With its window for limited tree felling closing in four weeks, Constitution Pipeline is again asking FERC for permission to allow the operation in New York (CP13-499).
The developer wrote the commission on Thursday, citing a federal court’s dismissal of an injunction sought by environmentalists seeking to halt cutting in Pennsylvania.
Crew installing silt fence (Source: Cardno)
Constitution argues this means the director of the Office of Energy Projects should allow it to conduct similar operations along the entire 124-mile route from the shale gas fields of northeast Pennsylvania to Schoharie County, N.Y. The 2nd Circuit Court of Appeals denied the environmentalists’ motion on Feb. 24 (16-345).
Constitution has to cut trees between Nov. 1 and March 31 to comply with U.S. Fish and Wildlife Service recommendations to mitigate impacts on migratory birds and the northern long-eared bat.
“Issues pertinent to this request were before the court and the court’s order provides additional support and the proper timing for the director to act on Constitution’s request … [with] the March 31 deadline established by the U.S. Fish and Wildlife Service fast approaching,” the letter states.
Constitution asked FERC to grant it a Notice to Proceed by March 2. FERC granted an NTP for Pennsylvania only on Jan. 29.
The developer said it would use chainsaws to cut trees at or above ground level and would not disturb soils or root systems. It said it would leave the felled trees in place until other construction started. But the operation has been challenged by environmentalists and New York Attorney General Eric Schneiderman, who contend that Constitution must first have clean water permits from the state Department of Environmental Conservation. (See New York AG: No Tree Cutting for Pipeline Without Water Quality Permits.)
Constitution said it had completed 70% of its planned cutting in Pennsylvania.
The project is a joint venture of Williams, Cabot Oil & Gas, Piedmont Natural Gas and WGL Holdings.
MISO officials presented a review of load and prices during an informational forum Feb. 23. Some highlights:
Real-time LMPs averaged $22.14/MWh for the month, a 21% decrease from a year earlier, while the day-ahead average fell 20% to $22.79/MWh. But rising natural gas costs helped boost power prices compared with December, with month-on-month real-time and day-ahead averages increasing 7% and 9%, respectively.
January marked the end of an 11-month decline in natural gas prices, as the Chicago Citygate rebounded 17% to average $2.33/MMBtu for the month, while Henry Hub jumped nearly 20% to $2.30/MMBtu. Still, Chicago Citygate prices remained far below the January 2015 average of $3.09/MMBtu.
MISO’s January load averaged 78.5 GW, up 8.2% from December but down 3% from the average for the same month a year ago, the grid operator reported. Load peaked at 98.2 GW on Jan. 19, compared with last January’s 106.5 GW peak and far short of the winter record of 109.3 GW set in January 2014. Day-ahead physical energy last month totaled 56.6 TWh, while real-time load hit 58.4 TWh, a drop from the 60.3 TWh in January 2015.
MISO wind output also hit an all-time peak of 12.7 GW on Jan. 27, exceeding the previous high of 12.6 GW set on Nov. 19. That figure, however, was quickly surpassed by a new record of 13.1 GW on Feb. 18.
MISO Develops New Metric to Monitor Queue Delays
MISO will measure progress in its generation queue using a new metric: study cycle scheduling, a process that makes existing interconnection agreements and facilities studies the basis for subsequent studies.
Using the metric, the RTO will flag the interconnection queue with “concern” or “review” status if generation interconnection studies can’t be completed on time. Jeff Bladen, executive director of market services, said MISO is currently experiencing delays in the queue because of an influx of restudies related to withdrawing interconnection projects.
“This new metric is allowing us to see more of the delays, but it’s also demonstrative of why reforming the queue process was so important,” Bladen said.
MISO is awaiting FERC approval of the proposed queue changes it filed Dec. 31. If approved, MISO will work to complete existing generation interconnect agreements and existing studies by May 20. (See MISO Unveils Queue Reform Transition as Wind Advocates Seek Delay.) MISO says the proposal will “reduce the delays and provide more certainty to timelines.”
“The reforms that we filed are to help resolve issues that are much more transparent with the metric,” Bladen said. He said that MISO was aware of the delay issues “at some level,” but the new metric made the issues much clearer.
FERC has accepted SPP’s proposal to address an underfunding problem in the RTO’s transmission congestion rights (TCR) market by reducing the number of auction revenue rights available in the annual allocation process (ER16-13).
