The Public Utility Commission of Texas asked ERCOT and SPP on Thursday to coordinate a joint study on Rayburn Country Electric Cooperative’s proposed transfer of most of its existing SPP transmission facilities and load into ERCOT (Docket 47342).
The East Texas co-op is an SPP member, but only about 150 MW (less than 20% of its load) and 160 miles of its transmission sit in the Eastern Interconnection. ERCOT estimates it will cost $38 million to connect the SPP load with the Texas grid.
Transmission lines | Berkshire Hathaway Energy
Commissioner Ken Anderson said it would be “helpful” if the two RTOs would “give all of us — SPP, ERCOT and the commission — reasonable comfort as to what the costs, benefits and challenges are, if any — and to do it as quickly as humanly possible.”
“We can do that,” said Warren Lasher, ERCOT director of system planning. SPP was not represented at the meeting, but both RTOs are expected to report back with a study scope at the Aug. 31 open meeting.
The grid operators have already produced a similar, much larger study on Lubbock Power & Light’s proposed transition of its 430-MW load from SPP to ERCOT. The study indicated the transition would cost them nearly $370 million. (See Load Migrations Put SPP’s Focus on Retention.)
2nd Price Formation Workshop Scheduled
The PUC has scheduled a second staff-led workshop for Oct. 13 on price formation issues in the ERCOT market to pick up where the discussion left off earlier this month (Docket No. 47199). (See ERCOT, Regulators Discuss Need for Pricing Rule Changes.)
Stakeholders have been invited to submit alternate proposals and additional analysis in response to a report commissioned by independent power producers NRG Energy and Calpine, which asserts “a need for adjustments” to the market’s pricing rules. The report, “Priorities for the Evolution of an Energy-Only Electricity Market Design in ERCOT,” was the primary topic during the Aug. 10 workshop.
Staff on Friday filed a timeline for submitting comments, proposals and analyses. ERCOT’s Independent Market Monitor will file a paper fleshing out its proposal to address reliability-must-run issues with a local reserve product by Sept. 15; the ISO’s staff will submit a second filing on real-time co-optimization and scarcity pricing by Sept. 29.
Commission staff will then present a revised request for stakeholder comment during the PUC’s Oct. 26 open meeting.
The commission agreed a second workshop would allow them to be more specific in addressing the recommendations and studies. They also plan to conduct their own workshop at a date to be determined.
“We could … give participants a stronger reference point of what we’re working on, so their comments can be more targeted,” Commissioner Brandy Marty Marquez said.
“While I enjoy workshops as much as anybody, I don’t want this to devolve in an endless series,” Anderson said. “It would be my hope the October workshop will include any and all ideas and the reports that come in by the end of September.”
MISO officials last week presented three proposals related to the implementation of the RTO’s new generator interconnection queue for stakeholder feedback.
The proposals — dealing with retaining interconnection rights, changing dispatch modeling and updating a study coordination agreement — are part of MISO’s effort to implement new interconnection rules approved by FERC in January (ER17-156). The new queue is intended to streamline a process that was plagued by restudies and backlogs. Last month, several stakeholders asked that some implementation details be fleshed out in discussions involving either the Planning Subcommittee or Planning Advisory Committee. (See MISO, Stakeholders Differ on New Queue Plan.)
But planning manager Neil Shah told the PAC on Wednesday that MISO will immediately change the queue’s dispatch modeling to match its annual Transmission Expansion Plan. Before, generators in the queue were modeled based on their expected level of output; now they will be modeled based on their maximum requested interconnection service level. Stakeholders attending last month’s Interconnection Process Task Force had said the decision should not be made without soliciting stakeholder input during MISO planning committee meetings. (See MISO Adopts New Dispatch Model for Queue Studies.)
Shah said MISO sees a need for consistency between the MTEP dispatch modeling, which is used for baseline reliability studies, and the interconnection process.
Retaining Interconnection Rights
MISO is offering more flexibility on retention of interconnection rights. It is recommending that owners of retiring generation be allotted three years of continuing interconnection rights for replacement generation to begin commercial operations. However, some stakeholders said six years is a more realistic time period to allow generation to be built.
On Wednesday, stakeholders indicated that they would like MISO to allow for generator replacement instead of making owners of retiring generation re-enter the interconnection queue with their replacement plans. The RTO is considering executing a commercial agreement and conducting an out-of-cycle study with “reasonable study deposits” for such replacement scenarios.
