Entergy said Wednesday it may sell its troubled James A. FitzPatrick nuclear plant to Exelon if New York approves the proposed Clean Energy Standard, which would provide large subsidies to nuclear stations.
If New York cannot agree on those subsidies, Entergy said, it will go forward with its plans to cease operations by January.
“In keeping with our corporate strategy to move away from merchant power markets and toward a company operating exclusively as a utility in regulated markets, we are working with Exelon to come to commercial terms on a sale transaction that depends largely on the final terms and timeliness of the New York State Clean Energy Standard,” Entergy Wholesale Commodities President Bill Mohl said. “We thank New York Gov. Andrew Cuomo for his leadership in promoting the Clean Energy Standard.”
Cuomo called the possible sale “welcome news.”
“My administration has been working closely with both companies to find a way to keep this vital energy resource operating,” Cuomo said in a statement. “While there remains much work to be done, I am pleased that significant progress is being made.
Fitzpatrick Nuclear Plant Source Entergy
“I have directed various state entities to continue working with the parties involved to finish the job. I am hopeful that a definitive agreement will be reached to ensure these benefits to New Yorkers are realized.”
The proposed nuclear subsidies are a recent addition to the state’s Clean Energy Standard. The clean energy blueprint would mandate use of renewable energy for half of the state’s electricity by 2030.
According to a July 8 report by the staff of the New York Public Service Commission, the nuclear subsidies would total $965 million over the first two years while providing economic and environmental benefits through carbon reductions, supply cost savings and property tax benefits of about $5 billion (Case 15-E-0302).
Initial cost estimates for the nuclear subsidies were $59 million to $658 million through 2023, with net benefits of about $1 billion. (See NYPSC: Minimal Cost to Meet 50% Renewable Goal.)
Three plants in the state — FitzPatrick and Exelon’s Nine Mile Point and R.E. Ginna — would be eligible for the subsidies. Cuomo wants to exclude Entergy’s Indian Point, which he wants shut down because of its proximity to New York City.
When the nuclear subsidies in the Clean Energy Standard were first announced, Entergy said they would have no effect on its plans to close FitzPatrick. But the company said Wednesday that its decision to seek a sale to Exelon is “consistent with Entergy’s commitment to consider any viable option that would allow FitzPatrick to remain in operation.”
Exelon spokeswoman Lacey Dean confirmed the talks on Wednesday, saying a deal would be “subject to several firm conditions.”
In addition to approval of the Clean Energy Standard, Dean said, the conditions were a guaranteed long-term revenue stream for the plant and an immediate positive impact on Exelon’s earnings.
She declined to say how long the talks had been in progress or if a purchase price had been discussed.
Fighting a PJM proposal to impose uplift costs on up-to-congestion trades, the Financial Marketers Coalition last week enlisted one of the intellectual pioneers of electricity markets in its defense.
Presenting the conclusions from his white paper on virtual trading, Harvard economist William Hogan told the Energy Market Uplift Senior Task Force that PJM should eliminate uplift costs from all financial transactions rather than extending them to UTCs.
UTC volumes have withered since September 2014 after FERC ordered a Section 206 proceeding to determine whether the RTO is improperly treating UTCs differently than increment offers (INCs) and decrement bids (DECs) (EL14-37). Unlike UTCs, INCs and DECs are subject to uplift charges and the financial transmission rights forfeiture rule. (See PJM Traders Continue to Shun UTCs on Uplift Fears.)
Hogan said PJM’s October 2015 paper, which recommended charging UTCs, was too narrowly focused and failed to acknowledge some of virtual transactions’ benefits, including countering market power, improving market efficiency and hedging real-time market risks.
“Uplift can arise for many reasons. … The focus on deviations, which are used for allocating uplift costs, do not go hand in hand with added uplift costs,” said Hogan, the Raymond Plank Professor of Global Energy Policy at Harvard’s John F. Kennedy School of Government. “We want to be careful about using [deviations] as a measure of failure of the system and then using that to allocate a subcategory of the costs.”
