FERC last week granted Northeast Transmission Development some incentives for its Artificial Island project but denied one adder and set its requested base return on equity for hearing and settlement procedures.
Salem Nuclear Generating Station on Artificial Island Source: Wikimedia
FERC denied in part NTD’s request for rate incentives, saying it had not provided adequate support for its proposed 50-basis-point “risks and challenges” adder (ER16-453).
But the commission accepted NTD’s request for a 50-basis-point adder for its participation in PJM. The commission also approved NTD’s hypothetical capital structure, recovery of deferred pre-commercial and corporation formation costs and abandoned plant recovery.
“The project will require a number of siting and permitting processes at multiple jurisdictional levels and may be canceled or modified through the PJM [Regional Transmission Expansion Plan] process,” FERC said. “The project also faces significant construction challenges regardless of whether NTD ultimately decides to construct an overhead or submarine line.”
FERC set for hearing NTD’s proposed base ROE of 10.5% in the face of protests from DMEC, which asked FERC to set a base ROE of 8.91%, and AMP, which called for a base of 8.88%. If a settlement is not reached, a trial-type evidentiary hearing will be held.
The formula rate and protocols will be accepted effective Feb. 16, subject to refund.
PJM planners are considering reconfiguring the project as a result of Public Service Electric and Gas’ $272 million cost estimate for its portion of the project — nearly double what PJM had estimated. That could alter the project’s scope enough to require it be rebid under FERC Order 1000. (See FERC Upholds Cost Allocation for Artificial Island, Bergen-Linden Projects.)
While MISO’s Market Subcommittee (MSC) will not be subject to a name change in light of the creation of the Resource Adequacy Subcommittee (RASC), it will have to revisit parts of its charter and management plan to reflect a division of market responsibilities, MISO’s Steering Committee decided last week.
Some stakeholders had suggested changing the name of the MSC to explicitly denote its focus on energy and ancillary markets, compared with the RASC’s emphasis on capacity markets. Most Steering Committee members shot down the suggestion in an April 27 meeting.
“In a selfish way, I would prefer not to add anymore words to the acronym,” American Electric Power’s Kent Feliks said.
“I don’t see a need to change it,” Manitoba Hydro’s Audrey Penner said. “Everyone has come to understand exactly what it means.”
The Steering Committee also examined the MSC’s charter and management plan to ensure the subcommittee’s oversight responsibilities avoid overlap with that of the RASC, recommending the MSC remove any references related to capacity markets.
Six Working Group and Subcommittee Charters Greenlit
The charter for the Loss of Load Expectation Working Group was also approved with the minor change that it report to the newly formed RASC instead of the Planning Advisory Committee.
The committee also approved the charter for the System Operator Training Working Group (SOTWG) despite stakeholder questions about whether the responsibilities of that group should be transformed into a MISO function.
MISO Grants 2 Data Requests, Denies Another
MISO will soon begin posting final five-minute real-time market clearing prices and historical five-minute real-time ex ante LMPs and market-clearing prices, according to Tom Welch, former liaison to the now-retired Data Transparency Working Group.
However, MISO declined a request to post all definitions contained in its monthly voltage and local reliability make-whole payments reports.
Welch said MISO cannot break down the report any further because individual components would reveal revenue sufficiency guarantee payments and make-whole payments for specific units, violating Tariff confidentiality provisions.
Welch also said MISO is reviewing a new request for reports that break down wind output by region.
With its effort to convert its Oncor transmission and distribution utility into a real estate investment trust (REIT) foundering, Energy Future Holdings filed a new bankruptcy plan Sunday.
The Chapter 11 reorganization plan, filed with the U.S. Bankruptcy Court for the District of Delaware, is the latest attempt by EFH to emerge from a $42 billion bankruptcy now two years old (14-bk-10979). The company asked for a confirmation hearing by Aug. 1; creditors are supposed to be able to vote on the deal by July 22.
Under the new plan, EFH said it still wants to spin off its Luminant generation and TXU Energy retail businesses to senior creditors. The difference this time is EFH would allow the creditors to take control of those assets without waiting for an Oncor deal.
The Wall Street Journal named Florida-based NextEra Energy, which has pursued Oncor since 2015 and intervened in Oncor’s docket with the Public Utility Commission of Texas (#45188), as a potential suitor.
Oncor, which delivers power to more than 3 million homes and businesses in North and West Texas, is estimated to be worth as much as $20 billion. Under the terms of EFH’s original bankruptcy filing, Oncor’s sale would have funded the exit plan.
But the PUCT’s order slapped numerous conditions on the proposed deal that made it less attractive to investors, including requiring federal tax savings be set aside for possible refunds to customers. The Hunt group’s proposed REIT structure would have allowed them to funnel as much as $250 million a year in tax savings to shareholders.
Sixteen Dallas business and political leaders, including Ross Perot, former U.S. Sen. Kay Bailey Hutchison and Roger Staubach, filed a letter with the PUCT last week asking the commission to reconsider its order.