Indianapolis Power and Light’s Lin Franks said MISO should check in with replacing generators to see what progress is being made before terminating rights at the end of an inflexible three-year deadline.
“Interconnection rights are not scarce in this footprint,” said Franks during an Aug. 15 Interconnection Process Task Force (IPTF) meeting. “If the rights are not scarce in the footprint ― and they’re not here ― it doesn’t make sense to put a definitive deadline on the project when they’re working through it.” She said although three years should usually be sufficient, she warned against the three-year deadline becoming an “unrealistic barrier to progress.”
“We still propose three years, but if at the end of the of that three-year period, the construction is still in progress, [MISO could allow] a three-year extension for commercial operations,” Shah said. He said MISO will consider the comments and bring back new queue implementation proposals in a few months.
Hwikwon Ham of the Minnesota Public Utilities Commission also pointed out that obtaining state approvals for generation construction can take time.
MISO will also allow generators to retain interconnection rights under an amended interconnection agreement when an owner upgrades equipment when it does not have a material impact on the grid.
New Study Coordination Agreement
MISO is also updating a coordination agreement with Manitoba Hydro and Minnkota Power Cooperative to improve the efficiency of generator interconnection studies under the revised queue. The agreement will be brought before the PAC in September.
Shah also repeated warnings about delays while MISO studies an unprecedented influx of queue projects under the definitive planning phase of the queue.
“It’s not set in stone. The timeline may change based on what we encounter,” Shah said.
Meanwhile, IPTF Chair Randy Oye said MISO PAC leadership is considering extending the life of the task force beyond its December sunset date, an extension approved by Steering Committee members late last month. If the IPTF is not extended beyond December, the IPTF and Steering Committee may have to assign unfinished queue issues to other MISO committees.
VALLEY FORGE, Pa. — After nearly a year of discussion on potential changes to PJM’s capacity model, stakeholders have begun determining what components a new construct should have.
At another two-day meeting of the Capacity Construct/Public Policy Senior Task Force (CCPPSTF) last week, stakeholders began developing the criteria on which the nine construct proposals will be compared. It was a year ago that American Municipal Power and likeminded stakeholders pushed for a “holistic” review of the RTO’s Reliability Pricing Model. (See Co-ops, Munis Call for Reset of PJM Capacity Model.)
PJM’s Murty Bhavaraju presented a model that RTO staff created to compare results for each of the proposals. The model currently only includes the five repricing proposals but will eventually address the other four, PJM’s Dave Anders said.
The model uses fictitious data in its comparisons, and Adrien Ford of Old Dominion Electric Cooperative asked if PJM could substitute data from recent Base Residual Auctions to give stakeholders a better indication of the real-world implications.
Staff balked.
“I think we probably need to explore what that would look like,” Anders said. “I think to make the step between this modeling and taking a prior BRA, there’s going to have to be a lot more assumptions.”
“I am worried that the results of that will be taken as price forecasts,” PJM’s Adam Keech said.
“If there’s concern about using the past, then what can we use?” Ford asked. “We also recognize that the supply stack in the examples isn’t anything like the actual supply stack. I seek to understand if we do have an issue here and, if so, how big it is.”
Ruth Ann Price of the Delaware Division of the Public Advocate asked PJM to identify if any proposals would discourage states from allowing resources within their borders to participate in the markets.
Susan Bruce, representing the PJM Industrial Customer Coalition, asked the RTO and its Independent Market Monitor to also report on how they believe the proposals would affect bidding behavior. “It would be helpful for us to understand what those concerns would be,” she said.
PJM staff agreed to research potential solutions that address stakeholder concerns.
MOPR Issues
Attorney Mike Borgatti of Gabel Associates explained the standards FERC set out in its 1991 Edgar Electric Energy (ER91-243) and 2004 Allegheny Energy Supply rulings (ER04-730) to prevent utilities from self-dealing. The Edgar ruling required demonstration that long-term power purchase agreements that utilities sign with their marketing affiliates are reasonably priced compared to alternatives. The commission said such a demonstration could include evidence of competition between affiliated and unaffiliated suppliers or a showing of prices paid by non-affiliated buyers. FERC refined its guidance in Allegheny.
