The PJM Nominating Committee is recommending Dean Oskvig, retired CEO of Black & Veatch, and Mark Takahashi, CFO of Ascendant Group, for election to the Board of Managers.
Dean Oskvig Source: Black & Veatch
They would fill the spots left vacant by Richard Lahey and Jean Kinsey when they retire at this year’s annual meeting, to be held next month.
Oskvig spent his entire 40-year career with Black & Veatch, where he began as an engineer and went on to become project manager, partner-in-charge, COO and ultimately CEO for energy. Previously, he served in the U.S. Air Force.
Takahashi is an international finance executive with 30 years of experience in energy finance after starting out as an engineer. He has worked in the engineering, procurement and construction, and power and utility sectors.
The committee also is recommending that South Carolina technical engineer Terry Blackwell be re-elected to the 10-person board. He was chosen last year to serve out the remaining term of William Mayben, who retired after eight years. (See New PJM Board Member Elected, Re-election Eligibility Changed.)
Mark Takahashi Source: Linkedin
This will be the first board appointment under new terms adopted last year: Members will be ineligible for re-election once they turn 75 or have served five terms.
That precludes Lahey from seeking another term; he has served on the board since its inception in 1997.
PJM does not disclose the ages of its board members, so it’s unclear whether Kinsey, who joined in 2003, could have sought another term.
The Nominating Committee consists of eight members: five PJM stakeholders and three board members. This year’s sector representatives were Marji Phillips, Other Suppliers; Joe Kerecman, Generation Owners; Lisa McAlister, Electric Distribution; Ruth Ann Price, End Use Customers; and John Horstmann, Transmission Owners.
The board members were Howard Schneider, who served as the nonvoting chair, Ake Almgren and Kinsey.
HOUSTON — NYISO CEO Brad Jones got to wear his cowboy boots again last Tuesday, returning to Texas for a discussion with the CEOs of SPP, MISO and his former employer, ERCOT.
Though three of the four grid executives claim Lone Star roots, Jones was the only one wearing boots onstage at the Gulf Coast Power Association session.
Footwear aside, the four of them had much in common, including concerns over cybersecurity and their management of shifting generation resources. They also expressed sharply differing views on some subjects, such as the value of FERC Order 1000.
Impact of Low Gas Prices, Renewables
ERCOT CEO Bill Magness, who moderated, began the discussion by asking his colleagues whether natural gas or renewables were causing bigger changes in their operations.
“Both,” responded MISO CEO John Bear, a Texas native. “Five years ago, we were about 85 to 90% provided by coal. It’s about half that right now. So we’ve really made a significant shift because of the wind generation and obviously the gas coming online.”
Bear said he didn’t share the fears of some that the Clean Power Plan and other environmental rules will “rob of us our fuel diversity.”
“In fact it’s giving us fuel diversity,” he said. “We’re losing our storage, because that coal pile is largely going away for us. But we are adding a lot more flexibility because of those gas plants.”
SPP CEO Nick Brown took note of his RTO’s growing wind generation — 12.5 GW installed and another 4 GW in the transmission queue. The RTO set a new record at 2 a.m. April 5, with wind representing 48.32% of generation. (See related story, Wind Energy’s Growth Causes Second Look at 2 Tx Projects.)
“If you had asked me five years ago if we would ever see 48% of the generation online at a given point in time being from … wind, I would have laughed at you,” Brown said. “And yet it is a reality. And I’m sure before the end of this year we’ll see 50%.”
In five years, Brown said, “we’ll be predominantly a renewable generation fleet with some thermal. We’re going to have to learn to operate differently.”
Magness said ERCOT is, like MISO, affected equally by renewables and low gas prices. It has been trading wind records with SPP and also expects to exceed 50% penetration this year. “We’re seeing hours of negative pricing across the system in a way that’s relatively new,” Magness said. “It used to be more isolated in the west zone.”
By contrast, New York gets only 4% of its power from variable renewables, said Jones, who joined the ISO in October. Controllable hydroelectric facilities provide another 20%. (See New NYISO Head: New York a ‘Fantastic Opportunity’.)
Unlike Texas, which is fighting the CPP in court, New York “wants to take leadership on low-carbon issues,” Jones said.
Thanks to its participation in the Regional Greenhouse Gas Initiative, the state doesn’t need to make any changes to comply with the CPP. But meeting Gov. Andrew Cuomo’s Clean Energy Standard, which calls for renewables providing half the state’s power by 2030, is another matter.
“To give you a sense of scale, [that would require] 25,000 MW of solar, if solar is the only technology we use. It’s 15,000 MW of wind if that’s the only technology, and we today have about 1,700” MW, he said.
Jones called out former ERCOT colleagues, joking, “I had to go to New York to get a capacity market.” With low energy market prices and a demand for increasing renewables, he said, “it is very valuable to have.”
Demand-Side Management
Because of the growth in intermittent resources, Brown said grid operators “need to pay more attention to the demand side of the equation.”
“Historically, as balancing authorities, we assume load is just this random event and then we chase it, most typically with these huge thermal machines,” Brown said. “The engineer in me has always hated that.”
He predicted policymakers will “allow wholesale market operators to send price signals to the end-use load and use that load as a controlling mechanism to help us balance.”
Bear agreed on the need. “At some point, loads are going to start growing again,” he said.
