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November 2, 2024

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Dynegy, NRG Ask FERC to Void Ohio PPAs

By Rich Heidorn Jr.

Dynegy, NRG Energy and other independent power producers asked FERC Wednesday to void the power purchase agreements FirstEnergy and American Electric Power have proposed to Ohio regulators, saying the deals fail the commission’s Edgar/Allegheny test regarding affiliate transactions.

PJM, meanwhile, filed an amicus brief with regulators Monday, calling AEP’s assertions that reliability would be threatened if its units retired “a red herring.”

The IPPs and the Electric Power Supply Association jointly filed complaints against the AEP (EL16-33) and FirstEnergy (EL16-34) proposals, saying they were seeking to ensure that “abusive” affiliate power sales contracts do “not evade [FERC] review.”

The Ohio-based companies have proposed PPAs to the Public Utilities Commission of Ohio that would provide a guaranteed return for their embattled generating stations for eight years. PUCO staff has signed on to both proposals.

The complainants said FERC should revoke the waivers it granted AEP and FirstEnergy regarding affiliate power sales to ensure a Section 205 review of the PPAs under the standards the commission set out in its 1991 Edgar Electric Energy Co. (55 FERC ¶61,382) and 2004 Allegheny Energy Supply Co. rulings (108 FERC¶61,082).

The Edgar ruling required demonstration that long-term PPAs utilities sign with their marketing affiliates are reasonably priced compared to alternatives. The commission said such a demonstration could include evidence of competition between affiliated and unaffiliated suppliers or a showing of prices paid by non-affiliated buyers. FERC refined its guidance in Allegheny.

“The fact that AEP has devised, and that the PUCO may approve, a clever scheme to shift costs of this abusive affiliate contract onto consumers does not alter the commission’s statutory duty to protect consumers from the effects of unjust and unreasonable wholesale rates or in any way make it less critical to ensure the integrity of the PJM markets,” the plaintiffs wrote, using nearly identical language in their FirstEnergy complaint.

The complainants cited “fundamental changes in circumstances since the commission granted the waiver that make it unjust, unreasonable and unduly discriminatory to allow AEP Generation Resources to enter into the affiliate PPA pursuant to its blanket market-based rate authorization.”

Quick Action Sought

They asked the commission to act quickly, noting that PUCO may rule on the PPAs as soon as next month and contending the agreements could have a major impact on PJM’s 2019/20 Base Residual Auction in May.

Joining EPSA, Dynegy and NRG in the complaint were the Retail Energy Supply Association and Eastern Generation, a subsidiary of a private equity fund managed by ArcLight Capital Partners, whose generation holdings include an 825-MW natural gas-fired generation facility in Vinton County, Ohio.

The Ohio Consumers’ Counsel filed comments supporting the call for FERC review.

“We expected allegations similar to those made in the complaint that was filed at FERC, and we are confident that the PPA will pass the test,” said FirstEnergy spokesman Doug Colafella.

“FirstEnergy’s Ohio Utilities were granted authority to conduct transactions with our unregulated affiliates after Ohio restructured its electric markets to allow shopping with energy suppliers.  This arrangement extends to our proposed purchased power agreement, so absent further FERC orders, separate FERC approval of the PPA is not necessary,” he added. “We carefully evaluated this issue when preparing our filing with the Public Utilities Commission of Ohio — the regulatory agency that is solely authorized to approve the proposed retail stability rider on customer bills associated with the PPA.”

AEP spokeswoman Melissa McHenry said PUCO “is fully able to protect retail customers. So, any allegations that AEP Ohio customers need to be protected from excessive charges are simply untrue.

“The core question for FERC is whether there is retail competition under Ohio law. FERC has determined in other cases that there is competition in Ohio and has agreed that the PUCO is better equipped to make that determination. The AEP Ohio PPA will provide rate stability for all AEP Ohio customers, and they can still choose any supplier for their electricity needs.

“The PUCO has conducted an extensive review process over the last two years to ensure that AEP Ohio customers are treated fairly and benefit from the PPA. The parties filing at FERC should participate in that process instead of appealing to a federal agency for relief at the last stage of the process,” she said.

The plaintiffs said the affiliate PPAs threaten “exactly the harm to both captive consumers and markets that prompted the adoption of [FERC’s] restrictions in the first place,” saying it would “saddle captive Ohio consumers with hundreds of millions or even billions of dollars in above-market costs” and distort prices in the PJM markets by subsidizing the continued operation of more than 6 GW of generation that AEP and FirstEnergy say would otherwise retire.

AEP has said that PUCO must approve or reject the PPA as is, saying it “lacks jurisdiction over the rates and terms” of the agreement. At the same time, the company says it does not intend to submit the agreement for FERC review.

“Failure to review the affiliate PPA would recreate precisely the sort of regulatory gap that the [Federal Power Act] was enacted to fill” in 1935, the plaintiffs said.

‘Greedy Tiger’

To conduct a review of the AEP proposal, the plaintiffs said the commission should first revoke the waiver it granted in 2014 regarding AEP Ohio, a franchised public utility, and its market-based affiliate AEP Generation (ER14-593). Because of Ohio’s retail choice, the AEP companies said in their petition for a waiver, AEP Ohio would not have captive retail customers.

The plaintiffs said that is not true regarding the proposed PPAs because they would be funded by surcharges on all customers within AEP and FirstEnergy’s service territories, regardless of whether they take provider of last resort service from the utilities or purchase from a competitive retail supplier.