Borgatti said he brought up the rulings to propose a “conceptual framework” for considering changes to the minimum offer price rule (MOPR).
“If we were to go this route, that would need to be something we spend a lot of time on,” he said.
John Hyatt of Monitoring Analytics, PJM’s Independent Market Monitor unit, said he believed that state sponsored competitive and non-discriminatory procurements are consistent with the IMM’s MOPR-Ex capacity proposal.
Roy Shanker, an industry consultant, expressed concern about using the rulings as guidance in this situation.
“Edgar certainly stands for the proposition of assuring there was not affiliate favoritism,” Shanker said. “It’s completely unacceptable to apply it without a thorough discussion of what nondiscriminatory means.”
PJM staff agreed to review the current MOPR policies to determine if they should be revised.
Fixed Resource Requirement
PJM provided a refresher on its current fixed resource requirement (FRR) rules. FRR contrasts with RPM in that it can be used by a load-serving entity to meet a fixed capacity requirement, while RPM is variable. FRR resources don’t receive RPM clearing prices and the LSE doesn’t pay the RPM locational reliability charge.
The education came in response to a proposal from Dayton Power and Light’s John Horstmann that would allow LSEs to choose acquisition from FRR, RPM or any combination of the two to address their capacity requirements. Horstmann acknowledged that his proposal has many factors that would have to be addressed, but argued that it also resolves many issues stakeholders have identified.
“I’d say look at the things you don’t have to worry about, including two-tiered auction design compromises, creation of a reference price, and auction participant bidding concerns,” he said.
Social Science Experiment
The nine proposals fall into three categories: Some completely redesign the capacity construct; some add to the RPM a repricing mechanism to avoid subsidized offers influencing clearing prices; and the last group would expand the MOPR to effectively prohibit subsidized units from offering into auctions.
In what he called a “social science experiment for stakeholders,” Anders split meeting attendees into three groups and directed each of them to identify the positive and negative aspects of one of the categories and develop potential questions for a poll of stakeholder interests.
Stakeholders found that the MOPR was straightforward and easy to understand, but that it could be subjective and fails to accommodate state policy actions. The task force’s charter called for developing RPM rule changes “that could accommodate/address both capacity construct objectives and state actions.”
The redesign proposals would give load and resources more flexibility in decision-making but could increase market volatility if enough buyers and sellers opt out. The repricing options all attempt to address price influence from subsidies but could incentivize undesirable behavior, such as bid suppression or additional pursuit of subsidies, stakeholders said.
Next Steps
The task force’s next meeting is scheduled for Wednesday, when Anders said stakeholders should be prepared to provide input on identifying the traits of an offer that would trigger repricing.
AMP’s Steve Liebermann said he plans to have revisions to discuss for his organization’s proposal — which focuses on encouraging long-term bilateral contracts — based on feedback he’s received.
“States with retail choice might have some difficulties with the bilateral-contract concept,” he said. “We think we have a workable solution.”
Other sponsors have already offered revisions or addendums to their proposals, including LS Power and Exelon. Both focus on repricing.
Jennifer Chen of the Natural Resources Defense Council promised some revisions as well. The NRDC’s proposal focuses on including seasonal resources that can’t meet Capacity Performance’s requirement to be always available.
FERC last week denied NRG Curtailment Solutions’ request for an exemption from NYISO penalties for nonperformance and invalid generator registrations on approximately 13% of its New York capacity obligations in May 2016 (ER17-834).
NRG argued that uncertainty about EPA emissions regulations compromised its ability as a Special Case Resource (SCR) to help the New York grid operator balance shortfalls in delivered capacity contracts.
SCRs are demand-side resources that agree to reduce load at the ISO’s instruction, using either curtailments or “local” generators — ones intended to self-supply a load and that do not supply the distribution system. As a “responsible interface party,” NRG Curtailment aggregates individual SCRs for the ISO.
An EPA rule change in 2013 allowed reciprocating internal combustion engines (RICE) providing emergency DR to run without extra emissions controls for up to 100 hours per year in emergency demand response programs, up from the previous limit of 15 hours annually. In 2015, the D.C. Circuit. Court of Appeals vacated and remanded the 100-hour exemption. (See Appellate Court Rejects EPA Rule on Back-Up Generators.) EPA was granted a stay of the D.C. Circuit’s decision until May 1, 2016.