Bear and Brown also questioned the value of Order 1000 and its competition requirements.
Bear said MISO has already committed to building $6 billion in transmission to eliminate congestion in its footprint.
“Because we did that, when you combine that with … $2 gas, there’s not a lot of congestion on the footprint, so finding those economic opportunities [to justify new transmission projects] is really hard,” he said.
He noted that transmission projects typically take eight to 10 years to complete. “Add an extra year to the process to bid those things out, pick amongst [the responses], work through the litigation process — I’m wondering if that’s really necessary,” he said.
Brown said SPP’s board will soon make a decision on whether to authorize its first competitive transmission project. The RTO received 11 responses to its solicitation to build a 115-kV line between North Liberal and Walkemeyer in southwestern Kansas. (See SPP Issues RFP for 115-kV Transmission Project.)
“We now call into question the need for this line just because of changes in the load forecast,” he said. “So we may have gone through all that [competitive solicitation] for nothing.
“I’ve always characterized the [Order 1000] process as very cumbersome, very costly, very time consuming. And it’s going to be interesting to see if the benefit of the competitive process justifies the extremely complex process.”
In contrast, Jones said he has a “positive perspective” on Order 1000, although he agreed on the need to “streamline” the competitive process.
Jones said the FERC order has helped New York break a “logjam” to initiate its first major transmission projects in 30 years.
One project, the Western Energy Connection, will add 1,000 MW of transmission capacity for hydro, gas and renewable generation, including the dam at Niagara Falls. “We can’t get all of that hydro resource into the state. It’s bottled up. And we’re having to spill some of that water down the river,” he said. (See NYPSC Directs NYISO to Seek Tx Bids.)
Cybersecurity Fears
The executives also shared their concerns over cybersecurity.
Bear said the issue was a minor concern for MISO five years ago. “The amount of time we spend on it now is unbelievable,” he said. “It’s that big black unknown. We’re doing everything we can to make sure we’re as prepared as we can be, but if anyone looks at you and says, ‘Are you sure that we’re never going to have an event?’, you can’t say ‘I’m sure.’”
Brown called the issue “the most frustrating” part of his job and said SPP is no longer solely focusing on keeping hackers out of the system.
“What keeps me up at night is, are they already in and we don’t know it? And the challenge is, I don’t know how much to spend. What’s the right amount? What’s the right amount of risk mitigation for this type of event? I don’t know the answer to that.
“How much protection do we have from our insurance carrier for a cyber penetration event? I still can’t get straight answers,” he added. “Even the coverage we have has certain exclusions in there that the underwriters are just adamant have to be there and I’m adamant that they can’t be there. We just don’t see eye to eye.”
WASHINGTON — U.S. Sen. John Boozman (R-Ark.) last week introduced legislation that would force the Commodity Futures Trading Commission to grant SPP the same broad regulatory exemptions the commission granted other grid operators in 2013.
The commission’s 2013 order exempted electricity transactions subject to FERC-approved tariffs from most provisions of the Commodity Exchange Act (CEA). SPP was not party to the order because its day-ahead market was not fully implemented at the time.
Unlike the 2013 order, the draft order CFTC is considering for SPP includes a preamble stating the commission’s intent to preserve “private rights of action” under Section 22 of the CEA. (See Witnesses Ask CFTC to Drop ‘Private Rights’ Clause.)
Massad
CFTC Chairman Timothy Massad testified Thursday at a hearing of the Senate Appropriations Committee’s Subcommittee on Financial Services and General Government, which is chaired by Boozman. The Arkansas senator did not raise the issue.
However, a Boozman spokeswoman said the senator introduced an amendment that was included in the manager’s package at the Senate Agriculture Committee’s markup on the CFTC’s reauthorization Thursday.
“The amendment would ensure the current regulatory framework remains in place and prevent inconsistent regulations between FERC and CFTC,” said spokeswoman Sara Lasure. She said Sen. Joe Donnelly (D-Ind.) co-sponsored the amendment.
Speaking at the Gulf Coast Power Association’s annual meeting in Houston last week, SPP CEO Nick Brown said the RTO was working with Boozman to bar the commission from allowing private rights of action for wholesale electric markets.
“To open this to 100 [U.S.] district courts is just insane in my mind,” Brown said. “I don’t know a better word for it. … This would just be a field day for the legal community.”
Other grid operators have expressed concern that the commission’s reference to private rights in the SPP order could undermine their 2013 waiver.
“The real risk is for market participants who are in the [congestion revenue rights and financial transmission rights] markets,” ERCOT CEO Bill Magness said. “When I had to come back to meetings at ERCOT and talk about CFTC again, it was a very unhappy day. We thought we were done with these discussions for a while.”
MISO met NERC’s frequency response requirement for 2015, although performance was not as good as a year earlier, adviser Terry Bilke told an April 13 Reliability Subcommittee meeting.
The RTO’s estimated annual frequency response was -475 MW/0.1 Hz in 2015, complying with its obligation of -211 MW/0.1 Hz under NERC’s frequency response standard (BAL-003-1).
Still, results from local balancing authorities were not as good as in 2014. “I was kind of hoping we’d see incremental improvement year-over-year,” Bilke said, adding that the decline was small enough to be attributed to sampling error.
“We’re still okay,” RSC chair Tony Jankowski said. “But there’s nothing that says we’re going to be OK except for past performance. And obviously, that’s [no] guarantee.”