He suggested exempting virtual trading from uplift charges and allocating the costs instead to the “real-time gluttons” — consumers who won’t respond to even the most extreme price signals.
It’s “foolish,” he said, to think that the costs could be allocated anywhere other than consumers. “In the end, in equilibrium, the load’s gotta pay,” he said. “Aggregate efficiency should be the standard.”
‘Reversal of the Conventional Wisdom’
Hogan’s stature — Public Utilities Fortnightly has called him “the chief architect of wholesale electric market design in the United States” — makes him a valuable ally. Among his other clients have been numerous utilities, MISO, ISO-NE and the Electric Power Supply Association, which enlisted him in its unsuccessful bid to eliminate FERC oversight of demand response. He was also among the experts who defended Richard and Kevin Gates’ Powhatan Energy Fund in their high profile campaign against FERC market manipulation charges.
Hogan conceded that his position on virtual trading represents a “reversal of the conventional wisdom.” He rejected arguments by those who contend that virtual bidding provides no significant benefits and thus extracts money via what a 2015 paper by Massachusetts Institute of Technology economist John E. Parsons and three FERC analysts termed “parasitic” profits.
At this year’s EBA Annual Meeting left to right: Greg Lawrence, William Hogan, David Patton, Sam Newell and Joe Bowring
He highlighted two studies — one focused on California and the other on ISO-NE — that concluded virtual transactions increased price convergence between the day-ahead and real-time markets and reduced dispatch costs. While “not a dramatic number — a single-digit percentage of improvement” — the studies showed how virtual transactions help smooth out the “lumpiness” of unit commitment costs, Hogan said.
“The inclusion of the convergence bidding and the virtual bidding made the whole system operate more efficiently,” he said. “Neither of these studies go all the way, but they are very suggestive.”
Hogan also took on PJM Independent Market Monitor Joe Bowring, who contends that UTC transactions are increasing shortfalls in FTR funding and that PJM should consider NYISO’s model, which limits virtual transactions to zones or hubs. (See Bowring: UTCs Boost FTR Shortfalls and PJM Ponders Changes to Virtual Trades, DA Market.)
Hogan said new recommendations contained in Bowring’s 2015 State of the Market report would result in the “undoing [of] financial transmission rights.”
“Forgetting … the larger context linking the market design economics to engineering principles can result in analyses and recommendations that can neglect the requirements of efficient electricity market design and recreate problems already solved,” Hogan wrote. (See “Financial Transmission Rights,” Bowring Urges Return to ‘Fundamentals’.)
Hogan was more conciliatory toward PJM’s 2015 paper, which he credited as “generally supportive of the contribution of virtual transactions as improving overall market performance” despite being issued “in a context where virtual bidding is under attack.” (See PJM Suggests Changes to Virtual Transactions.)
But he said the examples cited in PJM’s report “do not provide a framework for evaluating the overall cost and benefits of virtual transactions,” a task he acknowledged “is not easy.”
“The limited available analyses from other regions indicate that the benefits are material and outweigh the costs, but no available studies cover all the relevant issues.”
Focus on Deviations
PJM’s uplift charges totaled $314.2 million in 2015, down from $960.5 million in 2014, when costs spiked as a result of the polar vortex.
PJM UTC trading volumes fell by 85% after FERC said it might make the transactions liable for uplift assessments.
Because LMPs do not cover all production costs, uplift payments — or “residual” charges — are required to make generators whole. The biggest component of PJM’s uplift charges is the balancing operating reserve (BOR), the costs of which are allocated based on real-time deviations from day-ahead schedules.
Hogan said allocating uplift costs according to the deviations is inappropriate and “particularly problematic for virtual transactions, which by design involve a 100% deviation.”
He also said PJM’s cost allocation “does not arise from any fundamental model … [implying] that the allocation method is more an administrative compromise than the product of a principled analysis.”
Some deviations are expected and inevitable, Hogan said, citing the “lumpiness” of unit commitment costs. As an example, he described a generator being priced too high to clear the day-ahead market but clearing during the later reliability run.
