MISO last week revealed yet another twist in its deliberations over two southern Indiana transmission projects, leading some stakeholders to question whether RTO officials are following their planning rules.
In July, MISO said it would consider swapping the proposed 345-kV Duff-Coleman transmission project, estimated to cost $67.2 million, for a previously rejected Rockport-Coleman 345-kV transmission line estimated to cost $76 million. (See MISO Plan to Revisit Runner-up Tx Project Rekindles Shareholder Angst.)
PJM offered to share the cost of the latter project, which could solve stability problems at its Rockport substation. PJM’s contribution would reduce MISO’s spending on the line by about $29 million.
At last week’s MISO Planning Advisory Committee in Eagan, Minn., MISO staff proposed a “loop-in” giving the Rockport substation paths to both Duff and Coleman.
It’s attractive to PJM in part because the RTO needs two 345-kV circuits to its 745-kV substation. PJM officials say they have had stability problems at the substation because the area has added thousands of megawatts of generation but no new transmission since 1989. (See “PJM: Despite Lack of Cost Allocation Rules, MISO Project Too Good to Ignore” in PJM TEAC Briefs.)
“They need two lines out of Rockport. So we can build the original, single-circuit Duff-Coleman, loop it in, and that loop-in would give them two lines out — one to Coleman, one to Duff,” said Jeff Webb, MISO director of expansion planning.
Costs are still being studied, but MISO estimates the new alternative would add about $200,000 to the Duff-Coleman cost, an amount that would have a negligible impact on its cost-benefit ratio.
Shareholders, however, pressed MISO officials about the additional costs, asking whether customers would bear some of them. Webb said MISO would only agree if PJM picked up the costs of its benefits, holding MISO harmless.
If not, “then all bets are off and we’re going back to the original [Duff-Coleman] project,” Webb said.
But several stakeholders questioned whether MISO should be concerned with PJM’s needs in the context of MISO’s own need to address southern Indiana congestion problems. They also questioned whether MISO was following the proper processes in evaluating the expansions.
Kevin Murray of the Coalition of Midwest Transmission Customers asked why MISO was not constructing Duff-Coleman as a market efficiency project under MISO’s Transmission Expansion Plan (MTEP) and then evaluating Rockport-Coleman as an interregional project on its own merits.
“Well, because I think we have an opportunity here to be efficient about building out the grid on both sides without any harm to MISO,” Webb replied.
“You’re going to run into the same thing PJM ran into with Artificial Island,” Murray countered. “You’re pursuing an outcome where people are going to say you didn’t follow the process. And you’re going to get tied up in litigation at FERC and the customer is going to be the loser in all this because they’re going to end up paying for transmission congestion for a period in time when it doesn’t need to happen.”
He noted that other stakeholders, such as Northern Indiana Public Service Co., weren’t happy with the idea.
“NIPSCO objects to the fact that neither of the competing recommended projects … has been studied under the process specified by the MISO/PJM Joint Operating Agreement to determine cross-border benefits and RTO cost allocations,” NIPSCO said in a letter presented at the PAC meeting.
NIPSCO said the recent actions by MISO and PJM to modify the southern Indiana proposal “suggests that there are difficulties and inconsistencies” in resolving cross-border issues through current planning processes.
“Rather than address these issues, the RTOs have circumvented the defined JOA processes for an ad hoc solution,” the company said.
NIPSCO said the proposed projects should be studied under the JOA process using a joint MISO-PJM model.
David Davis of NextEra Energy asked whether MISO had the time to study the new proposal and allow for stakeholder review before the recommended projects in MTEP 15 are submitted to the MISO board Dec. 10. “It seems like that’s a pretty long putt,” he said.
Webb said he was confident that answers could be found within six weeks.
MISO’s Planning Advisory Committee last week deferred for a future meeting a vote on Wind on the Wires’ request to require external generators seeking network resource interconnection service to pay the dollars-per-megawatt portion of M2 milestone costs.
After a lengthy discussion, several stakeholders said they needed more information before voting.
Wind on the Wires, which represents the wind industry, argued that the M2 deposit should be applied to external generators because internal generators already put cash at risk to demonstrate that they are serious about moving forward. The deposits discipline generators to not jump in and out of the queue and cause re-studies, the group said.
MISO officials said they do not agree with Wind on the Wires’ proposed requirement for external units. They said not all internal generators pay an M2 deposit.
Two of three proposed MISO-SPP interregional projects touted to offer $235 million in benefits look much less attractive following additional modeling and are likely doomed.
MISO revealed the disappointing news at last week’s Planning Advisory Committee meeting, saying the new results indicate a disconnect in coordination between the two RTOs.
MISO and SPP staff worked for several months to find economic projects to relieve congested flowgates. At one point they had identified 70 such candidates.
New analyses appear to have doomed the Elm Creek-NSUB and S. Shreveport-Wallace Lake interregional projects. The Alto-Swartz 115-kV project continues to meet the benefit-cost threshold.
By June the list had been whittled down to three projects totaling $156.9 million near the RTOs’ seams in Kansas, Nebraska and Louisiana. (See 3 MISO-SPP Transmission Projects Move Forward.)
But the numbers turned out to be markedly different after the RTOs ran regional reviews that used different assumptions:
The Elm Creek-NSUB 345-kV project that previously showed $165 million in present value benefits over 20 years fell to $29.2 million in benefits. The benefit-cost ratio decreased to 0.89 from 1.22.