Data for the first quarter of this year showed that more than 400 generators provided no frequency response in the first quarter, while about 100 plants were determined to be harming MISO performance. Fewer than 200 generators rated an “OK” response, with a small number classified with “theoretical perfect performance.”
Daily real-time unit commitment rating at peak hour for March (top) and monthly performance (bottom).
“Interestingly, one of the best performers was a wind farm,” Bilke said.
That assessment comes as MISO stakeholders are being asked to respond to FERC’s Feb. 18 Notice of Inquiry, which seeks comment on whether RTO pro forma interconnection agreements should be changed to require all new generation be capable of providing frequency response (RM16-6).
Jankowski said the language in the notice indicates that FERC does not recognize all the factors at play.
“From the market’s perspective, I don’t think we have any indication that a generator is a frequency response generator or not, or a good performing generator or not,” he said. “So to have any sort of expectation that we don’t have enough [frequency response] because the market clears wrong, I don’t buy that. There isn’t a constraint for frequency response.”
MISO thinks frequency response should be compulsory for new generation and voluntary for all existing generation, Bilke said. He added that if reliability declines in light of a changing resource mix, FERC should revisit the issue.
Comments on FERC’s notice are due April 25. Jankowski urged the RSC to be “proactive” in making suggestions on frequency response incentives and penalties through local balancing authorities.
“Nothing precludes us from doing this today,” he said.
March Incident Breaks 3-Month Perfect Score on Commitment Performance
Last month’s sole “unacceptable” rating for real-time unit commitment performance — occurring March 22 — was attributed to an operator’s mistake.
“We had a unit that was left on in an operator error,” Steve Swan, MISO senior manager of dispatch and balance, said during a monthly operations update. “They misread the runtime. It’s been addressed.”
March otherwise contained all “excellent” daily performance ratings, receiving an overall score of 2.9 — just shy of “perfect,” but breaking a trend of perfect 3 rankings in peak hour unit commitment since December.
The month had no minimum or maximum generation alerts or warnings nor any tie-line errors lasting longer than 15 minutes.
Swan also reported that -45,308 MW was added to MISO’s inadvertent interchange balance in January, bringing the running total of imbalances since 2009 to -749,641 MW.
By the end of this month, MISO expects to complete two bilateral inadvertent interchange paybacks, where two balancing authorities swap under-generation for over-generation. Swan said MISO is also performing “internal data mining” to investigate why the footprintwide balance continues to be negative.
“We historically haven’t gotten a lot of review on [the report],” said Ron Arness, Seams Management Working Group liaison. He noted that, although feedback is light, stakeholders continue to request the report every year.
Independent transmission company GridLiance continued to gather up industry expertise last week with the announcement that American Electric Power’s J. Calvin Crowder has joined the company as president of the South Central region, which includes the ERCOT, MISO South and New Mexico grids.
Calvin Crowder
Crowder will oversee business development activities with public-power agencies from his base in Austin, Texas. Crowder was most recently president of AEP’s Electric Transmission Texas (ETT), which he helped grow to $3 billion in assets.
“Calvin is a highly regarded electric utility industry executive who brings an in-depth understanding of the utility business, collaborative management style and excellent relationships with RTO officials as well as state and federal regulators,” GridLiance CEP Ed Rahill said in a statement.
Crowder has 25 years of experience in the industry, much of it with AEP and its Central and South West predecessor. He has focused his career on regulatory and legislative matters, securing a $1.5 billion investment for ETT in ERCOT’s Competitive Renewable Energy Zone.
Crowder earned his bachelor’s degree in economics and his master’s degree in regulatory economics from New Mexico State University.
The Z2 Payment Plan Task Force brought two payment plan options to the committee, recommending the level-payment plan over a staggered-payment option. The task force’s recommendation cleared the 66.7% threshold for acceptance at 77.4% after a voice vote was inconclusive.
Under the level-payment plan, each entity with a net payable will be given the option to pay the entire amount at once or in equal installments every three months, beginning in November, with the final installment due in August 2017. FERC’s interest rate for refunds will apply to the outstanding balances. (See “Z2 Task Force to Present Final Recommendations,” SPP Briefs.)
The dollar amounts to be billed remain an unknown, which led to much of the members’ reluctance to approve the recommendation. Midwest Energy’s Bill Dowling called the schedule “problematic,” saying he has “zero” money in the budget to handle bills that may be coming his way.
“I’m still questioning why we have to decide now, without knowing how many zeros we’re talking about here, let alone how many commas,” he said. “It’s really tough to figure out where this money comes from, or how I get the money, until I get an invoice that says I have 30 days to pay.”
“If we wait until later to decide and some other action is needed, like going to FERC, that might prolong this process even further,” responded Oklahoma Gas and Electric’s David Kays, the task force’s chair.
“Ultimately, the amount you will pay or receive will be what it’s going to be,” said Aundrea Williams of NextEra Energy Resources. “Voting on the payment plan doesn’t really affect what you’re going to owe and receive.”
Kays said the software used to calculate the credits is scheduled to be in production by June 1. He said historical data will be available for stakeholder review in time for the MOPC’s October meeting.
SPP will review stakeholders’ data with them in late May. Kays said staff will walk through the calculations and demonstrate the software is performing correctly.
