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.)
FERC on Thursday rejected CAISO’s proposal to prohibit Energy Imbalance Market participants from implementing economic bidding at the market’s external interties until the ISO can develop “appropriate rules and procedures” to manage the transactions (ER16-1518).
The ISO’s Tariff currently stipulates that each balancing authority area (BAA) that joins the EIM can determine for itself whether to allow resources located outside the market to submit economic bids at the BAA’s transmission seams.
CAISO sought to change its Tariff in part because EIM participants PacifiCorp and NV Energy had expressed concerns that implementing the practice would add complexity to their initial participation in the market.
The ISO cited another reason for the change: “The CAISO’s experience with 15-minute bidding at its own interties suggests that the extent of the benefits from allowing such bidding is questionable,” it said in an April filing with FERC that included a raft of other EIM-related Tariff changes. The ISO cited the low liquidity in the 15-minute market at the ISO’s own seams — suggesting a lack of market interest — and the potential for EIM participants to incur increased transaction costs from external bids.
EIM participants will continue to have the choice of allowing external intertie bidding along their seems in light of FERC’s ruling.
CAISO also envisioned a “problematic” scenario in which EIM transmission flows could shift as a result of only one EIM participant requesting economic bidding at its interties. While the market consists only of three BAAs today, Arizona Public Service and Puget Sound Energy are scheduled to begin participating later this year, while Portland General Electric will join next year.
The Western Power Trading Forum (WPTF) — an industry group representing power marketers — filed the only protest against the proposal, calling the revision an “attempt to codify” an “effective roadblock to market evolution” that discriminated against third-party participation in the EIM. The organization accused CAISO and the other EIM participants of resisting making the changes required “to incorporate external resources [into] the EIM with efficient, flexible market-based mechanisms.”
The group also criticized the open-ended nature of the Tariff change, asking the commission to dismiss the proposal until the ISO provided a plan to implement EIM intertie bidding by a specific date. The organization suggested that FERC direct the ISO to undertake an “open and transparent” stakeholder process to develop the necessary rules and commit to implementation within a year.
Although the WPTF didn’t win the one-year deadline it sought, the group’s arguments largely found support with the commission.
“As an initial matter, we find it inappropriate for CAISO to include in its Tariff an indefinite placeholder,” the commission wrote, referring to CAISO’s failure to propose a timeline for resolving the intertie issue.
While acknowledging that CAISO “identified issues that warrant further evaluation,” the commission ruled that the ISO had not “sufficiently described” those issues or met its burden under the Federal Power Act to alter the Tariff in a way that would remove from EIM participants the discretion for implementing intertie bidding.
“Moreover, WPTF raised concerns about unduly delaying the ability of external resources to participate — concerns that CAISO does not full address,” the commission said.
WPTF won another concession: The commission called for further discussion of the issue, directing FERC staff to convene a technical conference to gather information about the challenges of implementing economic bidding at the EIM’s interties — with an eye to determining how to overcome impediments. Details for the conference will be set out in a subsequent notice.
The commission’s June 30 ruling did approve CAISO’s other proposed EIM-related Tariff revisions, which included:
Modification of the ISO’s method for assigning congestion revenues to EIM participants to more accurately reflect those participants’ contributions to congestion at an intertie. The current rule allocates revenues based on the number of participants that share ownership of the intertie.
A provision allowing CAISO to submit outage information to the regional reliability coordinator on behalf of each EIM participant.
An alteration to the calculations underpinning the start-up/minimum load costs and default energy bids for EIM generators that would exclude CAISO’s grid management charge, which EIM-only generators do not pay. Instead, they pay EIM administrative charges, which they can continue to include in their costs.
A requirement that EIM participants accept approved, pending and adjusted e-Tags as the only valid means to convey an import/export base schedule to another participant for the purposes of imbalance settlement.
The Monitor reiterated his suggestion that MISO and PJM scrap pseudo-ties in favor of firm flow entitlements, advice that PJM has recently turned down.