EFH said in its Chapter 11 filing Sunday that because the PUCT’s order “did not include all of the approvals required for consummation” of the original plan, investors party to the Oncor spinoff elected not to extend an April 30 deadline that gave the Hunt group exclusive rights to the acquisition. The Hunt group responded by choosing not to put up $50 million to retain those rights for an additional 30 days, sending Oncor back to square one.
During a bankruptcy court hearing April 28, the Hunt group’s lead attorney said the PUCT’s conditions and IRS concerns about continued tax benefits from REITs had soured the deal.
Oncor declined to comment. In a statement, Hunt indicated it may still pursue its original plan, saying the “termination notice served earlier [Sunday] does not preclude our transaction. The new plan filed by EFH early this morning explicitly contemplates a potential REIT transaction under our current proceeding before the [PUCT].”
The Hunt group had asked the PUCT for a rehearing, which is still scheduled to take place Wednesday. EFH legal counsel said during the bankruptcy court hearing that an alternative plan under consideration would allow the pursuit of a REIT.
EFH was the result of a $48 billion leveraged buyout of TXU Corp. in 2007. Investors led by KKR and TPG Capital bet on rising energy prices; instead, they found themselves saddled with $42 billion in debt following the 2008 global financial crisis and plunging gas prices because of the fracking boom.
A U.S. bankruptcy judge in December approved EFH’s plan to split into two separate companies — Oncor and the unregulated power generation and retail arms, Luminant and TXU Energy, respectively — wiping out the buyout sponsors’ equity. The Luminant-TXU Energy businesses would go to senior lenders owed about $24 billion.
Ohio’s electric industry, which has been roiled for months by American Electric Powers’s and FirstEnergy’s requests for above-market power purchase agreements, shows no sign of calming down anytime soon.
Andre Porter Photo Credit: Kevin Graff (Ohio Citizen Action)
On Friday, Andre T. Porter, the chairman of the Public Utilities Commission of Ohio, announced his resignation, little more than a year after taking the position and less than a month after shepherding through the controversial PPAs.
The commission’s order prompted AEP CEO Nick Akins to threaten that the company may lobby Ohio legislators to reregulate the state’s power market, a position that FirstEnergy also has indicated it would support.
During an earnings call Thursday, Akins said that the company would rather sell all its generation or seek reregulation rather than submit its PPA for FERC review. The commission said that despite Ohio’s retail choice law, the companies’ ratepayers were essentially “captive” customers because the PPAs would impose on them non-bypassable distribution charges.
As a result, the commission said the PPAs would be reviewed under the Edgar test, which will require the companies to prove the lack of affiliate abuse by evidence of head-to-head competition or benchmarks such as prices that non-affiliated buyers are willing to pay. The PPAs were not subject to competition, and both Dynegy and Exelon have proposed deals that they say would save ratepayers billions. (See Next up in Ohio PPA Battle: Dynegy Weighs in.)
Opponents of the PPAs asked PUCO to reconsider its approval Monday, the deadline for responses to the orders. And in a surprise move, FirstEnergy asked PUCO to allow it to withdraw the PPA but keep a charge on customers’ bills that would provide essentially the same rate increases the PPA provided (14-1297-EL-SSO).
The surcharges would be based on estimated power production costs, not actual costs. If approved by PUCO, it would allow FirstEnergy to avoid FERC review.
“FirstEnergy’s latest gambit underscores that its bailout proposal has nothing to do with protecting customers or preserving Ohio generation, and everything to do with propping up corporate profits,” said Shannon Fisk, managing attorney at Earthjustice, a nonprofit law firm representing the Sierra Club.
Will Ohio Reregulate?
An angry Akins told stock analysts Thursday that AEP “will advocate for legislation in Ohio that would reregulate generation in the state or provide a mechanism for AEP Ohio to own and develop generation assets, including the plants included in the PPA and renewables.”
In FirstEnergy’s earnings call Wednesday, before the commission’s order, there was no mention of reregulation.
But CEO Chuck Jones told The Plain Dealer last year that he would end Ohio deregulation “in a heartbeat.” And in a Securities and Exchange Commission filing after the FERC order, the company said that it “will consider both short-term and long-term legislative and regulatory solutions in Ohio to preserve the benefits associated with the” PPA.
Former PUCO Chairman Todd Snitchler says reregulation is unlikely.
“Given how far down the road Ohio has already gone, it would be very difficult to put the proverbial toothpaste back in the tube,” said Snitchler, who is now spokesman for the Alliance for Energy Choice, a group formed to fight the PPAs.
“I believe there is no strong appetite in the legislature to move toward reregulation … now that they are seeing the outcome that the legislation intended,” he said. “And quite frankly, I think it very odd that a company such as AEP is now going to say, ‘I’m going to pick up the phone and get them to do my bidding.’”