Stakeholders will be exposed to confidential data, which will require signing nondisclosure agreements. Staff assured members the NDAs would not preclude their ability to communicate with FERC.
Market Working Group Gives Updates on Revision Requests
The committee approved a Market Working Group revision request to clean up the Tariff’s out-of-merit-energy (OOME) language (RR 145) while remanding a second back to the working group for additional work (RR 154).
RR 145 is intended to correct dispatch and set point instructions for variable energy resources, clarify OOME treatment for qualifying facilities and make other minor changes to the Tariff’s OOME provisions.
The second change, RR 154, would make it clear when SPP should perform a repricing of the day-ahead and real-time balancing markets. Current protocols and the Tariff allow for the repricing in the day-ahead market “for any reason at any time,” said American Electric Power’s Richard Ross, the MWG’s chair.
Ross also:
Updated the committee on its work regarding the SPP Market Monitoring Unit’s nine suggested improvements to the market design. (See “Market Working Group Addressing Monitor’s Recommendations,” SPP Board of Directors/Members Committee Briefs.) Two of the nine recommendations — minimizing the over-allocation of transmission congestion rights and auction revenue rights in the day-ahead market, and improved reporting on planned outages — are complete, Ross said. A final report is expected to be presented at the July MOPC and board meetings.
Briefed the committee on the MWG’s Price Formation Task Force, which was created to “identify concerns with current pricing methodologies” and propose solutions. The task force is currently analyzing feedback gathered from the MOPC and the MWG.
Told the committee that estimated costs for Integrated Marketplace RRs since September 2013 have surpassed $11 million. He said nine of the 10 RRs will be implemented this year and next.
SPP Pondering ‘One-Offs’ as Potential Seams Projects
SPP Principal Regulatory Analyst Sam Loudenslager brought the committee up to date on the RTO’s effort to create a new class of seams transmission projects, which was rejected by FERC in November.
SPP had proposed a new transmission category to identify projects that fall outside the Order 1000 interregional planning process or may not be eligible for cost allocation. FERC rejected it, saying the plan was too broadly drawn (ER15-2705). (See FERC Rejects SPP Proposal for Seams Transmission Projects.)
The RTO’s staff has been seeking further direction from FERC to determine whether to make another filing. Loudenslager said his recent conversations with FERC staff indicated “they didn’t think we could present a filing that would pass their legal concerns.”
He said FERC staff focused on SPP’s criteria for seams and interregional projects. “They didn’t think we had been through the process enough.
“They suggested we might need to differentiate between [seams and interregional] projects,” Loudenslager added. He said staff encouraged SPP to bring them potential projects that “didn’t pass muster with MISO” as potential “one-offs.”
SPP’s current rules designate transmission facilities of 300 kV or above as “highway” facilities whose costs are allocated entirely on a regionwide, postage stamp basis. Facilities between 100 kV and 300 kV are “byway” facilities, with two-thirds of the costs assigned to the host zone and one-third allocated region-wide. Projects below 100 kV are allocated entirely to the host zone.
“We need a more convincing argument with FERC about why this needs to be a standard one-off,” said Carl Monroe, SPP’s chief operating officer. “We do have special circumstances where these one-offs have to be done outside the Order 1000 process, especially if they don’t fall into the stipulation of shared costs. That way, parties outside MISO could agree to a process where we might be able to find agreement with MISO members that fall outside the Order 1000 process.”
Loudenslager said FERC staff suggested SPP work with Associated Electric Cooperative Inc., a member of the Southeastern Regional Transmission Planning process based in Missouri. “To the extent we came up with something on AECI that didn’t pass muster with MISO,” he said, “they encouraged us to bring it to them as a one-off.”
MOPC Chair Noman Williams, chief operating officer for SouthCentral MCN, suggested staff continue to develop a business practice to add some structure to the one-off process.
“Have it at least all laid out so we don’t have to recreate the process [each time],” he said.
Staff Says No Further HPILS Construction Needed
Staff told the MOPC no additional construction is needed for the 2014 High Priority Incremental Load Study (HPILS) because of slumping oil prices and dropping rig counts.
The HPILS study, commissioned to address unexpected load growth resulting from oil and gas shale production, recommended $439 million in transmission upgrades to serve needs through 2013.
In approving the HPILS report in 2014, SPP’s board directed members affected by HPILS loads and assumed generation additions to provide updated forecasts of those loads and generators before the quarterly MOPC and board meetings. The board also directed members to notify staff should additional notices-to-construct be required.
Jay Caspary, SPP director of research, development and special studies, said 110 MW of load remains unserved in North Dakota’s Bakken Shale play through 2017 and 200-300 MW is unserved in New Mexico’s Permian Basin oil fields in Eddy and Lea counties near the Texas Panhandle. He said the loads are “consistent with previous projections” and recommended no change in HPILS project construction.
Basin Electric Power Cooperative completed a 75-mile, 345-kV line in North Dakota in December, while Southwestern Public Service has energized three projects in the Permian Basin, adding 40 miles of 345-kV lines (which operate at 230 kV) and 19 miles of 115-kV lines. SPS is working on another project between Lubbock, Texas, and Hobbs, N.M., which is scheduled to be in service by 2020.
Some stakeholders questioned the accuracy of the load forecasts, given the low price of oil and dropping rig counts.