“These retail customers could not be more captive with respect to costs of the affiliate PPA[s] if they were locked in a cage with a greedy tiger,” they said.

As evidence that the PPAs would impose above-market costs, they cited the counteroffer Dynegy made to PUCO earlier this month, which the company said would save consumers $5 billion. Exelon also has made a counteroffer it says would be cheaper. (See Next up in Ohio PPA Battle: Dynegy Weighs in.)

The plaintiffs also cited the “enormous” impact the PPAs would have on the PJM markets.

“This case involves the same issue of ‘uneconomic non-exit’ — i.e., subsidized retention of resources that would otherwise have left the market — with which the commission has been confronted in other proceedings. Because capacity markets are designed to convey the price signals needed both to encourage entry of economic new resources and to discourage the premature exit of economic existing resources, it follows naturally that uneconomic non-exit will present the same threat to such markets as uneconomic entry.”

$8 Billion in Excess Costs

The Ohio Consumers’ Counsel (OCC) said it was up to FERC to protect the state’s consumers from excess costs that could top $8 billion.

The counsel cited testimony by its consultant James Wilson, who projected that FirstEnergy’s 1.9 million consumers could each pay about $800 ($3.6 billion total) and AEP’s 1.3 million consumers could each pay about $700 ($1.9 billion) over the eight years of the PPAs.

Dan Doron, spokesman for the OCC, said the costs could be much higher if the power plants fail to clear in PJM’s energy and capacity markets.

PJM Market Monitor Joe Bowring has said the generators should not be allowed to participate using subsidized prices. In testimony to PUCO, Bowring said that the generators would “be returned to the cost of service regulation regime that predated the introduction of competitive wholesale power markets.”

Doron said that if the plants cannot participate in the PJM wholesale markets, “the estimated subsidies could increase to over $1,100, on average per customer, for FirstEnergy consumers ($5.15 billion) and over $1,000, on average per customer, for AEP Ohio consumers ($3.1 billion).”

PJM: Reliability Arguments a ‘Red Herring’

On Monday, PJM filed a 12-page amicus brief with PUCO, criticizing AEP’s assertions that reliability would be threatened if its units retired.

The RTO said new generation has replaced plants that retired in the past, ensuring Ohio continues to meet resource adequacy targets.

“Arguments that approval of the stipulation is needed to ensure reliability in Ohio are wide of the mark and represent a proverbial ‘red herring’ that should not distract from consideration of the issues presented in the record as to the merits of the proposed stipulation itself,” PJM said.

PJM also urged the commission, if it approves the proposal, to clarify that offers from the units must be no lower than their actual cost, without consideration of revenue under the deal.

The RTO also said that the generators’ owners — not ratepayers — should bear any nonperformance penalties under its Capacity Performance construct.

CEO Andy Ott echoed the RTO’s position in a response to several of those who have written letters to PJM’s Board of Managers seeking its intervention against the PPAs.

Timothy R. Eves, vice president of NTE Energy, which is building a 475-MW natural gas generator in Butler County, Ohio, said in a Jan. 27 letter to the board that the PPAs would “undermine confidence in the PJM markets and can lead to a chilling effect on future power plant development.”

He asked PJM “to swiftly take necessary actions at the state-level, RTO-level and at FERC to mitigate this looming harm.”

Oregon Clean Energy, an 860-MW gas-fired generator under construction in Lucas County, Ohio, made a similar appeal in a letter Jan. 22.

Suzanne Herel contributed to this article.

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Entergy: Clean Energy Standard Won’t Save FitzPatrick

By William Opalka

Entergy said Wednesday that New York’s proposed incentives for three of the state’s four nuclear sites is too little, too late to save the James A. FitzPatrick plant. The company’s stance appears calculated to provide leverage for its Indian Point plant, which was excluded from the state’s plan.

Staff of the New York Public Service Commission on Monday released a clean energy standard proposal that includes incentives for the state’s upstate nuclear fleet to remain a zero-emissions “bridge” until large-scale renewable generation is in place. Gov. Andrew Cuomo wants the PSC to adopt the CES by June. (See New York Would Require Nuclear Power Mandate, Subsidy.)

“We have advocated for a clean energy standard in New York for several years. Unfortunately, whatever this program may turn out to be, it would not be in place in time to change the outcome for FitzPatrick,” the statement said.

The company in November said it would close the 838-MW plant near Syracuse in early 2017 due to low energy prices and repeated that stance a month later when Cuomo’s offer of incentives became known. (See Entergy Rebuffs Cuomo Offer; FitzPatrick Closing Unchanged.)

“We do not know when the support might become effective, how much it might be, what terms and conditions would apply to receiving support or many other important details. And it appears that those details will not be addressed until later this year, at the earliest. Under these circumstances, we remain focused on safely operating FitzPatrick through the end of its current operating cycle, then safely decommissioning the plant,” the statement continued.

Entergy is advocating the CES be applied to its Indian Point plant in the Hudson Valley, a facility Cuomo has vowed to close due to its proximity to New York City.

“If the state is focused on reducing CO2 emissions, the clean energy standard should apply to Indian Point, which is an essential generation resource critical to the state’s goal of reducing CO2 emissions,” it said.

Exelon, the owner of New York’s other two nuclear plants, was more receptive to the CES plan.