The commission’s Feb. 19 order sets the amount of transmission system capability to be offered during the annual ARR allocation process at 60% for the fall, winter and spring seasons (October-May), as recommended by the RTO’s Market Monitoring Unit. SPP had proposed an 80% allocation during those months.
TCR market participants can convert firm transmission service reservations into a credit against daily congestion costs, either through a TCR or through payments received for the ARR.
‘Necessary Step’
FERC found adjusting the ARR allocation rules “are a necessary step” to correct the TCR underfunding.
“We view adjusting the system capability assumptions used to determine feasibility in the annual ARR allocation process as an important step toward reducing the potential for underfunding TCRs, thereby creating a more efficient TCR market,” the commission wrote.
The Monitor told FERC that the first full year of the Integrated Marketplace’s TCR operations produced a “high degree of disparity” between TCR payments and revenues, net of TCR uplift and TCR auction charges. It contended “this indicates that TCR auction prices did not accurately reflect the realized value of TCRs.”
The Monitor listed three contributing factors: “(1) the awarding of ARRs and TCRs beyond the physical limits of the transmission system, (2) the delayed reporting of planned transmission outages, and (3) the excessive valuing of self-converted TCR bids in auctions.”
TCR funding was 82% for its first full year, and the ARR funding level was 113%, the Monitor said. It shared data with FERC “demonstrating that, in every month, day-ahead congestion revenues fell short of TCR payments, while auction revenues exceeded ARR payments.”
FERC said using the 60% assumption during the October-May period will “better reduce the need to expand transmission constraint limits during the monthly processes, which contributes to the TCR underfunding problem.” Awarding fewer infeasible ARRs during the annual allocation process, the commission said, will mean SPP “will not have to expand transmission constraint limits as frequently.”
“As noted by the Market Monitor, expanding limits can lead to situations where TCR market flows exceed day-ahead market flows for certain transmission paths, resulting in TCR underfunding,” FERC wrote.
ARR Over-Allocation
SPP submitted its Tariff revisions to FERC in October, saying its market’s TCRs were underfunded because of an over-allocation of ARRs. The RTO told the commission “disparate system capability percentages used between the ARR and TCR processes” were largely responsible, resulting in awarding infeasible ARRs, and proposed more closely aligning the system capability percentages used between the annual ARR allocation and TCR auction processes.
The Integrated Marketplace, which became binding in March 2014, was originally designed to allocate ARRs in a single, annual process, with 100% transmission system capability assumed year-round when determining the feasibility of ARRs for the annual allocation.
SPP’s proposed Tariff revisions set ARR allocations at 100% for June, 90% for July-September and 80% for the remaining months.
The Monitor told FERC it did not support the proposed use of an 80% ARR allocation, saying it did not match the 60% system capability number used in the TCR auction process. It said the mismatch would result in potential TCR underfunding and noted the 80% allocation was “contrary to an earlier proposal, presented by SPP staff.”
The proposal was changed from 60% to 80% at the Markets and Operations Policy Committee level of the stakeholder process, the Monitor said, and it could not support the revised proposal because it “was not supported with analysis.”
SPP acknowledged that the proposed 80% figure “was the result of a compromise to achieve a more gradual approach to addressing the problem of TCR underfunding.”
FERC concluded that SPP had failed to “provide analysis or evidence to support the … assumption proposed for use during the October through May period.”
Ramp Rate Approach Would Excuse Nonperformance Penalties
WILMINGTON, Del. — PJM presented a first read of a proposed performance assessment hour ramp rate, which would inform when a generator is vulnerable to nonperformance penalties under the new Capacity Performance model. The approach is a short-term solution that PJM hopes to have in place before the delivery year starts June 1.
Under the proposal, units would be excused from penalties if they are following PJM dispatch that includes the ramp rate.
“The goal is having generators following our dispatch and not causing harm under stress conditions,” PJM’s Rebecca Stadelmeyer said.
PJM doesn’t want generators to disregard its dispatch orders and self-schedule more capacity to avoid penalties when they believe they are approaching a performance assessment hour.
Market Monitor Joe Bowring opposed the proposal. “This explicitly weakens the ‘no excuses’ policy,” he said. “It also hasn’t been demonstrated that the self-scheduling issue is widespread.”
Relying on historical data on ramp does not provide the appropriate incentives to perform during performance assessment hours, Bowring said.
Committee Chairman Mike Kormos assured him that the approach is temporary.