“These forecasts coming from folks who believe the price of oil will go back up to $50 or $60 a barrel kind of flies in the face of logic,” Empire District Electric’s Rick McCord said. “It doesn’t make sense to come in here and say [the recent slowdown] doesn’t have an impact. Could [SPP planners] give us some sort of an indication [of how much] load growth doesn’t show up to change what we’re doing?”
“We feel these [projections] are right for the system,” Caspary said. “The load growth is still there. It’s not what it was, but it’s still amazing compared to the rest of the SPP system.”
Ross asked whether staff could use its SCADA system to check “withdrawals off the transmission system.”
“I’m sure we can do that,” Caspary said, “but the directive we got was to look at the forecasts.”
Consent Agenda/RRs
The committee approved in a near-unanimous vote a revision request to SPP Business Practice 7650, which defines procedures for processing competitive transmission proposals as part of the RTO’s Integrating Planning Process.
The RR clarifies the steps taken to determine which detailed project proposals (DPPs) are equivalent to a transmission project in the Integrated Transmission Plan’s Transmission Owner Selection Process’ (TOSP) portfolio. The Business Practice Working Group (BPWG) said the criteria changes will further improve SPP’s ability to “efficiently and accurately” complete the DPP process within the ITP’s required timelines. DPP projects approved for construction as a competitive upgrade may be eligible for “incentive points” within the selection process.
A review of the first TOSP found a combined 1,672 DPPs were received for the 2015 ITP Near-Term and 10-Year assessments, and an additional 1,664 DPPs were submitted for the 2016 ITPNT. Stakeholders expressed their concerns that the drain on resources would affect the 2017 ITP10 schedule and lead to less-than-optimal solutions.
McCord, the working group’s chair, said submitting better DPPs would allow staff to spend more of the 30-day assessment window on needs and solutions, rather than ensuring incentive-point qualification, and lead to more innovative solutions. The language changes to the business practice would be effective with the 2017 ITP10.
ITC Holdings’ Marguerite Wagner cast the lone negative vote, following precedent set during the stakeholder process. The RR was approved by the BPWG and two other groups, with ITC Great Plains the sole dissenting vote each time.
“We don’t oppose the language,” Wagner said, “but we oppose the application of this language in the middle of the three-year cycle.” She said technology improvements could help reduce the number of DPPs, “so it’s unclear this is necessary at all.”
The committee also approved four other RRs from the BPWG and seven additional RRs from the MWG and two other working groups as part of the consent agenda:
BPWG-RR 147, clarifying the methodology to define a competitive upgrade’s 50% completion status;
BPWG-RR 148, updating BP 2150 to reference the current webRegistry;
BPWG-RR 149, updating BP 6150 to reference NERC reliability standards;
BPWG-RR 150, updating BP 4300 to reference a NERC reliability standard;
MWG-RR 25_MPRR 211, adding language to identify offer costs eligible for recovery with a “market” or “reliability” commitment;
MWG-RR 128, clarifying description of day-ahead start-up eligibility recovery rules;
MWG-RR 137, aligning enhanced combined cycle language with that for quick-start resources;
MWG-RR 142, preventing a resource from registering as a quick-start resource and a multiconfiguration combined cycle resource;
ORWG-RR 141, allowing use of updated ratings for facilities, elements and flowgates that reflect current ambient conditions or more relevant system conditions; and
ORWG-RR 146, removing the criteria revision process from the SPP operating criteria, as the process is now a MOPC process.
Criteria Review
SPP Director of Planning Antoine Lucas reviewed with the MOPC a planning criteria study of the Integrated System’s (IS) transmission grid that evaluates thermal and voltage limits and includes a stability assessment.
Lucas said a 2013 criteria study of the IS members — Basin, Western Area Power Administration-Upper Great Plains and Heartland Consumers Power District — identified four projects totaling $10.56 million to be completed before joining SPP in October 2015.
The study was updated when two additional IS members, Central Power Electric Cooperative and Tri-State Generation and Transmission, joined SPP in January. The 2016 integration study added two additional projects totaling more than $3 million.
FERC has again upheld the ISO-NE limited exemption for renewables from the RTO’s minimum offer price rule, saying it was necessary to protect consumers from paying for excess capacity (ER14-1639).
The commission voluntarily agreed to reconsider the issue after NextEra Energy and other generation owners asked the D.C. Circuit Court of Appeals to review FERC’s January 2015 order rejecting their challenge of the exemption (15-1070).
The generators claimed the exemption, which is limited to 200 MW annually, suppressed clearing prices in the Forward Capacity Market. The exemption was contained in an order in which FERC accepted ISO-NE’s compliance filing in response to the commission’s requirement for a sloped demand curve.
The companies had relied on a previous FERC order that recognized that exemptions could suppress capacity prices. However, the commission said that a unique set of facts presented in a specific case could justify an exemption.
“The renewables exemption fulfills the commission’s statutory mandate by protecting consumers from paying for … capacity that cleared through the [Forward Capacity Auction] and separately paying for renewable resources built by state entities to meet state policy objectives,” FERC said.
EPA issued a formal notice amending its 2012 rules governing toxic air pollutants from power plants in response to the U.S. Supreme Court ruling them illegal.