“Our initial impression is that the proposed mechanism to support the continued operation of upstate nuclear facilities as a ‘bridge’ to a low-carbon future could provide a meaningful path to sustain these facilities, which are vital to achieving New York’s clean air objectives,” Exelon said.

The company’s R.E. Ginna plant outside Rochester is likely to close in early 2017 when its ratepayer-subsidized reliability support services agreement expires. Its Nine Mile Point plant, adjacent to FitzPatrick, is also under financial stress.

“The implementation timeline is reasonable. We need to be certain that the mechanism provides the ability to maintain the safety and reliability of these facilities as the primary consideration. The economics of the proposal will be a critical determiner of its success, and we look forward to working with the governor, the PSC and other stakeholders to learn more,” Exelon said.

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New York Would Require Nuclear Power Mandate, Subsidy

By William Opalka

New York utilities would be required to procure more than 15% of their forecasted load in 2020 from struggling upstate nuclear power plants under a proposal now before the state’s Public Service Commission (15-E-0302).

The staff white paper on a Clean Energy Standard released late Monday also sets a goal of obtaining 29.5% of the state’s energy from renewable resources by 2020. Gov. Andrew Cuomo wants the PSC to finalize the CES by June.

The interim targets are part of Cuomo’s proposal to procure 50% of its energy from “clean” sources by 2030. The nuclear component is an economic lifeline to three struggling plants in western New York while also providing a “bridge” until renewable resources are developed at a mass scale, said Scott Weiner, director for markets and innovation. The three plants provide about half of the state’s nuclear energy; overall, nuclear provides 30% of New York’s electricity. The state’s fourth nuclear facility, Indian Point north of New York City, has been targeted for closure by Cuomo and is excluded from the proposal.

“The closure of the upstate New York nuclear plants due to the current natural gas market prices, and concomitant electric prices, would have a large negative impact on the state’s ability to meet its carbon reduction goal,” the paper states. “If the upstate New York power plants were to close in the near term, New York would have to procure more of its electricity from fossil fuel generating plants, primarily those burning natural gas, resulting in significant increases in carbon dioxide, nitrogen oxide and other air pollutants.”

‘Tier’ for Nukes

A new “Tier 3” would be created for nuclear facilities under the CES.

States with a renewable portfolio standard or a CES create tiers to distinguish between different types of clean energy resources and designate load requirements for each. In New York, Tier 1 is reserved for new renewable resources and Tier 2 is divided among existing renewables.

“The use of these three tiers will allow for clear connectivity among CES program elements and desired outcomes,” the proposal states.

Under the proposal, the nuclear requirement would start out at 4.6% in 2017 and escalate yearly through 2020. The mandate would start April 1, 2017, the day that both Exelon’s R.E. Ginna and Entergy’s James A. Fitzpatrick nuclear stations on Lake Ontario are now expected to close.

Ginna is seeking ratepayer subsidies to continue operating temporarily for grid reliability. Entergy announced plans to close the FitzPatrick plant because of low energy prices, and a third plant, Exelon’s Nine Mile Point, is under financial pressure.

All three plants are assumed by the white paper to remain open, although Entergy said last month that the governor’s incentives would not change their plans to retire FitzPatrick. (See Entergy Rebuffs Cuomo Offer; FitzPatrick Closing Unchanged.)

The renewable energy goals also would increase over time, from 26.8% in 2017 and 29.5% in 2020, reaching 50% in 2030. Targets for 2020 through 2030 will be added later.

Nuclear plants would be eligible to earn Zero Emission Credits (ZECs), similar to renewable energy credits (RECs) earned by wind and solar generators. Like RECs, ZECs will be tradable, but the two would not be interchangeable under the plan.

The maximum price of ZECs would be administratively set by the PSC. The white paper said that is intended to counter the potential exercise of market power, because of the limited number of facilities producing nuclear energy.

Prices “should be updated every year based upon the difference between the anticipated operating costs of the units and forecasted wholesale prices. In this manner the commission will be only setting an appropriate and fair value of the environmental attribute and will be acting independent of the actual wholesale prices for energy and capacity in the NYISO administrative market,” the proposal states.

An environmental group that advocates the closure of the plants said the nuclear component of the CES is a “slap in the face to the communities” affected by the plants.

“Nuclear power reactors may not emit carbon dioxide or methane, but that doesn’t make them clean or safe,” said the Alliance for a Green Economy. “The Public Service Commission is writing a blank check from electricity consumers to Exelon and Entergy corporations, owners of the aging upstate nuclear plants. Exelon and Entergy stand to gain hundreds of millions of dollars per year from this policy, while everyday people are left in the cold and the dark.”

A business group supports the overall policy but is worried about its cost.

Darren Suarez, director of government affairs for The Business Council of New York State, said Monday that his group supports the commission’s efforts to “grow renewable energy and conservation measures, and address the challenges of the state’s nuclear generators.”

“However, we remain concerned that the projected savings could vanish quickly, especially if customers are forced to subsidize a costly CES,” he added.

Anne Reynolds, the executive director of the Alliance for Clean Energy New York, said its members have a “keen interest” in the CES. ACENY has no position for or against nuclear power but hopes New York’s moves to keep it in the state’s energy mix are temporary.

“We were glad to see the reference to nuclear as a bridge to a renewables future, but we hope it does not become a permanent bridge that would preclude the development of renewables,” Reynolds said.