The rebuild of the S. Shreveport-Wallace Lake 138-kV line, which initially showed $46 million in benefits, is now projected at $2.7 million. The benefit-cost ratio dropped to 0.25 from 2.61.
The series reactor on the Alto-Swartz 115-kV line showed a slight benefit decrease — to $20.7 million from $23.4 million. The project originally was estimated to have an overall benefit-cost ratio of 4.32. Based on its $4.6 million share of the cost, the benefit-cost ratio for MISO is 5.98.
“The benefit-to-cost ratio for two out of the three projects did not meet the … criteria,” said Arash Ghodsian, technical advisor for economic studies at MISO. “We were not able to see the same level of congestion that we saw in the interregional models versus the regional.”
He said the interregional and regional models differed in their generation assumptions, the impact of MISO South’s industrial renaissance load growth and their handling of MISO Transmission Expansion Planning for 2015 and out-of-cycle projects. One key factor is differing predictions on generation retirements resulting from the Environmental Protection Agency’s Mercury and Air Toxics Standards.
“Are you saying MISO applied MATS retirement assumptions about SPP generation in the MISO model, but SPP did not have the same retirement showing in their model?” asked Cynthia Crane, principal regulatory analyst at ITC Holdings.
“That’s correct,” Ghodsian said.
Crane said the inconsistencies in the modeling is a “cause for concern.”
Ghodsian agreed. “It’s part of the process differences. Moving forward, we need to do better coordination between” MISO and SPP, he said.
The fate of the projects wasn’t officially determined at the PAC meeting. They will be discussed at next month’s PAC for potential recommendation “if any,” according to Ghodsian’s slide presentation.
MISO planners who just completed the third phase of a study on the Clean Power Plan said last week that a “multibillion dollar” transmission build-out will be necessary in almost every compliance scenario they’ve anticipated.
“Our final rule analysis will look to characterize the amount of that and the scope of it and what needs to be done. But we definitely see a big impact coming to the MISO system,” Jordan Bakke, senior policy studies engineer at MISO, told the Planning Advisory Committee.
Purple indicates economic generation that cannot be dispatched under state-level compliance with the EPA Clean Power Plan. Green indicates generation dispatched under state-level but not regional compliance.
The estimated costs for transmission expansion to meet compliance could be up to $10.8 billion in net present value over 20 years, according to the study.
“Transmission expansion will be needed to mitigate reliability impacts as well as economic congestion impacts of compliance. And a lot of this is driven by the level of coal plant retirements,” Bakke added.
The study also agreed with those by PJM and SPP in concluding that regional compliance with the Environmental Protection Agency’s carbon emission rule will be more cost-effective than if states go it alone.
MISO’s study concludes that a regional approach — including MISO, SPP, PJM, NYISO, the Tennessee Valley Authority, the Midwest Reliability Organization and the SERC Reliability Corp. in the Southeast — will save $4 billion to $11 billion in net present value over 20 years versus individual state compliance.
A sub-regional approach — through MISO’s North, Central and South areas — would save $2.5 billion to $11.5 billion over state compliance.
Coal Retirement, Transmission Needs Still Fuzzy
Planners said they won’t know how many plants will retire until they get a better read of the final EPA rule and get more feedback from stakeholders.
The analysis looked at five compliance scenarios, including increased cycling of coal units and higher utilization of combined-cycle units and combustion turbines.
The location of new gas and renewable generation will pose infrastructure challenges. Some of the new gas generation units, for example, will be located near existing gas pipelines but will be farther out from the existing transmission system. Generation will be coming from different parts of the system, “parts that the transmission system historically was not designed to fully deliver,” Bakke said.
Coal-to-gas conversions expected by 2030 under one scenario included in MISO’s analysis of EPA’s carbon emission rule. The scenario assumed that in addition to the 12.6 GW of MISO coal generation expected to retire under EPA’s Mercury and Air Toxics Standards, 25% of the remaining coal capacity in the Eastern Interconnection will convert to gas-fired combined cycle units.
The study found that the cost of adding electric and gas infrastructure for new or converted gas generators would be comparable regardless of the siting assumptions.
The study, which took more than a year, looked at candidates to relieve congestion identified in the draft rule analysis. In June, 107 congested areas were identified for potential economic transmission expansion. In July, that list was narrowed to 34 potential transmission projects related to the Clean Power Plan.
“This creates a first step,” Bakke said, adding that more potential transmission projects resulting from the rule will need to be reviewed.
Regional Approach More Cost-Effective
Another outcome of the study was confirmation that regional compliance approaches will be more cost-effective than more numerous, sub-regional approaches.
“We found this throughout our different phases that we looked at … It was more cost-effective from production cost standpoint, from a resource capital build-out — a variety of different metrics,” Bakke said.
Although the analysis is based on EPA’s draft plan and not the final rule, Bakke said the study allows MISO to “hit the ground running.”
Next, MISO will dive into more than 1,500 pages of the final rule and supporting documentation. “We’re confident that the generic or the overall framework is good, and we’re going to be taking feedback on how we can improve it going into our final rule analysis,” Bakke said.
Further Study Challenging
Stakeholders had a number of questions. Miles Taylor, an engineer at Northern Indiana Public Service Co., asked how MISO would deal with issues such as whether there might now be fewer coal plant retirements than some had expected initially.