The agency issued a formal notice amending the Mercury and Air Toxics Standards, saying that the costs of regulating emissions such as mercury, nickel and arsenic are reasonable and far outweighed by the public health benefits. EPA had issued a similar finding, but while the rules were being written. The Supreme Court ruled that the cost analysis should have been done before.
The court remanded the rules back to the D.C. Circuit Court of Appeals, which declined to halt their enforcement. EPA’s new cost analysis is largely based on its earlier one, with some supplementary material.
EPA last week increased its estimates of U.S. methane emissions, a change likely to figure in a battle over regulations the agency plans to issue on oil and gas drillers. The change, which increased 2013 emission estimates by 13%, were contained in an annual inventory the agency submitted to the U.N.
The agency said the new data show that the oil and gas sector is the largest source of methane, accounting for a third of U.S. emissions. The agency had said previously that cattle and other livestock were the largest source.
Methane has a much larger effect on global warming than carbon dioxide but dissipates more quickly than CO2.
Brenner Returns to FERC As Administrative Law Judge
FERC Chairman Norman Bay appointed veteran jurist Lawrence Brenner as senior administrative law judge.
The appointment marks Brenner’s second appointment as a FERC administrative law judge. He also served as an ALJ for the Department of Labor and the Nuclear Regulatory Commission. Additionally, Brenner has been a Maryland Public Service Commissioner since 2007.
Prior to his appointment, Brenner practiced law in Maryland, D.C. and New York. He earned a bachelor’s degree in economics from Brooklyn College and his doctorate from the State University of New York at Buffalo. Brenner also served in the Army in the Vietnam War.
EPA, the Department of the Interior and the Advisory Council on Historic Preservation want the U.S. Army Corps of Engineers to take a closer look at the Dakota Access pipeline plan.
The three federal agencies have asked the corps to perform another review of its spill contingency plans for the Energy Transfer Partners project. If constructed, the pipeline will stretch from North Dakota to terminals in Illinois. The corps has a role in the review process because of the pipeline’s multiple waterway crossings.
The pipeline received the final state regulatory approval from Iowa on April 8, but construction cannot begin before all federal approvals are obtained. There are also numerous legal challenges to the proposed pipeline, which could delay the start of construction.
Company Proposing Nuclear Waste Storage Facility in NM
Holtec International has filed a letter of intent with the Nuclear Regulatory Commission to build a $5 billion storage facility for nuclear waste near Carlsbad in Lea County, N.M. The company intends to build a long-term facility, with the idea that it would handle the waste while a permanent solution is found.
Holtec, a major supplier of stainless steel vessels used for dry-cask storage of nuclear waste, said its facility would store waste for up to 100 years, but it plans to initially apply for a license for 40 years.
If approved, it would give federal authorities time to come up with a longer-term solution for storing waste from commercial reactors. The government planned to use the Yucca Mountain repository in Nevada, but opposition led the Obama administration to pull the plug on that facility.
Former NRC Scientist Gets Prison for Hacking Attempt
A former Nuclear Regulatory Commission scientist was sentenced to 18 months in prison for attempting to infect the Department of Energy computer network with malware.
Prosecutors said Charles Harvey Eccleston, a disgruntled, ex-NRC employee, first tried to sell email information to a foreign country at its embassy in the Philippines.
He later met with undercover federal agents in a sting operation, agreeing to upload a virus onto government computers.
FERC has approved Williams Partners’ Transco Garden State Expansion Project, a series of compression improvements to an existing line aimed at boosting delivery in central New Jersey.
The $116 million New Jersey project will deliver an additional 180,000 dekatherms a day of natural gas to customers of New Jersey Natural Gas, which serves about 500,000 customers in Monmouth, Ocean, Morris, Middlesex, Sussex and Burlington counties.
Opponents complained that FERC’s action is another illustration of the agency’s willingness to side with pipeline operators.
TVA to Seek Early Permit for Small Modular Reactors
The Tennessee Valley Authority plans to apply for an early site permit for building small modular nuclear reactors on its Clinch River site, but federal design approval is expected to take a decade.
TVA’s application to the Nuclear Regulatory Commission will only evaluate the possibility of constructing an as-yet chosen design at its Clinch River site. It is starting the process with public meetings to discuss environmental and safety aspects.
The NRC review of the early site permit is expected to take three or more years. Design certification of a small modular reactor is expected to take up to five years, so a project could not realistically begin construction until the early 2020s.
Mass. Staffers Say Pipeline Co. Filed Misleading Documents
The Massachusetts Department of Environmental Protection staff accused Tennessee Gas Pipeline of filing misleading information to FERC in a bid to get permission to begin logging a pipeline right of way in a state forest.
The department says the Kinder Morgan subsidiary told FERC that Massachusetts officials wouldn’t require a water quality certificate before allowing logging operations in a bid to get approval for tree cutting in the Otis State Forest as part of a pipeline construction project.
Tennessee Gas officials mischaracterized statements from state authorities, the department said.
The U.S. Forest Service has granted developers of the Atlantic Coast Pipeline permission to survey new routes through the Monongahela and George Washington national forests. The agency previously rejected the planned route for the $5 billion, 500-mile project.
The agency is still requiring developer Dominion Resources to investigate alternate routes that don’t go through national forests. The Forest Service previously criticized surveys done by project contractors, suggesting the surveys were flawed and shouldn’t be used by FERC in determining approval.
