VALLEY FORGE, Pa. — The Planning Committee approved changes to Manual 19 allowing distributed solar generation to be included in the load forecast model.
The group was split in its decision, with 77 voting yes, 18 voting no and 89 members abstaining.
Steve Herling, PJM vice president of planning, said adding distributed solar will lower the load forecast.
PJM’s John Reynolds explained that to create a history of solar generation, planners used the generator attribute tracking system, or GATS.
“We know where they are, how big they are and how long they’ve been there,” Reynolds said of the panels, which Herling noted are the ones not participating in the PJM market.
“We’re not talking about big solar farms,” Herling said.
Planners leveraged that with information from the National Oceanic and Atmospheric Administration to calculate where the sun was in the sky at various times and locations. Each panel was assigned to a weather station for information on cloud cover. Together, the data can estimate how much light was hitting the panels.
That calculation of solar output was aggregated to a zonal number and subtracted from the metered load, Reynolds said, noting that there is virtually no solar metered data available.
The second step was to forecast solar additions by state, for which PJM contracted IHS Energy. Planners took into consideration that some of the new solar likely would be replacing older equipment.
Planners want to break out solar generation because it is growing faster than other behind-the-meter generation and they want to get ahead of the trend.
“It’s going to be important in the future. We’re comfortable making the adjustment now with a procedure that might need refinement,” Herling said. “It might not have a big impact now, but in five years it may. We want a procedure in place now for when solar takes off.” (See “New Load Forecast Model, Related Manual Changes Adopted” in PJM Markets and Reliability Committee Briefs.)
Regardless of PSEG Wheel, 4 Reliability Projects Necessary
Even if Consolidated Edison of New York stops using the so-called PSEG wheel to deliver power into New York City, four baseline upgrades in northern New Jersey are still needed, PJM told Transmission Expansion Advisory Committee members. (See Developer Questions Need for PSE&G Projects Without ‘Wheel.’”)
The four proposals, part of the Regional Transmission Expansion Plan, include the Sewaren storm-hardening project, two sections of the Bergen-Linden Corridor and the Edison Rebuild.
The cost allocation of three of the projects would change significantly in the absence of the wheel.
Currently, Con Ed and East Coast Power each share about half of the cost of the Sewaren upgrade. The change would move all of the cost to ECP.
All affected transmission owners would pay for the two sections of the Bergen-Linden Corridor under the current scenario. Absent the wheel, Con Ed’s allocation would be moved to ECP and Hudson Transmission Partners.
Planners to Recommend ComEd’s Loretto-Wilton Center Project
PJM planners in February will recommend the Board of Managers approve a market efficiency project to relieve constraints on a 345-kV line from Loretto to Wilton Center, Ill.
Proposed by Commonwealth Edison, the $11.5 million project will mitigate sag limitations on the line and replace the station conductor at Wilton Center.
The projected in-service date is 2019.
PJM Continues to Study Effect of Clean Power Plan
PJM is updating its analysis of the economic and reliability impact of EPA’s Clean Power Plan and expects to coordinate its work with MISO.
The primary study years will be 2023 and 2026. PJM also will look at years 2028 and 2030, but with less detailed modeling.
It will examine five mass- and rate-based scenarios for regional as well as individual state compliance.
States have until September to submit their compliance plans or request extensions from EPA.
The work is expected to be complete by July 31, and the TEAC will receive an update at its February meeting.
Connecticut regulators asked FERC last week to dismiss a complaint from a renewable energy developer that contends the state’s energy procurement practices violate the Public Utility Regulatory Policies Act.
The Connecticut Department of Energy and Environmental Protection and the Public Utilities Regulatory Authority said Allco Renewable Energy’s complaint is without merit because it is challenging a procurement program created by state law “that is different than, and a supplement to, Connecticut’s federally mandated PURPA program” (EL16-11).
Allco asked FERC to void the state’s award of a contract to a 250-MW wind farm in Maine. It cited FERC and federal court rulings that say states have no authority to procure energy except under PURPA, which is limited to qualifying facilities (QFs) of 80 MW or less. (See Solar Developer Asks FERC for PURPA Enforcement.)
