MISO closed its request for proposals on the Duff-Coleman 345-kV transmission project in Southern Indiana on July 6, saying it was pleased with the response.
Priti Patel, MISO North regional executive, said MISO was satisfied with the “robust” number of proposals on its first competitively bid project, but she didn’t disclose the number of proposals received or which developers submitted them. Patel said the RTO will post the list of developers that submitted complete proposals by Aug. 19. In the meantime, proposals are under review to determine their eligibility. Forty-eight developers qualified to submit bids to MISO.
“The broad interest from transmission developers demonstrates confidence in MISO’s competitive processes,” Patel said in a statement.
Per its original timeline, MISO expects to announce its transmission developer pick on the $67.4 million project by Dec. 30. The RFP window opened in January for the work, which includes the construction of two substations and a 28.5-mile line linking them. (See MISO Seeks Bids on Duff-Coleman Project.)
Berkshire Hathaway Energy is contesting FERC’s June decision to revoke the ability of the company’s subsidiaries to sell power at market-based rates in four neighboring balancing authority areas in the West.
The commission’s June 9 order prohibited Berkshire-owned utilities PacifiCorp and NV Energy — as well as 19 other affiliates — from offering power at market rates in the PacifiCorp East (PACE), PacifiCorp West (PACW), Idaho Power and NorthWestern areas based on concerns about horizontal market power. (See Berkshire Market-Based Rate Sales Restricted in 4 BAAs.)
In a request for rehearing and clarification filed July 11, Berkshire argued that the commission failed to make a “definitive finding” that the company possesses market power in the four regions before revoking market-based rate authority, as required under FERC Order 697 (ER10-2475).
“[The commission] did not provide sound reasoning, nor did it show a path to how it arrived at its decision,” the company said. “But, nonetheless, the commission moved ahead and revoked market-based rate authority and imposed cost-based rates.”
‘Moving Target’
Berkshire contended that it was denied due process after FERC failed to notify the company of the commission’s “newly announced standards for determining market power” ahead of the company’s initial “change in status” filing — standards it said the commission “articulated for the first time” in the June 9 ruling.
The company’s utilities “have repeatedly demonstrated their willingness to comply with any guidance that the commission has provided,” Berkshire said. “They should not be penalized for failing to hit a constantly moving target.”
Berkshire also sought clarification on whether its affiliates can use their own “case-specific” cost-based rates for sales in the four areas, or must rely on the commission’s default cost-based rates — requesting rehearing if it is the latter.
The June ruling stemmed from Berkshire’s 2013 acquisition of NV Energy, which put Warren Buffett’s conglomerate in control of 19 GW of generating capacity in the West — enough capacity to fail the “pivotal supplier” and “wholesale market share” indicative screens for market power in the four areas.
Delivered Price Test
Generation owners that fail the screens can disprove the presumption of market power by performing a more thorough delivered price test (DPT). The DPT factors in the native load commitments and generating capacity of all suppliers in a region in order to determine each supplier’s “available economic capacity” over 10 different seasons and load conditions.
The commission ruled that the DPT analysis submitted by the Berkshire companies was insufficient to rebut the presumption of market power, having failed to include “inputs, assumptions and facts appropriate to the unique characteristics of each balancing authority area when studying that particular area.”
The ruling pointed to an instance in which Berkshire’s analysis erroneously listed Idaho Power as a competing supplier during periods when that utility would “likely not” be positioned to provide competition.
Berkshire countered the finding that its tests were unreliable, saying that each of its 57 “unique” DPT analyses “was prepared in accordance with the commission’s previously announced requirements and each was similar in form and substance to” analyses the commission had previously approved.
FERC identified five alleged deficiencies in the tests, the company said.
“On that basis [the commission] concluded that ‘we are unable to validate the results of the [Berkshire companies’] DPT analysis and are unable to rely on the DPT analysis,’” Berkshire said.
Berkshire also questioned the commission’s use of its own “undisclosed analyses using alternative assumptions or data that yielded different results than those provided by” the company, saying that the commission failed to include the results of those analyses in the proceeding.
The company further contended that the “purported deficiencies” in the DPTs were the “sole basis” for the commission revoking market-based rate authority, rather than any alternative analyses or evidence submitted by intervenors or the commission itself.
“By its own admission, the commission’s decision was not ‘based on the results of the DPTs’ and does not purport to have made any finding based on the DPT results or any other substantial evidence that the [Berkshire companies] have market power in any of the mitigated markets,” the company said.
FERC on Wednesday directed staff to begin an investigation of alleged illegal tree-cutting along the New York section of the Constitution Pipeline route despite a finding that state officials’ demands for a stay and sanctions were “procedurally deficient” (CP13-499).
The order was in response to New York Attorney General Eric Schneiderman’s complaint in May that the pipeline’s developers allowed tree-cutting in defiance of a FERC prohibition in New York. Constitution denied the allegations and asked FERC to dismiss the complaint. (See Constitution Asks FERC to Dismiss New York Complaint.)