“We want to incent generators to be dispatchable. In order for us to maintain system control, some need to be loaded during the [performance assessment] hour itself, and we want to makes sure they don’t get penalized,” Kormos said. “How big of an issue it is, we don’t know, but I don’t want to find out on the hottest day in the summer.”
How Should Regulation Resources fit into the Capacity Market?
Greg Vaudreuil, co-founder of Mosaic Power, presented a problem statement to include regulation-only resources in the Capacity Performance market.
Vaudreuil said that resources such as batteries, flywheels and certain demand resources are at a competitive disadvantage because they can’t recover their capital and fixed operating costs the same way energy providers can.
“The market for [Capacity Performance] would benefit from fully accounting for and compensating all capacity-providing resources, and warrants PJM stakeholder consideration on the most effective means to incorporate the value emerging regulation-only resources [provide],” the problem statement said.
Manual 18 Revisions Endorsed
Members approved updates to Manual 18: PJM Capacity Market to conform with FERC’s order (ER16-333).
They address the circumstances under which a fixed resource requirement (FRR) entity must meet the percentage internal resource requirement, provisions for early termination of the FRR alternative and the election date for new FRR entities. (See IMEA Reaps Limited Relief from Capacity Rule Change.)
GDEC Definitions, Clarifications Approved
The MRC unanimously approved a handful of definitions and clarifications proposed by the Governing Document Enhancement and Clarification Subcommittee.
A clarification for the term “capacity import limit,” which members asked to vote on separately, also was approved, but with 18 “no” votes. That language was clarified to “meet its intent concerning the length of transmission service necessary to meet the capacity import limit (CIL) exception criteria regarding transmission service,” according to the presentation.
The committee deferred voting on clarifications to the term “pumped storage hydropower.” Those proposed revisions “address sell offer options for pumped storage hydropower units and self-scheduling and pool-scheduling of hydropower units.”
First Reads
The MRC also heard first reads on proposed revisions to:
Regional transmission and energy scheduling practices (See “Session will Study Transmission, Energy Scheduling Practices,” PJM Operating Committee Briefs.)
The Members Committee approved Tariff revisions exempting some reliability projects below the 200-kV threshold from the proposal window process. (See “Low-Voltage Projects to be Exempted from Competitive Window Process,” MRC & Members Committee Briefs.)
NIPSCO Settles for Lower Dollar Amount in Fixed Rate Hike Agreement
Northern Indiana Public Service Co. and the Office of Utility Consumer Counselor reached a settlement on a 5.4% rate increase, less than half the 11% boost that the utility sought in its initial filing.
The settlement would set the monthly fixed rate charge at $14, up from the current $11. NIPSCO initially sought a $20 monthly residential charge.
The rate increase, which requires approval of the Utility Regulatory Commission, would go into effect in the middle of the year.
Governor Vows to Continue Clean Power Plan Inaction
Pence
Gov. Mike Pence said the state will not devise an emissions-reduction strategy to comply with the Clean Power Plan, even if the federal carbon emissions regulations survive a legal challenge.
“For me, it won’t be a ‘pencil’s down’ order. We’ve never picked a pencil up,” Pence said. The governor has referred to the federal rule as the “Costly Power Plan” and said that compliance will increase rates for customers.
If the Clean Power Plan remains intact after court review and the state does not create a compliance plan, it would be forced to default to a federally imposed plan. “I think a wise leader of the state of Indiana would start to work on that transition and not play politics with it,” said Jodi Perras of the Sierra Club.
State Cancels $20M Contract for Capitol Energy Center
Brownback
Gov. Sam Brownback’s administration canceled a $16 million contract to build a utility center to replace the power plant in the marked-for-demolition Docking State Office Building after coming under intense bipartisan objections from lawmakers, who said the project was designed to skirt the Legislature’s oversight.
The energy center was to cost about $16 million, and financing would have pushed the total to $20 million. The state government may be responsible for penalties for severing the contract with McCarthy Building Companies.
The state Chamber of Commerce has filed an amicus brief supporting a lawsuit challenging the Clean Power Plan.
“We’re very concerned with protecting our low-cost energy advantage in Kentucky, being able to continue to run our power plants and utilize our natural resources such as coal to generate power,” said Chamber of Commerce public affairs director Kate Shanks. She said that the state’s economy is “electricity intensive” and depends upon low-cost electricity.
The chamber is joining more than 160 business organizations that are supporting the lawsuit by 29 states challenging EPA’s plan to reduce carbon emissions. The U.S. Supreme Court temporarily blocked implementation of the EPA rule on Feb. 9.
