State Briefs

Boulder Continues to Consider Municipalization

Xcel Energy is expected to present new data to the city of Boulder this week to try and persuade the City Council to nix plans to acquire the utility’s assets and operate as a municipal entity.

City Attorney Tom Carr told the council that if the city is unable to come up with a plan that maintains service reliability and competitive customer rates, while also reducing greenhouse gas emissions at the pace mandated by the city charter, he would recommend abandoning municipalization plans.

The state’s Public Utilities Commission ruled in November that Boulder cannot acquire Xcel facilities that exclusively serve customers outside city limits. The commission declined to force Xcel to share its facilities with the city.

More: Daily Camera

DISTRICT OF COLUMBIA

OPC: Don’t Spend Merger Money Just Yet

The Public Service Commission should not spend $21.55 million from the merger agreement between Exelon and Pepco Holdings Inc. in case the decision is returned to the courts, the Office of the People’s Counsel said in a filing last week.

The public advocate, along with district government and several clean energy groups, is asking the PSC to reconsider its decision allowing the $6.8 million deal.

The $21.55 million that Exelon provided the district is part of a $78 million public investment fund. (See Exelon Closes Pepco Merger Following OK from DC PSC.)

More: Washington Business Journal

ILLINOIS

Peoples Gas to Pay $18.5M Over Misleading Costs

Peoples Gas and parent company Integrys Energy Group will pay customers $18.5 million for allegedly withholding information about its $8 billion program that replaces 2,000 miles of old iron gas mains beneath Chicago streets.

The settlement reached last week ends investigations by Attorney General Lisa Madigan and the Commerce Commission into allegations that project leaders failed to disclose $3.5 billion in cost overruns to regulators until Wisconsin Energy acquired Integrys last June. Peoples Gas maintains it did nothing wrong.

The settlement involves a combination of bill credits, legal reimbursements and grants to provide relief to low-income households for heating expenses.

More: Chicago Tribune

KANSAS

State Suspends Clean Power Plan Compliance Work

The state will officially suspend its work devising a plan to comply with the federal Clean Power Plan on May 19. It is at least the third state to take such a step after a U.S. Supreme Court ruling in February staying the rules until legal challenges are resolved.

Republican Gov. Sam Brownback signed the measure into law last week after the GOP-dominated Legislature approved it by wide margins late last month. The law prohibits state agencies from conducting studies or doing other work toward drafting a compliance plan until the U.S. Supreme Court’s stay is lifted.

Kansas was among 27 states challenging the rules, finalized by President Obama’s administration last year.

More: The Associated Press

MARYLAND

Morris Schreim to Take Walter Hall’s Place at PSC

The Public Service Commission has appointed Chief Engineer Morris Schreim to senior commission adviser. He takes the place of Walter Hall.

Schreim, who has been with the commission since 2013, will advise it on matters related to PJM and FERC.

Andrew Dodge will assume the position of chief engineer and director of emergency management. Dodge retired in December as vice president of technical services at Baltimore Gas and Electric.

More: Maryland PSC

MONTANA

Colstrip Owners Discuss Future with Governor

The CEOs of three of the Colstrip plant’s owners sat down with Gov. Steve Bullock last week to discuss what will happen to the aging coal-fired complex as out-of-state political forces push toward the eventual closure of its two older units.

Kimberly Harris of Puget Sound Energy, Paul Farr of Talen Energy and Bob Rowe of NorthWestern Energy represented half the plant’s ownership. Talen owns 50% of Units 1 and 2 and a 30% share of Unit 3. It also operates the entire four-unit Colstrip complex.

Farr made it clear that Talen wants to sell its stake in the plant. He suggested that industrial customers sign a power purchase agreement with the plant to keep it operational.

More: Billings Gazette

NEW HAMPSHIRE

Eversource Predicts Increase In Service Charge in July

Eversource Energy is predicting an increase in its energy service charge starting in July at the same time that three other state utilities, which purchase power from regional markets, are expecting lower prices.

The company filed a price forecast with regulators but is not formally requesting the rate change. It is predicting that it will request a rate of 10.94 cents/kWh, a 9.5% increase from the current 9.99 cents/kWh. Utilities in the state adjust their rates every six months to reflect shifting generation prices.

Eversource, which produces its own power, is allowed to pass through the cost of operating coal-fired power plants that it owns into its rate. Three other utilities buy power on the wholesale market, and their rates have dropped because of historically low natural gas prices.

More: New Hampshire Union Leader

NEW MEXICO

State Passes 1,000-MW Wind Capacity Mark

The state surpassed 1,000 MW of installed wind capacity last year, and analysts say the state is well positioned to expand its renewable power output.