Because uplift is a result of residual costs, attempting to figure out the cost causation “is a fool’s errand,” Hogan said.
“The important question is the aggregate net benefit of virtual transactions, not the residual cost. If virtual transactions increase the net benefits in the market, then there is no incentive-based reason to assign additional costs to virtual transactions.
“Allocating the uplift costs to network connection charges would be better than adding to a so-called ‘uplift’ charge on load billed per megawatt-hour,” he continued. “If an uplift charge is necessary, it should be allocated to the least price-responsive loads. If a nondiscriminatory uplift charge is required, it should be spread across the widest possible base of loads that cannot bypass or avoid the charge.”
Hogan said the “principal problem” PJM identified with virtual transactions is a “computational burden that would be only indirectly affected by uplift allocations and could be addressed through other means with fewer negative consequences for the broader market design, such as by continuation of bidding budgets that allowed flexibility in the choice of virtual transactions.”
Recommendations, FERC Action
In addition to calling for an end to uplift charges, Hogan identified two other recommendations that differed from PJM’s:
Analyze the impact of virtual trading on unit-commitment decisions rather than assume differences between day-ahead and real-time conditions. “The PJM analysis refers to the importance of commitment decisions throughout the report but does no explicit analysis of those commitment decisions,” Hogan said. “The absence of the analysis undermines the PJM conclusions.”
Increase the number of locations at which virtual transactions may be placed.
FERC is long overdue to issue a ruling in its Section 206 inquiry. In opening the docket, FERC said it would rule within five months after it receives comments following a technical conference. The conference was held in January 2015 with follow-up comments due at the end of May.
However, the commission may be delaying action to see what emerges from PJM’s stakeholder process. The task force, which has been discussing the issues since July 2013, is scheduled to meet next on Sept. 1.
Environmental groups and others have asked the D.C. Circuit Court of Appeals to review FERC’s approval of PJM’s Capacity Performance model, saying the rules unfairly limit participation by renewables and demand response.
The new rules, created in response to the high number of forced outages during 2014’s polar vortex, aim to improve reliability by increasing the rewards for capacity resources that provide power when called on during times of high demand and increasing the penalties on those that fail to do so.
One of the challenges was submitted by the Natural Resources Defense Council, the Sierra Club, Union of Concerned Scientists and Earthjustice. Another was filed by the Advanced Energy Management Alliance, a trade association representing DR providers and their customers. American Municipal Power, an organization of municipal utilities, filed a third challenge July 6. The court consolidated those petitions.
Then on July 8, another challenge was submitted by American Public Power Association, National Rural Electric Cooperative Association, New Jersey Board of Public Utilities and the Public Power Association of New Jersey.
The environmentalists said that ruling, and FERC’s June 2015 order approving CP, conflict with the Federal Power Act (ER15-623, EL15-41, EL15-29).
“In addition, the new rules will funnel billions of dollars from electricity consumers to fossil and nuclear power plants while severely limiting clean energy participation in PJM’s capacity market,” said Jennifer Chen, an attorney for the Sustainable FERC Project, which is housed within the NRDC.
Competition from more and diverse resources reduces energy prices, Chen wrote in a blog post. The new model will limit the participation of clean energy sources such as wind, solar and DR, driving up costs, she said.
While the new rules allow summer and winter resources to aggregate a single capacity offer, no aggregate offers were submitted in the first Base Residual Auction with CP for delivery year 2018/19.
In the second auction under the new rules in May, only 6% of cleared DR resources qualified as CP, compared with 9% of wind and one-tenth of 1% of solar.
Base capacity resources, which are not held to CP standards, will be eliminated for the delivery year 2020/21.
In addition to increasing prices, the CP rules will “punish the same clean energy and demand response resources that helped keep the lights on during the extreme weather events of the last couple of years,” said Casey Roberts, staff attorney with the Sierra Club.
The impact of CP on capacity prices is not yet clear, however.