“While procedurally deficient as a complaint and petition, the May 13 filing may constitute a valid request for investigation,” FERC wrote. “Accordingly, the commission construes it as such and refers this matter to commission staff for further examination and inquiry as may be appropriate.”
Schneiderman alleged there is “a reasonable basis to conclude that Constitution expressly or tacitly authorized, encouraged and/or condoned the tree and vegetation cutting, clear-cutting and other ground disturbance activities” within the pipeline’s 99-mile right of way in New York. Tree cutting had been allowed by FERC in the approximately 25-mile section in Pennsylvania.
FERC said Schneiderman’s filing was deficient because it “does not include any specific facts to support such allegations, but instead relies upon speculation.”
The New York Department of Environmental Conservation in April denied a water quality permit, effectively stopping the project. Constitution has appealed in federal court. (See Constitution Pipeline Appeals Rejection of Water Permit.)
While ruling that the New York complaint was insufficient, FERC said that Constitution could “face potential sanctions” if it failed to comply with its regulations.
The pipeline, intended to bring Pennsylvania shale gas into New York and New England, is being developed by Williams Partners, Cabot Oil & Gas, Piedmont Natural Gas and WGL Holdings. It received FERC approval in December 2014.
ERCOT is soliciting must-run alternatives (MRAs) to the reliability-must-run agreement it recently extended to NRG Texas Power’s Greens Bayou Unit 5 in the Houston area.
The Texas grid operator issued a notice to market participants July 13, saying it is seeking “lower-cost, effective alternatives” to the RMR agreement, its first in five years.
ERCOT in June executed the agreement through September to strengthen transmission stability in the Houston region. Its Board of Directors later extended the RMR through June 2018. (See “Board Expands Greens Bayou RMR Contract to 2018,” ERCOT Board of Directors Briefs.)
Greens Bayou Source: NRG
Under the agreement’s terms, the 371-MW gas-powered unit must be available during summer months, between July 2016 through June 2018. ERCOT must pay $3,185/MWh year-round and an incentive factor of as much as 10% to reserve the unit’s capacity.
Qualified scheduling entities, representing generation and demand response resources, have until Aug. 24 to submit proposals. ERCOT says it will consider individual and aggregated options that provide reliability benefits comparable to the RMR unit, while providing cost savings.
ERCOT staff has said it expects that the $590 million Houston Import Project, scheduled to be completed by summer 2018, will help solve the area’s transmission concerns.
The ISO’s protocols authorize it to replace an RMR agreement with an MRA agreement if the MRA resource:
Provides an acceptable solution to the reliability concern the RMR unit currently addresses;
Provides at least $1 million in annual savings over the projected net annualized costs for the RMR unit; and
Satisfies objective financial criteria demonstrating that the MRA resource’s provider is reasonably able to fulfill its performance obligations.
Using internal records, private emails and recorded conversations provided by a whistle-blower, The New York Times published a lengthy investigation July 5 into the delays and costs overruns at Southern Co.’s Kemper coal-gasification plant.
The Times found that the plant’s owners understated its costs and repeatedly tried to conceal its multitude of problems. Southern is under investigation by the Securities and Exchange Commission, and the Occupational Safety and Health Administration told the company in March that it violated federal whistle-blower protections when it fired Brett Wingo, an engineer who was the Times’ primary source for the article.
In response, Southern released a statement the same day as the article’s publication, calling Wingo’s claims “unsubstantiated” and insisting that the newspaper took quotes from recordings out of context. “Rather than educate readers on the worldwide benefits of this cutting-edge, first-of-its-kind facility, today’s New York Times article on the Kemper project provides a negative recap of previously disclosed developments that have already been addressed,” the company said.
Ameren filed for a $206 million rate increase with Missouri regulators in early July, the seventh request for a rate review in a decade. A final determination is due at the end of May 2017.
The company says the increase equates to an average 7.8% rate boost for consumers. Missouri’s Office of Public Counsel says the increase is actually closer to 8.3% for residential customers, who will bear more of the cost burden than other customer classifications.
Warren Wood, Ameren Missouri’s vice president of external affairs and communication, said the increase serves to recoup some of the $1.4 billion in investments the company made since its $122 million rate increase two years ago. He also said the company is also coping with the bankruptcy of Noranda Aluminum smelter, its largest consumer.
Cube Hydro Partners said it will buy and upgrade four hydropower units along North Carolina’s Yadkin River from Alcoa Power Generating, a subsidiary of aluminum smelter Alcoa. The transaction, for an undisclosed sum, will add 215 MW to Cube’s current 126-MW portfolio.
Alcoa developed and operated the four hydro units along a 38-mile stretch of the Yadkin for nearly 100 years as part of its aluminum smelting operation at Badin Works. Alcoa closed the plant in 2010.
Cube, based in Bethesda, Md., currently owns and operates 14 hydro plants in New York, Pennsylvania, Virginia and West Virginia.
Duke Energy announced last week that it is providing North Carolina municipalities subsidies to help construct electric vehicle charging stations. The company said it would provide $1 million for EV charging stations and $500,000 for electric bus stations.