By a 3-2 vote, state regulators rejected a $4.9 billion bid by international investors to buy Cleco, effectively killing the utility’s sale.
The Public Service Commission majority said the sale to a consortium of investors led by Australian company Macquarie Infrastructure and Real Assets would have increased costs for Cleco’s 286,000 customers.
The buyers can appeal the decision to state court.
The Public Service Commission has scheduled five public hearings in March to hear testimony on Baltimore Gas and Electric’s request for increases of $120.9 million in electric distribution rates and $79.5 million in gas distribution charges.
BGE filed the request in November, which would raise rates about $15 a month for customers who use both services. The new revenue would recover the cost of installing more than 1 million smart meters.
Hearings are scheduled for Annapolis, Towson, Ellicott City, Bel Air and Baltimore. The public also can file comments electronically.
PSC Accepting Proposals for Offshore Wind Projects
The Public Service Commission has opened a 180-day application period for offshore wind projects after receiving an initial application.
Under the state’s Offshore Wind Energy Act of 2013, a project must be sited on the outer continental shelf, 10 to 30 miles off the coast in a designated leasing area.
Consumers Energy Pledges to Increase Actual Meter Read Rates
Consumers Energy, under fire for estimating too many of its customers’ bills, said it will make an effort to improve meter reading operations. The assurance was included in a report to the Public Service Commission.
The utility said it only had 85.5% actual readings in 2015, down from a record 93.7% in 2011. It blamed the decline on cold temperatures, unleashed dogs and the departure of more than half the company’s 310 meter readers in 2015. “This performance is not what our customers expect and deserve, and we will make it right,” the company stated. It promised to immediately obtain actual readings from customers with more than 11 months of estimated bills.
The PSC opened its investigation last month after it received more than 300 complaints from Consumers ratepayers who objected to paying inaccurately estimated bills.
The Red Lake Band of Chippewa Indians signed an agreement with Winkelman Building Corp. and Innovative Power Systems for a 15-MW solar system that it says will generate enough electricity to power all of the tribe’s government buildings, its three tribal casinos and the tribal college.
The tribe’s ultimate goal is to generate enough solar power in five years to supply every home on Red Lake, said Chairman Darrell G. Seki Sr. “We’ll provide our own energy for our people, not from the power plants that pollute our lakes,” he said.
The Red Lake Indian Reservation covers about 1,259 square miles and has about 5,160 residents.
Talks between Clean Line Energy and the Hannibal Board of Public Works to provide the Mississippi River city with cheap electricity in exchange for supporting the company’s high-voltage power line are being put on hold.
During its Feb. 16 board meeting, board General Manager Bob Stevenson announced that discussions were being tabled with Clean Line, which has proposed a high-voltage DC transmission line to deliver wind energy from western Kansas into Missouri, Illinois and Indiana. Clean Line has been trying to win the city of Hannibal’s support with promises of electricity for as little as 2 cents/kWh.
Ralls County Presiding Commissioner Wiley Hibbard, who said that most of his constituents strongly oppose the project, applauded the board for putting on the brakes on talks.
Colstrip Shutdown Would Cost $14M in Annual State Taxes
The Department of Revenue says the state would lose $14 million a year in tax receipts if two of the Colstrip Generating Station’s four units close down.
The shuttering of Colstrip’s two oldest units seems more likely as the units’ out-of-state owners are facing increasing pressure to reduce their reliance on coal-powered generation.
The Colstrip complex produces 2,094 MW and emits 13.5 million metric tons of carbon dioxide annually, according to EPA. It also pays 80% of the taxes in Rosebud County, population 9,329.
The Board of Public Utilities and the Economic Development Authority have approved a low-interest $2 million loan for Eos Energy Storage, which specializes in making low-cost DC battery systems for electric utilities.
The loan was provided through the Edison Innovation Green Growth Fund, which aims to help companies advance energy-efficient technologies that can compete with traditional electricity generation.
The Board of Public Utilities last week denied a request by Jersey Central Power & Light and Mid-Atlantic Interstate Transmission for the transmission company to be considered a public utility.
The request is part of an effort by FirstEnergy to spin off its utility-owned transmission assets into a new subsidiary. (See FERC OKs FirstEnergy’s Tx Spin-off; NJ, Pa. Approval Still Needed.) Six other actions requested by the petitioners are pending before the board.
The board ruled that utility status requires an “electricity distribution system, plant or equipment.”