Industry experts say the state has excellent wind resources, and investors already have put almost $2 billion into developing turbines in the state. Wind power accounted for 6.3% of all power generated in the state, according to John Hensley, manager of industry data and analysis for the American Wind Energy Association. An additional 300 MW of capacity is expected to come online this year.

The state currently has 14 wind projects that support more than 1,000 jobs and generate enough power for 189,000 homes.

More: Public News Service

Judge Allows Lawsuit Over City Munies to Proceed

A state judge last week denied the city of Farmington’s motion to dismiss the city of Bloomfield’s breach of contract lawsuit, filed in August as part of its attempt to purchase an electric utility from Farmington.

“A municipality must be able to control the utilities within its jurisdictional boundaries and acquire the necessary property and equipment to do so,” Judge Bradford Dalley said. “It cannot be said that the passage of time extinguishes that role, especially when the right has been recognized in an agreement preserved in a court order.”

The city of Bloomfield alleges that a 1960 court case and the subsequent judgment and decree served as a contract between the two cities that recognized Bloomfield’s right to purchase the utility from Farmington at any time. Farmington argues that the 1960 decree, known as the Culpepper Decree, was not a contract and was subject to the statute of limitations.

More: Farmington Daily Times

NEW YORK

SolarCity Subpoenaed In Lobbying Probe

SolarCity acknowledged it has been subpoenaed in a federal probe of improper lobbying and undisclosed conflicts in state contracts.

The company is developing a state-funded “gigafactory,” the centerpiece of Gov. Andrew Cuomo’s “Buffalo Billion” initiative. U.S. Attorney Preet Bharara is investigating how certain vendors were selected to construct the projects, including SolarCity’s. A company spokeswoman said it is complying with the investigation and that the company had no say in the selection process.

The governor’s office, the state economic development agency, the State University of New York Polytechnic Institute, the Public Service Commission’s Department of Public Service and the New York State Energy Research and Development Authority also have been subpoenaed.

More: Newsday

RHODE ISLAND

$700 Million Gas-Fired Power Plant Opposed

At a packed public hearing, the state Energy Facility Siting Board heard opposition to a new $700 million natural gas-fired power plant that would be built in the western part of Burrillville.

Residents told the board that Invenergy’s proposed facility does not belong in an area surrounded by woodlands, including protected lands in the Buck Hill and George Washington management areas.

About one-half of the plant’s 1,000-MW capacity was successfully bid into the ISO-NE Forward Capacity Auction for the 2019/20 commitment period. A decision from the siting board is expected early next year.

More: Providence Journal

SOUTH DAKOTA

City Oks State’s Largest Solar Project

The Pierre City Commission last week approved leasing 5 acres at the Pierre Regional Airport to Geronimo Energy in what is expected to be the state’s largest solar energy project.

Minnesota-based Geronimo will install the 1-MW facility this summer. The power will be distributed into Pierre’s municipal electrical system.

It also will be first solar project for Missouri River Energy Services, which provides 43% of the city’s electrical power. The city gets the remaining 57% of its electricity from the Western Area Power Administration, which is not part of the project.

More: Capital Journal

WISCONSIN

Watchdog Calls out $138M School Energy Overruns

A little-known exemption has allowed 147 school districts to exceed state-imposed revenue limits by spending a combined $138 million on energy efficiency measures.

The Wisconsin Taxpayers Alliance says that a 2009 law allowed state school districts to exempt energy efficiency expenditures from state rules that require voter approval if revenue limits are exceeded. The Wisconsin Association of School Boards said the exemption encourages school districts to make investments in energy efficiency to achieve long-term operating savings.

A bill to end the exemption, sponsored by two Republican legislators, was stalled in the Legislature last session.

More: Wisconsin Watchdog

May 16, 2016

Stephen Whitley: A Lifetime of Keeping the Lights On

By William Opalka

NORTH FALMOUTH, Mass. — Having spent 45 years running transmission grids, former NYISO CEO Stephen Whitley is an infrastructure guy.

Stephen-Whitely,-former-NYISO-CEO-web — Stephen Whitley © *RTO Insider*

Whitley, who retired last October after seven years at the ISO, emphasized the importance of wires and pipelines in his keynote speech Wednesday at the Northeast Energy and Commerce Association’s 23rd Annual New England Energy Conference.

He reflected on his career, which also included 30 years of operations and management positions at the Tennessee Valley Authority before he moved to the Northeast. His personal highlight reel seemed to be a solid string of crisis management. Nuclear shutdowns at TVA in the late 1980s. The 2003 blackout. A horrific New England cold snap in 2004. Hurricane Sandy. The polar vortex.

“It seemed like these problems followed me around,” he joked.

A common theme was “the need for transmission” to navigate through these near-disasters.

Five-Year Shutdown

In 1985, the Nuclear Regulatory Commission ordered shutdowns of the Brown’s Ferry plant in Alabama and the Sequoya station in Tennessee over safety concerns.