“I don’t know how anyone who understands dispatch could think this is a good idea, but there seem to be a lot of people on the other side of the border that think this is a good idea,” said Patton, who added he’d be interested in checking in with PJM “in a few months” to see if their footprint is weary from high prices.
Dynegy’s Mark Volpe asked Patton if MISO’s pseudo-ties “far from the seam” are a main contributor to higher congestion.
“The farther you are from the seam, the more constraints you’re going to impact, and it’s harder for PJM to model all those constraints,” Patton said. He said MISO’s $302.2 million worth of real-time congestion in the first quarter is up 51% from winter but still down 17% from spring 2015.
Stakeholders asked if MISO could list all pseudo-tied units. Jeff Bladen, executive director of market services, said the RTO doesn’t publicly post information on which resources are pseudo-tied, but market participants could access the nonpublic information using MISO’s commercial model, which provides inputs to the real-time and day-ahead markets.
Patton also told stakeholders the RTO should “close some loopholes” in the Planning Resource Auction design by applying physical withholding thresholds on a company basis, rather than a market participant basis, to address companies with affiliates.
Stakeholders asked if the recommendation would break up local resource zones; Patton said that would be an entirely different recommendation.
Patton also suggested MISO apply a “reasonable” transfer capability in the next PRA. He said the binding transfer constraint of 874 MW between MISO South and Midwest used in the April auction caused the uniform $72/MW-day clearing prices in zones 2, 3, 4, 5, 6 and 7. Patton wants the limit set “based on the expected ability to reliably transfer power in real-time operations.”
Subcommittee Chair Kent Feliks said the session was the beginning of stakeholders’ review. “I think the point of this today was to get the recommendations on the table to start picking them apart,” he said.
MISO, Monitor Seek Change to Contingency Reserve Selection
MISO may change the economic selection and dispatch behind contingency reserves in an effort to reduce uplift charges.
Akshay Korad, an engineer with MISO’s market evaluation and design department, told stakeholders MISO historically experiences “significant uplift” when contingency reserves are deployed. The current logic seeks to minimize scheduling costs and not production costs.
Type I demand response providing spinning reserves received about $900,000 per year in uplift charges from 2010 to 2015 because of high curtailment costs — which are not accounted for when the RTO selects the resources.
Offline supplemental generators deployed for contingency reserves were paid an average of $275,000 per year in uplift from 2010 to 2015, with last year’s costs totaling $720,000. Korad said offline resources are selected based solely on their reserve capacity offer. “Minimum runtime and commitment costs are not considered in the selection,” he said.
MISO and the Monitor are proposing different solutions, but both would add deployment-cost considerations.
The Monitor advocates the creation of a supply curve for contingency reserves with a deployment risk adder for each resource. The approach would require a Tariff change to ban negative contingency reserve offers.
MISO proposes adding deployment cost considerations to its scheduling logic.
Thomas Sikes of WPPI Energy asked if MISO could offer deployment cost historical data with its proposal. Korad said such information hadn’t been collected. Other stakeholders pointed out that work on dispatch of contingency reserves has consistently been rated a low priority on MISO’s project selection process.
Stakeholders were asked to provide input on the two proposals within a few weeks.
MISO Moving to 3-Hour Clearing Window by November
MISO’s David Savageau said the RTO is on track to “consistently” solve the day-ahead market within three hours.
Savageau said work will continue on the day-ahead and reliability assessment commitment software over the next four months. MISO is “confident it will meet the three-hour window in November,” he said.
MISO Sends Out Customer Survey
MISO has sent its 2016 customer satisfaction survey to 1,200 potential respondents, MISO spokesperson Jay Hermacinski told stakeholders, urging their participation. The survey, independently administered by Opinion Dynamics, is open for responses until Aug. 5.
“We take the results seriously. We analyze the data geographically, we share results with the Board of Directors, we post results to our website,” Hermacinski said.
FERC’s technical conference last week on Order 1000’s performance produced a mix of feedback, with some participants suggesting complete overhauls of the landmark rule and others saying it’s too early to tell if any changes would be useful. But nearly every participant urged the commission to improve transparency in transmission planners’ decision-making processes (AD16-18).