Deepwater Wind is considering a Brooklyn waterfront site as a staging ground for a potential offshore wind project off Long Island.
New York City issued a request for proposals to use the mostly vacant 72-acre South Brooklyn Marine Terminal site as an industrial maritime facility. Bids are due March 4.
Deepwater has approached two local companies to explore possible partnerships in connection to the project. The company began construction in July on a 30-MW wind farm in Rhode Island waters, the first in the country. It has also announced plans for projects near Martha’s Vineyard in Massachusetts and along the New Jersey shore.
The state Emergency Commission voted to bill Energy Transfer Partners $100,000 to pay for an independent review of the company’s proposed Dakota Access oil pipeline. The $3.8-billion, 1,130-mile pipeline would carry crude oil from the state to Illinois.
The Public Service Commission approved the construction permit for the pipeline last month but said it now needs the company to pay for the review, the most expensive independent review the PSC has commissioned since reviews began in 2008. PSC Chairwoman Julie Fedorchak said the requirement was to “hold the company responsible for high standards.”
Regulators in South Dakota and Illinois have approved the project, which still needs approval by Iowa regulators and by the U.S. Army Corps of Engineers.
Bill to Define Avoided Costs to Clarify Return on Solar
Although the state has no net-metering law in place, a bill has been introduced in the House of Representatives that would help set definitions of “avoided cost,” or the amount a utility would have to pay a solar owner for power generated and fed back into the grid.
“South Dakota is one of the few states that has gone with just the avoided cost, the bare minimum as far as reimbursing generating customers,” according to Don Kelley, chairman of the board of directors of Dakota Rural Action, which is advocating for a uniform avoided-cost rate.
The sponsor of the bill, Rep. Paula Hawks, said she wants to set a consistent rate and policy “so people know they’re getting the same rate whether they’re in the Black Hills or in eastern South Dakota.”
Regulators OK Southern Co.’s Acquisition of AGL Resources
The State Corporation Commission unanimously voted to approve Southern Co.’s $12 billion acquisition of gas utility AGL Resources, which would create the second-largest utility in the U.S. with 9 million customers.
Southern would also acquire AGL’s share of the proposed $5 billion, 550-mile Atlantic Coast Pipeline. AGL was one of the owners — along with Duke Energy, Dominion Resources and Piedmont Natural Gas. Since the project was revealed, Duke Energy announced plans to acquire Piedmont for $4.9 billion.
Southern says it expects to complete the acquisition by the middle of this year. When completed, Southern will have 11 regulated electric and natural gas companies with 200,000 miles of transmission and distribution lines, more than 80,000 miles of natural gas pipelines and 46,000 MW of generation.
Bill Would Allow Gas Surveyors on Private Land Without Permission
The state Senate will consider a bill allowing surveyors for natural gas pipelines to enter private land without the permission of landowners. Under the new provision, surveyors would be able to go on private property if they first send a letter to property owners notifying them of their plans.
The bill is a response to a Monroe County judge’s ruling denying Mountain Valley Pipeline’s request to survey the properties of three uncooperative families. Pipeline issues currently are atop the state’s agenda, with seven pipeline projects underway. The state has experienced intense gas development of the Marcellus and Utica Shale formations.
This is the latest of several bills aimed at supporting pipeline development. One makes it harder for landowners to sue because of pollution; another allows pad construction before permits are granted; and a third allows companies to drill on co-owned land without permission from all owners.
Challenge to PSC Ruling on Tx Line Allowed to Go Forward
A LaCrosse County Circuit Court judge is allowing a town’s challenge of a transmission line to move forward. Holland is challenging the Public Service Commission’s approval of the Badger-Coulee line, proposed by Xcel Energy and American Transmission Co.
The 345-kV line is part of a larger project, the CapX2020, which would run across Minnesota and western Wisconsin. Xcel and ATC say that the line is necessary for system reliability. The town says there is no clear need for the line and objects to the route.
WASHINGTON — The Nuclear Energy Institute held a conference at the National Press Club Wednesday to discuss the progress made in cleaning up and dismantling the Fukushima Daiichi nuclear power plant in Japan. The Tohoku earthquake and tsunami on March 11, 2011, caused a meltdown at the plant, forcing thousands of people to abandon their homes.
While speakers primarily focused on safety improvements made in both the U.S. and Japan as a result of the disaster, others spoke about the effect it had on the workers and residents in the area, as well as the culture and communication at Tokyo Electric Power Co. (TEPCO), which operates the plant.