Bakke said that while MISO looked at a variety of scenarios, it is hoping to get more specific feedback from stakeholders as they make more sense of the final rule in the months ahead.
George Dawe, vice president of Duke-American Transmission Co., representing the transmission developer sector, asked how MISO would assess the future if several individual states decide to go it alone rather than engage with a regional compliance solution.
Bakke replied that initial state plans are due to be filed just over a year from now. “We should at least have an indication going into that what states have planned to do.”
MISO said that if some states refuse to file a compliance plan, the RTO could make some modeling assumptions based on what EPA would likely prescribe for a state.
One thing that’s clear is that there’s an appetite for the information that MISO will gather in the next phase of its Clean Power Plan study. Darren Kearney, an analyst at the South Dakota Public Utilities Commission, said states will rely on the RTOs to help them understand the least-cost compliance options.
Bakke assured him that MISO will provide as much information as it can as soon as it can.
FERC last week denied the SPP Market Monitoring Unit’s request for rehearing of a December 2014 order that rejected the Monitor’s use of a market-impact test to track physical withholding.
The commission found the test to be “overly limiting” and said the Monitor failed to demonstrate FERC was mistaken in requiring the test’s elimination (ER15-21-001).
FERC’s 2014 order required SPP to eliminate proposed revisions that added the market-impact test as a monitoring threshold for instances of physical withholding and said the RTO did not show how its proposal addressed FERC concerns.
The Monitor requested the rehearing in late December, saying including the market-impact test in its withholding screen was consistent with other grid operators’ practices. The Monitor said the test is “designed to be liberal in identifying capacity withheld” and if it is not used, monitoring for physical withholding “will continue to produce excessive false positive screen failures for the [Monitor] to analyze.”
FERC noted the Monitor did not challenge allegations that the proposed changes to the physical-withholding provisions “would sufficiently limit the number of screen failures.” The commission further said neither SPP nor the Monitor explained how the SPP proposal addressed FERC’s concerns about the test’s overly limiting nature.
“Thus,” FERC said in its order, “neither SPP nor the MMU supported the contention that the [market-impact test] was just and reasonable.”
The SPP Monitor had said MISO uses the impact test for physical withholding and argued the SPP Tariff should also have limits for the Integrated Marketplace.
FERC said the Monitor had not explained why the MISO mitigation test was appropriate for SPP. “The use of a specific threshold for mitigation purposes in one market does not necessarily make the threshold appropriate to use in monitoring and referral in another market,” the commission said.
Gov. Continues Fighting Artificial Island Cost Allocation
Markell
Gov. Jack Markell is urging FERC to rework a ruling by PJM that would force Delaware customers to pay for most of the cost of building a transmission line to stabilize a New Jersey power plant.
Markell and representatives of Delmarva ratepayers have protested PJM’s cost allocation of the project, which would bill Delaware ratepayers for 89.5% of a $275.5 million project to improve the reliability of electric deliveries from the Salem/Hope Creek nuclear complex on Artificial Island in New Jersey. (See Officials Urge PJM to Reject Artificial Island Proposal.)
Markell also weighed in on a complaint filed by Linden VFT, which is disputing another PJM construction plan on similar concerns about cost allocation.
SC Lawmakers Opposing Duke Plan for New NC Tx Line
Duke Energy’s plan to run a new transmission line from a South Carolina natural gas plant into North Carolina is being opposed by a number of South Carolina lawmakers, who say the project is not beneficial to the Palmetto State. Four elected officials, led by Rep. Doug Brannon (R-Landrum) have sent protests to the South Carolina Office of Regulatory Staff.
“None of our constituents will benefit from this transmission line project,” Brannon wrote. “On the contrary, the property value for the properties impacted by this project will be devastated. The properties in question are some of the most valuable in South Carolina.”
Duke said the line is necessary to serve load in the Ashville, N.C., area, which has seen demand double since the 1970s. The North Carolina Utilities Commission has not yet ruled on the project.
Hydropower has growth potential in the state, say advocates looking for alternative forms of carbon-free energy to comply with pending government regulations to reduce carbon emissions.
“The rivers are not producing as much as they can,” Arkansas Waterways Commission Executive Director Gene Higginbotham said recently. “Arkansas is a water-rich state, and we have a good state water plan that is saving aquifers and using more surface water.”
The state currently has seven hydropower plants. The U.S. Army Corps of Engineers, which operates two hydropower dams on the Arkansas River, has studied adding another plant near Pine Bluff, at a cost of about $202 million.
ICC Laying off 24, Part of Broader State Furloughs
Rauner
Gov. Bruce Rauner’s administration has announced the layoffs of 94 unionized workers in four state agencies, saying the legislature’s inability to pass a balanced budget made the moves necessary. The layoffs include 24 employees at the Commerce Commission.
The American Federation of State, County and Municipal Employees said the governor is jumping the gun and putting the public at risk. The ICC layoffs would reduce its staff by 35%, the union said. “Other layoffs would throw out of work men and women involved with nuclear safety, tourism, recycling and overseeing utilities,” said an AFSCME spokesperson.
Annapolis Backing Solar Facility Built on Closed Landfill
The City of Annapolis has signed a 20-year power purchase agreement with the developers of a solar facility built atop a closed landfill.