FERC Commissioners lead technical conference on Order 1000
Issued in July 2011, Order 1000 sought to increase transmission development by eliminating incumbent utilities’ monopolies and creating incentives for more innovative, cost-effective and efficient projects.
The order — and its 2012 sequels, 1000-A and 1000-B — have caused heated debate as well as confusion about how the order is to be applied.
Transparency and ‘Evaluation Risk’
Dawe
George Dawe, vice president of Duke-American Transmission Co., said one of his biggest challenges as a competitive developer is what he called “evaluation risk.”
“I have no idea what the RTO is going to do. I have a general framework for how they plan to evaluate my project after I’ve spent ‘X’ amount of dollars, but no real idea because they’re not being real specific. We need that kind of clarity to keep the developers engaged.”
Those on the customer side also called for transparency.
Gulley
Donald L. Gulley, president of the Southern Illinois Power Cooperative, said his members are not only asking for transparency but also the opportunity to review the results so they can understand what is working and what isn’t. “What it comes down to for us is … what is the consumer ultimately going to pay?” he said.
However, increased transparency poses a litigation risk for RTOs, said Craig Glazer, PJM vice president of federal government policy.
“Order 1000 is driving transparency, so it is driving us to put more and more things in our Tariff. We’ll have to sort of step back when trying to balance between transparency and specificity in the Tariff with not so much specificity that we have taken away the judgment and discretion part of planning,” he said. “When we document every part of the process, that, to me, is creating the ‘gotchas’ that we will have to deal with.”
Ivancovich
CAISO Deputy General Counsel Anthony Ivancovich added that “a wrong decision that can be corrected by litigation is much better than a wrong decision that’s embedded in your tariff and can’t be resolved by litigation because it’s the filed rate.”
Cost Containment
Williams
Another recurrent topic during the two-day conference was cost caps. Noman Williams, the chief operating officer and senior vice president of engineering and operations for GridLiance, said caps change the standard transmission development process by transferring the risk of overruns from ratepayers to the builder. “It brings value back to the consumer,” he said. “It is incumbent on us, when we say we want those opportunities and we don’t want to have structure, that we also explain how the cost-containment, cost-cap bids can be applied.”
Sharon Segner, vice president of LS Power Development, lauded PJM and CAISO for figuring out “how to make the cost caps enforceable and not just a PowerPoint presentation.” Developers who fail to stay within their caps risk both the project and the approved rate, she said, and “that is a lot.”
Hanemann
Kim Hanemann, senior vice president for delivery projects and construction for Public Service Enterprise Group, said cost-containment provisions “are of limited value.” PSEG “does not view Order 1000 right now as improving the transmission planning process or bringing value to our customers” because it focuses too exclusively on costs, she said.
“Projects with the greatest overall value may be more expensive in the short term, but they might provide other ancillary benefits, such as reducing congestion and replacing aging infrastructure,” she said. “Simply put, the project with the lowest bid-cost is not necessarily the best project or value for our customers.”
In 2014, PJM planners recommended PSEG’s Public Service Electric and Gas to construct a stability fix for the company’s Artificial Island nuclear complex in New Jersey. However, the PJM board reopened the bidding and ultimately awarded much of the project to LS Power, citing the developer’s lower cost and inclusion of a cost cap.
Mroz
Richard S. Mroz, president of the New Jersey Board of Public Utilities, said cost and cost caps shouldn’t factor into decision-making until the end of the process.
The process must focus on the scope of the project and what needs to get done, he said, before it can determine how much that will cost. “That’s something that can get lost in the process. That sense of cost consciousness is what drives me and what should drive the process for everyone.”
Lucas
John Lucas, general manager of transmission policy and services for Southern Company Services, who was also representing Southeastern Regional Transmission Planning, asked that the region — which isn’t overseen by a grid manager — be excused from any rules on cost-containment.
“We would note that [cost caps are] voluntarily adopted processes … that were not required in Order 1000,” he said. “Therefore, if the commission feels the need to make adjustments in those regions, we would just ask that you direct changes to the regions where those processes have been adopted.”