On April 15, 2016, EPA issued guidance that RICE generators may not operate for any period of time unless they meet emission standards for nonemergency engines. On May 2, 2016, the D.C. Circuit issued a mandate implementing its earlier decision.
NRG said it only enrolled generators in the May 2016 installed capacity auction that would participate for 15 hours or less because it believed that the 15-hour rule would be reinstated with the elimination of the 100-hour rule. The company said it had no ability to withdraw resources that no longer complied with the revised emissions rule but that it stopped selling capacity from DR resources with noncompliant generators for the June 2016 auction.
Increasing Emissions Stringency
NYISO opposed NRG’s waiver request in a filing in February, arguing that EPA’s intent to apply more stringent emissions requirements was apparent beginning in July 2015, contrary to the company’s contentions. The ISO said EPA’s motion to stay indicated that the agency clearly intended not to revert to its 15-hour limit.
While NRG may not have intended to enroll ineligible resources, NYISO said, if the company was unsure, it could have waited until EPA had clarified its position. The ISO believes that NRG assumed the risk of noncompliance and therefore should be subject to the penalty provisions of its Tariff.
NYISO said that while it had not yet determined whether penalties were “appropriate” for NRG’s capacity sales for May 2016, “sales by invalidly enrolled SCRs would be subject to a penalty.” In addition, an aggregator can be penalized when its unforced capacity sales exceed the greatest quantity megawatt reduction achieved during a single hour in a performance test or event called by the ISO.
FERC ruled that granting the waiver “would have undesirable consequences, as it would effectively serve only to relieve NRG of the financial consequences of its market commitments … and could encourage similarly risky bidding behavior that market participants seek to remedy after the fact through a waiver.”
Stepping in where others have failed, San Diego’s Sempra Energy on Monday announced a $9.45 billion cash deal to acquire bankrupt Energy Future Holdings and its 80% interest in Texas utility Oncor.
Sempra’s move short-circuited a looming battle between Berkshire Hathaway Energy and hedge fund Elliott Management, the largest holder of EFH bonds, which had opposed as too low BHE’s $9 billion all-cash offer in July. Elliott said it was working on a competing bid totaling $9.3 billion. (See PUCT Staff Welcomes Buffett’s Oncor Bid; Debtor Miffed.)
Elliott spokesperson Michael O’Looney said the investment fund is “supportive” of Sempra’s proposed transaction, “which provides substantially greater recoveries to all creditors of Energy Future than the proposed Berkshire transaction.”
Including debt, BHE’s bid valued Oncor at $18 billion, while Sempra’s values the utility at $18.8 billion.
Sempra CEO Debra Reed said the acquisition will “enhance our earnings beginning in 2018 and further expand our regulated earnings base, while serving as a platform for future growth in the Texas energy market and U.S. Gulf Coast region.”
Debt and Equity
The company said it expects to fund the transaction using a combination of its own debt and equity, third-party equity, and $3 billion of expected investment-grade debt at the reorganized EFH. Sempra will hold about a 60% equity ownership of EFH and projects the transaction to be completed in the first half of 2018.
BHE, which had said last week it would not increase its $9 billion all-cash offer for Oncor, announced Monday that EFH had terminated its proposed acquisition. Warren Buffet’s company is renowned for its fiscal discipline and avoids bidding wars.
The Nebraska-based company is eligible for a $270 million breakup fee, but it would have to be approved by the court overseeing EFH’s bankruptcy case in Wilmington, Del.
On late Friday, Berkshire said it had reached a settlement agreement resolving “all issues” with Public Utility Commission of Texas staff, the Texas Office of Public Utility Counsel, the Steering Committee of Cities Served by Oncor, Texas Industrial Energy Consumers and International Brotherhood of Electrical Workers Local 69.
Oncor CEO Bob Shapard praised Sempra as a “well-respected and experienced utility operator with a quality workforce and management team.”
“The announcement today is just another example of how our 3,900 employees have made Oncor one of the most sought-after companies in the energy sector today.”
At a previously scheduled bankruptcy court hearing Monday, EFH creditors expressed their support for the Sempra deal. Judge Christopher Sontchi set a Sept. 6 date for an expedited hearing on Sempra’s merger agreement. The deadline for filing objections is Aug. 31.