The city signed the agreement with Annapolis Renewable Energy Park, a 16.8-MW photovoltaic park on 80 acres of landfill outside of the city. The city says the power will offset CO2 emissions of 12.5% of the city’s annual household electrical usage.
“This project is about turning a liability into an asset,” Mayor Michael Pantelides said. “This park will turn a large plot of unused land into a revenue generator and a job creator.”
Lawmakers Urge Residents to Write to Canada to Stop Nuke Waste Plan
State and federal lawmakers are urging residents to oppose a Canadian plan to bury nuclear waste in an underground vault less than a mile from the Lake Huron coastline. Congressman Dan Kildee (D) and state Senate Minority Leader Jim Ananich have proposed a “community initiative” of letter writing to the Canadian government to protest Ontario Power Generation’s waste storage plan.
The company wants to bury low- and medium-level radioactive waste more than 600 meters deep, very close to the shore of Lake Huron. The utility says there is no risk to the lake.
Holland Using Waste Heat to Power Snow-Melt System
The City of Holland has a novel use for the waste heat from its municipal power plant: keeping city sidewalks clear of snow and ice.
The city, which is replacing its old coal-fired DeYoung plant with a natural gas unit, says the 145-MW plant will continue to use its waste heat to run a snow-melt system that keeps its downtown sidewalks and parking lots clear during the winter. The system, a network of underground 1-inch plastic pipes that carry warm water from the plant’s cooling system, was installed in the 1980s.
The $240 million gas plant will begin operations next year.
Columbia is switching its municipal power plant from coal to wood due to Environmental Protection Agency rules on coal combustion residuals.
Columbia’s Municipal Power Plant is scheduled to accept its final delivery of Indiana coal from Peabody Energy in October, when the rules go into effect. Officials say it would be too costly to retrofit the plant to meet the new standards.
The Public Service Commission last week approved KCP&L Greater Missouri Operations’ request to reduce the fuel-adjustment charge on its monthly bills. The change takes effect Sept. 1. It will mean a decrease of about $3.11/month for the typical residential customer in the Kansas City area and a decrease of about $2.69/month for the typical residential customer in the St. Joseph area.
The fuel adjustment charge reflects fuel and purchased-power costs during the six-month period of December 2014 through May 2015. The company’s tariff allows it to pass through increases or decreases in its energy costs to customers outside of a general rate case.
KCP&L-GMO provides electric service to 314,900 electric customers in the state.
Judge Upholds PSC’s Denial of NorthWestern’s Rate Increase
A district court judge has upheld a ruling by the Public Service Commission that shot down NorthWestern Energy’s proposed rate increase. The request dates from 2012, when the company sought compensation for outage costs and for revenue losses due to the success of its energy efficiency programs.
The PSC estimated the increase would have boosted customer rates by about $4.2 million if it had been in effect for the past three years. The judge ruled that the PSC acted reasonably in denying the request. The company is considering an appeal to the state Supreme Court.
The Board of Public Utilities says it is seeking a consultant to help it implement a five-year-old law to develop offshore wind power. The law mandated that the state develop regulations that would govern project financing, including how much of the cost would be borne by ratepayers.
BPU President Richard Mroz and Commissioner Joseph Fiordaliso disclosed the plan during their Senate confirmation hearings. Both were confirmed.
The law requiring offshore wind power has been the subject of political wrangling and is now four years past due. The state’s Energy Master Plan calls for development of 1,100 MW of wind energy by 2020. Nailing down financing guidelines is crucial to advancing the plans, which could cost as much as $1 billion.
Two intervenors in plans to shut down a pair of coal-fired units at the San Juan Generating Station filed documents last week opposing a compromise between Public Service Company of New Mexico (PNM) and environmental groups. New Energy Economy and Southwest Generation Operating Co. oppose the agreement reached by PNM, Western Resource Advocates and the Coalition for Clean Affordable Energy, made up of 12 environmental, clean energy and consumer advocacy groups.
The deal calls for PNM to submit to a hearing before the Public Regulation Commission in 2018 to determine whether the power plant near Farmington, built in 1972, should continue to operate after 2022. The agreement would keep in place the basic tenets of PNM’s current plan to close two of the plant’s four coal-fired units; PNM says that under the plan, the San Juan complex would burn about 49% less coal than it does now.
New Energy Economy argued in its filing that the agreement “contains no commitment by PNM to retire any of its remaining coal-fired capacity” at the power plant. New Energy also said PNM’s promise to procure renewable energy credits in the plan do not mean PNM will use more renewable energy.
A contractor working for Long Island Power Authority and PSEG Long Island claims in a federal lawsuit that the utilities mismanaged a controversial high-voltage transmission line project through North Hempstead, then shortchanged the firm by at least $1.5 million.
Energy Contract Recovery, of Port Huron, Mich., claims in the breach-of-contract suit that LIPA and PSEG failed to obtain permits and traffic control restrictions on time; did not accurately describe the site and underground conditions; and failed to deliver materials needed for the job and properly coordinate with other contractors. When the contractor’s representatives exerted their expertise to finish the project, PSEG employees rebuffed them and became “abusive and threatening,” according to the suit.