In their response, Connecticut officials said commission action is not warranted because Allco is not actually challenging the state’s PURPA program. “Petitioner does not complain about any aspect of Connecticut’s PURPA program and, in fact, concedes the ‘potential availability of a PURPA contract,’ but elects not to participate in the program,” the officials wrote.
“Petitioner is a disappointed bidder in the Connecticut renewables solicitation conducted two years ago,” they added. The officials said their procurement programs do not violate PURPA or the Federal Power Act. “Cognizant of the commission’s exclusive authority over wholesale sales of energy, the Connecticut agencies have not set or modified rates or otherwise acted on matters within the commission’s FPA authority,” they said.
Allco filed the complaint with FERC on Nov. 9 after a federal appeals court said the company had not exhausted its administrative remedies in challenging the state procurement.
Allco said that the appeals court’s decision endorsed its contention that the state had violated PURPA by preempting federal authority over wholesale contracts. However, the appeals court issued an amended decision on Dec. 1, disputing Allco’s characterization. The court said it “express[es] no view on the merits of Allco’s preemption theory.”
Ed Tatum Jr., long one of PJM’s most vocal stakeholders, will be taking his deep voice and courtly demeanor to MISO as American Municipal Power’s vice president of transmission.
Tatum, who has more than 30 years of industry experience, previously was vice president of RTO and regulatory affairs for Old Dominion Electric Cooperative.
In his new post, he will be developing strategies to reduce transmission costs for Columbus, Ohio-based AMP, which has 132 members in nine states.
“I have known the folks from AMP for many years in both the PJM and FERC forums and have always enjoyed working with them. They are smart, innovative, eager to effectuate meaningful and positive change, and fair,” Tatum told RTO Insider. “When this position opened up, we sat down, and I quickly realized this was an excellent opportunity for me — even with the consideration of leaving ODEC and Richmond after almost 30 years!”
In his new position, Tatum will continue to participate in PJM stakeholder committees as well as those of MISO, advocating on transmission- and reliability-related issues. He also will be involved in interpreting and implementing regulations developed by FERC.
Tatum also has worked with Oglethorpe Power Cooperative in Tucker, Ga., and the Rural Electrification Administration in D.C.
He holds a bachelor’s in electrical engineering from the University of Virginia and a master’s in business administration from the University of Richmond.
“Costs and other issues associated with transmission are extremely important to our members,” said AMP CEO Marc Gerken. “As transmission-dependent utilities, AMP members increasingly look to us for strategies and opportunities to control these costs.”
WASHINGTON — The transportation bill President Obama signed last week includes provisions intended to protect the grid from terrorist attacks and natural disasters, giving the secretary of energy emergency powers and creating a Strategic Transformer Reserve.
The legislation, which will provide $305 billion in highway funding over five years, cleared the Senate 83-16 on Thursday, following a 359-65 vote in the House. Obama signed the bill Friday.
The bill represents both a vindication and a rebuke of former FERC Chairman Jon Wellinghoff’s controversial campaign to raise awareness of the grid’s vulnerability to sabotage.
It also checked off an item on current Chairman Norman Bay’s wish list. Testifying before the House Energy and Power Subcommittee last Tuesday, Bay said it was essential that the government have emergency powers to respond to a cyberattack.
“That emergency authority does not need to reside with FERC. It could reside elsewhere in the federal government,” Bay said. “But someone needs to have it.”
Presidential Declaration
Title 55 of the bill includes five “Energy Security” sections, including Section 61003, which authorizes the president to declare a grid security emergency in response to a geomagnetic storm, electromagnetic pulse, or cyber or physical attack. Such a declaration would authorize the energy secretary to issue emergency orders to protect or restore electric infrastructure critical to “national security, economic security, public health or safety.”
The emergency orders could apply to the North American Electric Reliability Corp., regional entities and owners and operators of critical electric infrastructure.
The bill gives the secretary six months to develop rules of procedure regarding the exercise of emergency authority. FERC would be permitted to order cost recovery for such actions assuming the costs were “prudently incurred and cannot reasonably be recovered through regulated rates or market prices.”