“It was 6,000 MW of capacity and we thought it would be three or four months, but it turned out to be five years,” he said.

The TVA hydro system simultaneously suffered through two droughts, so 4,000 MW of hydropower were reduced to 2,500 MW for much of that time, causing “a few tough years.”

“The way we got through it most of the time was through the transmission grid,” Whitley said.

Whitley said the system survived through imports from areas with greater fuel diversity, an experience that would be repeated in his later jobs in New England and New York.

7,000 MW out of Service

In 2004, New England — less reliant on natural gas for power generation than it is now — suffered through five days with minus 10-degree temperatures and 45-mph winds, recalled Whitley, who was ISO-NE’s chief operating officer at the time. “One day I went to the control room and one of the operators told me we had 7,000 MW of power plants that couldn’t come online.”

The crisis was eased when some New York generators switched to oil-fired generation, which freed up some gas pipeline capacity.

“That’s when you see it’s not just the electric system that is so important, it’s the infrastructure of the gas supply system and the diversity of the generation capacity,” Whitley said.

Transmission, fuel diversity and imports also got NYISO through Hurricane Sandy in 2012 and the polar vortex in early 2014.

Whitley said he worries the next crisis could result from the Northeast’s switch to “all renewables and gas” without, he says, adequate infrastructure to support it. He said the recent suspension of the Northeast Energy Direct pipeline was disappointing. (See Kinder Morgan Board Suspends Work on Northeast Energy Direct Pipeline.)

Without diverse energy supplies and robust infrastructure, he said, the system will be stressed.

“Each region is going to have to be more capable of carrying its own load,” Whitley said. “As all these coal plants shut down, there just isn’t going to that much surplus available.”

May 16, 2016

PJM Planning Committee and TEAC Briefs

VALLEY FORGE, Pa. — Interconnection customers would face a stricter submittal process for their projects beginning Nov. 1 under Tariff changes unanimously approved Thursday by the Planning Committee.

The revisions were recommended by the Earlier Queue Submittal Task Force, which was convened to figure out ways to incent earlier participation in the process after current rules failed to influence behavior. (See “Stricter Rules Proposed for Queue Submittal Process,” PJM Planning Committee and TEAC Briefs.)

In general, the changes require earlier submittal of documentation in order to secure a place in the project queue. PJM would perform a deficiency review only after all elements, aside from site control, were in hand.

Applications would have to clear their deficiencies by the close of the queue window or be terminated.

The revisions also would allow project deposits to become chargeable immediately, and PJM would spend the refundable portions first.

In addition, the opening of queue windows would be moved up to April from May and to October from November, which will improve the chances for large generators to participate in the May Base Residual Auction.

Typical TO Upgrades Would be Excluded from Competitive Window Under Proposal

PJM is proposing to exclude typical transmission substation equipment violations from the Order 1000 competitive window process. The Planning and Markets and Reliability committees will be asked to approve new Operating Agreement language in June.

A historical look at the Regional Transmission Expansion Plan revealed that such fixes rarely yield greenfield proposals. If analysis showed that a greenfield project is possible, PJM would open a proposal window.

The exclusion would not apply to supplemental or market efficiency projects. (See “Proposal Would Exclude TO Upgrades from Order 1000 Window,” PJM Planning Committee and TEAC Briefs.)

IRM Study Assumptions Presented for First Read

The Resource Adequacy Analysis Subcommittee is recommending that PJM retain its current load model selection process for the installed reserve margin (IRM) study with one minor change: The procedure will be modified to recognize that the annual peak can only occur in the peak summer week.

PJM’s Tom Falin said that had the change been implemented for the 2015 reserve requirement study, it would have resulted in the same load model being chosen and produced the same IRM and forecast pool requirement.

The Planning Committee will be asked to endorse the study assumptions at its next meeting.

“It’s really a minor change with no consequence,” Falin said.

Planners will continue to model a 2,500-MW ambient derating in the summer period.

The RAAS met six times over five months to study all of the assumptions used in the IRM study after PJM’s methodology was questioned. (See “IRM, FPR Rising; PJM Methodology Challenged,” PJM Planning Committee Briefs.)

The group identified three assumptions that warranted in-depth investigation: the load model selection process, world modeling and the capacity benefit of ties, and the ambient derating of generators in the summer period.

“It’s essentially the same as last year, but the subcommittee is more comfortable with those assumptions after having drilled into them,” Falin said.

PJM-MISO to Create ‘Targeted Market Efficiency Projects’

PJM and MISO are working to revise their joint operating agreement to create a category of “targeted market efficiency projects” that could be undertaken quickly and relatively inexpensively to remedy historical congestion. These would be treated separately from traditional market efficiency projects, which look at projected model conditions under future assumptions, said PJM’s Chuck Liebold.