The company said that would increase by 30% the number of charging stations throughout the state, where it said there are currently about 700 stations operating and about 4,700 plug-in EVs registered.
“Over the past decade, Duke Energy has supported the development of several hundred electric vehicle charging stations in North Carolina,” said David Fountain, Duke’s North Carolina president. “Adoption of EVs depends on a robust infrastructure for consumers.”
The Indiana Utility Regulatory Commission has given final approval to Duke Energy’s proposed 17-MW solar farm on a naval base.
The 76,000-panel project will be situated on 145 acres at the Crane naval station in southwestern Indiana and begin selling power early next year. The project, the second solar installation partnership between Duke and the Navy, would be the second-largest solar plant in the state.
Duke Consolidates Renewable, Distributed Energy Divisions
Duke Energy consolidated its renewables and distributed energy businesses following the departure of 14-year veteran Greg Wolf, president of its Commercial Portfolio unit.
The Commercial Portfolio, which oversees Duke Energy Renewables, will be combined with its Distributed Energy Resources wing, now headed by Rob Caldwell.
Caldwell, an 18-year Duke veteran, will become president of the new division: Duke Energy Renewables and Distributed Energy Technology. Some functions of the old divisions will be pooled, while others will remain separate, according to the company.
Westar Shareholders Allege Execs Undervalued Company
A group of Westar Energy stockholders has filed a class action suit in Kansas alleging that executives undervalued the company in its $12.2 billion sale to Great Plains Energy in May.
Under the sale agreement, shareholders will get $60/share: $51 in cash and $9 worth of Great Plains stock. The plaintiffs, however, think that is too cheap. They say that Westar’s stock price rose 55% in the year before the sale, but the $60/share total offered shareholders is only a 13% increase.
“Westar stockholders, who stand to receive a portion of the merger consideration in Great Plains stock, will also be burdened with the onerous debt Great Plains will be taking on,” according to the lawsuit. “The proposed transaction will almost triple Great Plains’ debt.”
NextEra Subsidiary Begins Construction on Wind Farm
Kingman Wind Energy has signed a $26.4 million agreement with Kansas’ Kingman County to begin construction on a 200-MW wind farm later this year.
Kingman is a subsidiary of NextEra Energy Capital Holdings, and it has a 20-year contract to sell the power to Westar Energy. The agreement was signed late last month.
EDF Renewable Energy said last week it has sold half of its Slate Creek Wind Project in Kansas to a consortium led by Axium Infrastructure. EDF will continue to own the other half and provide part of the operations and maintenance.
The 150-MW project began operations in December. Its power is sold to Kansas City Power & Light on a 20-year, fixed-price power purchase agreement.
KCP&L Opens 1st Solar Plant, Producing 4,700 MWh Annually
Kansas City Power & Light last week opened its first commercial-scale solar power facility, capable of generating more than 4,700 MWh of energy annually. The 12-acre plant has 11,500 solar panels at KCP&L’s Greenwood Energy Center, south of Kansas City.
“Solar technology is constantly getting better and more efficient,” said Chuck Caisley, KCP&L’s vice president for marketing and public affairs. “We are investing in solar because of its relatively quick construction and our commitment to a sustainable future.”
Alstom Grid infringed on a patent for energy efficiency technology used in Dominion Resources’ “Edge” products, a federal jury found, awarding $489,000 to subsidiary Dominion Voltage.
The company uses the app in substations to stabilize and slightly reduce voltage in areas where smart meters are installed, resulting in lower electricity bills. The software is used by 12 U.S. utilities.
The ruling, out of the U.S. District Court for the Eastern District of Pennsylvania, said Alstom had willfully violated the patent and convinced one of its utility customers to use it.
Jersey Central Power & Light has finished the last phase of a $48 million transmission project to bolster reliability for customers in the New Jersey counties of Mercer, Middlesex and Monmouth.
The project involved constructing a new 8-mile, 115-kV transmission line and upgrading an existing 230-kV line along a 3.5-mile right of way.
The utility installed more than 200 new wood utility poles, five new steel monopoles and more than 174,000 feet of new wires. A new transformer and circuit breaker upgrades also were installed at the substation in Highstown.
KCP&L Files for 7.5% Rate Increase with Missouri PSC
Kansas City Power & Light has filed a 7.5% rate increase request with the Missouri Public Service Commission. If approved, the increase would go into effect in April 2017.
KCP&L said in a news release the request is “needed to recover money spent upgrading the company’s infrastructure, adding regional transmission lines and complying with environmental and cybersecurity mandates.” The average customer’s bill would increase by $9/month.
The increase will affect customers in the KCP&L Missouri service area, which encompasses the Kansas City area. KCP&L asked for an 8.2% rate increase in February for a different territory in Missouri previously served by Aquila before its 2008 acquisition.
The Hawaii Public Utilities Commission rejected NextEra Energy’s $4.3 billion takeover of Hawaiian Electric Industries, finding that the deal was not in the public interest.
The companies have elected not to challenge the decision in court, and NextEra will pay HEI $95 million in break-up fees.