PJM’s first auction under CP last August saw prices rise 37% to $165/MW-day in most of the RTO, while the ComEd and Eastern MAAC regions cleared at more than $200.
But in the second auction, prices dropped to $100/MW-day in most of the RTO. Eastern MAAC fell to $120 while the ComEd zone cleared at $203. (See PJM Capacity Prices Fall Sharply.)
The subject of accommodating seasonal resources in the new model has been the subject of much debate.
At PJM’s annual meeting in May, state consumer advocates urged the Board of Managers to change the new rules to allow more participation by DR, energy efficiency and solar resources by procuring capacity seasonally. (See Consumer Advocates, Enviros Press PJM on Seasonal Capacity.)
Also in May, the Markets and Reliability Committee approved a charter for the new Seasonal Capacity Resource Senior Task Force. The motion passed with 68% of a sector-weighted vote, with some members voicing concern over its potential to undermine the CP product. (See MRC Approves Charter for Seasonal Capacity Effort.)
NextEra Energy is said to have offered Energy Future Holdings a combination of cash and debt for its Oncor subsidiary and leads the list of potential suitors for Texas’ largest transmission and distribution utility, according to a Bloombergreport.
Bloomberg quoted “people familiar with the talks” as saying Florida-based NextEra, which had made an unsuccessful bid last year for Oncor, “is closest to reaching a deal” among at least seven companies that have expressed an interest. The sources said an agreement could be reach by early July.
Bloomberg also said Warren Buffet’s Berkshire Hathaway and Edison International are among the other companies eyeing Oncor. Spokespersons for the various companies either declined comment or didn’t respond to requests for comment last week.
Dallas-based Hunt Consolidated in May withdrew its year-long application to buy Oncor but filed a lawsuit last month against the Public Utility Commission of Texas asking it to reverse a March order that set conditions on the deal. (See Hunt Reopens Oncor Bid in Lawsuit Against PUCT.)
Bloomberg’s sources said NextEra’s proposal is higher than the Hunt bid.
Oncor is EFH’s regulated subsidiary and said to be valued at $17 billion to $18 billion. EFH, which has been working to emerge from bankruptcy for two years, has a July 8 deadline to file an amended reorganization plan.
Whoever comes up with a new deal for Oncor would have to seek approval from the Delaware bankruptcy court hearing EFH’s case and the Texas PUC, among others.
NextEra is also involved in an attempted acquisition of Hawaiian Electric, a deal announced in December 2014 and valued at $4.3 billion. A state representative told a Hawaii TV station last week that NextEra’s pursuit of Oncor does raise some concerns.
“Clearly some of the financial [analysts] have speculated that if the company is going to be investing there significantly, that it may change the kind of investment and the plans they make out here,” Rep. Chris Lee said.
Coal’s share of SPP’s energy production continues to slide in the face of low gas prices and increased wind generation, according to the RTO’s latest State of the Market report.
The SPP Market Monitoring Unit’s spring report says coal-fired generation accounted for just 41% of the RTO’s energy production between March and May, its lowest percentage ever and a stunning 31% drop from spring 2014, when coal resources provided 59% of the RTO’s energy. Coal generation accounted for more than 65% of total generation in 2007, SPP’s first year as an organized market.
Coal’s diminished market share is largely attributed to the continuing drop in gas prices. Prices at the Panhandle Hub have dropped 64% since spring 2014, from $4.66/MMBtu to $1.68/MMBtu, and 32% since spring 2015, when the price was $2.46/MMBtu.
That contributed to average real-time LMPs of $17.37/MWh (compared to $34.72/MWh in 2014) and day-ahead LMPs of $17.07/MWh (versus $37.03/MWh in 2014). The Monitor said it is the first time since the Integrated Marketplace opened in March 2014 that day-ahead prices were below real-time.
Coal-fired resources were also backed down by the ready availability of wind energy, which accounted for 21.5% of all energy produced this spring, compared to 15% last year. SPP’s wind penetration has risen from the 30% range to a new high of 49.17% of total generation this year.