“These projects would be very targeted in nature,” he said. They probably would consist of upgrades to terminal equipment, and an aggressive in-service date would be assigned to them.

The upgrades would be recommended on an annual basis, with proposals going before the boards of each RTO in December.

He said the study process will be similar to an effort the RTOs undertook last year, when they were unable to approve any projects. (See MISO-PJM ‘Quick Hit’ Projects Shrink to Two.)

The projects would be evaluated based on five years of benefits at a benefit-cost ratio of 1.0.

Planners Choose Project to Relieve APSouth Congestion

Planners intend to recommend a $340.6 million APSouth market efficiency project to the Board of Managers, despite some stakeholders’ recommendations that they take another look at three other proposals.

LS Power’s Sharon Segner said that the 9A (without capacitors) proposal is not necessarily the most feasible and that it faces permitting problems.

“We’ve been [evaluating proposals] for more than a year now, and I am confident with what we’re proposing now,” PJM’s Tim Horger said.

He said the project provides the most congestion savings to PJM and APSouth as well as the most production cost savings.

The project would tap the Conemaugh-Hunterstown 500-kV line and build a new 230-kV double circuit line between Rice and Ringgold. The plan also calls for building a new 230-kV double circuit line between Furnace Run and Conastone and rebuilding the Conastone-Northwest 230-kV line. (See “Planners Select Dominion-Transource Project to Address APSouth Congestion,” PJM Transmission Expansion Advisory Committee Briefs.)

It is projected to be in service by 2020.

Two Dominion Zone Reliability Projects Recommended

PJM presented two reliability projects it intends to recommend to the Board of Managers out of more than two dozen it received in the first proposal window of the year.

Both are in the Dominion transmission zone in Virginia, with projected in-service dates of June 1, 2020.

One addresses the overload of the Chesterfield-Messer Road-Charles City Road 230-kV circuit. The $22 million project consists of rebuilding 21.3 miles of existing line between Chesterfield and Lakeside.

The other addresses the overload of the Carson-Rogers Road 500-kV circuit. The $48.5 million project would rebuild the circuit.

Cogentrix Hopewell Units to be Deactivated

PJM has received a deactivation notice from James River Genco for Units 1 and 2 of Cogentrix Hopewell in the Dominion zone.

Together, the units represent 92 MW. The requested deactivation date is May 31, 2017.

PJM is conducting a reliability analysis.

Preliminary CPP Compliance Analysis Presented

PJM presented some of the first findings of its study of Clean Power Plan compliance to Transmission Expansion Advisory Committee members.

The review continues to indicate that regional compliance is cheaper. In addition, it showed that mass-based compliance provides more certainty in emissions levels than rate-based but that the latter approach can lead to fewer retirements.

Rate-based compliance also reduces wholesale energy market prices. (See “Reference Model for CPP Study Introduced,” PJM Planning Committee and TEAC Briefs.)

– Suzanne Herel

May 16, 2016

PJM Operating Committee Briefs

VALLEY FORGE, Pa. — About 1,900 MW of behind-the-meter generation may be unavailable because of tightened environmental rules, PJM told the Operating Committee last week.

PJM shared with the committee new EPA guidance issued in response to an appellate court decision last year that voided a rule exempting diesel generators providing demand response from air emissions limits.

EPA had exempted reciprocating internal combustion engines providing “emergency demand response” from emissions limits for up to 100 hours each year. The D.C. Circuit Court of Appeals ruled that the agency had “cavalierly sidestepped its responsibility to address reasonable alternatives” to the use of the generators. (See Appellate Court Rejects EPA Rule on Back-Up Generators.)

As a result of the ruling, EPA said such an engine “may not operate … for any number of hours per year unless it is in compliance with the emission standards and other applicable requirements for a nonemergency engine.”

That means behind-the-meter generation may only be used if it can respond when dispatched by PJM and comply with local, state and federal laws, including environmental permits, PJM said. Demand response that fails to perform when dispatched by PJM will be penalized, and there are no exceptions for the status of environmental permits.

“We have reached out and talked to our [curtailment service providers], and virtually everyone we talked to has made arrangements so they can meet their commitment for the summer,” PJM’s Pete Langbein said. “We at PJM do not see an impact going into the summer on capacity.”

Generators Employing Best Practices for Winterization

ReliabilityFirst Corp. gave the Operating Committee a lessons learned presentation resulting from its plant winterization visits since 2014.

PJM members have deployed “inventive solutions,” including additional enclosures to prevent freezing, portable heaters and a downspout system to divert rain and moisture away from inlet air filters, ReliabilityFirst said.