A spokesman for Ohio House of Representatives Speaker Cliff Rosenberger told The Columbus Dispatch that “at this time, we are considering all options and are willing to have a discussion to ensure we make a decision that is best for Ohio’s future.”
State Sen. Bill Seitz (R-Cincinnati) told the Dispatch he wants an “all-hands-on-deck, high-level meeting” with the governor’s office and legislative leaders to determine next steps. “There is a limit to which we can prop them up,” he said, later adding, “I’m not saying it’s impossible. I’m saying it’s a very tall order of business.”
Akins said Thursday that legislators could choose a narrow reregulation that covers only a few power plants.
PUCO Chair Porter Leaving May 20
Porter announced he will leave PUCO effective May 20. “At this time, my wife and I have made the very difficult decision to pursue a new opportunity for our family back in the private sector,” he wrote in a letter to Gov. John Kasich.
Porter did not say where he was going, but rumors have been rippling through the utility industry that he has taken a position with an RTO.
At Thursday’s PJM Markets and Reliability Committee meeting, CFO Suzanne Daugherty addressed the rumors, saying Porter was not coming to PJM. Sources at the meeting told RTO Insider they believe Porter, an attorney, is headed to MISO.
MISO declined to comment Monday. Porter was not available for comment. PUCO spokeswoman Holly Karg said he has not indicated where he is going.
Before working at the state’s Commerce Department, Porter served as a commissioner from 2011 to 2013. His current term wasn’t scheduled to expire until April 2020.
“When I joined state government in 2011, I did so with the personal aspiration to be impactful within an allotted period of time,” Porter wrote in his letter. “At the PUCO, while working independently of the administration, I’ve led the commission in addressing some of the most challenging utility issues in recent history.”
Nominating Council
Replacing Porter won’t happen quickly, Snitchler said. A nominating council would have to come up with four names to submit to Kasich for consideration, a process that could take months. In the meantime, he said, the governor could name one of the sitting commissioners as acting chair.
In FirstEnergy’s earnings call Wednesday, Guggenheim Partners analyst Shahriar Pourezza asked about rumors of Porter’s resignation. “The timing is a little bit suspect and it’s a crucial period,” he said.
“I think Chairman Porter showed outstanding leadership during the time he was at the commission,” CEO Jones answered. Porter called Jones to inform him that he was leaving to pursue another job, the CEO said. “When job opportunities present themselves, you don’t get to pick the timing of them. So we had a good conversation, and I don’t think you should read anything into it other than what was said.”
The timing of Porter’s departure — and his arrival to the commission — was also noted in a report by UBS Securities analyst Julien Dumoulin-Smith. “We note he was effectively brought back into the role coincident with the start of the Ohio FE and AEP PPA process, and with its recent approval (and conclusion of the docket), his return to the commission appears closed,” he said.
Analysts ‘Struggling’
Jones told analysts the company would hold off on providing a second-quarter earnings guidance until FERC determined the PPA’s fate.
Analysts asked when the company expects FERC to make a decision, with Chief Legal Officer Vespoli predicting the commission will want to provide guidance before PJM’s Base Residual Auction in May.
Meanwhile, FirstEnergy Solutions President Donny Schneider acknowledged that two of the plants covered under the PPA — the W.H. Sammis coal-fired plant and the Davis-Besse nuclear plant — would be profitable even without the contract.
“Yes, for 2016, Sammis and Davis-Besse would definitely both have positive earnings-per-share impacts,” Schneider said in response to a question from Macquarie Research Equities analyst Angie Storozynski.
“We are all struggling, I think, with the impact of your PPAs on your bottom line, because we just don’t know what is the offsets from the current earnings power of these assets,” Storozynski said.
“I understand you are struggling with it,” Jones replied. “And believe me, as soon as we can give you clarification, we plan to do that. Once we have an answer from FERC, we will tell you what the value of this company is going forward with the” PPA.
FirstEnergy’s stock closed at $33.05 Monday, down 8% since FERC’s ruling. AEP was up 0.7% to $64.36.
Andre T. Porter, the chairman of the Public Utilities Commission of Ohio, submitted his resignation to Gov. John Kasich on Friday morning, little more than a year after taking the position and less than a month after shepherding through controversial power purchase agreements for FirstEnergy and AEP Ohio.
Photo Credit: Kevin Graff (Ohio Citizen Action)
“At this time, my wife and I have made the very difficult decision to pursue a new opportunity for our family back in the private sector,” he wrote to Kasich. “With mixed emotions, I must inform you that I will resign as PUCO commissioner effective as of the close of business on May 20, 2016.”
Porter did not say where he was going, but rumors have been rippling through the utility industry that he has taken a position with an RTO. At yesterday’s PJM Markets and Reliability Committee meeting, CFO Suzanne Daugherty addressed the rumors, saying Porter was not coming to PJM.