“This is a big change, clearly a change to the benefit of the estate and the creditors,” said Sontchi, thanking the parties for “freeing up his day.” The judge had scheduled up to eight hours of testimony and arguments on Elliott Management’s opposition to the Berkshire offer.
Oncor is the sixth largest transmission and distribution utility in the nation, serving more than 10 million Texans through more than 122,000 miles of wires and 3.4 million meters. It has been the subject of a tug-of-war since parent EFH, saddled with almost $50 billion in debt after poor bets on energy prices, declared bankruptcy in April 2014.
Dallas’ Hunt Consolidated and Florida-based NextEra Energy had separate bids fall apart in the face of the Texas PUC’s strict ring-fencing measures and demands that Oncor be run by a “truly independent” board with control over decisions on capital expenditures and operating expenses. (See NextEra-Oncor Deal Meets Third Denial.)
PUC Concerns
Although it was rejected by Elliott Management, Berkshire’s offer was received positively by PUC staff.
During the PUC’s open meeting Thursday, Commissioner Ken Anderson restated his insistence that Oncor be protected from incurring any additional debt from EFH’s bankruptcy proceeding. Anderson’s focus is on the billions in debt owed by Oncor stemming from the 2007 leveraged buyout of EFH’s predecessor, TXU.
That debt “was all incurred either in connection with the original [leveraged buyout] or refinancing the 2007 leveraged buyout,” Anderson said. “None of it ever was, nor can it be, an obligation, directly or indirectly, or legally implied of Oncor. None of either the principal or interest can go into rates.”
Anderson alleged that the suitors before BHE intended to use Oncor’s profits to pay off what he viewed as “imprudently incurred debt” by the utility’s holding company.
“The continued existence of any material amount of debt above Oncor will be a concern,” Anderson said. “One of the most important aspects is the cash flow generated out of Oncor must be protected. It needs to be available to Oncor’s management and to Oncor’s board to put it back into the business.”
The debt “is not Oncor’s problem. It is the problem of the commission now, but when the dust settles, I don’t want it to be the problem of either this commission or future commissions.”
Sempra has committed to support Oncor’s plan to invest $7.5 billion of capital over a five-year period to expand and reinforce its existing system.
New CEO
When the transaction is completed, Shapard will become executive chairman of the utility’s board of directors. Allen Nye, currently the utility’s general counsel, will succeed Shapard as CEO. Both have been asked to serve on the board, which will consist of 13 directors, including seven independent directors from Texas, two from existing equity holders and two from the new Sempra-led holding company.
The transaction is subject to customary closing conditions, including the approval of the PUC, FERC, the bankruptcy court and antitrust regulators at the U.S. Justice Department.
“It is important for Oncor to remain financially strong,” Sempra’s Reed said. “Our proposal will help bring a satisfactory resolution to Energy Future’s bankruptcy case, keep Oncor financially strong and protect Oncor customers, while addressing the needs of Texas regulators, creditors and the U.S. bankruptcy court.”
The deal would allow Sempra to regain a foothold in Texas, where it once owned and operated 10 power plants and currently maintains a 200-person office in Houston to support marketing and development activities. A Fortune 500 corporation that includes San Diego Gas & Electric and Southern California Gas, Sempra had 2016 revenues of more than $10 billion.
Sempra’s announcement was not a complete surprise. Word began leaking out last week that a mystery bidder had emerged to take on BHE’s offer. During a bankruptcy hearing Friday, legal counsel for Elliott identified the new competitor for Oncor as “a large investment-grade utility.”
Elliott’s representative also told the court that EFH was considering pursuing talks with the new competitor. EFH’s board met Friday and Sunday before accepting Sempra’s offer.
FERC last week approved GridLiance West’s acquisition of Valley Electric Association’s 230-kV transmission network in a deal valued at about $200 million (EC17-49).
The commission also granted GridLiance’s request for incentive rate treatment for operating the network. And while FERC accepted the company’s formula rate template for filing, those rates will be subject to a further evidentiary hearing before a settlement judge to determine the reasonableness of proposed rate inputs, return on equity and income tax allowance (ER17-706).
The decision to approve the transaction came despite objections from some CAISO members who contended that the transaction would result in increased in costs to ISO stakeholders.
GridLiance will be taking over 164 miles of 230-kV lines linking Valley Electric’s base in Pahrump, Nev., with both Las Vegas and the Mead substation — a major delivery point for power wheeled into California — as well as substations along the length of the system. The sale will earn Valley Electric 2.4 times its investment in the system, which significantly increased in value when the cooperative joined the ISO in 2013.