The PUC said the companies failed to demonstrate benefits for Hawaii residents and a commitment to the state’s clean energy goals. The commission voted 2-0 to reject the deal. Commissioner Thomas Morak, recently appointed by Gov. David Ige to replace outgoing Commissioner Michael Champley, abstained from voting, but he said he supported the commission’s decision.
RAPID CITY, S.D. — More than five hours of presentations and stakeholder discussions over two days last week did little to resolve SPP’s albatross of Z2 credits, but they did potentially add more than four years to the crediting project’s timeline and increase the possibility that it will result in litigation.
Faced with an approximate bill of $848.8 million for 158 creditable transmission upgrade projects over the last 10 years (up from last summer’s staff estimate of $750 million), the Markets and Operations Policy Committee voted to give companies five years to pay off their Z2 bills, up from the 10 months approved by the Board of Directors in April. (See “Board Approves Z2 Level Payment Plan,” SPP Board of Directors Briefs.)
The board will take up the recommendation during its quarterly meeting next week. If approved, the change will require a filing at FERC.
The MOPC also rejected all five requests from the so-called Group B members — American Electric Power, the City of Chanute, Kan., Golden Spread Electric Cooperative, Kansas Electric Power Cooperative (KEPCO) and Westar Energy — to have their $42.6 million in charges allocated to the base plan and included in regional and zonal charges under SPP’s Tariff, rather than being directly assigned to the companies.
Still unclear is when the amounts owed and due become final, how to handle sponsoring customers who are no longer customers and what happens when companies go to state regulators to recover their costs.
Dogwood Energy’s Rob Janssen suggested members were flying blind and said they should take a “rational” look at their options before going to FERC.
“No one knows the real impact of voting to transfer funds when we don’t know what the funds are. We need more facts on the table,” he said. “I don’t know if everyone is lawyered up enough to understand the implications, but I strongly suggest everyone do so before the next board meeting.”
“I feel like now that the numbers are higher than some people expected, they want to change the rules of the game,” said Greg McAuley of Oklahoma Gas & Electric. “I don’t think that’s the right way to do business.”
“We’re likely headed to a complaint at FERC because of the magnitude of the [Z2] numbers,” SPP CEO Nick Brown told the Regional State Committee on Monday. “The last thing I want to do is spend an inordinate amount of time before an administrative law judge in D.C.”
The Group B waiver requests were deferred by the MOPC, the board and the Cost Allocation Working Group in June. At the same time, those groups approved the Group A waiver requests to allocate their $56.4 million in obligations to the base plan. (See SPP Z2 Project Faces Further Hurdles, Possible Delay.)
Group A members — AEP, Arkansas Electric Cooperative Corp., the Northeast Texas Electric Cooperative and the Oklahoma Municipal Power Authority — are point-to-point transmission customers with Z2 obligations whose waiver requests were endorsed by SPP staff. Group B members are transmission customers that SPP said didn’t qualify for waivers, and Group C are those who didn’t request waivers.
McAuley grew visibly irritated as the discussion over Z2 waivers wore on. The OG&E settlement zone’s base-plan funding obligation of $31.7 million dwarfs every other zone, except AEP’s $29.9 million, and the company is waiting to learn its customers’ point-to-point claw-backs and credits for sponsored projects.
“We have retail customers who have waited patiently to be paid. Now, all of a sudden, we’re being told, ‘No, it’s too much,’” McAuley said. “We voted on how we were going to deal with the issue. People had expectations, and now we’re going to change it again. Everyone’s been impacted by this one way or the other, but now it’s time to settle accounts.”
“I raised the issue before that we were putting the payment plan in before we knew the impacts,” said Bill Grant, whose Southwestern Public Service’s zone faces a $10.4 million obligation. “SPP has some ownership in this, because they said this wasn’t going to be a big amount. Now we have some numbers and they’re not small. I think a lot of the people in this room would vote differently now. It is a pretty substantial number to some zones, and to some zones, that’s a pretty substantial number to recover for our customers.”
Attachment Z2 of SPP’s Tariff details how sponsors that fund network upgrades can receive reimbursements through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrade. SPP has struggled for years to perform a proper accounting of the bills and credits and who owes what to whom.
AEP’s Richard Ross opened the second day of the MOPC discussion Wednesday by proposing the payment plan’s extension to five years.
Ross also proposed waiving all of Group B and Group C’s directly assigned upgrade costs, but that motion was rejected in a separate roll-call vote.
“You’re going to think I’m up to something, but the most important thing is that top line … spreading things out over five years,” Ross said, pointing to the language on the projector screen. “The second thing is, whatever we do, my customers will pay the same. I fear this will end up in FERC or the courts or somewhere. … I’m not interested in that.”
“If we can agree on this, I’d like to encourage we get behind this and have no further delays,” Grant said. “Let’s get this filed [at FERC], so we can have certainty around the issue. This has gone on way too long. It’s a concern for people who owe money, it’s a concern for people owed money. Our major concern is the impact to customers, and this five-year plan helps us address it.”