New York’s most recent renewable portfolio standard expired in 2014. State regulators have been discussing a revised RPS for months in a so-called large renewables proceeding. Nuclear generation has now been added to the proceeding.

‘Drama’

The nuclear mandate was outlined at Thursday’s commission meeting.

The meeting started with “drama,” as PSC Chair Audrey Zibelman put it, when the Republican-led state Senate hand-delivered a letter to the commission seeking a delay in action on the CES and the creation of a $5.3 billion Clean Energy Fund.

The letter, signed by Majority Leader John Flanagan, his deputy and the head of the energy committee, said action was “premature” on the CEF, another order that’s part of the state’s Reforming the Energy Vision proceeding.

“The CEF is a major fiscal initiative and has the potential to be even larger when taking into account the CES,” they wrote. “While we do not believe the commission is taking the fiscal implications of these initiatives lightly, it is the position of the conference that these proceedings would be strengthened by a real cost-benefit analysis and genuine opportunity for public input.”

The commission held a 38-minute executive session to discuss the letter but decided to proceed. Zibelman was particularly pointed in saying the letter failed to demonstrate any reason for the commission to delay action.

“This petition was filed in 2014 and there has been considerable opportunity for public commentary both in terms of the number of public statements, hearings and meetings … as well as the process before us,” she said. “There’s no question that we have in front of us a very robust record.”

For administrative ease, Zibelman said, the CES has been rolled into the existing proceeding for large-scale renewables (15-E-0302) rather than a new docket.

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FERC Proposes Uniform Offer Cap Across RTOs

By Michael Brooks

Two years after the polar vortex, and on the eve of a major snowstorm on the East Coast, FERC last week proposed a uniform “soft” offer cap for all RTOs’ day-ahead and real-time markets (RM16-5).

Under the commission’s Notice of Proposed Rulemaking, generators’ incremental energy offers would be capped at the higher of $1,000/MWh or an RTO-verified cost-based offer.

energy market offer capMost RTOs and ISOs already cap offers at a hard $1,000/MWh. In December, FERC approved doubling PJM’s offer cap to $2,000/MWh in reaction to the extreme cold of the January 2014 polar vortex, which drove up natural gas prices to the point that some generators could not recoup all of their costs (ER16-76).

PJM members approved the increase in October after a long stand-off. Some members who were originally opposed to the increase agreed to support a compromise proposal, as they predicted it would be a temporary change. (See PJM Members OK $2,000/MWh Energy Market Offer Cap.)

The NOPR would allow generators with cost-based offers that are more than $1,000/MWh to set LMPs. FERC, however, said it is seeking comment on whether it should place a hard cap on these offers and, if so, what this cap should be.

FERC said the current structure may suppress LMPs below the marginal cost of production. “If this occurs, resources may lack an economic incentive to supply power during times when the electric system may need it most. Additionally, if resources cannot reflect their short-run marginal costs in incremental energy offers due to the cap, the grid operator cannot dispatch the most efficient set of resources.”

A standard offer cap would also allow RTOs “to avoid issues that could arise if one region has an offer cap that materially differs from a neighboring region,” FERC said.

“The draft NOPR proposes to make the change to the offer cap applicable to all RTOs and ISOs in order to avoid exacerbating seams issues,” said Emma Nicholson of the commission’s Office of Energy Policy and Innovation. “Otherwise, different offer caps in neighboring regions could result in power flows that reflect the level of the two offer caps as opposed to reliability needs or economics.”

Nicholson also said that the NOPR doesn’t eliminate the $1,000 cap entirely because of feedback from RTO market monitors, who said the cap “plays a back stop role in market mitigation.”

Commissioner Cheryl LaFleur said the NOPR “strikes a good balance … between generally maintaining the $1,000 cap but allowing higher offers that can be verified to set prices.”

“The commission is proposing to take important steps that, in my mind, would increase both confidence and transparency” in the markets, Commissioner Colette Honorable said.

Comments are due 60 days after the NOPR’s publication in the Federal Register.

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Pipeline Developer Asks Massachusetts to Order Route Access

By William Opalka

Tennessee Gas Pipeline is asking Massachusetts regulators to grant it access to more than 400 properties whose owners have refused to cooperate with the company as it prepares for construction of the Northeast Energy Direct project.

tennessee gas pipeline
Opponents of the Northeast Energy Direct pipeline marched in protest last week. (Source: PopularResistance.org)

In a petition to the Department of Public Utilities, the pipeline said access is needed to conduct “civil, archeological and cultural resources, wetlands and waterbody delineation, and endangered or rare species” surveys as part of the project’s review by federal regulators (16-03).

The order would be “preliminary to eminent domain” actions if property owners continue to refuse permission. The project would transport natural gas from Pennsylvania into New England. (See Northeast Energy Direct Files for FERC Certificate.)

“Tennessee has in good faith made efforts to obtain survey permission from owners of survey properties, including sending at least two letters requesting survey permission and attempting to discuss the request in person or via telephone,” the petition says. “Many survey property landowners have granted Tennessee permission to conduct the surveys.”

However, 408 have “either expressly refused to grant Tennessee permission to conduct the surveys or not granted Tennessee permission to conduct the surveys,” the petition says.

“These landowners are minding their own business and seeking to simply live their lives in peace. We are working to ensure that they have the legal guidance they need to deal with this assault on their privacy and unjustified intrusion on their property,” Kathryn Eiseman, president of the Pipe Line Awareness Network for the Northeast, said in a statement.