Houston-based CenterPoint Energy (CNP) on Friday reported a net loss of $509 million ($-1.18/share) for the fourth quarter of 2015. The loss included a $984 million impairment charge for its Enable Midstream Partners spinoff, a joint venture with OGE Energy and private-equity firm ArcLight Capital Partners.
The transmission and consumer natural gas company reported a net loss of $692 million ($-1.61/share) for the year. It said net income would have been $465 million ($1.08/share) without impairment charges of $1.846 billion, compared to $611 million ($1.42/share) in net income in 2014.
CenterPoint CEO Scott Prochazka told analysts Feb. 26 he expects 2016 earnings in the range of $1.12 to $1.20/ share.
“We expect continued strong financial performance from utility operations in 2016, which is incorporated in our guidance,” he said in a statement.
Shares of CenterPoint stock finished down 61 cents Friday, or 3.19%, closing at $18.53.
PJM last week joined more than a dozen other parties in calling for a FERC review of power purchase agreements that would provide FirstEnergy and American Electric Power a guaranteed return for their struggling generating stations in Ohio.
“If approved, the [PPAs] will create incentives that will likely lead to these generation units being offered, unless checked, in a manner that could harm the overall competitiveness of the PJM markets,” PJM said in comments supporting complaints by the Electric Power Supply Association and independent power producers.
“This outcome could impact significantly PJM’s administration of the wholesale markets in its region and affect the mission entrusted to these markets — assuring efficient, long-term resource adequacy,” PJM said.
EPSA, the Retail Energy Supply Association, Dynegy, Eastern Generation and NRG Energy asked FERC in January to revoke the waivers it granted AEP and FirstEnergy regarding affiliate power sales to ensure a Section 205 review of the eight-year PPAs (EL16-33, EL16-34). (See Dynegy, NRG Ask FERC to Void Ohio PPAs.)
They also are requesting an expedited decision, given that the Public Utilities Commission of Ohio could rule in coming weeks. And they contend that the results could impact PJM’s 2019/20 Base Residual Auction, to be held in May.
‘Premature’ Attack
Before the comment window closed Feb. 23, the complaints garnered the support of more than a dozen parties, including the Pennsylvania Public Utility Commission. No one submitted comments supporting FirstEnergy, but the Ohio Energy Group — industrial customers including Alcoa, Ford, GE Aviation and TimkenSteel — wrote in support of AEP.
“The complaint represents a premature collateral attack on a proposed PPA that is not yet finalized and that could substantively change as a result of state commission decisions,” the group said. PUCO is able to protect its own customers from any “affiliate abuse,” and there is no “definitive evidence” that the proposed PPA would distort the PJM markets, it said.
Sammis power plant (Source: Chris Dilts via Creative Commons)
AEP and FirstEnergy filed similar responses, saying allegations of market distortion are unfounded.
“The PUCO is undertaking a comprehensive review of the impact of AEP Ohio’s proposal on Ohio retail customers,” AEP said. “This is precisely the reason why the commission should adhere to its longstanding policy and defer to the PUCO’s resolution of the retail rate matters that form the basis for the complaint.”
Because Ohio is a retail choice state, the companies argue, customers there are not “captive.”
“The commission should reject the complaint on the merits, given that complainants have alleged no change in law in the state of Ohio that alters the basis on which the commission granted FirstEnergy a waiver from the affiliate transaction requirements,” FirstEnergy said.
Retail Choice Irrelevant
The plaintiffs say the state’s policy on retail choice is irrelevant because the PPAs would be funded by surcharges on all customers in AEP and FirstEnergy’s service territories, regardless of whether they take provider of last resort service from the utilities or purchase from a competitive supplier.
Among those supporting EPSA’s complaint was a coalition of 10 northwest Ohio communities.
“This is the first any of us has ever intervened at FERC — and that alone shows our resolve to oppose this awful PPA. It will cost Northern Ohio at least $3 billion,” said the Northwest Ohio Aggregation Coalition.
“When all the jargon is stripped away, the FirstEnergy PPA requires regular people to pay an extra month’s electric bill each year for eight years. It is not for the electricity that they use,” the coalition said. “Instead, the money that people need for school clothes and medical co-pays will go solely to bail out the company’s aged and inefficient coal and nuclear plants.”
Hardwood Flooring and Paneling Inc. in Middlefield, Ohio, said the PPA would cost it an additional $105,834 over eight years to pay for the 2.1 GW the business uses annually.