Staff assured members that interest on the debts would only apply to the initial balance and not accrue during the five-year payment plan. (Members can still choose to pay everything up front.) The revised payment plan cleared the MOPC with four votes in opposition and five abstentions.
The committee then rejected five individual waiver requests by either voice or roll-call votes. KEPCO argued unsuccessfully to have $6.1 million in revenue credits applied to the base plan, saying four service requests ranging between 7 MW and 25 MW should not have been aggregated together. As a result of the aggregation, KEPCO exceeded the Tariff’s resource-load ratio rule — limiting customers’ transmission service requests to 125% of their projected system-peak responsibility.
“If you apply the Tariff the way we interpret it, we don’t believe we exceeded our 125% limit,” KEPCO COO Les Evans said.
Midwest Energy’s Bill Dowling noted FERC distinguishes between discrimination and undue discrimination. “The Tariff discriminates between parties who are not similarly situated,” he said. “I consistently got the message from SPP [that] you can’t change something after the fact because you didn’t like the way it turned out. If we [grant the request], we’re sort of opening the door to other requests.”
KEPCO’s waiver request failed to come close to the 67% threshold, not even clearing 50% in positive votes. The four requests that followed — from AEP, Chanute, Golden Spread and Westar Energy — all met the same fate.
The rejections did not faze Westar’s John Olsen when his company’s time came up. Asked whether he wanted to proceed with a vote after having seen the previous results, Olsen sighed with resignation, “Oh, hell yes. Why not?”
“I continue to reflect on how can we do business this way based on what’s happened here this morning,” said McAuley, who opposed all five requests.
“We all have FERC attorneys. My suggestion is pay your FERC attorney and go to FERC and solve this,” OG&E’s Jake Langthorn told members. “If we want to come up with a fix to the Tariff, it’s going to take a lot more work than we can do this morning.”
FERC Ruling
The lawyers have already been active.
Ross’ proposal was made possible by FERC’s July 7 approval of an SPP request to waive the one-year limit for adjusting payment obligations and revenue distributions (ER16-1341). SPP’s request drew at least 18 protests or interventions.
FERC’s order also allowed transmission customers to request exemptions on safe-harbor cost limits.
“We note that it has been eight years since the commission accepted SPP’s Tariff provisions to implement revenue crediting. In the intervening years, SPP has experienced multiple delays in implementing the crediting Tariff provisions,” FERC said.
“Upgrade sponsors who have been negatively affected by SPP’s delay will finally, through this order, get the appropriate relief. We remind SPP of the need for transparency and timeliness when implementing commission-accepted Tariff provisions, especially in matters that so directly impact market participants and customers and are completely under the control of SPP.”
Project Progressing
The Z2 crediting project itself is progressing. The software system is partially complete and scheduled to deliver revenue crediting reports in September.
OG&E’s David Kays, chairman of the Regional Tariff Working Group, told the committee that staff has completed the historical calculations for long-term credit obligations for network service. He said base-plan funding adjustments and detailed settlements for historical data are still underway.
The final historical results are scheduled to be available for stakeholder review prior to the quarterly MOPC and board meetings in October, with the Z2 settlement invoices expected in early November.
“Everything seems to be trending along in a manner that is anticipated,” Kays said.
As the two-day conversation devolved into the minutia of the Z2 calculations, transmission-service and point-to-point requests, rate schedules, claw-backs and threshold limits, an exasperated Paul Malone of the Nebraska Public Power District almost threw his hands up in surrender.
“I need a program,” the MOPC vice chairman said. “I feel like I’m in a game of cricket, and I don’t know any of the rules.”
MOPC Chairman Noman Williams, of South Central MCN, was sympathetic.
“I want to thank everyone for wandering through the mud here,” he said as he closed the agenda item. “I guess it could have been done differently, but it had to be done.”
Utah lawmakers plan to draft a bill requiring PacifiCorp to gain legislative approval before joining an RTO based on an expanded CAISO.
Members of the Public Utilities, Energy, and Technology Interim Committee approved a motion to create the proposed law July 13 after listening to more than 90 minutes of testimony from power industry participants — most of whom were wary about the state’s participation in a regional integration effort driven by California.
Specific terms of the legislation were left unclear.
Utah sits squarely inside the PacifiCorp East (PACE) balancing authority area, which also extends into portions of Idaho and Wyoming. It is served by PacifiCorp’s Salt Lake City-based Rocky Mountain Power subsidiary.
The entire state of Utah is contained within the PacifiCorp East (PACE) balancing authority area, which the utility hopes will become part of an expanded CAISO.
“This potential issue is significant from both a policy perspective and a financial perspective,” said Thad LeVar, chair of the Utah Public Service Commission.
LeVar noted that PacifiCorp must go before his agency for a ruling once it makes a determination to join an expanded regional grid. The decision “shouldn’t fall solely to the regulatory arena without some guidance from the legislators in the state,” he said.
Governor Skeptical
Laura Nelson, director of Gov. Gary Herbert’s Office of Energy Development, said the office was skeptical about an RTO but still engaged in the process related to its development.