It identified just three areas for improvement: routinely operate any idle or standby equipment; make sure heat “tracing” or freeze protection is installed on any vulnerable equipment; and ensure the plant instrument air system is continuously supplying moisture-free air.

PJM Proposes to Sunset SIS, Move Topics to DMS

PJM is proposing to sunset the Systems Information Subcommittee and move some of its discussion topics to the Data Management Subcommittee, whose charter would be expanded.

Those topics relate to inter-control center communication protocol data links, Manual 01 changes and phasors.

The proposal also includes creating an “implementation forum,” which will be the primary venue for PJM to communicate technical changes to members and vendors.

Summer Base Case Study Yields No Reliability Issues

No reliability issues were identified in the 2016 summer base case study.

Off-cost generation re-dispatch and switching was required to control local thermal or voltage violations in some areas.

All voltage violations on networked transmission were controlled by capacitors, and all other such violations were caused by radial load, PJM said.

– Suzanne Herel

May 16, 2016

PJM LMPs Drop 47% in 1st Quarter

PJM energy market prices dropped 47.4% in the first quarter compared with a year earlier because of lower fuel prices and demand, the Independent Market Monitor reported in its quarterly State of the Market report.

LMPs averaged $26.80/MWh for the quarter versus $50.91/MWh in the first three months of 2015.

Net energy revenues — a measure of market performance and investment incentives — decreased by 62% for a new combustion turbine, 51% for a new combined cycle plant, 38% for new wind and 62% for a new solar installation.

Mild weather and low fuel prices contributed to a 79% drop in uplift costs, to $39.1 million from $186.4 million in 2015. Congestion costs decreased by almost 54% to $292.2 million.

– Rich Heidorn Jr.

May 16, 2016

PJM Members Committee Preview

Below is a summary of the issues scheduled to be brought to a vote at the Members Committee on Thursday during PJM’s Annual Meeting. Each item is listed by agenda number and description, followed by a summary of the issue and links to prior coverage in RTO Insider.

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

CONSENT AGENDA
Members will be asked to approve revisions to Manual 34: PJM Stakeholder Process as a result of a periodic review. The changes update language and formatting for clarification and graphics for better readability.
Revisions to the governing documents involve non-substantive reorganization and relocation of definitions.
PJM proposes to change the emergency energy default customer baseline (CBL) from the “hour before” methodology to the current default economic CBL. (See “Members Endorse New Way to Measure Emergency DR,” Market Implementation Committee Briefs.)
PJM BOARD OF MANAGERS NOMINATING COMMITTEE

Members will be asked to elect members to the Board of Managers. The committee is recommending Terry Blackwell for re-election and nominating two newcomers, Dean Oskvig, retired CEO of Black & Veatch, and Mark Takahashi, CFO of Ascendant Group. (See Committee Recommends 2 Industry Vets for PJM Board.)

May 16, 2016

Analysts Expect Lower Clearing Prices in 2019/20 PJM Capacity Auction

By Suzanne Herel

Analysts are predicting lower clearing prices for PJM’s 2019/20 Base Residual Auction, which began Wednesday and concludes today. Results are to be published May 24.

Last year’s auction, held in August, saw prices of $164.77/MW-day for Capacity Performance in most of the RTO, with the ComEd zone at $215/MW-day and Eastern MAAC hitting $225.42. Base capacity priced about $15/MW-day lower. (See PJM Capacity Prices up 37% to $165/MW-day.)

Morningstar analyst Jordan Grimes forecasts a price of $160/MW-day for the Capacity Performance product in the RTO and MAAC regions and $180/MW-day in EMAAC and SWMAAC. He predicts base capacity will price at a discount of $10/MW-day.

Julien Dumoulin-Smith of UBS Securities reduced his forecast CP price from $140/MW-day to $125/MW-day for the RTO region, with prices higher in EMAAC, DPL-S, PS-N and PSEG ($200/MW-day) and ComEd ($225/MW-day).

Grimes took note of ISO-NE’s Forward Capacity Auction 10 in February, in which prices dropped by more than a quarter. (See Prices Down 26% in ISO-NE Capacity Auction.)

“PJM participants fear a similar fate,” Grimes wrote. “We believe this fear is unwarranted. PJM will have to clear a significant amount of coal and peaking gas capacity in the upcoming auction.”

In a note to investors last week, Dumoulin-Smith said new gas generators, a lower load forecast and the Supreme Court ruling upholding FERC jurisdiction over demand response compensation will likely keep prices from rising in most of the region.

Dumoulin-Smith also said he expects a larger differential between CP and base capacity than last year. “We believe we could well see a base print for the RTO region below $100/MW-day. This pricing pressure could help limit any increase in demand response product availability.”

The RTO plans to acquire 157,092 MW of capacity for delivery year 2019/20, 80% of it Capacity Performance. This year’s price cap is $448.95/MW-day, compared with $450.86/MW-day for the 2018/19 auction.