In a filing with FERC, GridLiance said that incorporating its revenue requirement into CAISO’s High Voltage Access Charge will increase that charge by about 0.48%, or $10.8 million. The company attributed the rate bump to the differing business structures of Valley Electric, which is a nonprofit rural electric cooperative, and GridLiance, a for-profit startup that will incur greater costs for overhead, administrative costs and taxes.
GridLiance argued that the increased cost would be offset by the benefit of having the transmission network of a well-funded transmission company that would add competition to the CAISO market and be focused on expansion and enhancement of the ISO transmission system.
The Transmission Agency of Northern California (TANC) contended that, although GridLiance had promised not to recover through rates any acquisition premium paid for the Valley Electric network, the $10.8 million increase in the ISO’s transmission revenue requirement (TRR) constituted such a premium. TANC noted that the increase represented a near doubling of the TRR for the network — without GridLiance having incurred any costs for improvements or modifications. The agency also argued that the transaction would not result in any “quantifiable or non-quantifiable” benefits that would offset the increased costs.
GridLiance West’s acquisition of Valley Electric Association’s 230-kV will provide the company with strategic access to the CAISO market. | Valley Electric Association
Southern California Edison (SCE) contended that the initial revenue requirement included in GridLiance’s proposed formula rate may be “unjust and unreasonable” and possibly included “improper and unsubstantiated costs and expenses.” SCE argued that the commission could not decide about the acquisition without fully vetting the impact of GridLiance’s formula rate filing.
The “Six Cities” utilities of Anaheim, Azusa, Banning, Colton, Pasadena and Riverside raised many of the same concerns, asking why the revenue requirement for the transmission facilities will increase just because of a transfer of ownership.
FERC came down firmly on the side of GridLiance, saying the 0.48% increase in the access charge was “not unexpected” given the company’s capital structure, tax obligations and “need to earn a return.” The commission also determined that GridLiance had presented evidence that increased costs would result in offsetting benefits.
“GridLiance West represents that it intends to develop needed upgrades and important transmission projects that will improve system reliability and increase transmission capacity to meet growing demand for renewable resources, including, and in particular, exports out of the Valley Electric area,” the commission said.
Valley Electric said that it would be unable to perform those necessary upgrades in a timely manner.
“Due to its singular focus on developing and owning transmission facilities, GridLiance West will not face the difficult decisions Valley Electric has faced in allocating its limited financial resources among the various infrastructure development needs within its service territory,” the commission said.
FERC last week granted Grand River Dam Authority’s (GRDA) request for a permanent 2-foot increase in the reservoir level of the 105-MW Pensacola Project in northeastern Oklahoma, despite opposition from a nearby Native American tribe (Project Nos. 1494-437, 1494-441).
The Miami Tribe charged that FERC had not lived up to its obligations under Section 106 of the National Historic Preservation Act, which requires federal agencies to conduct a review to determine how a proposed project may affect historic properties and to seek ways to avoid, minimize or mitigate any “adverse effects.”
Overhead of Pensacola Dam complex including auxiliary spillways | courtesy of the U.S. Geological Survey
The tribe asserted the commission never engaged in a Section 106 review with respect to tribal cultural properties in and around the hydropower project, which includes a 5,950-foot-long, 147-foot-high dam and the 46,500-acre Grand Lake reservoir. The review would have included gathering information from tribes, identifying historic properties of relevance to the tribes and assessing the effects that the project has already had on historic tribal properties.
FERC disagreed, saying the Miami Tribe relied on assertions made by Oklahoma agencies “that have since been revised,” and pointed out that the state agencies did not object to the commission’s finding that the reservoir-level change would not affect historic properties.
| Grand River Dam Authority
GRDA, an SPP member, last year requested maintaining the reservoir level at the dam on the Grand River at 743 feet between Aug. 16 and Sept. 15, 2 feet above current levels. It also requested a 742-foot level between Sept. 16 and Oct. 31, 1 foot above current levels. The company proposed returning to the project’s existing surface elevation or “rule curve” for the remainder of the calendar year.
The project’s dedicated flood storage is listed at 745 to 755 feet. When reservoir levels are within the flood pool, the U.S. Army Corp of Engineers can direct releases from the dam.