The 5-mile transmission line from Great Neck to Port Washington drew criticism from residents who claimed its 80-foot utility poles were unsightly and dangerous. ECR was initially contracted by National Grid in 2013 to construct the 69-kV line, which PSEG said was needed to ensure reliable power to the region. The work was scheduled to begin in December 2013, but the necessary permits weren’t secured until Feb. 11, 2014, according to the lawsuit.
Solar companies say a federal tax credit is essential to making residential and commercial projects economically viable, and they warn that the loss of the credit would be a serious blow to the industry.
U.S. Sen. Chuck Schumer (D) held a news conference Wednesday at the massive SolarCity factory now under construction in South Buffalo to call for an extension of the federal solar tax credit program and a change in federal regulations that would let homeowners and businesses take advantage of the tax credit sooner. The 30% federal solar investment tax credit is set to expire for residential projects in 2016 and to shrink to 10% for commercial projects.
Extending the tax credit and letting residents and companies receive the tax benefits as soon as construction begins, instead of waiting for projects to be completed, would encourage long-term investments in solar energy, provide certainty for solar customers and boost sales for companies such as SolarCity, for which the state is building the largest solar panel factory in the Western Hemisphere at the RiverBend site.
The Public Service Commission approved a siting permit for a $6 million natural gas liquids pipeline that will connect Oneok’s Lonesome Creek gas plant to its Garden Creek pipeline. The pipeline will have a capacity of 30,000 barrels a day. The gas plant, which is to be completed by December, will be able to process 200 million cubic feet of natural gas per day, according to the PSC.
PUCO Chairman to Utilities: ‘Stop Trying To Scare Ohioans’
Porter
The chairman of the Public Utilities Commission has warned utilities to stop using scare tactics in their lobbying efforts.
“Stop trying to scare Ohioans,” said Andre Porter, who chastised state utilities for suggesting that the state’s deregulation was imperiling system reliability.
FirstEnergy, one of the utilities seeking to adjust its power purchase agreements to guarantee a steadier revenue stream, denied it was fear mongering. CEO Chuck Jones “made it very clear we’re not seeking re-regulation in Ohio,” spokesman Doug Colafella said in response to Porter’s comments. “Our priority is the PPA in front of the commission.”
Two electrical cooperatives have postponed their consolidation plans after questions were raised about the motivations and duties of one of the co-op’s board members. Canadian Valley Electric Cooperative and Central Rural Electric Cooperative have been studying consolidation plans for two years. The co-ops had picked a new name, Cenergy Electric Cooperative and distributed marketing materials to members touting the benefits of consolidation, including projected savings of $48 million over 10 years. But votes by co-op members were postponed after an allegation arose about the “fiduciary duty” of a Canadian Valley board member.
Meanwhile, two western co-ops will consolidate next year after their members approved the plan earlier this month. Kiwash Electric Cooperative and Caddo Electric Cooperative will become CKenergy Electric Cooperative on Jan. 1, with a combined 25,000 meters and more than 7,600 miles of electric distribution lines. A report says consolidation would save the co-ops between $20 million and $30 million over a 10-year period.
Federal Judge Sets Court Date in Wind Farm Lawsuit
DeGuisti
An Oklahoma federal judge has ordered a trial next year over nuisance claims against a wind farm west of Oklahoma City. U.S. District Judge Timothy D. DeGiusti set a bench trial for April 11 against Kingfisher Wind, a unit of Apex Clean Energy.
Construction has started already on the 298-MW wind farm, but a group of landowners want the turbines to be placed at least 2 miles from their homes. About 150 people are working on the construction of the project, which will have 149 turbines. The company has said it expects the project to be finished by year’s end.
“Apex is taking a big risk in continuing to construct these industrial wind turbines when a ruling could require removal shortly after construction,” said Terra Walker, one of the plaintiffs.
Commission Finds No Changes in Marcellus Region Streams
A study by the Susquehanna River Basin Commission of 58 watersheds in the Marcellus Shale region found no change in the water quality as a result of drilling for natural gas in the area. The study showed that from 2010 to 2013, the water quality in the studied watersheds remained good.
The Remote Water Quality Monitoring Network, which began in 2010, now tests the water quality of the streams continuously. The electronic devices transmit reports remotely to the commission’s headquarters in Harrisburg every two to four hours.
Trains Carrying Oil Won’t be Slowed Despite Safety Report
A request from Gov. Tom Wolf’s office to reduce the speed limit for the up to 70 trains that daily transport crude oil through the state is being resisted by the two major railroad companies.
The suggestion comes from a report Wolf commissioned from the Railroad Engineering and Safety Program at the University of Delaware, which contained 27 recommendations, including reducing by 5 mph the federal speed limit of 40 mph.
Norfolk Southern and CSX said they believe their safety procedures already are sufficient.
The Environmental Protection Agency has proposed the first-ever federal regulations governing methane emissions by oil and natural gas drillers. Janet McCabe, EPA’s acting assistant administrator for the Office of Air and Radiation, estimated that exploration companies would need to invest up to $420 million to stop leaks and capture methane from working wells. But she said the industry could save as much as $550 million from captured gas.
The new rules are part EPA’s broader efforts to cut planet-warming emissions. Methane can trap 25 times more heat than carbon dioxide, but dissipates more rapidly. McCabe said the target for methane emission reduction is 20% to 30%.
The oil and natural gas industries are expected to challenge the rules.