The Monitor also said cleared virtual transactions are approaching the levels of other RTOs, at about 10% of reported load. It said gross virtual profits for the Integrated Marketplace’s most recent 12 months totaled nearly $78 million, with gross virtual losses totaling nearly $58 million.
Virtual trades have shown net profits every month since the Integrated Marketplace began, with the exception of May 2014.
The Public Utility Commission of Texas said it will invite stakeholder comments as it takes a cautious approach to Lubbock Power & Light’s planned integration into the ERCOT grid.
“I think this is an incredibly complicated situation. I’m not sure it’s even clear how … we evaluate it,” PUC Chair Donna Nelson said during the commission’s June 29 open meeting. “I do have concerns about the FERC jurisdiction aspect of it … I’m concerned about [Lubbock] having generation that flows outside of Texas.”
“We need to be mindful of the precedent it sets,” Commissioner Ken Anderson agreed. “I believe there might be other entities in Texas — other regions, groups — that look with envy on ERCOT, and for good reason.”
LP&L announced last September it planned to disconnect from SPP and join ERCOT by 2019. Xcel Energy, whose Southwestern Public Service subsidiary serves LP&L’s load, asked FERC in May for an $88.7 million interconnection switching fee should the municipal utility proceed with its plan. (See Xcel Asks for $88.7M Fee for Lubbock Switch to ERCOT.)
Nelson, Anderson and Commissioner Brandy Marty Marquez all said they would like to see LP&L’s integration turned into two separate cases, one involving the move from SPP’s grid to ERCOT’s, and the other involving a cost-benefit analysis of the transfer on ratepayers. Nelson said she would issue a memo outlining the parameters on further studies before the PUC’s next open meeting July 20 (Docket No. 45633).
An ERCOT study completed in June indicated it would cost $364 million and take 141 miles of new 345-kV right of way to incorporate LP&L into ERCOT. (See “LP&L Integration Could Unlock More Panhandle Wind Energy,” ERCOT Board of Directors Briefs.)
The City of Lubbock has told the PUC it would prepare an impact analysis of the LP&L load that would migrate to ERCOT, using the Texas grid operator’s report as a starting point. It said its report will be “holistically framed around three key areas of study”: the effects on existing ERCOT stakeholders, on existing SPP stakeholders and on Lubbock customers.
“I think it’s appropriate to allow people to file responses to the ERCOT filing and to what Lubbock has filed,” Nelson said. “We have to make sure ERCOT [and] the ratepayers of Texas are treated fairly. I think SPP and the ratepayers in SPP should be treated fairly too.”
Marquez said one of her concerns is “what happens to the communities that are left behind, and what kind of rates do they absorb?”
Anderson said he wants more “clarity” from ERCOT on the available integration options, saying the ISO’s preferred option “seems to be predicated on the assumption that most of what they are recommending will be needed anyway.”
“If two years later we have to go back and approve what ERCOT recommended,” Anderson said, “by then, we may have way overpaid.”
The municipality has said it faces time constraints in meeting its 2019 timeline, but the commissioners said that wasn’t their primary concern.
“I’m not going to take on that responsibility,” Nelson said. “We need to avoid putting ourselves in a position where we’re there to rescue the day if people have put themselves in that position.”
“These are Texans, but these are Texans that didn’t want us,” Marquez said. The SPS region opted out of Texas’ competitive market before it opened in 2002.
Municipal utilities Austin Energy and CPS Energy of San Antonio, both ERCOT members, also opted out of competition.
The Public Utilities Commission of Ohio staff has proposed a new rider for FirstEnergy that would allow the recovery of $131 million annually from ratepayers for three to five years in order to maintain the company’s investment-grade credit rating.
“Staff believes the long-term financial health of FE will have benefits for the Ohio regulated distribution facilities, as well as the state of Ohio in general,” PUCO’s Joseph Buckley testified Wednesday (Case No. 14-1297-EL-SSO).