This is the second and last year that the auction will offer two products. The base product will be eliminated beginning in the 2020/21 delivery year.

UBS predicts “price compression” in EMAAC, with Talen Energy’s Sapphire portfolio clearing at least partially.

Morningstar’s model predicts Exelon’s Quad Cities nuclear plant will not clear. Exelon CEO Chris Crane said earlier this month that the company will close Quad Cities if it doesn’t clear the auction and Illinois legislators don’t approve measures to shore up the money-losing plant. (See Absent Legislation, Exelon to Close Clinton, Quad Cities Nukes.)

UBS predicted disappointment for “more RTO-exposed generators” such as Dynegy, NRG Energy and FirstEnergy. It said that although it expects new capacity resources to clear the auction, their ability to obtain financing is in question.

“We have noted a meaningful slowing in development activity in recent months. Banks appear to be increasingly cautious to lend against assets given the wider pullback in power valuations and cumulative exposures to merchant PJM increasing. We expect this slowing to principally impact the 2020/21 auction next May 2017.”

May 13, 2016

Con Ed-PSEG ‘Wheel’ Ending Next Spring

By William Opalka

Consolidated Edison will stop using the “PSEG wheel” next April, following through on a promise it made late last year in a dispute with PJM over transmission upgrade costs.

The company said it would not renew two point-to-point transmission agreements under which Public Service Electric and Gas takes 1,000 MW from Con Ed at the New York border and delivers it through New Jersey to Con Ed load in New York City.

Con Ed, which said it has identified less costly alternatives, informed the New York Public Service Commission of its decision in a letter May 2 (12-E-0503).

The company says that renewing the wheel after its April 30 expiration would expose it to $680 million in cost allocation charges for two transmission projects that it says primarily benefit New Jersey customers.

“Con Edison no longer requires power sources from the PJM wheel for reliability purposes, and unfair cost allocations have become too costly for our customers,” spokesman Bob McGee said. “Other electric projects added in recent years that already serve our customers will help us maintain reliability. We will continue to have access to the PJM wheel in an emergency.”

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 of the cost. Con Ed was also assigned $51 million of PSE&G’s $100 million Sewaren storm-hardening project.

Con Ed contended it should pay only $29 million for the two New Jersey projects, but FERC approved PJM’s cost allocation on the Bergen-Linden project last month in a 3-1 vote. (See FERC Upholds Cost Allocation for Artificial Island, Bergen-Linden Projects.)

Paul McGlynn, PJM general manager of system planning, told the PJM Planning Committee on Thursday of Con Ed’s intentions.

“We will need to make changes to the procedures we use in planning and operations,” he said. “This is just a heads-up that we’re going to need to be discussing it in the future. As plans take shape, we will be doing analysis on them. The goal is to discuss and determine how we will manage that interface without the wheel.

“When that wheeling agreement is canceled, we will need to redo cost allocations for any and all of the projects that Con Ed has allocation for, and we’ll have to file them at FERC. They would become effective when the agreement actually terminates in the spring of 2017,” McGlynn added.

“NYISO is working with PJM to develop an effective going-forward approach for the border,” ISO spokesman David Flanagan said. “In addition, NYISO will include this change in the full range of system information currently being gathered for the 2016 Reliability Needs Assessment that will study potential reliability needs for the period of 2017-2026.”

Bergen-Linden Corridor Upgrade Source: PSEG — Bergen-Linden Corridor Upgrade *Source: PSEG*

Identification of the transmission projects that allowed Con Ed to cancel the wheel began in 2012, although for an entirely different reason. New York regulators at that time began discussions about transmission alternatives that would be needed if the Indian Point nuclear plant closed because its licenses were not renewed.

The NYPSC approved several projects in 2013 for that contingency, including three named the Transmission Owner Transmission Solutions. FERC in March accepted a cost allocation formula submitted by state regulators and New York transmission owners, including Con Ed. (See FERC OKs Settlement for NY TOTS Projects.)

One of the alternative projects, the $274.3 million “Staten Island Unbottling” would make 440 MW of generation available to the New York grid through Con Ed’s substations in a two-phase project.

However, in a February order, the NYPSC accepted a Con Ed motion to cancel the second phase. Con Ed said that once the wheel expired, transmission limitations caused by it would be eliminated and that only the $51.3 million first phase was necessary.

Suzanne Herel contributed to this article.

May 13, 2016

EPA: Methane Rules to Have Minimal Impact on Gas Costs

By Rory Sweeney

EPA said rules it issued Thursday to reduce methane emissions from oil and gas development will raise wholesale natural gas prices by less than 1%, but the industry’s leading trade group warned the “unreasonable and overly burdensome” regulations could depress shale gas development.