Stakeholders and PJM officials said privately they believe Porter is headed to MISO. Officials at MISO did not respond to requests for comment Friday morning.
Porter, an attorney, was not available for comment, according Holly Karg, director of public affairs for the commission. She said he has not indicated where he is going, and said he would not be issuing any further comments today.
“We very much appreciate Andre Porter’s distinguished record of public service as a member of the governor’s cabinet where he directed the Ohio Department of Commerce and — in an independent role — as commissioner and most recently chairman of the Public Utilities Commission,” said Joe Andrews, Kasich’s press secretary, in a prepared statement.
Before working at the state’s Commerce Department, Porter served as a commissioner from 2011 to 2013. His current term wasn’t scheduled to expire until April 2020.
“When I joined state government in 2011, I did so with the personal aspiration to be impactful within an allotted period of time,” Porter wrote in his letter. “At the PUCO, while working independently of the administration, I’ve led the commission in addressing some of the most challenging utility issues in recent history.”
FERC late Wednesday rescinded waivers it granted American Electric Power and FirstEnergy, meaning the controversial power purchase agreements approved by Ohio regulators will be subject to the commission’s affiliate abuse test.
The commission granted a request by the Electric Power Supply Association and others asking it to rescind the affiliate sales waivers it gave AEP in 2014 (EL16-33) and FirstEnergy in 2008 (EL16-34) based on Ohio’s retail choice law.
The commission said despite retail choice, the company’s ratepayers were essentially “captive” customers because the PPAs, approved by the Public Utilities Commission of Ohio on March 31, would impose on them non-bypassable distribution charges.
“These non-bypassable charges present the ‘potential for the inappropriate transfer of benefits from [captive] customers to the shareholders of the franchised public utility,’ and, thus, could undermine the goal of the commission’s affiliate restrictions,” FERC said.
As a result, the PPAs will be subject to FERC’s Edgar test, which will require the companies to prove the lack of affiliate abuse by evidence of head-to-head competition, or benchmarks such as prices that non-affiliated buyers are willing to pay.
That will be a difficult hurdle for the companies to clear, as the PPAs were not subject to competition, and critics say they could impose billions in extra costs on consumers.
FirstEnergy shares dropped 4.85% in after-hours trading. AEP shares were down 1.2%.
Lifeline
FirstEnergy and AEP have said the PPAs are crucial to keeping some of their underperforming coal-fired plants running in the state.
In approving the eight-year contracts, Ohio regulators said they were striving for “rate stability” by building in safeguards intended to protect consumers, modifying the plans to limit bill increases. The commission also added provisions meant to “encourage” grid modernization and retail competition. (See FERC Action Awaited Following PUCO OK on PPAs.)
Although the PPAs guarantee the generators receive revenue streams above current market prices, AEP and FirstEnergy contend the deals will save customers money if natural gas prices increase.
FirstEnergy spokesman Doug Colafella said the company was disappointed in the ruling. “Our affiliate FirstEnergy Solutions was previously granted authorization to conduct transactions with our Ohio utilities in 2008, and the PPA will benefit our customers by protecting them against rising retail prices and volatility in future years.
“We also believe that the PPA complies with existing FERC rules that promote retail shopping, and our Ohio customers will continue to have the ability to choose a competitive supplier. FirstEnergy is evaluating its options, which include seeking rehearing of FERC’s order, as well as filing the PPA for FERC’s review. It’s always been our position that the PPA will satisfy the FERC’s criteria for an affiliate contract.”
AEP: Reregulate Ohio
On an earnings call Thursday, AEP CEO Nick Akins said the company would lobby Ohio legislators to reregulate the power market — or sell all its generation — as a result of the FERC ruling.
“FERC’s decision to require review of the AEP Ohio power purchase agreement is a disappointing and unfortunate intrusion by FERC into Ohio’s ability to define its own long-term electricity supply and protect customers and the state economy from electricity price spikes and market volatility,” a clearly frustrated Akins said on the call.
“Although we believe the AEP Ohio power purchase agreement is the best long-term approach for our Ohio customers and the state and that it would survive FERC review, AEP is not interested in participating in a drawn-out FERC review process,” he said.
“We are focused on being a regulated utility company, so we will initiate a strategic review of the generation assets in the power purchase agreement, similar to the review already in place for our other competitive generation assets. At the same time, we also will advocate for legislation in Ohio that would reregulate generation in the state or provide a mechanism for AEP Ohio to own and develop generation assets, including the plants included in the PPA and renewables.”
EPSA Challenge
EPSA, the Retail Energy Supply Association, Dynegy, NRG Energy and GenOn Energy Management had asked FERC to rescind the waivers to ensure a Section 205 review of the eight-year PPAs. (See Dynegy, NRG Ask FERC to Void Ohio PPAs.)
In its companion orders, FERC agreed with the complainants that the affected customers are essentially captive. In addition, in the case of FirstEnergy, “the commission addressed the more general concern raised by a protester that FirstEnergy’s electric security plan proposal would create barriers to competition.”