July Hottest Month on Record, Federal Weather Agencies Say
July’s average global temperature was 61.86 degrees, making it the warmest month on Earth since records have been kept, federal weather officials said. Scientists from the National Oceanic and Atmospheric Administration said the new mark broke previous records set in 1998 and 2010 by a seventh of a degree, the largest margin ever by which an old record was eclipsed.
“It just reaffirms what we already know: that the Earth is warming,” NOAA climate scientist Jake Crouch said. “The warming is accelerating and we’re really seeing it this year.” NOAA records go back to 1880. The findings were confirmed by records kept by NASA and a Japanese weather agency.
Union of Concerned Scientists Cites DOE Study Slamming MOX Facility
The Union of Concerned Scientists said that a Department of Energy study concludes that the federal program to convert surplus plutonium to commercial grade nuclear fuel is an expensive and risky disposal method.
The UCS said it has obtained a study written by experts from the Nuclear Regulatory Commission, the Tennessee Valley Authority and the commercial nuclear industry that concludes the mixed-oxide fuel (MOX) program under construction in Aiken, S.C., is caught in “difficult, downward spiraling circumstances.”
The report said the cost of the MOX facility has ballooned from $1.6 billion to $30 billion. The report said it would be cheaper and less risky to ship the plutonium to the Waste Isolation Pilot Plant in New Mexico for burial.
The U.S. Department of Agriculture has awarded a $46 million federal loan to North Dakota-based Central Power Electric Cooperative to help finance 51 miles of new power lines and several substations. The funds come from USDA’s Rural Utilities Service electric loan program.
“Demand is the main driver of this,” said Dennis Hill, executive vice president and general manager of the North Dakota Association of Rural Electric Cooperatives. “The little single line with a small transformer just doesn’t work anymore.”
The new lines would be spread throughout the cooperative’s existing 1,300-mile network, according to Hill, who added that the project would commence after a four-year work plan is submitted. CPEC serves nearly 56,000 customers in 25 North Dakota counties.
A FERC administrative law judge has found that BP manipulated the natural gas market in Texas in 2008, and now the company faces millions in penalties and disgorged profits.
“This is a classic case of physical for financial benefits,” Judge Carmen Cintron said. “The evidence in this case shows that the Texas team had hundreds of affirmative acts in furtherance of the manipulative scheme during the investigative period.”
Federal regulators in 2013 proposed that BP pay a $28 million penalty and pay back profits of $800,000 plus interest. The ruling will now go before the full five-member commission for a final ruling. BP has vowed to appeal. “The evidence overwhelmingly demonstrated that BP’s natural gas traders did not engage in any market manipulation,” a company spokesman wrote in an e-mail.
Federal Gulf Oil Leases Attract Low Interest, Prices
A federal auction for drilling rights in the Gulf of Mexico is attracting the weakest interest since 1986.
Plummeting oil prices and industrial contraction meant that only five companies bid, for a total of $22.7 million. The auction happened on a day when American oil prices fell to about $40/barrel. Last summer prices were $100/barrel. The integrated oil giants ExxonMobil, Shell and Chevron didn’t even bother to bid.
“Concerns over the pace of economic growth in emerging markets, continuing (albeit slowing) supply growth, increases in global liquids inventories and the possibility of increasing volumes of Iranian crude entering the market contributed to the changed forecast,” the Department of Energy said.
DOE Gives $5.2 Million Grant to Duke Algae Uses Study
The Department of Energy has awarded a $5.2 million grant to Duke University to study possible uses of algae for renewable energy.
Zackary Johnson, an assistant professor of molecular biology at Duke, is heading a three-year study called MAGIC, or Marine Algae Industrialization Consortium. There have been efforts to derive fuel from algae, but so far none have been economically viable.
“To make algae a competitive player in this field you have to consider all the things the algae are producing,” Johnson said. “We’re essentially trying to make oil the waste product, so that it can compete with fossil fuels.”
A power generator fined $5 million for allegedly cheating ISO-NE wants federal regulators to drop two other allegations or combine them with the original complaint (IN15-4).
FERC fined Maxim Power in May for overcharging ISO-NE by offering into the day-ahead market with a price for oil-fired generation when in fact it was burning cheaper natural gas. (See FERC Fines Maxim Power $5M in Switching Scheme.)
FERC filed suit July 1 in U.S. District Court in Massachusetts to enforce its penalty.
FERC’s suit followed a Notice of Alleged Violations in November that included two other alleged schemes: that the company gamed ISO-NE market mitigation rules in 2012 and 2013, and that it boosted its generators’ outputs during testing using “extraordinary measures” in order to collect inflated capacity payments from 2010 to 2013.
Those two allegations were not mentioned by the commission in its filings seeking to collect the fine.
On Wednesday, Maxim attorney William S. Scherman sent a letter asking four FERC commissioners to add the “unpursued claims” to their federal court suit or confirm that they are no longer pursuing them. Commission Chairman Norman Bay, who headed the Office of Enforcement during the cases’ investigations, has recused himself in the matter.
“Maxim Power should not be forced to litigate piecemeal in federal district court,” Scherman wrote. “This would not only be inefficient and burdensome but also significantly add to Maxim Power’s litigation costs. As the commission knows, all companies consider litigation costs as part of their case assessment. But intentionally seeking to drive up a private entity’s litigation costs is not a reasonable litigation strategy.”
Scherman asked the commission to take action by Sept. 3.