The company, a unit of Kinder Morgan, said it needs a 400-foot wide corridor along the project’s route. It said that Massachusetts law allows granting of the order before FERC gives final approval for the project.

The department has scheduled six hearings statewide on the company’s request, starting in Pittsfield on March 29. Written comments will be accepted through May 6.

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PJM MRC/MC Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday, January 28, 2016. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

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

Markets and Reliability Committee

2. PJM Manuals (9:10-9:25)

Members will be asked to endorse the following manual changes:

  1. Manual 27: Open Access Transmission Tariff Accounting. Changes allow for network service peak load values submitted by electric distribution companies to be scaled by the eRPM auction software if they do not add up to the annual network service peak load allocation for the area.
  2. Manual 38: Operations Planning. Changes resulting from annual review correct typos, revise terms for consistency and update PJM reliability study procedures.
  3. Manual 40: Training and Certification Requirements. Implements a new process requiring operators or dispatchers not in compliance be removed from their shifts. Also establishes a compliance score scheme that will trigger a violation notice to the company and potentially FERC. (See “New Operator Compliance Rules to Take Effect Feb. 1,” PJM Operating Committee Briefs.)

3. Energy Market Offer Cap (9:25-9:45)

Tariff and Operating Agreement changes provide clarification conforming to FERC’s order that revisions to the energy market offer cap exclude the 10% adder from cost-based offers more than $2,000/MWh. The committee is being asked to endorse the revisions on first read due to time-sensitivity. (See PJM Members OK $2,000/MWh Energy Market Offer Cap.)

4. Virtual Transactions (9:45-10:00)

A proposed problem statement and issue charge address the nodes at which virtual transactions may be made. The issue stems from a report PJM published in October, “Virtual Transactions in the PJM Energy Market,” that identified instances in which existing market rules allow virtual transactions to be used in a manner that do not add value to the market commensurate to the costs imposed by them. (See PJM Suggests Changes to Virtual Transactions.)

5. Distributed Battery Storage in PJM Markets (10:00-10:15)

Drew Adams of battery maker A.F. Mensah will propose a problem statement and issue charge to study establishing a clear path to market in PJM for distributed battery storage systems.

6. Unit Commitment (10:15-10:30)

Barry Trayers of Citigroup Energy will propose a problem statement and issue charge to investigate separating financial day-ahead obligations from the physical unit commitment.

7. Capacity Performance Cost Allocation (10:30-10:45)

PJM is presenting a problem statement and issue charge asking stakeholders to review whether the Reliability Pricing Model method of cost allocation should be revised. In its Capacity Performance filing, PJM proposed changing the method by which it allocates the cost of procuring capacity. Given the protests and comments received, however, it asked FERC to postpone ruling on that component until the matter could be addressed through the stakeholder process.

8. Seasonal Capacity Resources (10:45-11:00)

Members will be asked to endorse a problem statement and issue charge regarding incorporating seasonal resources into the Capacity Performance construct. Capacity Performance rules allow aggregation of seasonal resources to convert them into “synthetic” annual resources but none were submitted in the first Base Residual Auction involving CP. Stakeholders will be asked to consider whether Tariff language can be improved or developed to encourage seasonal resources to participate in the market.

9. Voltage Threshold (11:00-11:15)

Revisions to the Operating Agreement would exempt transmission reliability projects of less than 200 kV from the competitive proposal windows. Such projects are almost always assigned to incumbent developers, and PJM said the change would enable its engineers to focus on problems more likely to result in a competitive greenfield project. (See “Voltage Threshold will Exempt Some Projects from Proposal Window,” PJM Planning Committee and TEAC Briefs.)

10. Long-Term Firm Transmission Service Task Force (11:15-11:25)

Proposed changes to Manual 14A: Generation and Transmission Interconnection Process and 14B: PJM Regional Transmission Planning Process would modify long-term firm transmission service methods. Revisions to 14A would add a cost allocation obligation for new service requesters toward facility upgrades. Changes to 14B describe the baseline and new service request studies, the distribution factor and rating limit allowed to contribute to flowgates and the interaction of baseline and new serve request studies on constraints identified in the capacity import limit studies.

11. PAR Task Force (11:25-11:35)

Other changes proposed for Manual 14A would make clear that phase angle regulator (PAR) technology is eligible for transmission injection rights. (See “Phase Angle Regulators Qualify for Transmission Rights,” PJM Planning Committee and TEAC Briefs.)

12. Governing Documents Enhancement & Clarification Subcommittee (GDECS) (11:35-11:45)

Proposed revisions to the Tariff, Operating Agreement and Reliability Assurance Agreement offer clarifications and consistency for certain terms.

Members Committee

Endorsements(1:25-2:40)

  1. Energy Market Offer Cap(2:10-2:30)

See related item above.

  1. Liaison Committee (LC) Charter (2:30-2:40)

Members will be asked to approve changes to the Liaison Committee charter. The revisions provide for an LC meeting with the board or the second General Session meeting in a calendar year to be canceled upon a super-majority vote of the sector whips. The Members Committee would need to receive three business days’ notice of such a vote. Any sector voting not to cancel a meeting would be required to provide at least one topic to be discussed.

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FERC Postpones Action on Supply Chain Protections

FERC on Thursday gave final approval to revisions to seven critical infrastructure protection (CIP) reliability standards.