The commission directed AEP and FirstEnergy to revise their market-based rate tariffs within 30 days and file notices of a change in status “addressing whether this change in circumstances affects any other waivers the commission previously granted.”
On Wednesday night, EPSA released a statement saying it was still reviewing the orders.
“Tonight, FERC issued orders (without dissent) granting the complaints EPSA, with support from a broad coalition of consumers, environmental groups and others, filed last January to remove the waivers protecting the controversial Ohio PPAs from full FERC review,” it said. “This means if AEP and FE elect to proceed with the wholesale contracts, they will need to file the PPAs … and show among other things that the deals they negotiated with themselves satisfy FERC’s rules designed to protect against such affiliate abuse.”
‘Effectively Captive’
FERC said its “fundamental goal in categorizing certain customers as ‘captive’ is to protect customers served by franchised public utilities from inappropriately subsidizing the market-regulated or non-utility affiliates of the franchised public utility or otherwise being financially harmed as a result of affiliate transactions and activities. … Where, as here, circumstances demonstrate that a retail customer has no choice but to pay the costs of an affiliate transaction, they effectively are captive with respect to the transaction.”
FERC did agree with AEP and FirstEnergy on one point, rejecting the complainants’ claim that the PPAs would distort prices in PJM by subsidizing the continued operation of generation that would otherwise retire.
The commission said that PJM bidding behavior was not relevant to the affiliate abuse complaint and thus outside the scope of the cases. However, the commission noted that a third complaint filed by Calpine over the PPAs, in which PJM rules are central, remains pending (EL16-49). The complainants asked FERC to expand PJM’s minimum offer price rule to ensure the PPAs don’t distort May’s 2019/20 Base Residual Auction.
FERC took note of the jurisdictional implications of its ruling, insisting in the AEP order that its ruling “does not frustrate or usurp the Ohio commission’s role in protecting retail customers. Rather, this commission has an independent role to ensure that wholesale sales of electric energy and capacity are just and reasonable and to protect against affiliate abuse. The commission’s affiliate restrictions protect against captive customers of franchised public utilities cross-subsidizing market-regulated power sales affiliates. The affiliate PPA raises the potential for cross-subsidization from AEP Ohio’s retail customers – who are captive in the sense that they cannot avoid the non-bypassable charge – to AEP Ohio’s market-regulated power sales affiliate, AEP Generation.”
The commission used virtually identical language in its FirstEnergy order.
Reaction
Former Pennsylvania Public Utility Commissioner John Hanger said the rulings “are obviously going to throw a huge monkey wrench in the FirstEnergy and AEP plans.”
Hanger, now a private energy industry attorney, predicted the company’s PPAs “will have a short shelf life.” He applauded FERC’s moves.
FERC, he said, “is not being swept by the powerful forces in state capitals. Electric utilities are the 800-pound gorillas” in state politics, he said.
Former PUCO chairman Todd Snitchler, now with The Alliance for Energy Choice, said Wednesday night he was “obviously pleased” with the rulings after taking a cursory review but wanted more time before commenting further.
“Today, federal regulators stood up for customers and defended fair markets and competition, sending a clear signal to any utility trying to bail out their uneconomic power plants through political prowess,” the Environmental Defense Fund said. “FERC’s decision to block these bailouts will save Ohioans $6 billion while spurring energy innovation and reducing harmful pollution.”
Ohio Consumers’ Counsel Bruce Weston also celebrated the order. “In response to legal action by the Consumers’ Counsel and others, federal officials today provided Ohioans the benefits of competitive markets and lower rates that they did not receive in the state plans filed by FirstEnergy and AEP,” Weston said. “The federal ruling has the potential to save each of several million Ohio electric consumers hundreds of dollars over the next eight years, while protecting the competitive market envisioned by the Ohio legislature in 1999.”
SANTA FE, N.M. — SPP awarded its first competitively bid transmission project under FERCOrder 1000 on Tuesday, but it may not be built because of declining load forecasts.
The RTO’s Board of Directors and Members Committee both voted to accept an industry expert panel’s (IEP) recommendation to award the 22.6-mile, 115-kV line from Walkemeyer to North Liberal in southwest Kansas to Mid-Kansas Electric.
The proposed Walkemeyer-North Liberal 115-kV line is in Seward County, in the southwest corner of Mid-Kansas Electric’s service territory.
Oklahoma Gas & Electric was selected as the alternative “designated transmission owner” should Mid-Kansas be unable to construct the project. Mid-Kansas and OG&E received the panel’s two highest scores among the 11 competitive proposals submitted to SPP.
Mid-Kansas CEO Stuart Lowry accepted congratulations from fellow members and gathered his employees in a group hug after the vote, before telling RTO Insider the company had proposed the project be re-evaluated. He later told members the Mid-Kansas and Sunflower Electric Power system has seen a 27% reduction in load forecasts within the project’s region.