FirstEnergy’s Davis Besse Power Plant Source: Wikimedia
Buckley cited Moody’s Jan. 20 credit opinion saying that the company could receive a rating downgrade without an increase in revenues allowing it to generate cash flow from operations equal to at least 14% of its debt. He said staff believes that three years is enough time for FirstEnergy to address its finances, and that it could request an extension of the rider if necessary.
The Distribution Modernization Rider would require FirstEnergy to maintain its corporate headquarters and most of its operations in Akron or forego the credit. The agreement also would be terminated if the company or its subsidiaries were to undergo a change in ownership.
Critics of FirstEnergy’s attempts to win subsidies from Ohio regulators objected.
“While the staff frame their proposal in terms of grid modernization, the apparent absence of any requirement that FirstEnergy invest the money on modernizing the grid means that this new proposal is effectively just another corporate bailout,” Earthjustice, representing the Sierra Club, said in a statement.
Dick Munson of Environmental Defense Fund called it “an unnecessary subsidy.”
PUCO staff said last week that modified proposal should be rejected in favor of the recommended rider.
Doug Colafella, a spokesman for FirstEnergy, said Friday, “The filing of staff’s testimony is another step in the regulatory process. We will continue to work with the commission and other parties to achieve an outcome that will protect our customers and communities.”
On Thursday, FERC Chairman Norman Bay responded to a letter from U.S. Sen. Joseph Manchin (D-W.Va.) explaining the commission’s role in the dispute (EL16-33, EL16-34). Manchin, a staunch supporter of his state’s coal mining industry, had asked FERC on April 20 to “allow [Ohio’s] prudent action to stand.”
Great Plains Energy and Westar Energy filed a joint application with the Kansas Corporation Commission to approve the $12.2 billion sale of Westar to Great Plains.
The companies estimated pre-tax savings and efficiencies from the merger at about $65 million in the first year. The sale also is expected to generate $60 million in transaction costs through 2020. If approved, the transaction will close in spring 2017.
The deal is also subject to FERC approval, and the Missouri Public Service Commission is still evaluating whether it should have jurisdiction.
Wisconsin Co-op Using 4-Legged Vegetation Management System
The Eau Clair Energy Cooperative has hit upon an energy-saving, green method of controlling the vegetation at its solar farm in Fall Creek: sheep.
The co-op turned loose 15 three-month-old lambs to control the grass and weeds at the facility, the largest community solar facility in the state. “It’s all about sustainability,” Eau Clair spokeswoman Mary Kay Brevig said. “It’s kind of funny, they kind of stay in a group; they’re fairly timid.”
The co-op obtained the sheep from member Lambalot Acres. “They’ve got solar panels, which is a very green source of energy, and we’ve got sheep, which just eat the greens,” Dylan Klindworth of Lambalot Acres said.
DTE Energy has installed a natural gas-burning residential combined heat and power system at a Northern Michigan home, footing the $27,000 price tag in exchange for monitoring the unit for a year.
The PowerAire by Houston-based M-TriGen is a three-cylinder engine that produces 4 to 8 tons of thermal energy for heating, 2 to 10 tons of cooling capacity and 5 to 10 kW of electricity. Robert P. Fegan Jr., principal market technical consultant for DTE, said the unit can fully power the 3,200-square-foot house if needed.
DTE is performing viability tests on the unit, the first of its kind to be installed in Michigan. M-TriGen Vice President of Sales Randy Erwin said around 50 PowerAire units are in service in several states.
Korean Firm, Alliant Complete Wisconsin’s Largest Solar Plant
Alliant Energy has put Wisconsin’s largest solar installation, built on top of a coal-ash landfill, into service.
Korean solar energy firm Hanwha Q Cells built the 7,700-panel, 2.2-MW plant on Alliant’s landfill property near the Wisconsin-Illinois border. Alliant said it will purchase power from the project for the next 10 years and have an opportunity to purchase the $5 million installation after that.
The new solar plant is part of Alliant’s recent settlement with EPA over pollution from its coal-fired fleet.