Entities complying with emergency orders would not be liable for violating the Federal Power Act, FERC orders or reliability standards as long as they did not act in a “grossly negligent manner.”
Another provision, Section 61002, clarifies that generators won’t be liable for exceeding emissions limits while operating under emergency orders. Such orders would be required to minimize environmental impacts and limited to 90 days but could be renewed.
Strategic Transformer Reserve
Section 61004 requires the secretary to submit a plan to Congress within a year for the development of a Strategic Transformer Reserve, including enough large transformers (100 MVA or higher) and trailer-mounted emergency mobile substations “to temporarily replace critically damaged large power transformers and substations that are critical electric infrastructure or serve defense and military installations.”
Wellinghoff a Lightning Rod
The provisions are a response to the April 2013 attack on Pacific Gas and Electric’s substation in Metcalf, Calif.
Metcalf Substation
At least two gunmen were believed involved in the attack on the 500/230-kV substation near San Jose, causing more than $15 million in damage that idled the substation for nearly a month. The gunmen targeted transformer radiators, firing an estimated 150 rounds and hitting 10 of 11 banks.
Wellinghoff, who served as FERC chairman from 2009 to 2013, called the Metcalf attack “the most significant incident of domestic terrorism involving the grid” to date.
The former chairman found himself under fire after The Wall Street Journal quoted him in articles about a confidential FERC analysis that concluded the country’s entire grid could be shut down for weeks or months by disabling only nine critical substations. Transformers are typically custom designed and can take 18 to 36 months to replace.
The newspaper did not identify the locations of those substations or its source for the study, but it quoted Wellinghoff saying “there are probably less than 100 critical high voltage substations on our grid in this country that need to be protected from a physical attack.”
NERC, members of Congress and Wellinghoff’s former FERC colleagues complained that the disclosures had jeopardized, not improved, security.
Wellinghoff also came under scrutiny in February, when Department of Energy Inspector General Gregory Friedman warned that FERC’s protection of information on the vulnerability of the grid is “severely lacking” and suggested that Wellinghoff had not been truthful when questioned about the disclosures. (See DOE IG Warns FERC Information Security ‘Severely Lacking.’)
Critical Electric Infrastructure Information
Section 61003 requires FERC to develop regulations governing how it classifies information as critical electric infrastructure information (CEII), including “appropriate sanctions … for commissioners, officers, employees or agents of the commission who knowingly and willfully disclose critical electric infrastructure information in a manner that is not authorized.” The section also exempts CEII from disclosure under federal, state or local public records laws.
The former chairman, currently a partner at the energy law firm of Stoel Rives, did not respond to a request for comment.
Pipeline Drills
The bill echoes steps taken by FERC and RTOs to improve gas-electric coordination following the 2014 polar vortex, when some fossil fuel plants had to shut down for lack of fuel.
It requires the energy secretary to improve DOE’s assessments of supply chain problems and to streamline processes for obtaining temporary regulatory relief to speed up emergency response. It also mandates emergency drills involving state and federal officials and oil and gas pipelines. (Section 61001, Emergency preparedness for energy supply disruptions.)
The final energy section, 61005, requires the secretary to propose within one year a method for evaluating how government policies impact energy supply and diversity, competitive energy markets, the U.S. balance of trade and national security.
The provision appears to be at least in part a response to complaints that EPA’s Clean Power Plan will weaken fuel diversity by replacing coal-fired generation with gas and renewables. Its sponsor, Rep. Richard Hudson (R-N.C.), opposes the EPA rule.
More to Do
In her own testimony before the House subcommittee last week, Commissioner Cheryl LaFleur suggested policymakers have more work to do.
“I think that the [reliability] standards that we’ve put in place, which require every transmission owner to identify the most critical facilities and protect them, are an important step,” she said. “But I think beyond that, a lot of the protection has to come from how we build the grid — building more redundancy so we kind of ‘de-criticalize’ those places so that a physical attack won’t cause as much damage, and building in more standardization so if something goes wrong we can share transformers more rather than having to build a custom one in every place.”