“That is real money that could be used on more productive purposes [such as] updating our equipment, increasing our inventories and building a new finishing plant for our hardwood flooring products — all of which bring more taxable income to the state of Ohio,” Vice President Barbara Titus wrote.
Ohio Citizen Action wrote on behalf of its 30,000 members, which the group said will be harmed.
The Pennsylvania PUC said it intervened because of “a concern that the FE affiliate PPA, as currently structured, represents a potential threat to the continued efficient function of PJM’s wholesale capacity markets, especially with regard to the upcoming 2019/2020 Base Residual Auction (BRA).
“More precisely, FE’s affiliate PPA presents the risk of potential subsidization of generation facilities that would otherwise be retired, resulting in conveyance of incorrect price signals in the next and subsequent capacity market auction auctions.”
The Ohio Manufacturers’ Association Energy Group, representing about 1,400 companies, said the manufacturing sector is one of the top electricity consumers in the state.
“Any impacts arising from future increases to electricity prices will have a significantly negative effect on their businesses,” it wrote.
OGE Energy fell short of Wall Street expectations Friday when it reported a fourth-quarter profit of $29.4 million and earnings of 15 cents/share. According to Zacks Investment Research, analysts had expected earnings of 23 cents/share.
The Oklahoma City-based parent of Oklahoma Gas & Electric recorded $447.1 million in revenue for the quarter. For the year, OGE posted a profit of $271.3 million ($1.36/share), compared with earnings of $395.8 million ($1.98/share) in 2014.
OGE shares closed down $1.88 Friday at $25.08, a 7% drop. It began the year at $26.29/share.
CEO Sean Trauschke attributed the earnings shortfall to low energy prices.
“The significant drop in commodity prices had an impact on our business as well as our communities,” he said in a statement. “However, we have made significant investments to improve our business and our company is better positioned to handle these challenges.”
Trauschke told analysts Friday the company is on target to continue to grow its dividend of 10% through 2019.
OG&E has approximately 825,000 customers in Oklahoma and western Arkansas. Its OGE parent also holds a 26.3% limited partner interest and a 50% general partner interest in Enable Midstream Partners.
WILMINGTON, Del. — A problem statement and issue charge seeking to develop RTO-wide criteria for end-of-life transmission facilities kicked off a long and heated discussion before being approved by an 80% sector-weighted vote of the PJM Markets and Reliability Committee on Thursday.
Just two of 12 Transmission Owners voted in favor of the proposal, which won 90% or more support from each of the other sectors.
Ed Tatum of American Municipal Power presented the proposal, which AMP co-sponsored with Old Dominion Electric Cooperative, the PJM Industrial Customer Coalition, the PJM Public Power Coalition, LS Power and ITC Mid-Atlantic Development.
“Aging infrastructure is a primary driver of investment,” Tatum said, noting that $5.5 billion in replacement projects have been identified and more are expected. That’s because most of the grid was built 30 to 50 years ago, he said. “We’re concerned about the number of dollars being spent.”
Some transmission owners have criteria for end-of-life facilities, but others do not, treating them as supplemental projects, Tatum said. Supplemental projects are improvements not required for compliance with PJM system reliability, operational performance or economic criteria.
Uniform guidelines would improve how the local and regional planning process determines the need for replacement facilities, according to the problem statement.
The newly formed End of Life Task Force will be charged with developing “alternatives for providing more transparency and consistency in the review of end-of-life projects, including the development of PJM end-of-life-criteria.” It will report to the MRC.
The majority of transmission owners opposed the plan, saying the problem statement prescribed a solution, that such guidelines should be voluntary and that it was illegally treading on the rights of transmission owners to maintain their own equipment. They called for an education session before bringing the issue back for a vote and said any such task force should report to the Planning Committee.
Tatum said the sponsors rejected a proposed revision by the TOs to make the guidelines voluntary because “making it voluntary is the status quo.”
And, he said, “Based on the conversations I’ve had with a number of you, I think that the definition you all may be using for maintenance is a bit expansive. My water heater blew last week and I didn’t maintain it, I replaced it.”
Speaking on behalf of the TOs, Chip Richardson of PPL said, “The TOs have expressed some concern that the very nature of this problem statement would violate their rights. … We think that the MRC needs to understand that this is a task to do something. This is not a problem statement or opportunity to do something. We’re implementing a solution that this group has chosen.”