US Nuclear Workers Allegedly Sold Information to China
An East Tennessee resident who worked as a senior manager in the Tennessee Valley Authority’s nuclear program is one of six Americans workers in the nuclear industry accused of selling information to China’s top nuclear power companies.
None of the workers was named in a federal espionage conspiracy indictment against China General Nuclear Power, Chinese nuclear engineer Szuhsiung “Allen” Ho and Ho’s firm, Energy Technology International. Ho allegedly conspired to solicit information that would allow his country to produce nuclear material based on American technology.
Aside from the Tennessee resident, whose gender was not specified, the Americans referenced in the indictment are engineers. Four work for an unnamed Pennsylvania-based nuclear energy firm, while the fifth works for a Colorado-based firm that supplies technical support to the nuclear industry.
The Court of Federal Claims has ordered the federal government to pay $76.8 million in damages to three New England nuclear plant operators for failing to create a permanent repository for spent nuclear fuel.
The ruling is the third time that the government has been ordered to pay Connecticut Yankee, Maine Yankee Atomic Power and Yankee Atomic Electric for costs they incurred for on-site storage of nuclear fuel at their decommissioned plants in Maine, Massachusetts and Connecticut. The companies sued in 1998, and the latest order covers costs incurred by the three companies from Jan. 1, 2009, to Dec. 31, 2012.
SANTA FE, N.M. — Only a few months away from revising its transmission planning process, SPP is continuing to work under the old Integrated Transmission Planning (ITP) format.
The Markets and Operations Policy Committee last week approved the scopes for the final studies to be conducted under the old rules. (See “MOPC Approves TWG, ESWG Recommendations” below.) Members then sat through the Transmission Planning Improvement Task Force’s joint education session for the MOPC and the Strategic Planning Committee, getting an early look at recommendations that will be made in July.
The task force, assigned to develop “progressive, forward-thinking, regional planning processes,” shared its current recommendations, which include:
Implementing an annual ITP planning cycle;
Using a standardized study scope;
Establishing common reliability planning models; and
Creating a staff/stakeholder accountability program by stressing timely data exchanges, reviews and approvals within the planning process.
“We want to treat this as a process improvement,” said NextEra Energy Transmission’s Brian Gedrich, the task force’s chair.
SPP currently conducts a 20-year assessment focused on a strategic economic study (ITP20) without issuing notices to construct (NTCs); a 10-year assessment that can issue NTCs for mostly 100-kV projects and above; and a near-term assessment aimed at reliability needs and maintaining long-term firm service over a five-year horizon.
Gedrich said the current process winds up creating too many models “that don’t necessarily line up with each other,” and that scope documents can be “a real problem.”
“We recreate a scope every time we start, and that can take a lot of time to get through the approval process,” he said. “What’s key to speeding up the process is [eliminating] slippage that has to be re-evaluated. Today, we basically have a three-year cycle. The [studies] are done sequentially in their own silos. We’ve found the three-year planning cycle to be too long … it can’t be responsive to changes.”
Gedrich said using a “holistic” planning approach and reducing the number of futures in new analyses to three would also speed up the process.
“We need to standardize the scope up front and not recreate the document every time,” he said. “The futures would be more incremental changes.”
The task force is recommending a transition to the new planning process in September 2017. The model builds and scope development would lead to the initial ITP assessment, to be completed in July 2019.
To keep up with the timeline, the current planning cycle will need to be completed and the necessary revisions to the new process would have to implemented. Those changes would include modifying the Tariff and other governing documents and securing the necessary tools and resources.
“The goal is results,” Gedrich said. “We don’t want to fail at the beginning. We want to be ready, so we don’t hit a glitch.”
The task force has a white paper out for review and comment. It will come back to the MOPC and Board of Directors in July for final approval.
MOPC Approves TWG, ESWG Recommendations
The MOPC accepted the Transmission Working Group’s 2017 near-term and 2017 10-year assessments, an assessment of the system’s compliance with NERC transmission planning (TPL) reliability standards, and re-evaluations of the 2016 near-term assessment and NTC evaluations.
The 2016 ITPNT identified 86 proposed upgrades comprising 49 projects and recommended 35 NTCs be issued. Fourteen additional NTCs are to be modified. The assessment will also result in eight NTCs being withdrawn, primarily because alternative projects were identified. The $140 million in withdrawn NTCs leaves the 2016 ITPNT with nearly $230 million in approved NTCs.
The recommended 2017 ITPNT scope will evaluate as potential violations NERC TPL-001-4 planning events that do not allow for nonconsequential load loss or curtailment of firm transmission service.
Stakeholders debated the scope’s use of NERC standards. Antoine Lucas, SPP’s planning director, said staff is seeking to incorporate the new TPL standard into the planning process rather than doing TPL assessments separately as in the past.
“This will be the last ITPNT as we know it,” American Electric Power’s Richard Ross said. “I don’t want staff [spending] a whole lot of time trying to fix problems with a process that’s about to be abandoned.”
The committee also approved the TWG’s recommendation to remove consideration of TPL-001-4 events not already considered in the 2017 ITP10’s original scope. The motion passed with 13 nay votes and five abstentions.
TWG Chair Travis Hyde, of Oklahoma Gas and Electric, said the group’s review of the TPL-001-4 standard revealed the 2017 ITP10 models did not meet SPP’s modeling requirements and that the assessment could not be used for compliance.
