the project.

The U.S. Bureau of Ocean Energy Management has awarded about a dozen leases for commercial wind, but only the Block Island project has begun construction.

Deepwater Wind spokeswoman Meaghan Wims said the Long Island project, to be called the South Fork Wind Farm, is part of a larger lease obtained from BOEM. “We bid 90 MW to LIPA as part of this” request for proposals, she said. “Our total capacity at that site is 1,000 MW, to be built over phases. The South Fork Wind Farm is the first phase.”

Deep Water Wind (Deep Water Wind) — View of the Block Island offshore wind project currently under construction by Deepwater, which was selected to build the Montauk project.

Montauk Project to Use 15, 6-MW Turbines

Deepwater will install 15 6-MW turbines about 30 miles off the coast of Montauk. Two 5-MW lithium-ion batteries will replace transmission investments that otherwise would be necessary. If all goes well, construction work could begin by 2021, with an operational date of December 2022, Falcone said.

“It is part of our goal to attain 400 MW of renewable energy, as part of the New York Clean Energy Standard, by 2023,” LIPA CEO Tom Falcone said in an interview Friday.

“We have an area of our service territory, East and South Hampton, with a lot of load growth, and we needed to address it in some way,” Falcone said. He said LIPA considered a transmission project to address the growing load, but after reviewing responses to its RFP, it determined the offshore wind project fit all the requirements.

“It’s the right project, the right size, and we can land in the right price area,” he said. Falcone said the project will cost a typical residential customer about $1.20/month.

Earlier offshore wind proposals were much more expensive than that, he said. Now, the cost of offshore wind is about the same as utility-scale solar — a resource not suited for crowded Long Island.

“I am not aware of any other utility that has signed a contract on a utility-scale project like this,” Falcone said. “We don’t have many other options” when it comes to renewable energy, he said. “On Long Island, land is constrained. But we have this tremendous offshore wind resource, thousands of megawatts. It is a tremendous resource.”

Lead Time Reduced

Falcone said much of the federal review process necessary for the Montauk project has already been done by Deepwater, which could save up to three years in the lead time for the project. “That was one thing that was particularly attractive” about the Deepwater plan, he said. “They are ready to go.”

Offshore wind projects need to be reviewed by BOEM to ensure they don’t encroach on commercial shipping areas or fishing grounds.

Community opposition has hindered other offshore wind projects on the East Coast. A 468-MW facility proposed off the coast of Massachusetts is tangled up in opposition from residents and no firm construction start date has been set.

Since news of its project got out, said LIPA Spokesman Sid Nathan, the authority has received dozens of messages of support from lawmakers, business owners and labor leaders. “We don’t expect community opposition of the proposal,” Falcone said.

“New York is boldly leading the way on a clean-energy revolution that will transform the nation’s energy future,” Deepwater CEO Jeffrey Grybowski said. “There’s real momentum for offshore wind in the United States, and Long Islanders are leading the charge.”

Currently, the largest offshore wind facility in the world is the 630-MW London Array, a 175-turbine facility off England’s eastern coast, in the outer Thames Estuary. DONG Energy is building tandem wind farms off the Dutch coast that will total 700 MW.