MISO’s research and development team has been tapped to take part in a Department of Energy project to design faster and more accurate generation dispatch software.
MISO is partnering with Pacific Northwest National Laboratory, General Electric’s Grid Solutions and Gurobi Optimization in the $3.1 million, three-year High-Performance Power-Grid Operation (HIPPO) project, which is being funded by the department’s Advanced Research Projects Agency-Energy (ARPA-E).
The project seeks to ease grid operators’ optimization challenge — dispatching the cheapest generation to meet loads while maintaining reliability — through algorithms that allow supercomputers to conduct multiple equations simultaneously.
Jeff Bladen, MISO’s executive director of market design, called HIPPO “a more robust approach to [security-constrained unit commitment] platforms that are used on a daily basis.”
“This has become increasingly challenging as the power grid grows in complexity, including the addition of intermittent renewable energy, new regulations and the increased use of natural gas and smart grid technologies,” Pacific Northwest National Laboratory said in a release on the project. “HIPPO could save consumers and power grid operators billions of dollars while also enabling greener and more sustainable grid operations.”
MISO Wants to Know if Data-Gathering Rule Spells Tariff Changes, Audits
MISO officials will be watching closely today as FERC conducts a technical conference on its Notice of Proposed Rulemaking requiring RTOs and ISOs to begin registering market participants through common alpha-numeric identifiers (RM15-23).
The NOPR, issued in September, would require market participants in RTOs to report extensive information about themselves and acquire a Legal Entity Identifier. FERC said the rule would aid its enforcement efforts by providing a way for identifying connections between companies and individuals. (See Are You Two Related? FERC Wants to Know.)
“We want to understand what the definition [of connected entities] is so we know what we need to do,” said Dustin Grethen, a credit analyst at MISO.
Grethen said MISO needs to figure out if it will have to replace the Tariff term of “affiliate” with “connected entity” and whether the RTO would be required to audit connected entities based on the information contained in the submission alone. “MISO wouldn’t be in a very good position to determine if [that data] is correct and right,” Grethen said.
Aaron Fate, MISO’s senior corporate counsel, said MISO found the NOPR a “little opaque.”
Stakeholders: Ramp Capability Needs Explanation Before Product Testing
Stakeholders called on MISO to provide more information before beginning testing of the RTO’s new ramp capability product in a month.
MISO expects to receive the software from its vendor this month, then have market participants take part in product testing in mid-January. The RTO is targeting an April 1 “go live” date pending a compliance filing with FERC.
The software is designed to alleviate net load variations by setting aside rampable capacity from the five-minute dispatch interval.
Dhiman Chatterjee, MISO’s senior manager of market analysis, said “more detailed discussion” is needed on whether the software will be programmed for the existing hourly integrated prices or new five-minute dispatch settlements.
MISO’s Kevin Larson said the software will be particularly helpful in managing wind generation.
Discussions on providing both up ramp capability and down ramp capability products began over two years ago, and some stakeholders said the information posted on the topic has grown stale.
“A lot of ramp capability information is from 2013,” observed Amber Metzker, Xcel Energy’s manager of market operations.
Likewise, Travis Stewart, a senior associate with Gabel Associates, asked MISO to update the Q&A document to reflect its most recent information. Jeffery Moore, with Ameren Missouri’s project management team, asked for a workshop to be held on the subject. Larson agreed; at press time, no date had been set for the workshop.
Testing, testing…
MISO is seeking to increase participation in its monthly load modifying resource drills.
Danielle Logsdon, senior project specialist, said the drills, held the second Tuesday of each month, exist to ensure reliability during shortage conditions and that generators know the process for emergency response.
According to MISO, as many as 55 market participants receive drill scheduling instructions every month. Of those, an average of six persistently take no action, even after MISO makes follow-up calls.
“Consistently, it’s the same [market participants] that do not participate,” Logsdon said.
MISO’s Demand Response Working Group asked that the Market Subcommittee take up the issue. Logsdon invited stakeholder suggestions on how to improve participation.