The committee also approved the Economic Studies Working Group’s updates to the 2017 ITP10 scope, which will result in using natural gas prices from the ABB reference case rather than NYMEX futures and updating language to allow for a Clean Power Plan and a reference case portfolio.
The ESWG must still complete needs assessments and develop solutions and a portfolio for the 2017 ITP10.
PJM last week asked FERC not to order changes to the RTO’s minimum offer price rule before May’s Base Residual Auction but agreed the standard should be changed to counter subsidized offers from existing generators. The RTO said revisions could be made for next year.
Davis Besse Nuclear Power Plant Source: Wikipedia
Eleven generating companies had asked FERC to expand the MOPR, which currently applies only to certain new resources (EL16-49).
The complaint was filed before the Public Utilities Commission of Ohio approved power purchase agreements for FirstEnergy and American Electric Power. PUCO unanimously approved modified versions of the PPAs, which the companies said are crucial to keeping underperforming members of their Ohio fleets running, on March 31 (14-1297-EL-SSO and 14-1693-EL-RDR). (See FERC Action Awaited Following PUCO OK on PPAs.)
In their complaint, the generators said they feared such agreements could lead to below-cost offers from existing resources that would suppress capacity clearing prices.
AEP and FirstEnergy told FERC last week that granting the complaint would lead to higher prices for consumers.
PJM: Don’t Rush Changes
In its answer, PJM said FERC should not rush to change the MOPR by next month.
“However, PJM agrees that under certain circumstances and given the existing PJM MOPR, sell offers in [Reliability Pricing Model] auctions submitted by existing generation capacity resources could result in unjust and unreasonable rates when such resources are subsidized by state-approved out-of-market payments,” the RTO said.
FERC could find the MOPR provisions to be “incomplete and unsustainable” and direct PJM to revise the rules in time for the May 2017 BRA, it said.
Delaying changes “would allow the commission to carefully and comprehensively identify the problem raised by complainants and allow an orderly process to consider alternatives through an open stakeholder process,” PJM said. The RTO suggested that FERC keep the issue open so that it could report back with results from its analyses.
“Such a ‘staging’ of this proceeding would provide stakeholders an inclusive role in formulating a rule having widespread application and send the appropriate signal that the issue requires further analysis and focus,” PJM said.
The RTO said that if the commission decides to take action before next month’s auction, it should consider two narrowly drawn, short-term alternatives: PJM could reject a sell offer that it believed would result in an unjust and unreasonable outcome, or FERC could order PJM to require a price floor for the PPA-related resources.
Higher Prices?
In its protest, AEP called the complaint “the latest in a continuing effort by various generators and marketers … to block AEP and FirstEnergy from implementing reasonable measures to benefit Ohio retail customers in a way that does not interfere with wholesale markets.”
There is no “emergency” requiring immediate FERC action, it said, calling “fanciful” the complainants’ notion that “the effect of the AEP PPA will be to dump thousands of megawatts of otherwise uneconomic generation into the upcoming capacity auction and materially suppress prices.”
On the contrary, it said, excluding 6,000 MW from the AEP and FirstEnergy PPA units “for no valid economic reason could cause a substantial unwarranted cost increase to consumers in the PJM region.”
It also said that because the complaint was filed before PUCO ruled, it doesn’t take into account the amendments the commission made to the company’s proposal.
FirstEnergy said the complaint was based on flawed assumptions.
“The complainants create a so-called market solution that is facially discriminatory and preferential and that would penalize and harm the retail customers of FirstEnergy and AEP while likely benefiting the complainants’ shareholders with increased market share,” the company said.
It, too, said there was no reason to address the issue before the May BRA.
The commission voluntarily agreed to reconsider the issue after 
The agency issued a formal notice amending the Mercury and Air Toxics Standards, saying that the costs of regulating emissions such as mercury, nickel and arsenic are reasonable and far outweighed by the public health benefits. EPA had issued a similar finding, but while the rules were being written. The Supreme Court ruled that the cost analysis should have been done before.
FERC Chairman Norman Bay appointed veteran jurist Lawrence Brenner as senior administrative law judge.
EPA, the Department of the Interior and the Advisory Council on Historic Preservation want the U.S. Army Corps of Engineers to take a closer look at the Dakota Access pipeline plan.
FERC has approved Williams Partners’ Transco Garden State Expansion Project, a series of compression improvements to an existing line aimed at boosting delivery in central New Jersey.
The Tennessee Valley Authority plans to apply for an early site permit for building small modular nuclear reactors on its Clinch River site, but federal design approval is expected to take a decade.
The Massachusetts Department of Environmental Protection staff accused Tennessee Gas Pipeline of filing misleading information to FERC in a bid to get permission to begin logging a pipeline right of way in a state forest.
The U.S. Forest Service has granted developers of the Atlantic Coast Pipeline permission to survey new routes through the Monongahela and George Washington national forests. The agency previously rejected the planned route for the $5 billion, 500-mile project.
An East Tennessee resident who worked as a senior manager in the Tennessee Valley Authority’s nuclear program is one of six Americans workers in the nuclear industry accused of selling information to China’s top nuclear power companies.
The Court of Federal Claims has ordered the federal government to pay $76.8 million in damages to three New England nuclear plant operators for failing to create a permanent repository for spent nuclear fuel.