Mid-Kansas is owned by five electric cooperatives members and a not-for-profit company, and managed and operated by Sunflower, a wholesale generation and transmission provider.
Mid-Kansas said the area has seen a drop in forecasted loads from oil and gas exploration. It also loses the auxiliary load of a nearby gas-powered generating plant when SPP doesn’t dispatch the plant. The load forecast that drove the need for the Walkemeyer project was conducted almost three years ago as part of SPP’s Integrated Transmission Planning 10-year assessment.
“I try to put myself in [the stakeholders’] shoes,” Lowry said. “This project is a reliability project, so it’s totally driven by load forecasts. We’re seeing a reduction in the region, so we made a decision we need to report on this. If the information is correct, we want to do what is best.”
Lowry said Mid-Kansas has contracted with Burns & McDonnell to provide an “independent set of eyes” on the need for the new line.
Mid-Kansas asked SPP last month to re-evaluate notices-to-construct it has already received for the two noncompetitive portions of the project, which include terminal upgrades at the existing North Liberal and Walkemeyer substations. The board granted staff’s request for an expedited review of the need for both NTCs, which were awarded last summer.
Paul Suskie, SPP’s executive vice president of regulatory policy and general counsel, said SPP members are free under the Tariff to request project re-evaluations at any time.
“The request to restudy this line is a part of our stakeholder process that occurs every year,” he said. “SPP will re-evaluate this line as we have others in the past.”
Mid-Kansas’ winning bid received an 892.85 score on a 1,000-point scale from the IEP, 13% higher than OG&E’s proposal, which scored a 785.67. The other nine bidders were not identified.
Mid-Kansas was one of only two bidders to win 100 incentive points for providing a “detailed project proposal,” but it would have won even without it, the IEP said.
The IEP’s scoring methodology graded each respondent on engineering design, experience in project management, construction and operations, a rate analysis (estimated total cost, including financing, FERC incentives and any cost certainty guarantees by the bidder) and finance (including financial viability and creditworthiness).
The panel said the Mid-Kansas proposal met all of its evaluation criteria, receiving 90% of the possible finance points and contained the second-lowest 40-year net present value.
“Our recommendation was built around what the entire panel felt would a successful project,” said the panel’s chair, Steve Strickland, who spent 35 years with Entergy Arkansas. “We defined that as a project that operated as intended, was on schedule and under budget.”
The Mid-Kansas and OG&E proposals were very close with their engineering and construction cost estimates ($8.33 million versus $8.44 million, respectively) and NPV estimates ($10.57 million versus $10.15 million).
“This represents a lot of hard work by our staff. A lot of the credit goes to them,” said Lowry, naming Mid-Kansas COO Kyle Nelson, CFO Davis Rooney and Al Tamimi, vice president of transmission planning and policy at Sunflower. “There was a lot of uncertainty over the process, how the proposals would be evaluated … everyone learned a great deal.”
Formed in 2005, Mid-Kansas serves a combined 200,000 members in western and central Kansas. Its assets include 843 MW of natural gas, coal and wind generation and about 1,140 miles of transmission. Sunflower adds another 655 MW of generation and 1,205 miles of transmission.
SPP stakeholders developed and FERC approved a transmission owner selection process to comply with Order 1000, which required the removal of federal rights of first refusal for certain transmission projects.
The process began in June 2014, when interested parties had 180 days to respond to the Walkemeyer project’s request for proposals. The IEP was established in November, and shortly thereafter it began its review and evaluation of the 11 responses.
[Editor’s Note: An earlier version of this article incorrectly stated the net present value of the Mid-Kansas and OGE proposals in billions rather than millions. It also incorrectly stated that the noncompetitive portion of the project included a switching station.]
MISO is recommending that Michigan Electric Transmission Co. (METC) construct a portion of a proposed transmission line intended to upgrade supply for Coldwater, Mich., while rejecting expedited review for a broader proposal.
The RTO is backing a portion of the proposed $65 million Coldwater load interconnection project that would provide the city an additional 18 MW of supply capability by 2017 via a 138-kV tap from an existing METC line. Parent company ITC Holdings sought expedited review of a larger project that would have included an additional 18 MW of capacity by 2021. (See “MISO Receives 1st Expedited Review Request,” MISO Planning Advisory Committee Briefs.)
MISO said it agreed with stakeholders at the Technical Study Task Force, which reviewed the project in March, that only the improvements necessary to manage Coldwater’s 2017 incremental load required expedited treatment. Less pressing work to meet the 2021 goal would be relegated to the MISO 2016 Transmission Expansion Plan.
Of Coldwater’s total load of 88 MW, 65 MW is currently supplied through a single 4.5-mile 138-kV transmission circuit, Thompson Adu, MISO senior manager of transmission expansion planning, told the Planning Advisory Committee last week. New industrial load is expected to push that total to more than 120 MW by 2026.