PJM generators will earn $10.9 billion from this year’s capacity auction — a 45% jump from last year — in the first test of the RTO’s new Capacity Performance requirements. But some merchant generators smarting from low gas prices and competition from wind say that’s not enough for what ails them.
Securities analysts said the results will boost earnings for Exelon, Dynegy, NRG Energy, Public Service Enterprise Group, Calpine and Talen Energy.
The results have particular implications for Exelon’s Illinois nuclear fleet and American Electric Power’s potential sale of its merchant fleet.
Exelon: Retirements Still on the Table
Exelon announced Monday that three of its nuclear plants in PJM failed to clear the 2018/19 auction, including the 1,819-MW Quad Cities plant in Illinois, the second year in a row that it failed to clear. Company officials say they may retire Quad Cities if the Illinois General Assembly does not pass legislation that would boost revenues for the company’s nuclear fleet.
Exelon must notify PJM by September of any plants it won’t offer into the May 2016 Base Residual Auction for delivery year 2019/20.
Quad Cities, which has lost about $300 million over the last six years, is expected to lose about $50 million annually, according to Joseph Dominguez, executive vice president for government and regulatory affairs at Exelon.
Analysts from UBS Global Securities called Exelon “the clearest ‘winner’” in the auction because of its assets in both the ComEd zone, where prices hit $215/MW-day, and EMAAC, which cleared at $225/MW-day.
But Dominguez said the increase in capacity prices was a “marginal improvement” for Exelon’s generation. “What we got today is important, but it’s one year’s worth of revenue,” he told the Chicago Tribune on Friday. “We have to see a sustainable path forward.”
FirstEnergy spokesman Mark Durbin echoed Exelon Monday, saying PJM’s rule changes “resulted in clearing prices that really come closer to the operating costs of plants. But it’s only representative of one year; we’re not sure how reflective it is of long-term trends. It is a snapshot in a one-year time frame.”
Capacity revenue represented less than one-fifth of energy market revenue in PJM in 2014.
The results also did not help Exelon’s money-losing Clinton, Ill., plant in MISO. Exelon faces a December deadline for informing MISO if the 1,065-MW plant will be shut down before the planning year beginning June 1, 2016.
Seeking Help from the States
Exelon wants Illinois legislators to approve legislation that would require utilities to purchase credits from low-carbon generators including nuclear and wind. Illinois lawmakers did not take action on the Low Carbon Portfolio Standard before the spring legislative session ended, but they may consider it in November.
AEP and FirstEnergy also are seeking aid from state officials. The companies have asked the Public Utilities Commission of Ohio to approve above-market purchase power agreements from their coal generators.
PUCO has scheduled evidentiary hearings beginning Sept. 28 to consider the request from AEP, which is hoping to boost the value of its merchant fleet for a possible sale. (See Cold Weather, Low Gas Prices Drive AEP Earnings.) The commission is expected to consider FirstEnergy’s “Electric Security Plan” proposal as part of a rate case later this month.
In FirstEnergy’s second-quarter earnings call, CEO Chuck Jones cited PJM’s capacity market changes and the Ohio ESP as “key initiatives [that] will drive the near-term financial strategy” of the company.
Meanwhile, Dominion Resources won approval from the Virginia legislature in February for a nine-year rate freeze, meaning it won’t have to share the rise in capital revenues with ratepayers. Dominion said it wanted to suspend its biennial rate reviews to provide it and customers with “rate stability” as it responds to the Environmental Protection Agency’s Clean Power Plan.
While Dominion is assuming the risk of increased compliance and operating costs, analysts said the freeze allows the company to retain an additional 5 to 8 cents per share of earnings from PJM capacity revenues.
Transition Auctions
With the first auction under PJM’s new rules behind them, generators are now turning their attention to this month’s CP transition auctions for the 2015/16 and 2016/17 periods.
PJM will hold a transition auction on Wednesday and Thursday to obtain CP resources for 60% of the updated reliability requirement for delivery year 2016/17. Results are expected Monday, Aug. 31. The transition auction for 2017/18 (70% CP) will be Sept. 3-4, with results posted Sept. 9.
Participation is voluntary and open to any resource able to meet CP requirements, regardless of whether the resource cleared in the BRA for the delivery year.
FirstEnergy’s Jones said the transition auction results will have a big impact on how much the company is willing to spend to boost its plants’ reliability.
“We need to see where both the Base Residual Auction and then where in particular the transition auctions clear, because those are the more imminent,” he said. “For the Base Residual, you got three years to figure how to get your units reliable for that one. The transition auctions are a little more pressing in terms of time.”
UBS is predicting CP resources will clear the two auctions at about $120/MW-day, a “modest risk premium” to the base capacity resources, which cleared at $59/MW-day for 2016/17 and $120/MW-day for 2017/18 RTO-wide.
Other Generators
PSEG announced that its planned Sewaren Unit 7 had cleared the auction — the only new generation in EMAAC. The company said it plans to begin construction on the $600 million combined-cycle plant in early 2016. The company said it will replace the nearly 70-year-old Units 1, 2, 3 and 4.
PSEG said it cleared about as much capacity as in the 2014 auction, with all but one unit clearing as CP.
Talen declined to share the details of its offerings, but spokesman George Lewis said, “In general, we see the CP product as a positive, and the results from Friday are generally good and certainly within what was expected. It met most people’s expectations.