PSEG’s Lopriore Retiring After 43 Years in Generation
Lopriore
Rich Lopriore, whose career in electricity generation has spanned more than four decades, is retiring as president of PSEG Fossil.
Lopriore came to Public Service Enterprise Group from Exelon during an aborted attempt at a merger between the two companies. He previously served as plant manager at Exelon Nuclear’s Byron Station and then senior vice president in charge of Mid Atlantic Operations for Exelon nuclear. He also worked at Duke Energy’s Brunswick Nuclear Plant.
Lopriore will retire to Massachusetts. A replacement has not been named.
Pipeline giant Energy Transfer Equity has called off its proposed acquisition of Williams Co., following a Delaware judge’s ruling that the transaction could be terminated. The deal was valued around $38 billion, including debt, when it was reached in September.
Dallas-based Energy Transfer has sought for months to kill the cash-and-stock deal following a sharp decline in the energy markets last year. Tulsa-based Williams and Energy Transfer had accused each other of breaching the terms of the agreement, and the deal’s value declined as a fall in oil prices hurt the financial prospects of their customers.
The fight over the deal may be far from over. Williams shareholders approved the transaction during a special meeting June 27, and the company filed papers to begin the appeal process in the Delaware Supreme Court.
GridLiance and the Kansas Power Pool announced a collaboration to improve the transmission infrastructure in KPP’s service area.
GridLiance’s South Central Region within SPP will work with KPP’s 31 member cities to jointly plan, construct and operate transmission infrastructure. GridLiance will also manage NERC compliance and assist KPP in navigating SPP’s processes, providing greater participation in transmission planning, rate determination and other key functions.
San Diego Gas and Electric is the first California investor-owned utility to meet its cap under the state’s original net energy metering (NEM) rule, which restricts projects eligible for net metering to 5% of a utility’s peak load.
The company will now shift future distributed energy customers to NEM 2.0, a revised rule issued earlier this year by the California Public Utilities Commission in anticipation of the continued rapid growth in rooftop solar.
The new rule requires continued compensation for customers who export energy to the grid while also subjecting them to an interconnection fee, time-of-use rates and new fees to support low-income and energy efficiency programs.
APS Elevates Company Veteran To Head Nuclear Operations
Bement
Arizona Public Service last week announced that Bob Bement has been appointed executive vice president for nuclear operations at the utility’s Palo Verde nuclear generating station.
Bement will take over as chief nuclear officer on Oct. 31, replacing Randy Edington, who will assume a role as an adviser to company CEO Don Brandt.
Bement has overseen nuclear operations at the plant since 2007, having previously held senior positions with Exelon and Arkansas Nuclear One.
Oklahoma Gas and Electric implemented a $69.5 million interim rate increase last week as it awaits a decision from the Oklahoma Corporation Commission in its rate case.
OG&E filed for a $92.5 million rate increase in December. An administrative law judge heard arguments in hearings that ended in May. Oklahoma law allows utilities to establish interim rates if the three-member OCC hasn’t issued a final order within 180 days.
The utility said the increase, subject to refund, would be offset by a lowering of the fuel-adjustment charges that it is required to pass along to consumers.
The Indiana Utility Regulatory Commission on Wednesday accepted a settlement negotiated between Duke Energy and local consumer groups on a statewide infrastructure upgrade plan.
The seven-year, $1.4 billion plan results in an average 0.93% increase in Duke Energy Indiana customer rates annually over the next seven years. Individually, the year-long increases range from 0.58% to 1.35% until 2023.
The IURC found that “public convenience and necessity require” Duke’s planned transmission, distribution and storage improvements.
The settlement was reached in March among the Indiana Office of Utility Consumer Counselor, Duke Energy Indiana, steelmaker Companhia Siderurgica Nacional, Steel Dynamics, Wabash Valley Power Association, Indiana Municipal Power Agency, Hoosier Energy Rural Electric Cooperative and the Environmental Defense Fund.