The final rule approves NERC’s proposed requirements for personnel and training, physical security of the grid’s cyber systems and information protection (RM15-14).

It requires NERC to make changes addressing protection of transient electronic devices, such as thumb drives and laptop computers, at low-impact Bulk Electric System cyber systems and protections for communication network components between control centers. It also requires NERC to refine its definition for low-impact external routable connectivity and to conduct a study assessing the effectiveness of CIP remote access controls, the risks posed by remote access-related threats and vulnerabilities, and appropriate controls.

Supply Chain Protections not Included

The order does not include a provision in the commission’s July Notice of Proposed Rulemaking that would have required NERC to develop requirements for supply chain management for control system hardware, software and services. (See FERC Seeks Supply Chain Protection Against Cyber Threats.)

The commission said it will consider action on that issue based on advice from staff following a Jan. 28 technical conference.

A supply chain standard would be only the third time the commission has ordered NERC to initiate a standard, following standards addressing geomagnetic disturbances and physical security.

The commission’s supply chain concerns were prompted by two malware campaigns against vendors of industrial control systems.

The final rule takes effect 65 days after publication in the Federal Register.

— Rich Heidorn Jr.

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Company Briefs

EnsyncEnergySourceEnsyncEnSync Energy Systems of Menomonee Falls, Wis., has set up a Hawaii hydroponic and aquaponics company to detach from the grid entirely. Using an energy management system composed of solar generation and batteries, Mari’s Garden in Mililani, on Oahu, is operating the water pumps for its hydroponic and fish farming operation off the grid.

The system uses a 25-kW photovoltaic unit and 40 Aquion battery stacks to store 92 kWh of energy. Mari’s Garden said it plans to expand the PV system to 75 kW later this year.

More: Pacific Business News; EnSync Energy Systems

Richey Named Site Vice President at FE’s Beaver Valley Nuclear Station

firstenergyFirstEnergy has named Marty Richey the site vice president at the Beaver Valley Nuclear Power Station in Shippingport, Pa. He takes the place of Eric Larson, who will represent FirstEnergy Nuclear Operating Co. as a loaned executive to the Institute of Nuclear Power Operations in Atlanta.

Richey, a 27-year industry veteran, most recently was plant manager at Entergy’s Waterford Nuclear Generating Station in Killona, La.

He also is a veteran of the U.S. Navy Nuclear Power Program, where he was a mechanical operator and engineering lab technician.

More: FirstEnergy

Japanese Company’s New Power Storage System Goes Online

SumitomoSourceSumitomoSumitomo Corp. is starting up its new power storage system, Willey Battery Utility, in Hamilton, Ohio, which will participate in PJM’s frequency regulation market.

“As a developer of wind and solar power plants which are unavoidably intermittent generation sources, we think it is quite important that we also contribute to the stabilization of power grids through balancing services,” said Nick Hagiwara of the Sumitomo Corporation of Americas.

The 6-MW, 2-MWh system was developed by RES Americas. It is the Japanese conglomerate’s first investment in a large-scale, stand-alone battery project in the United States.

More: Sumitomo Corp.

Plastic Sheet Could Provide Solution to Battery Overheating

A Stanford University chemical engineer has invented a plastic sheet that can be inserted into lithium ion batteries to prevent overheating.

The sheet is embedded with carbon-coated nanoparticles of nickel that allow it to conduct electricity. However, it expands when it heats up, pulling apart the nanoparticles so they no longer conduct electricity.

When the sheet cools down, the battery begins operating again.

More: Delaware Public Media

PSEG Solar Source Acquires Solar Projects in Ca., Utah

PSEG SolarPSEG Solar Source is increasing its solar capacity to 214.6 MW with the $110 million acquisition of projects in California and Utah from Colorado solar developer juwi Inc.

The 3.9-MW PSEG Lawrence Livermore Solar Energy Center is being built at the Lawrence Livermore National Laboratory, about 45 miles east of San Francisco.

The 62.7-MW PSEG Pavant II Solar Energy Center will be located about 110 miles south of Salt Lake City.

More: The Philadelphia Inquirer

ComEd Receives $4M Grant from DOE SunShot Initiative

COMED (EXELON) logoThe U.S. Department of Energy has awarded $4 million to Commonwealth Edison to create solar and battery storage technology in its microgrid demonstration project in the Bronzeville neighborhood in Chicago. The grant is part of the department’s SunShot Initiative.

The project is a precursor to ComEd’s proposed development of six microgrids in Illinois.

“Distributed generation is the future of the electric grid,” said ComEd President and CEO Anne Pramaggiore. “The microgrid demonstration we are building in Bronzeville is a blueprint for other utility-owned microgrids around the country.”

More: Commonwealth Edison

Duke Says it Set Solar Record in NC

Duke Energy logoDuke Energy says it installed more than 300 MW of solar generation in North Carolina this year, eclipsing its record of 160 MW the year before.

Duke last year spent $500 million to build four solar farms in the state with a capacity of 141 MW and bought 150 MW more.

The company said it plans to build another 75 MW of solar this year. The company expects North Carolina to rank second behind California for utility-scale solar construction in 2015.

More: The Charlotte Observer; Duke Energy

Houston Gas Firm Lays off 600 in Fayetteville Shale

southwesternenergysourcesweHouston-based Southwestern Energy said it is laying off 1,100 employees, including 600 throughout its Fayetteville Shale operations in Arkansas, amid a steady decline in natural gas prices.