“Our view is it’s a partial picture at this point,” Lewis said. “We’ll find out more next week and the week after what the outcome of the [transition] auctions will be, and whether the results of the [BRA] will change the way generators or capacity resources will view bidding into these capacity auctions.”
Dynegy and Calpine had no comment on the results. AEP, NRG and AES did not respond to requests for comment.
A Calpine spokesman noted, however, that 4,600 of its 5,700 MW of PJM generation is in either ComEd or EMAAC.
Stocks Tumble
PJM generators saw their shares drop slightly on Monday, but it was a day when the market was down across the board on fears of economic weakness in China. The Dow Jones industrial average finished the day down 588 points, or 3.6%.
Exelon closed the day down 1.1% at $32.64 after an intraday high of $33.54. Dynegy was down 2.4% at $24.71, with an intraday high of $26.51. NRG shares dropped 1.8% to close at $19.22 after seeing an intraday high of $20.36. PSEG closed down 3.31% at $40.65, with an intraday high of $41.83. Calpine dropped 3.82% to close at $15.87, with a high of $16.76.
Talen saw the biggest slump, 4.7%, which brought its shares down to $15.17.
Below is a summary of the issues scheduled to be voted on at the Markets and Reliability and Members committees Thursday. 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 covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM MANUALS (9:10-9:20)
Members will be asked to endorse the following manual change:
Manual 37: Reliability Coordination — Modifies section 2.4.2. (Change management process), replacing reference to the Change Control Review Board with the Enterprise Change Management Standard. The standard ensures that changes to PJM business application systems, programs, data, systems software and hardware are authorized and applied so as not to compromise the stability and security of any information technology component. Also updates the definition of system operating limits (SOL) to make clear that PJM controls to the most conservative limits and that interconnection reliability operating limits (IROL) are an elevated level of SOL, not distinct from it. Clarifies the SOLs and IROLs monitored by the RTO as well as SOL violations reporting.
3. EXTERNAL CAPACITY TRANSFER RIGHTS (9:20-9:40)
The committee will be asked to endorse a rule change allowing load-serving entities to meet their capacity requirements with historic resources. Current capacity rules procedures lack a method to recognize historical resource and transmission commitments that were used to serve the capacity needs of LSEs’ internal network load, a situation that impacted the Illinois Municipal Electric Agency when PJM modeled its ComEd locational deliverability area (LDA) with a separate variable resource requirement curve. The proposed solution is three-pronged: The percentage internal resource requirement is enforced only if the LDA has been separately modeled due to certain triggers; a fixed resource requirement (FRR) entity would be permitted to terminate its FRR alternative election prior to meeting the minimum five-year commitment period requirement under certain conditions; and first-time elections of the FRR alternative would be due four months prior to a Base Residual Auction instead of the current two-month deadline. (See “Members OK Rule Change on External Capacity Transfer Rights” in PJM Market Implementation Committee Briefs.)
4. TRANSPARENCY OF OPERATIONAL CHANGES (9:40-9:55)
Proposed manual revisions would require PJM to announce the creation of new “closed-loop” pricing interfaces five days before the close of the next financial transmission rights auction. The rules would except outages of short duration (less than 10 days) and those setting price for demand response according to current manual and tariff instructions. PJM uses such interfaces to capture operator actions in LMPs rather than in uplift because its modeling software is unable to set prices for voltage problems. (See “Package Calls for Notice on Pricing Interfaces” in PJM MIC Briefs.)
5. MARKETS GATEWAY (9:55-10:05)
The committee will be asked to endorse revisions to the Operating Agreement and Tariff to reflect the transition from the eMarket tool to Markets Gateway. Training on the new tool is expected to be held in the second half of this year.
Members Committee
CONSENT AGENDA (1:20-1:25)
B. The committee will be asked to endorse a Tariff revision instituting previously endorsed fees for proposed transmission projects. Beginning next year, PJM will charge $5,000 to study greenfield or upgrade proposals of between $20 million and $100 million and $30,000 for projects costing more than $100 million. The fees will be implemented on a two-year trial basis. (See “PJM Lowers Proposed Tx Project Study Fee” in PJM Planning Committee Briefs.)
C. New Tariff language aims to more accurately reflect how PJM processes requests for merchant network upgrades. The changes address definitions, queue entry, agreements and the capacity market.
After failing to win approval from the MRC for a proposal to redesign the FTR and auction revenue rights process, Steve Lieberman of Old Dominion Electric Cooperative is seeking its endorsement from the Members Committee. (See ODEC Seeks Last-Ditch Vote on Deadlocked FTR/ARR Issue.)
The proposal garnered just 59% of a sector-weighted vote at the MRC’s July 23 meeting. Since then, the proposal has been presented to the Liaison Committee and has been the subject of conversation among numerous stakeholders and members, according to ODEC.
The proposal incorporates three elements. The first, drawn from a PJM staff proposal regarding the Stage 1A 10-year process, would escalate current ARR results using a zonal load forecast growth rate of +1.5%. The other two elements would change the method of reporting the monthly payout ratio so that any negative target allocations are included as revenue, slightly increasing the reported payout ratio. It also would treat each FTR individually, eliminating the netting of positively and negatively valued FTR positions in a portfolio prior to determining positively valued FTR payout ratios.