FERC last week rejected a CAISO proposal to extend the life of a program designed to protect some renewable energy resources from being assessed uplift costs associated with their variable output (ER17-1337).
The ISO established the Participating Intermittent Resource Program (PIRP) in 2014 as part of enhancements to its real-time market under FERC Order 764. PIRP provided older variable energy resources (VERs) a three-year transition period in which to acquire the capability to respond to dispatch instructions, during which they would avoid being assessed for startup costs for conventional generation needed to respond to uninstructed, intermittent output.
The program also accommodated renewable resources that needed additional time to renegotiate long-term power purchase agreements that expressly prohibited them from responding to real-time price signals.
CAISO earlier this year proposed to extend PIRP for an additional year until Apr. 30, 2018, contending that several resources operating under the program required more time for the transition. The ISO contended that the nine resources using the program had received a net benefit of $5.6 million between 2014 and 2016, an amount that was not expected to increase significantly with a one-year extension. The cost of extending the measure would continue to be allocated across all ISO scheduling coordinators.
In denying the extension, FERC said that “CAISO has not argued that the three-year transition period was an unreasonable time frame, or that circumstances have changed since the commission originally accepted” PIRP. The commission also noted that extending the program would expose market participants to additional uplift charges for another year while not guaranteeing that the protected resources would resolve their challenges during that time.
“Further, CAISO does not assert and the record does not indicate that allowing the protective measures to expire on April 30, 2017, would pose a risk to reliability, or that the relevant VERs would suffer significant financial losses as a result of their expiration,” the commission said.
The commission also agreed with Pacific Gas and Electric that allowing PIRP to remain in place would not give the relevant resources an “economic incentive” to respond to CAISO dispatch signals.
“CAISO itself has highlighted the need for resources to respond more quickly to CAISO dispatch instructions to curtail generation during oversupply conditions,” the commission said.
Calpine announced Friday it has agreed to be acquired by Energy Capital Partners and other investors for $5.6 billion in cash, or $15.25/share, a 51% premium to Calpine’s share price when news of a potential deal became public in May, and a 13% bump from Thursday’s close.
Energy Capital Partners, a private investment firm, is being joined by a group of investors led by the Canada Pension Plan Investment Board, which said it will invest $750 million, and Access Industries, a privately held company with investments in a wide variety of industries and companies, including Warner Music Group, Houston-based oil and natural gas producer EP Energy, and Russia-based aluminum manufacturer UC RUSAL.
The investors will be purchasing Calpine’s 26-GW fleet of 80 power plants in operation or under construction, the largest fleet of natural gas generators in the U.S. Its assets are concentrated in California (5,500 MW of natural gas and 725 MW of geothermal); Texas (13 combined cycle plants totaling 9,000 MW) and the East (31 plants totaling 9,400 MW in 14 states and Canada, most of them in PJM and ISO-NE).
In addition to its generation assets, Calpine also has two retail businesses — Calpine Energy Solutions and Champion Energy — which operate in 25 states, Canada and Mexico.
| M.J. Bradley & Associates (2017); “Benchmarking Air Emissions of the 100 Largest Electric Power Producers in the United States”
M.J. Bradley & Associates ranked Calpine as the nation’s 10th largest power producer in 2015. Calpine claims to be the top-ranked generator in gas-fired capacity in Texas, with a No. 2 ranking in California and No. 3 rankings in the Mid-Atlantic and New England states.
Undervalued
During a call to discuss second-quarter results before the deal was announced, CEO Thad Hill explained the rationale for going private, saying “the public equity markets have undervalued our business and underappreciated our strong track record of executing on our financial commitments and our stable cash flows.”
Hill, who became COO in 2010 was promoted to CEO in 2014, said the acquisition will not change the company’s operations. The company will maintain its headquarters in Houston and its current management team, he said.
The sale will allow the company to “continue to strengthen our wholesale power generation footprint, while benefiting from ECP’s support, industry expertise and long-term investment horizon,” Hill said in a statement.
| Calpine
ECP partner Tyler Reeder confirmed that the deal would not result in operational changes, saying that the investors “see significant value in Calpine’s operational excellence and strong and stable cash flows, and have been impressed by the company’s exceptional leadership and talented employees.”