Richardson said the TOs would have supported the issue if the guidelines were voluntary. He called for an education session to address three issues: to whom the task force should report; the rights of the TOs and PJM under the Consolidated Transmission Owners Agreement; and the implications of such criteria on cost allocations for projects in the Regional Transmission Expansion Plan.
“We’re launching a solution but are not well informed of what the implications are,” he said.
Tatum said it was not the intent of the sponsors to infringe upon TOs’ rights and that the task force would not be considering the issue of cost allocation. While the problem statement suggests “criteria and guidelines” would improve transparency, the task force would consider other approaches that accomplish the goal, he said.
PJM Vice President of Planning Steve Herling said transparency was the RTO’s primary concern as well, and to that end it could support the problem statement and issue charge.
“There’s an expectation as we start our planning process … that there is the opportunity for full vetting,” he said. “As long as [the criteria] are out there and people can see them and we have the opportunity to vet the issues and solutions, I think we’re OK with this moving forward. I’m less concerned with who the group reports to. The same people are going to have to be on the task force regardless.”
Jason Barker of Exelon cautioned that the task force’s work could embroil PJM in litigation if it treads on TOs’ rights under the CTOA.
“This is unquestionably a discussion about cost allocation. The overture here is that that’s not an intent … but it naturally follows from the discussion we’re having. Let’s acknowledge the elephant in the room,” he said, adding, “With regard to the committee reporting, it’s interesting that the sponsors want to put this at the MRC. We have a PC that’s described in our Operating Agreement: ‘The [Planning Committee] shall advise the [Markets and Reliability Committee and PJM] on matters pertaining to system reliability … and planning strategies and policies.’ That’s exactly what we’re talking about here. This is exactly in the PC’s wheelhouse, and there’s really no reason to diverge from it aside from politics.”
Gloria Godson of Pepco Holdings Inc. said the initiative “may be a back door way of imposing a risk profile on the TOs.”
A TO’s asset management practices result in a certain life expectancy for each asset and when the asset needs to be replaced, she explained after the meeting. “If the PJM stakeholders become the determinants of when and how transmission assets will be replaced, [they] will effectively be imposing their risk profile on the TOs and usurping this key corporate decision-making of the company owning the asset,” she said. “Who is going to bear the risk for these assets going forward?”
Dan Griffiths, executive director of the Consumer Advocates for the PJM States, said that no one in his group opposed it.
Jim Jablonski, of the Public Power Association of New Jersey, said he would welcome more transparency in the rates that consumers are charged.
One municipality has seen its annual bill rise over four or five years from $300,000 to $1.5 million, he said. “I get questions about why this is happening,” he said. “I need to be able to explain.”
Co-sponsor Susan Bruce, representing industrial customers, said, “Customers have seen their bills increase on the transmission side like never before.”
The task force’s work, she said, “is meant to be done in a way that is respectful of TOs’ rights and those who end up paying” for transmission costs.
Northern Indiana Public Service Co. and the Office of Utility Consumer Counselor reached a settlement on a 5.4% rate increase, less than half the 11% boost that the utility sought in its initial filing.
By a 3-2 vote, state regulators rejected a $4.9 billion bid by international investors to buy Cleco, effectively killing the utility’s sale.
Consumers Energy, under fire for estimating too many of its customers’ bills, said it will make an effort to improve meter reading operations. The assurance was included in a report to the Public Service Commission.
The Red Lake Band of Chippewa Indians signed an agreement with Winkelman Building Corp. and Innovative Power Systems for a 15-MW solar system that it says will generate enough electricity to power all of the tribe’s government buildings, its three tribal casinos and the tribal college.
Talks between Clean Line Energy and the Hannibal Board of Public Works to provide the Mississippi River city with cheap electricity in exchange for supporting the company’s high-voltage power line are being put on hold.
The Board of Public Utilities and the Economic Development Authority have approved a low-interest $2 million loan for Eos Energy Storage, which specializes in making low-cost DC battery systems for electric utilities.
Deepwater Wind is considering a Brooklyn waterfront site as a staging ground for a potential offshore wind project off Long Island.
The state Emergency Commission voted to bill Energy Transfer Partners $100,000 to pay for an independent review of the company’s proposed Dakota Access oil pipeline. The $3.8-billion, 1,130-mile pipeline would carry crude oil from the state to Illinois.
The State Corporation Commission unanimously voted to approve Southern Co.’s $12 billion acquisition of gas utility AGL Resources, which would create the second-largest utility in the U.S. with 9 million customers.