Infrared image of emissions from natural gas storage tank Source: Texas Commission on Environmental Quality, epa — Infrared image of emissions from natural gas storage tank *Source: Texas Commission on Environmental Quality*

The agency said the rules will cost a net $320 million annually through 2020, with a $390 million total cost reduced by $70 million in revenue from sales of methane now lost into the atmosphere. By 2025, the estimated total cost increases to $640 million, offset by gas sales of $110 million, for a net cost of $530 million. The estimates, in 2012 dollars, assume a price of $4/Mcf.

EPA estimated that the rules will reduce gas well drilling by about 0.% and production by about 0.03% between 2020 and 2025, compared to the baseline. The agency estimated wellhead prices for onshore lower-48 production will increase during that period by about 0.2% and net imports will rise by about 0.11%.

Reduced Innovation?

The American Petroleum Institute said the costs will be more than twice EPA’s estimate, pegging them at $806 million per year in 2025.

“It doesn’t make sense that the administration would add unreasonable and overly burdensome regulations when the industry is already leading the way in reducing emissions,” Kyle Isakower, API’s vice president of regulatory and economic policy, said in a statement. “Imposing a one-size-fits-all scheme on the industry could actually stifle innovation and discourage investments in new technologies that could serve to further reduce emissions.”

The new rules are designed to reduce fugitive methane emissions from compressor stations, gas processing plants and well sites, including fracking operations. The rules also cover pneumatic pumps and controllers, centrifugal compressors and reciprocating compressors. Well site compressors are exempt.

Monitoring

The rules — which cover new and modified operations — are stringent, requiring substantially greater monitoring and emissions control than before across all areas of the extraction and production process. Well sites will be required to conduct biannual monitoring using either an infrared camera or a vapor “sniffer” and must repair leaks within 30 days. Compressor stations must be quarterly. Natural gas processing plants are already checked this way for other emissions, but they now must include methane.

Gas Separator Source: EPA, natural gas, methane — Gas Separator *Source: EPA*

After fracking a well, operators will need to install equipment that separates gas from the fluid that flows back to the surface and collect or combust it. Wildcat, exploratory and low-pressure wells are required to have combustion devices but not the separation equipment.

Many of these operations were already regulated for volatile organic compounds (VOCs) and hazardous air pollutants (HAPs) — but not methane — under the 2012 New Source Performance Standards, which regulate pollutant emissions from new or modified sources. The new rules also include several edits to the NSPS, including how flares can be done, leak detection and repair, and monitoring and testing of storage-vessel control devices.

EPA said the rules are justified because the costs will be outweighed by “monetized climate benefits” of $360 million in 2020 and $690 million in 2025. Such benefits were calculated in relation to greehouse gas emissions only, but the agency said there will be additional benefits from the associated reductions in VOCs and HAPs.

Methane is second only to carbon dioxide in its overall contribution to global warming. A ton of methane traps 25 times as much heat in the atmosphere as the same amount of CO₂ over a 100-year period.

The changes to the NSPS were released along with two other rules affecting the industry. One requires emissions reductions for operations on certain Native American lands. The other clarifies what equipment should be grouped together to calculate whether a site is a major or minor emissions source.

EPA estimates about 270 full-time equivalent workers will be needed to meet compliance. The agency estimates that will increase to about 1,800 in 2025.

May 12, 2016

UPDATED: PUCO Grants FirstEnergy Rehearing on PPA; Opponents File Protests

By Ted Caddell

The Public Utilities Commission of Ohio agreed Wednesday to hear FirstEnergy’s arguments for why it should be able to withdraw its controversial power purchase agreement and substitute a new plan.

It also granted all of the applications for rehearing sought by opponents of the PPA, including the Electric Power Supply Association, the Ohio Consumers’ Counsel, the Environmental Defense Fund, the Sierra Club, the Retail Energy Supply Association and the PJM Power Providers Group.

“Because of the number and complexity of the assignments of error raised in the applications for rehearing, as well as the potential for further evidentiary hearings in this matter, we find that it is appropriate to grant rehearing at this time,” the commission said (14-1297-EL-SSO). “This will allow parties to begin discovery in anticipation of potential further hearings.”

Although its rehearing request also was granted, the EDF protested the ruling.

“So, without listening to the arguments against the deal, the PUCO rubberstamped [FirstEnergy’s] request for a rehearing,” the EDF’s Dick Munson wrote in a blog post that went up within minutes of PUCO’s order.

Both FirstEnergy and American Electric Power were granted eight-year PPAs after more than a year of legal wrangling. But their victories were short lived, as FERC ruled that the agreements would require a review that could nullify them.