The cuts, set to be complete by the end of the first quarter, will leave 560 employees in the central Arkansas natural gas play. Southwestern said the “organizational changes” are necessary to be competitive in a “low gas price environment.”

Natural gas at regional hubs was trading around $2.13/MMBtu on Thursday, down from a 52-week high of $3.47. Southwestern reported a third-quarter net loss of $1.8 billion, or $4.62/share.

More: Arkansas Business

Enel Green Power Building 7th Wind Farm in Oklahoma

EnelGreenPowerSourceEnelEnel Green Power North America has started construction on a 108-MW wind farm southwest of Oklahoma City, its seventh such project in Oklahoma.

Enel’s Drift Sand project is expected to be finished by the end of the year. The electricity will be sold to Arkansas Electric Cooperative Corp. under a long-term power purchase agreement.

Enel, whose first Oklahoma project was finished at the end of 2012, is now the state’s second-largest wind farm operator, with 958 MW. The $180 million Drift Sand wind farm will push the company to 1,066 MW of wind capacity in Oklahoma.

More: The Oklahoman

Peabody Energy Pulling out of Prairie State Energy Campus

PeabodyEnergySourcePeabodyPeabody Energy announced it is selling its share of the troubled Prairie State Energy Campus in Missouri to Wabash Valley Power Association for $57 million.

Peabody, which is being pressured by the downturn in the coal industry, said it was selling its 5.06% stake in the 1,600-MW coal-fired generating station about an hour southeast of St. Louis as part of its move to shed noncore assets.

The price of the generating station skyrocketed amidst cost overruns and missed deadlines, and stands at about $4 billion now. The plant has shown steadily increasing performance, however.

More: St. Louis Post-Dispatch

Kinder Morgan Plans Spending Cuts After Q4 Losses of $637 Million

Kinder Morgan said last week that it planned to cut spending after posting a net loss of $637 million for the fourth quarter.

The company attributed the loss to higher taxes and interest expenses, coupled with a decline in market values. The company showed a net profit of $126 million for the same period a year ago. For the full year of 2015, Kinder Morgan reported net income of only $311 million, compared with nearly $1.03 billion in 2014.

The company also cut its capital budget for 2016 to $3.3 billion from its previous estimate of $4.2 billion. “What we’re trying to do is really make sure that we’re investing capital on the highest-return opportunities that we have, make sure that we’re fulfilling our commitments and delaying spend where it can be delayed or deferred, and taking on partners where it makes sense for us to take on partners,” CEO Steve Kean said Wednesday.

More: Reuters; Natural Gas Intelligence

Piedmont Gas Shareholders OK Duke Energy Deal

PiedmontNatGasSourcePiedmontShareholders of Piedmont Natural Gas approved the sale of the company to Duke Energy for $4.9 billion. Of about 81 million eligible voting shares, about 54 million voted in approval, with 1.1 million against.

Piedmont will retain its name and keep its Charlotte, N.C., headquarters. Duke has said that it does not expect many job losses as a result of the acquisition. Piedmont has about 1,900 employees.

Both Piedmont and Duke Energy are major partners in the proposed $5 billion Atlantic Coast Pipeline, a natural gas pipeline that is to run from West Virginia to markets in Virginia and North Carolina.

More: The Charlotte Observer

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MISO Planning Advisory Committee Briefs

Aiming to prevent claims of preferential treatment under its new competitive transmission process, MISO last week released a formal protocol prohibiting bidders from contacting any MISO staff member directly about requests for proposals.

The rules were released as MISO prepares to receive bids on its first competitive transmission project, the Duff-Coleman 345-kV upgrade. (See MISO Seeks Bids on Duff-Coleman Project.)

Brian Pedersen, MISO’s senior manager of competitive transmission services, said the RTO created a new email address (TDQS@misoenergy.org) so transmission developer applicants wouldn’t contact any MISO staffer.

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“We’re moving from a workshop environment to a competitive bid environment … and we want to make sure people know how to communicate appropriately,” Pedersen said. “Once we receive proposals, MISO will only respond to procedural questions. … We’re not going to respond to any substantive questions about the [evaluation] and where we’re at in it.”

MISO said it will publicly post a list of received questions and its responses on the MISO competitive transmission webpage.

Meanwhile, stakeholders will continue working into spring on changes to Business Practice Manual 27 to align it with Tariff changes approved by FERC in November regarding the qualification and selection of competitive developers and the pro forma developer’s agreement (ER15-2657, ER15–2658). Redline changes will be discussed at the March and April Planning Advisory Committee meetings. MISO hopes to make the changes effective by May 1.

BPM Changes Completed for Expedited Project Review

MISO presented stakeholders with BPM changes to replace the out-of-cycle review process with the new expedited review procedure.

MISO will now post all valid expedited requests within two weeks of receipt and notify stakeholders of such requests.

The final BPM language concludes almost a year of discussion on the topic, after stakeholders raised objections to Entergy’s Lake Charles transmission upgrades last February. Some critics questioned whether Entergy was seeking to circumvent the competitive bidding process. (See MISO Seeks Stakeholder Input on Out-of-Cycle Process amid Entergy Controversy.)

“We’ve not had an expedited review of the expedited project review,” joked Matt Tackett, a principal adviser for MISO, during a presentation of the final BPM language.