METC’s proposed radial supply line would carry 83 MW when completed, Adu said.
MISO Adds Tariff Provisions for Identical Market Participant-Funded Projects
MISO has revised its Tariff to comply with a December FERC order requiring a first-come, first-served selection procedure when more than one market participant proposes to fund the same transmission projects.
The process set out in the Tariff will mirror that already represented in a MISO business practices manual.
The issue was brought to light last year when Boston Energy Trading and Marketing and J. Aron & Co. both proposed to fund Ameren Illinois’ Effingham-Effingham NW 138-kV line in Illinois at an estimated cost of more than $1 million.
Boston Energy filed a complaint saying that MISO tried to force it to partner with J. Aron on the project based on language in a BPM but that it lacked Tariff authority to do so.
FERC sided with Boston Energy, saying MISO’s Tariff was unjust and unreasonable because it lacked provisions for processing market participant-funded transmission projects (EL15-89). The commission required new Tariff language that addresses how the RTO “will handle multiple, similar requests for market participant funding of a transmission upgrade.”
The Tariff revisions will mirror BPM language already vetted by the PAC. Adu said the new language will be filed with the commission by the June 20 compliance deadline.
MISO Order 1000 Compliance
MISO is nearing completion of its Order 1000 interregional compliance obligations, said Eric Thoms, the RTO’s manager of planning coordination and strategy.
FERC accepted MISO’s compliance filings with both SPP and Southeastern Regional Transmission Planning, while seeking clarification on cost allocation, interconnection projects and ownership rights in its joint filing with PJM (ER13-1944-001, et al.).
Meanwhile, MISO continues to pursue interregional efforts with its neighbors. At present, 14 projects near the MISO-SPP seam are being considered in MTEP16.
MISO and PJM have begun searching for “low-cost, quick-implementation upgrades” as part of their 2016 quick hits study process. Thoms said there was “value” in the quick hits studies, but the process needs to be formalized to reflect cost allocation.
“If we’re looking at low-hanging fruit … there’s no need for [multiple regional approval processes],” he said.
MISO and PJM have also completed two targeted studies from 2015 on the Michigan-Indiana and Quad Cities interfaces.
“We’ll continue to monitor this issue,” Thoms said.
FERC on Thursday cleared a backlog of disputes over MISO’s revenue sufficiency guarantee (RSG), issuing a quartet of orders in dockets dating back to 2009 concerning intermittent resources, headroom, cost allocation and resettlement procedures.
The commission:
Exempted intermittent resources from RSG charges when they respond to MISO curtailment orders (ER11-2275-003) but refused to rehear arguments that such resources should be exempt from RSG charges altogether (ER09-411- 005);
Upheld MISO’s continued use of a real-time headroom definition in its allocation of RSG charges (ER11-2275-002); and
Refused to rehear arguments about MISO’s RSG assessments on MISO customers making both virtual supply offers and electricity withdrawals (EL07-86-012, et al.).
Generation or demand response resources receive RSG payments if they are committed through the reliability assessment commitment (RAC) process after the close of the day-ahead markets and they receive insufficient real-time energy and operating reserve revenues to cover its production costs.
Intermittent Resources
FERC’s order exempting curtailed intermittent resources from RSG charges was made effective July 2, 2011, rather than the May 2011 date sought by renewable generators. E.ON Climate and Renewables North America and NextEra Energy Power Marketing protested the later date, saying it subjected them to extra months of revenue sufficiency guarantee charges for “no just reason.”
FERC ruled the extra 60 days were reasonable because MISO needed extra time to adjust its systems and procedures to incorporate the exemption.
In the second case, the commission reiterated a compliance order rejecting a request to exempt intermittent resources from all RSG charges.
The commission cited an “extensive record” documenting that “increases and decreases in the real-time output of intermittent resources, as well as the reduced forecasts or unavailability of such resources, may cause real-time revenue sufficiency guarantee costs.”
FERC said the rehearing requests from more than 15 companies only repeated arguments it previously rejected and that exempting intermittent resources from RSG charges “would unfairly shift costs to other market participants.”
The companies had claimed MISO’s Independent Market Monitor overstated intermittent resources’ contributions to the make-whole costs and a MISO analysis didn’t take into account several intermittent characteristics, including transmission de-rates, grandfathered transmission agreements, system topology and changes in loop flows.
FERC said that while it recognized changes between thermal and intermittent resources, the differences didn’t warrant an exemption.
Headroom Definition
In a third ruling, FERC upheld MISO’s definition of real-time headroom — the difference between the real-time economic maximum dispatch and real-time dispatch targets for resources — in its allocation of RSG charges.
Under methodology proposed by MISO and accepted by FERC in 2011, the headroom charge was calculated based on the lesser of headroom or the aggregate of the hourly economic maximum dispatch amounts of all resources committed in any RAC process. In the Thursday order, FERC clarified that the headroom definition isn’t limited to intra-day RAC commitments and includes commitments made in MISO’s forward RAC process.