“We do not intend to make any changes to the company’s financial policy or previously announced $2.7 billion deleveraging plan,” he added, referring to plans to pay off the debt in full by 2019.
Including debt, The Wall Street Journal reported, the deal’s enterprise value is $17 billion.
The deal allows Calpine a 45-day “go-shop” period to seek a higher offer. The company would have to pay the ECP group a $142 million termination fee for canceling the deal. The fee would be reduced to $65 million if Calpine terminates the agreement within 106 days.
“We don’t think it is likely there is a topping bid,” Greg Gordon, an analyst at Evercore ISI, wrote in a research note, according to Bloomberg. “It was probably very hard to pull together an equity consortium for this size of a deal and it was a competitive process.”
The acquisition is subject to approval by Calpine stockholders, antitrust regulators, FERC and state regulators, including those in New York and Texas, the company said. Closing is targeted for the first quarter of 2018.
Seesaw Ride for Investors
York Energy Center | Calpine
Founded in 1984, Calpine went public in 1996 and grew steadily over the next several years before falling into bankruptcy in 2005. It moved its headquarters from California to Houston after exiting bankruptcy in 2008.
Like other independent power producers, Calpine has been pinched by low power prices and competition from renewables.
NRG Energy, which lost $626 million last quarter, is planning to sell as much as $4 billion of its assets, and last month it ordered an undisclosed number of layoffs. Dynegy, which lost $296 million in the second quarter, is reportedly considering an acquisition by Vistra Energy. (See Report: Vistra Energy Suggests Takeover of Dynegy.)
Calpine’s 2016 profit of $92 million was a 60% drop from 2015. It reported a second-quarter loss of $216 million after losing $56 million in the first quarter. Rising gas prices have resulted in reduced capacity factors for the company’s non-peaker plants, falling to an average of 43.6% in the first six months of the year from 48.8% a year earlier.
After peaking at almost $25/share in late 2014, Calpine’s share prices fell as low as $10 in April before news of a potential deal. Shares closed Friday at $14.92.
Energy Capital’s Plans
Based on its history, ECP may not keep Calpine for very long.
In 2015, it sold EquiPower — a company it created five years earlier to oversee a portfolio of fossil generators in the eastern U.S. — to Dynegy. In 2008, two years after acquiring it, ECP sold FirstLight Power Resources, a 1,440-MW portfolio of mostly hydro generation, to a subsidiary of GDF SUEZ, now ENGIE.
The firm also helped Dynegy finance its $3.3 billion acquisition of 17 U.S. power plants, selling its stake to Dynegy last year for $750 million. The company was Dynegy’s largest stakeholder as of June, according to Bloomberg.
ECP’s current holdings include Wheelabrator Technologies, which generates power from municipal solid waste and other renewable waste fuels.
FERC last week asked for additional comments on the rule it proposed in November that all newly interconnecting generators provide primary frequency response.
The Notice of Proposed Rulemaking, which reflected both reliability concerns and the technological advances of renewable generators, proposed revising the pro forma Large Generator Interconnection Agreement (LGIA) and Small Generator Interconnection Agreement (SGIA). (See FERC Proposes Frequency Response Requirements for Renewables.)
On Friday, the commission issued a notice requesting supplemental comments on electric storage and small generators (RM16-6).
The commission said it was prompted by the Energy Storage Association (ESA) and other commenters who said that the NOPR failed to address storage’s “unique technical attributes” and could discriminate against them.
ESA said that the proposed use of nameplate capacity as the basis for primary frequency response service and the fact that electric storage resources can operate at the full range of their capacity — without a minimum set point — would require them to provide a “greater magnitude of [primary frequency response] service than traditional generating facilities.”
“In light of these concerns, the commission seeks additional information to better understand the performance characteristics and limitations of electric storage resources, possible ramifications of the proposed primary frequency response requirements on electric storage resources, and what changes, if any, are needed to address the issues raised by ESA and others,” the commission said.
FERC also asked for more information on commenters’ concerns that small generating facilities could face disproportionate costs in providing frequency response.
Commenters including the Sierra Club, the Sustainable FERC Project and the National Rural Electric Cooperative Association said that the NOPR failed to prove the commission’s conclusion that “small generating facilities are capable of installing and enabling governors at low cost in a manner comparable to large generating facilities.”
Comments will be due 21 days after publication of the notice in the Federal Register.