“Our consistent message has been that any participation in the [CAISO] must protect Utah’s long-term interest and authority over its power system,” Nelson said, citing the state’s role in protecting ratepayers, maintaining system reliability and choosing the generating resource mix.
Nelson told the committee that the state needs to perform an “exhaustive” study to determine if PacifiCorp’s membership is in the best interest of ratepayers. “Any recommendations about joining CAISO are not yet fully informed,” she said.
Ratepayer protections were foremost among the concerns of Michele Beck, director of the state’s Office of Consumer Services. While Beck acknowledged that there are technical benefits to participating in a more centrally operated grid, she questioned who would enjoy them.
“Do the benefits accrue to customers, or will they accrue to just select elements within the industry?” she said. “Are the benefits reasonably distributed across the footprint? Are the modeled benefits durable?”
She said that membership in an expanded CAISO should be conditioned on a demonstration that it has greater benefits than the Western Energy Imbalance Market, in which PacifiCorp currently participates.
“We’re struggling to document that all the benefits of the EIM that have been stated and have been published have been realized,” Nelson said.
Chris Parker, director of Utah’s Division of Public Utilities, said he was concerned about risks as well as benefits — namely the state’s risk in giving up control over its utilities to an RTO, whose backstop authority would be FERC.
Fear of California Dominance
Parker also cited the risk of an RTO being dominated by California interests, saying his agency would seek assurances that policy changes would require the unanimous support of participating states. He said CAISO’s latest RTO governance proposal — which would initially provide California with numerical voting superiority — was unacceptable. (See Governance Plan Fails to Dispel Western RTO Concerns.)
Rocky Mountain Power CEO Cindy Crane called the development of an independent governing structure a “threshold” issue for her company in its decision to participate in an expanded CAISO.
“What we are not doing is joining the California ISO,” Crane said. “We are working to transform an existing operating entity into something that could be a regional operating entity.”
Crane said the requirement that an RTO deliver “risk-balanced” net benefits to PacifiCorp customers in each of its six states was a second condition for the utility.
“If it’s not going to deliver benefits for our customers, there is no reason for us to advance,” she said, adding that regulators in each PacifiCorp state will have the authority to decide whether the utility joins.
Watching California’s Legislature
A few witnesses testifying before the committee said the fate of a Western RTO is now in the hands of California lawmakers, which are slated to begin considering legislation in August that would loosen the state’s authority over CAISO.
“We’re at the point where we’re waiting to see what the California legislature is willing to give up,” said Parker, referring to the concerns about California’s dominance in a governing structure. “If they’re willing to give up enough, then it may be worth it.”
Mary Beth Gentleman, a former co-chair of the energy practice at law firm Foley Hoag and current Hillary Clinton volunteer, said that the presumptive Democratic nominee for president would likely have coattails if elected, resulting in a switch to a Democratic-controlled U.S. Senate, but a takeover of the U.S. House appears far less likely. While there may be opportunities for bipartisan energy legislation, a continuation of the legislative stalemate may continue.
“I think the Clinton approach will be to avoid legislation, if at all possible, avoid anything that is fully dependent on both houses passing something. Instead, she would use other tools in the toolbox [such as agency actions and executive orders] to advance a clean energy agenda,” she said.
Republicans would likely maintain control of both houses of Congress if Donald Trump, the party’s presumptive nominee, is elected president, said David Tamasi, a senior vice president at Rasky Baerlein Strategic Communications. The Trump campaign eschews traditional staples such as position papers, detailed policy discussions and other documents that signal the legislation he might pursue.
But based on a speech Trump gave in North Dakota at the end of May that called for promoting domestic fossil fuel production and weakening EPA, “his energy policy is absolutely in lock-step with what the Congressional leadership has been pushing,” Tamasi said. “There’s absolutely no daylight on that between them.”
Natural gas pipelines are primarily under the jurisdiction of FERC, but important reviews of them — and of transmission lines like Northern Pass — occur under EPA’s National Environmental Policy Act, said John Moskal, senior adviser for energy policy and infrastructure in EPA Region 1, which comprises New England.
“We’ve been dealing mostly with gas pipeline projects, whereas 10 years ago it was all LNG import terminals,” he said. “Natural gas has been part of the picture here for a long, long time.”
Marc Nascarella, director of the Massachusetts Department of Public Health’s environmental toxicology program, said the state is unique in that 351 towns have health departments with input into power plant siting issues. And there are three components to every local review, he said.
“Environmental problems are extremely emotional. Environmental solutions are highly technical. … Environmental policy or environmental decisions are highly political. If there is a concern that this power plant is going to cause a health impact, and the political force gets the emotive response behind it, the science be damned,” he said.
This adds a layer of complexity to a project that may require modifications by the developer, he added.
A three-judge panel of the D.C. Circuit Court of Appeals upheld FERC Order 1000 after Oklahoma Gas & Electric and other utilities challenged the landmark rule’s elimination of incumbent transmission owners’ right of first refusal to develop transmission projects.
OG&E sued FERC in December 2014, arguing that when it agreed to join SPP, it gave up some transmission planning rights in return for the right of first refusal. The utility said FERC couldn’t meet a higher legal burden to negate that part of the membership agreement, which predated Order 1000.