MISO’s Transmission-Dependent Utilities sector had said MISO’s headroom cap should be eliminated or limited to include only headroom contributed by resources committed in the intra-day RAC. The commission said the forward reliability assessment commitment process is part of the real-time commitment process, and therefore should be included.
A group of six financial marketers said FERC headroom costs should be allocated to all market participants based on market load ratio, rather than assessed on virtual offers and deviations. FERC responded that headroom allocations are already based on market load share.
The order also upheld MISO’s allocation of exempted deviations, which were challenged by Westar Energy on the basis that too many costs are allocated to deviations than to load. FERC brushed the complaint aside. “As the commission has stated in previous revenue sufficiency guarantee charge proceedings, there is no such thing as an ideal and static proportion of costs that should be allocated to any activity. Rather, a reasonable allocation is one that reflects cost causation principles,” FERC said.
Virtual Offers
In the final order, FERC refused to rehear arguments about flaws in RSG proceedings first brought up nine years ago. In 2007, Ameren, Northern Indiana Public Service Co. and eight other utilities alleged discrimination in MISO’s RSG rate because it was assessed on only a subgroup of MISO customers making both virtual supply offers and electricity withdrawals. MISO was directed to modify its Tariff so the RSG applied to all cleared virtual supply offers. The RTO then began stakeholder discussions on refunds and resettlement for the period of Nov. 5, 2007, to Nov. 9, 2008.
Several companies requested rehearing on the matter. Tenaska Power Services wanted FERC to order MISO to issue refunds with interest. Seven financial marketers asked for MISO’s RSG to be recalculated by adding exempted deviations back into the formula. The bulk of the requests claimed that MISO didn’t hold any stakeholder meetings on the resettlement.
FERC refused all rehearing requests, saying the issues in the case were “strictly limited to the compliance requirements” and the companies’ requests were beyond the scope of the order. “The resettlement process undertaken by MISO, reflecting its interpretation of the MISO tariff with respect to exempted deviations, has been the subject of proceedings in docket no. ER04-691,” FERC noted.
FERC last week denied five requests for changes in PJM’s treatment of demand response, rebuffing filings by the Independent Market Monitor, DR providers, industrial customers and Public Service Enterprise Group.
The commission rejected an allegation by the Monitor that PJM doesn’t treat DR in a way comparable with generation capacity resources. The Monitor said it should be subject to a must-offer requirement in the day-ahead energy market as well as the energy offer cap (EL14-20). (See Monitor Asks FERC for Must-Offer on Demand Response.)
“The commission has … explained that comparability does not require that generation resources and demand response resources be subject to the same operational parameters in every circumstance,” FERC said.
Viridity Energy had filed a complaint that PJM’s compensation provisions are discriminatory to capacity-only resources because an end-use customer that registers with one curtailment service provider (CSP) for capacity and a second CSP for energy does not receive a guaranteed energy payment when called to reduce load in response to an emergency.
FERC cited reliability issues and the avoidance of double payments in denying the complaint (EL12-54).
The commission said the differences in compensation were justified by the need to avoid errors in measurement and verification by customers represented by two different CSPs from inadvertently or intentionally submitting duplicate offers for the same megawatts covering the same time period. “Duplicate offers, as PJM notes, could create reliability problems by erroneously indicating to PJM’s operators that they will be getting twice the demand reduction that is actually available during an emergency condition. As PJM further notes, market participants, in this circumstance, could be required to pay twice for the same reduction.”
EnergyConnect and Comverge were denied rehearing of a May 2014 order accepting rules increasing the operational flexibility of DR. FERC also found that PJM’s compliance filing satisfied the requirements of the May order (ER14-822).
The commission also denied a rehearing request from the PJM Industrial Customer Coalition regarding a January 2014 order that capped PJM’s procurement of certain limited-availability DR products. The order noted that PJM’s limited and extended summer DR products will be eliminated as a result of the new Capacity Performance rules (ER14-504).
Finally, FERC denied a rehearing request from PSEG that challenged a requirement that DR providers submit certain information before the Base Residual Auction proving their ability to perform when needed (ER13-2108). In part, the commission found that the general statement of obligation applies to all capacity resources and is not specific to DR.
Chairman Norman Bay said that the Supreme Court upholding FERC’s jurisdiction over DR has allowed the commission to begin clearing a backlog of DR cases. “There were a number of DR matters that could not be resolved until the Supreme Court issued its decision,” he said.
The RTO is backing a portion of the proposed $65 million Coldwater load interconnection project that would provide the city an additional 18 MW of supply capability by 2017 via a 138-kV tap from an existing METC line. Parent company ITC Holdings sought expedited review of a larger project that would have included an additional 18 MW of capacity by 2021. (See “MISO Receives 1st Expedited Review Request,” 