Opponents Sound Off

On Thursday, PUCO received a stream of filings against the modified FirstEnergy plan, including those from the Ohio Energy Group, the Northeast Ohio Public Energy Council, the Sierra Club, the PJM Power Providers Group (P3) and the Electric Power Supply Association.

P3 and EPSA accused FirstEnergy of doing an end-around play to avoid review by FERC. FirstEnergy, they said, is wrongly “attempting to use the commission’s application for rehearing process to circumvent the FERC order.”

“FirstEnergy, however, has made a mistake in how it presented its new PPA proposal to this commission,” they wrote. “FirstEnergy did not include or mention its new proposal in its application for rehearing, robbing the commission of jurisdiction over the proposal in this proceeding. This means that the commission cannot grant rehearing on the proposal and, contrary to its May 11, 2016, action, cannot reopen this proceeding to allow discovery on the proposal. The proposal is dead on arrival and the commission must follow the law by not exercising jurisdiction through rehearing.”

The Sierra Club also filed in opposition to the FirstEnergy plan.

“While FirstEnergy is trying to put old wine in a new bottle to escape review under federal customer protection standards, its latest shareholder bailout proposal is the same bad deal for Ohio customers,” said Shannon Fisk, managing attorney at Earthjustice, which represents the Sierra Club. “FERC smartly put a hold on FirstEnergy’s bailout so that customers would not be losing money while the legality of the bailout is fully reviewed. PUCO should not sign off on FirstEnergy’s brazen effort to evade FERC’s order.”

Thursday was also the deadline for arguments against AEP Ohio’s request to modify its PPA, and that docket also swelled with filings from opponents.

FERC ruled April 27 that the PPAs — in which AEP’s and FirstEnergy’s regulated utilities would purchase output from the companies’ merchant generators — must be reviewed under the Edgar affiliate abuse test (EL16-33 and EL16-34).

AEP CEO Nick Akins said after FERC’s ruling that the company would either lobby Ohio lawmakers to reregulate the state’s electricity market or sell off its Ohio fleet rather than submit to FERC review. FirstEnergy CEO Chuck Jones has also said he would welcome reregulation. (See All Eyes on AEP, FirstEnergy with Ohio PPAs in Doubt.)

Both utilities then filed for rehearing with PUCO. FirstEnergy asked the commission to withdraw its PPA and replace it with a customer charge that would still protect its aging power plants. Munson called FirstEnergy’s new plan “sleight of hand” and said PUCO’s decision Wednesday “suggests commissioners care more about appeasing a politically connected company than protecting customers or considering both sides of an argument.”

AEP Request

AEP scaled back its original request for PPAs for all of its 3,100-MW Ohio merchant fleet, asking PUCO for an agreement covering only its 440-MW share of the Ohio Valley Electric Corp. (14-1693-EL-RDR, 14-1694-EL-AAM). AEP said it will stand by its commitment to develop 900 MW of renewable energy — a promise that convinced the Sierra Club to sign on to its plan — with certain provisos.

On Thursday, the Office of the Ohio Consumers’ Counsel and the Appalachian Peace & Justice Network jointly filed a memorandum urging PUCO to deny AEP’s request to change its “electric security plan” (ESP).

“Even though AEP Ohio appears to have shuttled its plans for an affiliate PPA, in light of FERC’s rulings, it nonetheless has come up with another way to extract money from customers,” the two organizations wrote. They said AEP Ohio’s idea to seek a PPA covering only the OVEC portion of its generating fleet was already denied once by PUCO in a 2015 decision. “There is no reason to stray from that decision,” they wrote. PUCO at that time, they said, ruled that a OVEC-only PPA rider “would not provide a sufficiently beneficial financial hedge, or other commensurate benefits, to AEP Ohio’s customers to justify approval.”

“The PUCO should also consider that when AEP Ohio negotiated the OVEC contract, it agreed to an allocation of risk regarding Capacity Performance penalties and bonuses,” the groups argued. “The PUCO should not undo the deal that AEP Ohio itself struck by bailing it out from the agreed-to risk allocation and imposing the risk on customers.”

The groups also argue that PUCO’s rules don’t allow AEP Ohio to modify the ESP. It only allows it to accept PUCO’s modifications or withdraw and terminate its entire request, they said.

P3 and the Electric Power Supply Association also argued that AEP’s rehearing request and “rehashed proposal” should be denied, also noting PUCO’s 2015 ruling.

“With the affiliate PPA removed from the PPA rider, AEP Ohio is left with only its OVEC entitlement — a construct this commission expressly rejected in 2015,” they wrote. “The commission should deny AEP Ohio’s application for rehearing, reverse its approval of the stipulation and terminate this hearing.”

The Mid-Atlantic Renewable Energy Coalition filed a memo supporting AEP’s rehearing request, saying it is necessary to “preserve the significant public policy benefits” of the original renewable energy agreements.