Debate over Incentives
There was also debate regarding project incentives, with consumer advocates saying some should be eliminated while industry members asked for more and said they wanted several — including construction work in progress and abandonment incentives — standardized for all projects.
Bernardy
That brought strong opposition from Peggy Bernardy, staff counsel with the California Department of Water Resources. “The commission should resist the urge to standardize incentives that might be calcified and set in stone for perpetuity,” she said. “That is a risk to us.”
Hughes
“The commission is perhaps unwittingly complicit in creating an investment environment in which nothing gets done without some form of ‘incentives’ — but which, in reality, are subsidies that only create the illusion of success,” said John Hughes, CEO of the Electricity Consumers Resource Council (ELCON). “Subsidies to promote responses by independent transmission companies to the competitive solicitations mandated under Order No. 1000 do not achieve competitive markets.”
Developers, however, said the potential revenue offered by incentives are key in larger companies getting projects supported by their executives.
Sponsorship or Competitive Model?
Raja Sundararajan, vice president of transmission finance, strategy and siting for American Electric Power, said the order is largely working well, containing both necessary flexibility and transparency. Of the two project-selection methods — sponsorship or competitive bidding — he greatly favored the latter.
Sundararajan
CAISO, MISO, SPP and WestConnect have adopted the competitive bidding model, in which transmission planners, with stakeholder input, identify the projects they want and then solicit bids from developers. The winners are eligible for regional cost allocation.
Under the sponsorship model, in contrast, transmission planners and stakeholders identify transmission needs and allow developers to propose potential solutions. PJM, ISO-NE, NYISO, South Carolina Regional Transmission Planning, Florida Reliability Coordinating Council, Southeastern Regional Transmission Planning, Northern Tier Transmission Group and ColumbiaGrid have adopted the sponsorship model.
CAISO’s competitive solicitations have a six-month window that allows time to put together a “real” proposal, Sundararajan said. The sponsorship model is “great for generating ideas” but “doesn’t lend itself” to preparing a comprehensive proposal because it doesn’t allow enough time for the necessary research, he said.
Sheehan
“When the rules are known and the methodology is consistently applied, business works best,” said Michael Sheehan, executive director of NextEra Energy Transmission. California is “getting repeated bidders coming back to competitions in that market because it is clear, transparent, consistently applied and you’re getting feedback.”
ELCON’s Hughes called the project-approval process “nothing more than a food fight” within the RTOs, saying that his membership is seeing transmission costs rise each year without any benefits to show for it.
Southern Co.’s Lucas said there hasn’t been enough information gathered yet to suggest any changes to the order, while Omar Martino, director of transmission for EDF Renewable Energy, said there are many changes that need to be implemented. RTOs are holding onto “historical ways of doing things” that are increasing congestion and hampering grid efficiency, he said.
Planning vs. Regulation
Glazer
PJM’s Glazer said that by factoring cost into their project approvals, RTOs are effectively setting rates. That movement into a regulatory role “is what makes us nervous,” he said, suggesting the RTO be allowed to take tough decisions to FERC for a second opinion.
PSEG’s Hanemann said grid operators don’t have adequate proficiency in several project development considerations, such as environmental permitting requirements, industry practices, local regulations and equipment procurement.
CAISO’s Ivancovich warned against installing rigid mathematical formulas for decision-making, saying it doesn’t allow for evaluating each proposal on its facts. “You need to establish integrity and credibility that we will be fair in looking at” each proposal, he said.
The entire proceeding was guided by the FERC commissioners’ questions on the positive and negative impacts of the order. Commissioner Cheryl LaFleur said she attempts to follow what she called the “regulatory Hippocratic Oath: Don’t make things worse.”
LaFleur
In a statement before the hearing, LaFleur noted that FERC has dealt with ratemaking and incentive issues resulting from the order on a case-by-case basis and asked for feedback on whether it should issue a policy statement or rulemaking to address the issues generically. “I also hope to address how to harmonize requests for incentives, particularly regarding return on equity, with competitive proposals that include cost caps or other limits on a developer’s ability to recover costs,” she wrote.
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.
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.