The utility has not yet decided whether it will appeal the decision to the full court. SPP supported OG&E’s case, which was also joined by Southwestern Public Service, ITC Great Plains, Xcel Energy Services, Mid-Kansas Electric and Sunflower Electric Power.
The Department of Energy has failed to protect whistle-blowers at its nuclear plants from retaliation, a Government Accountability Office audit found.
The report said the department has issued only two violation notices in the past 20 years against contractors who created chilled work environments at nuclear sites. Employees who try to use the department’s whistle-blower protection program find it difficult to navigate without legal help, the report says.
The report was requested in 2014 by three Democratic senators in response to reports of retaliation against whistle-blowers at the Hanford nuclear reservation in Washington state. The audit broadened to the handling of 87 contractor employee complaints at 10 of the department’s largest nuclear facilities.
FERC Allows BG&E to Recover $1.2M from Scrapped MAPP
Baltimore Gas and Electric may recover nearly $1.2 million it spent on the Mid-Atlantic Power Pathway (MAPP) project, which was canceled by the PJM Board of Managers in 2012, under a settlement between the company and the Maryland Public Service commission that FERC approved earlier this month.
The MAPP involved a 230-mile 500-kV transmission line from Virginia to New Jersey intended to “relieve load deliverability criteria violations” expected to occur on the Delmarva Peninsula. In canceling the project, PJM said that its “reliability drivers no longer existed.”
FERC had granted BGE incentives effective May 29, 2009, allowing it to recover costs if the project were abandoned. The commission has previously approved settlements between others state regulators and utilities that had contributed to the project.
Entergy has asked the Nuclear Regulatory Commission for more time to meet post-Fukushima upgrade requirements at its Pilgrim Nuclear Power Station in Massachusetts, which is set to close by June 2019.
The company asked for a deadline of Dec. 31, 2019, in order to avoid making permanent modifications before the closure. Instead, it wants to use a FLEX strategy, so called because it uses portable equipment.
“The plant does have a limited operational timeframe going forward, but our mandate is to make sure that the public is going to be adequately protected,” NRC spokesman Neil Sheehan said.
FERC has approved an application to conduct a feasibility study for an 8-MW hydro facility outside of Richmond, Va., at the existing Bosher Dam on the James River. The proposed project would use the existing 12-foot-high dam and create a 1,000-acre impoundment area, with new intakes, a new tailrace and four 2-MW turbines, along with a new powerhouse and substation.
The Richmond Department of Public Works, along with the James River Association and others, questioned the need for the facility during the public comment period, but FERC said the feasibility study was necessary to determine the validity of any opposition concerns.
The project is being proposed by Energy Resources USA.
Two jointly proposed pipeline projects to move Marcellus and Utica shale gas in Ohio to the Midwest and Canada received a favorable draft environmental impact statement from FERC.
DTE Energy and Spectra Energy’s 260-mile Nexus Gas Transmission pipeline would move 1.5 Bcf/d. It is being developed along with the Texas Eastern Appalachian Lease project, which would expand Spectra subsidiary Texas Eastern Transmission’s system by 950,000 dekatherms/day to accommodate the new pipeline.
FERC noted some “adverse environmental impacts, but impacts would be reduced to less-than-significant levels” with mitigation efforts. Public comment is open until Aug. 29. The commission said the final EIS should be ready by Nov. 30.
The Department of Energy is providing $15 million for algae-based biofuel projects in California and Florida. The grants are aimed at furthering the commercialization of biofuels as a renewable, affordable fossil fuel replacement, it said.
Three companies and their research partners will receive the funds. Global Algae Innovations in California is working on cultivation and preprocessing technology to produce algal oil. MicroBio Engineering, also based in California, is researching wastewater treatment and carbon-dioxide mitigation to produce useable oils. Finally, Florida-based Algenol Biotech is working to devise ways to use cyanobacteria to produce algal oil.
House Passes Funding Bill For Interior Department, EPA
The House passed a $32.1 billion funding bill for the Interior Department and EPA, about $1 billion less than what the Obama administration requested, and a $64 million cut over current spending levels. The bill includes a number of riders intended to block EPA water, power plant and coal mining regulations.
“There is a great deal of concern over the number of regulatory actions being pursued by the EPA in the absence of legislation and without clear congressional direction,” Rep. Ken Cavert (R-Calif.) said. “For this reason, the bill includes a number of provisions to stop unnecessary and damaging regulatory overreach by the agency.”
The bill passed 231-196, with most Democrats opposing it. The White House has threatened to veto it.
Report: Green Energy Funding Down 23% from Last Year
A report by Bloomberg New Energy Finance shows that renewable energy funding has fallen 23% for the first six months of the year compared to last year. It said investments globally were about $116.4 billion for the first half of the year. Second-quarter investments were $61.5 billion, 12% higher than the first quarter, but still 32% lower than the $90 billion for the same period last year.
“It is now looking almost certain that the global investment total for this year will fail to match 2015’s runaway record,” Michael Liebreich, chairman of the advisory board at BNEF, said in a statement accompanying the report.