“We are happy with the settlement,” said Anthony Swinger, director of external affairs for the IOUCC. “We believe the settlement strikes the right balance between ratepayer protection and the utilities’ need to make infrastructure improvements in order to provide safe, dependable service.”
“We have an aging energy grid — some equipment that is decades old — and our work will focus on replacing some older infrastructure to reduce power outages,” Duke Energy Indiana President Melody Birmingham-Byrd said. “We’ll also be building a smarter energy structure with technology to provide the type of information and services that consumers have come to expect.”
Duke plans to invest in line sensors and “self-healing” systems, as well as replace aging substations, utility poles, power lines and transformers.
A little over a year ago, the IURC denied Duke Energy Indiana’s original proposal, causing the utility to trim $400 million from the plan, including the elimination of a $192 million project to install smart meters. The company now says that if it pursues smart meters using the settlement, it is “committed to exploring energy efficiency pilot programs that are now possible with smart meter technology.”
The New York Green Bank wants to increase its portfolio by two-thirds over the next year, mostly by investing in larger clean energy projects.
In its annual business plan released last week, the state’s clean energy investment arm said it wants to invest $200 million, or $50 million per quarter, in projects that otherwise might not attract enough private capital on their own.
The bank invested $120.5 million in nine transactions over the past year, which was leveraged into a project portfolio valued at $518.3 million. These commitments are expected to result in 128 MW of new capacity.
The Green Bank is administered by the New York State Energy and Research Development Authority as part of the state’s $5.3 billion Clean Energy Fund. (See NYPSC OKs $5.3B Clean Energy Fund.) The bank has a short-term goal of deploying private capital at a rate of 3-to-1 above its own funds, with a longer-term goal of an 8-to-1 ratio when the fund ends in 2025.
The bank is seen as a way to jump-start projects to achieve New York’s goal of obtaining 50% of its energy from clean sources by 2030.
So far, the bank has received $220 million from the state. Now it wants to scale up the project pipeline.
“NYGB has identified two potential opportunities to accelerate market transformation via the creation and introduction of targeted financial products. In both cases, the market is potentially large, but currently suffers from fragmentation, lack of standardization and lack of scale,” the plan says.
Based on input submitted by project developers, financiers and other stakeholders in response to a recent request for information, the Green Bank expects to issue two requests for proposals. Its new targets are commercial real estate and multi-family solar and/or energy efficiency systems that would be owned by the building owner instead of third parties, and ground-mounted solar systems for corporate or industrial end users.
On the same day the business plan was released, the Green Bank closed a $25 million loan for residential solar installer Sunrun. The loan is intended to accelerate construction of more than 5,000 solar projects across the state. It comes on the heels of a separate $25 million loan from the Green Bank in May that was part of a $340 million credit facility Sunrun executed over the past several months.
The bank has been capitalized at $1 billion with support from ratepayer funds and New York’s proceeds from its participation in the Regional Greenhouse Gas Initiative. It has a goal of becoming self-sustaining by 2018 through returns from its project portfolio. (See Project Interest Overwhelms New York’s Green Bank.)
Great Plains Energy and Westar Energy filed a joint application with the Kansas Corporation Commission to approve the $12.2 billion sale of Westar to Great Plains.
The Eau Clair Energy Cooperative has hit upon an energy-saving, green method of controlling the vegetation at its solar farm in Fall Creek: sheep.
Alliant Energy has put Wisconsin’s largest solar installation, built on top of a coal-ash landfill, into service.
Pipeline giant Energy Transfer Equity has called off its proposed acquisition of Williams Co., following a Delaware judge’s ruling that the transaction could be terminated. The deal was valued around $38 billion, including debt, when it was reached in September.
GridLiance and the Kansas Power Pool announced a collaboration to improve the transmission infrastructure in KPP’s service area.
San Diego Gas and Electric is the first California investor-owned utility to meet its cap under the state’s original net energy metering (NEM) rule, which restricts projects eligible for net metering to 5% of a utility’s peak load.