Sean Brady, Wind on the Wires’ regional policy manager, thanked Tackett for not “rushing” stakeholders through the review process. “I really appreciate that,” he said.

MISO said it would not solicit any further input on the BPM language but would delay posting it until the PAC decides whether to endorse it at its February meeting.

MISO Planning Confidentiality, Notification Changes to Attachment Y Procedure

MISO will require more notification and relax some confidentiality rules concerning generator suspensions and retirements and system support resources planning under Tariff changes outlined to the PAC.

The proposed changes would affect the Attachment Y process, which ensures MISO has time to identify transmission needs resulting from the loss of a generator.

The changes would subject black start units and pseudo-tied generators to Attachment Y requirements that units intending to retire or suspend operations provide at least 26 weeks’ notice.

In addition, information made public by a generator owner will no longer be considered private, and information won’t be confidential after a retirement date has passed.

Some public interest organizations said MISO should make Attachment Y notices public upon their filing, as in PJM. MISO said a 2012 FERC order directed the RTO to keep Attachment Y notices and study results confidential for units that do not qualify as an SSR (ER12-2302).

MISO may also require a new Attachment Y notice 26 weeks prior to the change in status of a SSR unit wishing to retire or alter its agreement, MISO’s Neil Shah said.

Several market participants said that the current 36-month cumulative time limit on generator suspension in a five-year period and the 26-week notice requirement would need to be adjusted under MISO’s proposed switch to a four-month summer and an eight-month winter capacity construct. Shah said that suggestion will be considered only once capacity market changes are finalized.

Generation owners would have to file directly with FERC to determine how much they will be compensated for fixed costs under an SSR and complete either an OASIS posting or a FERC filing to terminate interconnection rights. Suspended generators unable to return to service at the end of suspension period will be considered retired and have their interconnection rights terminated.

Shah said MISO’s decision to change the process is based on experience gained since 2012. Tariff changes will be filed by Feb. 26; MISO is requesting an effective date of May 1.

Work on MTEP17 Futures to Continue Through September

Work on changes to the Transmission Expansion Plan futures process will last through the first three quarters of 2016, Matt Ellis from MISO’s policy studies unit told the PAC. “This is really more a teaser for what’s to come in 2016,” Ellis said of his presentation.

MISO said the new futures process, set to take effect beginning with MTEP17, will use familiar procedures. As with previous MTEPs, final decisions will be made during PAC meetings, while technical details will be hashed out in workshops.

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MISO plans to review its resource siting methodology for use in PROMOD models beginning in March and finalize it in July. (See “CPP to Play Role in Reworked Futures Development,” MISO Planning Advisory Committee Briefs.) “We’ve had basically the same siting information for years, so we’ve worked time into the process for re-siting,” Ellis said.

The RTO said it wants to employ a scenario-based analysis with the possibility for many outcomes rather than the least-cost plan under a single scenario. “The scenarios should simulate likely or plausible real-life future system conditions and provide an envelope of outcomes that is significantly broad, rather than a single expected forecast,” MISO wrote.

MISO is hoping to review draft results of the new futures process by the August PAC. “We want to wrap up the whole MTEP17 futures planning process by September,” Ellis said.

Ellis is asking for feedback by Feb. 10 on MISO’s proposed timeline, which he says is subject to change.

— Amanda Durish Cook

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FERC Outlines Principles for Clean Power Plan Analyses

By Rich Heidorn Jr.

FERC staff last week released a white paper identifying what it called “four guiding principles” that may help RTOs and other transmission planning entities analyze compliance with EPA’s Clean Power Plan.

Although the commission has no direct role in CPP compliance, it may be called on to evaluate the impacts of plant retirements and other responses on reliability.

Staff said modeling of the CPP should address: transparency and stakeholder engagement; study methodology and interactions between studies; study inputs, sensitivities and probabilistic analysis; and tools and techniques. The white paper borrows from a 2015 report by M.J. Bradley & Associates cited by EPA.

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Alliant Energy’s coal-burning Edgewater Generating Station (Source: Alliant Energy)

“Incorporating these guiding principles in the modeling of the CPP compliance plans is one way to promote a robust analysis of the reliability impacts of the CPP,” the commission said, adding that it may conduct additional technical conferences on the rule. (See MISO, SPP Stakeholders Developing Trading Plan to Comply with EPA Carbon Rule.)

“State-by-state variations in compliance approaches may add additional uncertainty and complexity, particularly for transmission planning entities that cover multiple states or states with multiple transmission planning entities,” FERC said. “Further, the use of inconsistent models, or inconsistent modeling inputs, may suggest reliability problems where none exist, or may mask problems that do exist. If models and modeling inputs are not transparent, it will be difficult for stakeholders, state commissions, planning authorities or the commission to identify, understand or address potential problems.”

FERC said the impacts of CPP compliance plans can be evaluated through a combination of studies, including resource adequacy, production cost, integrated gas-electric systems simulations and power flow and transient stability analyses.

“Incorporating the results of one study into a subsequent study can result in a more robust analysis,” the white paper says. “For example, the results of a resource adequacy analysis can be used to define the assumptions for the composition of the generation fleet used in a production cost or natural gas infrastructure study. This iterative process can lead to more robust results than using static assumptions.”

It also called for use of new tools to measure the impact of increased renewable and natural gas generation.