Unit 2 at the Donald C. Cook nuclear plant in Berrien County, Mich., returned to service last week after being shut down for six days because of a steam leak.
Plant spokesman Bill Schalk attributed the July 6 steam line rupture to “vibration-induced metal fatigue” of an expansion joint. He said the rupture also damaged the wall of the turbine building.
Vendors fabricated new parts for the line and repaired it. The plant came back online July 12. The Nuclear Regulatory Commission says it will analyze the plant crew’s response to the incident.
The first new U.S. nuclear plant to be built in two decades is closer to being deployed after the Tennessee Valley Authority last week completed a key performance test on the reactor.
The unit, which has been operating at 30% of its 1,150-MW capacity, was raised to 50% so operators could perform load rejection tests, in which power is rapidly lowered and raised to simulate a storm-induced loss of load or other accident.
“All of the tests went like clockwork,” a TVA spokesman said. The corporation expects to bring the Watts Bar Unit 2 to full power later this summer.
Preparing for next year’s termination of the Con Ed-PSEG “wheel,” PJM is using a three-pronged approach to coordinate stakeholder efforts through its Operating, Markets Implementation and Planning committees.
Each committee received updates last week on Consolidated Edison’s decision not to renew the agreement, under which NYISO moves 1,000 MW from upstate generators through Public Service Electric and Gas facilities in northern New Jersey to serve Con Ed load in New York City.
Con Ed said it would not renew the agreement, which began in the 1970s, after receiving a $680 million bill for two transmission upgrades in PSE&G territory — cost allocations that Con Ed complained were unreasonable. (See Con Ed-PSEG ‘Wheel’ Ending Next Spring.)
PJM and NYISO are determining new protocols for three interconnection facilities (Waldwick, Goethals and Farragut) that, as of next year, will no longer carry 1,000 MW from upstate New York, through PJM and back into NYISO.
PJM assigned Con Ed $629 million of the costs of PSE&G’s $1.2 billion Bergen-Linden Corridor upgrade to address a short-circuit problem; PSE&G was allocated $52 million. Con Ed was also assigned $51 million of PSE&G’s $100 million Sewaren storm-hardening project.
The transmission contract for the wheel expires May 1. Con Ed informed the grid operators that it found cheaper alternatives.
PJM and NYISO are collaborating on a replacement protocol that maintains reliability and is mutually beneficial to both grid operators. The protocol will adhere to FERC’s open access rules and support any existing market-to-market exchanges, PJM said. It will utilize existing infrastructure and won’t address merchant facilities, they said.
The Impact of PARs
Several stakeholders expressed concern that PJM’s goal of “free-flowing ties” would be hampered by the eight phase angle regulators (PARs) that currently govern the direction of flows on lines connecting the RTO with NYISO. There are one each on the A, B and C lines that flow 1,000 MW from PSE&G into New York, three just south of Waldwick on the J and K lines that flow the 1,000 MW into PSEG from upstate and two on the Branchburg-Ramapo 5018 line.
One of PARs on the 5018 line owned by Con Ed failed in June, and it was unclear whether NYISO and Con Ed plan to replace it. Participants asked if the PARs could be removed. “I worry about PJM calling balls and strikes on market optimization,” said Ed Tatum, vice president of transmission for American Municipal Power.
Several participants questioned why the PARs must be kept at all. Speaking after the meeting, Mike Bryson, PJM’s vice president of operations, explained that NYISO has always had a philosophy of using control devices to manage congestion and loop flow.
‘Insider Information’
Other participants expressed concern that the discussions between PJM, NYISO, PSEG and Con Ed haven’t been transparent. Dave Pratzon of GT Power Group, which represents some generators, asked for confirmation that the discussions haven’t included any “insider information.”
Bryson said PJM has ensured that conversations never overstepped the rules. “When we approach that line, we back the parties away,” he said.
Wheel’s New Look
PJM officials said further detail wouldn’t be available until August’s MIC meeting because of the timeline required to approve changes to the PJM-NYISO joint operating agreement. A broader picture wouldn’t be available until September.
Tim Horger, manager of market simulation at PJM, said the New York interface will likely be changed to model what’s “actually going to happen in real time.”
Both NYISO and PJM ran independent studies to determine interchange flows unconstrained by PARs — what they called “natural flow.” The studies were based on a summer peak case and found that 32% would flow over the western ties that connect between the “Twin Tiers” of Pennsylvania and New York, while 68% would interchange between the eastern ties involved with the wheel.
PJM engineer Asanga Perera said that part of the wheel’s benefit today is that the 1,000 MW coming into New York City from New Jersey pushes back on bottlenecks north of the city so it doesn’t see additional congestion.
Cost Allocation
With Con Ed out of the picture, the $680 million in upgrade costs will be reallocated to the existing stakeholders based on guidance in PJM’s manuals, officials said.
In response to a request from Tatum, PJM Vice President of Planning Steve Herling said he would look into providing a document answering frequently asked questions about the change and any public documents that governed the decision-making process.