“I think the purpose for this surfacing is we’ve had the same level of non-participation from the same companies. That’s how they want to run their shop,” said DeWayne Todd, chair of the working group. Todd also asked stakeholders for suggestions on how to get non-participants involved in drills.
FERC last week granted Talen Energy’s request to sell four generators totaling 1,351 MW to satisfy divestiture conditions the commission ordered last year in approving the company’s spinoff from PPL and Riverstone Holdings (EC14-112-02).
The original order offered two divestiture options; the alternate proposal FERC approved last week was submitted by Talen in September. (See Talen Seeks Change in Divestiture Options.)
FERC said the plan was in the public interest and had a comparable effect on competition as the other options.
Talen already has announced sales agreements for the four plants.
One is the 399-MW Crane coal-fired facility in Baltimore, which is being purchased by an affiliate of Avenue Capital Group, a global alternative investment firm, for an undisclosed sum. (See Talen to Sell Crane, Gets FERC OK on Deals.)
The remaining three are in Pennsylvania: The 704-MW combined-cycle Ironwood plant is being sold to a subsidiary of TransCanada, based in Calgary, for $654 million. The Holtwood and Lake Wallenpaupack hydroelectric projects, with a combined generating capacity of 292 MW, are being bought by a subsidiary of Quebec-based Brookfield Renewable Energy Partners for $860 million. (See Talen Energy to Sell 3 Pa. Generators for $1.5 billion.)
Talen requested the third divestiture option after failing to negotiate a lease extension for its 158-MW combined-cycle plant in Bayonne, N.J., which was part of the original two options. The lease expires Oct. 31, 2018, and Talen has notified PJM that it intends to deactivate the plant the following day.
That plant provides steam to a tank terminal storage facility, which owns the land on which the generator sits. That facility is owned by a subsidiary of the Australian conglomerate Macquarie Infrastructure.
Macquarie filed the only protest to Talen’s divestiture request, saying the terms of Bayonne’s lease have been known for the past 28 years — contrary to Talen’s claims that the lease termination was “not foreseeable or reasonably certain to occur when Bayonne was first included in the mitigation options.”
In its protest, Macquarie said it made an offer to buy the facility, “but the second stage of the bidding process was canceled before completion.”
FERC’s decision allows Talen to retain a group of generators known as the “Sapphire Units.” To address the commission’s concerns of horizontal market power, Talen will offer them into the PJM energy market within the 5004/5005 submarket at cost-based offers.
Former FERC Commissioner Philip Moeller, who helped steer efforts to reform regional transmission system planning that became Order 1000, told an audience last week that it is time to take a look at compliance with the landmark 2010 rule.
Moeller told a TransForum East gathering in D.C. that he was “kind of a lukewarm supporter of Order 1000.” He decried what he called “Order 1000 fatigue,” saying that some compliance filings were on their third or fourth iteration, and he called for FERC to look at what is and isn’t working, and perhaps to make changes.
“I believe we’ve spent way, way, way too much time talking about the cost of transmission and way, way, way too little time talking about the value of transmission,” he said. “The debate really focuses on cost, whereas I think the debate really should focus on value.”
A U.S. District Court judge has dismissed a suit that sought to overturn Virginia’s 1982 moratorium on uranium mining.
Virginia Uranium and three other companies sued Gov. Terry McAuliffe and various other state officials after Virginia denied a permit to mine an estimated 119-million-ton uranium deposit in Pittsylvania County. Judge Jackson L. Kiser said that since the moratorium dates to 1982, long before McAuliffe was in office, current officials couldn’t be named in the suit.
Kiser also dismissed the plaintiffs’ argument that the federal Atomic Energy Act of 1954 gives the federal government sole regulatory authority over safety concerns at the heart of the state’s moratorium. The federal act, the judge said, “institutes no permitting regime respecting nonfederal uranium deposits’ conventional mining and does not otherwise regulate nonfederal uranium deposits or their conventional mining.”
The Department of Energy and Israel’s Ministry of National Infrastructure, Energy and Water Resources chose six joint American and Israeli clean energy projects to receive $5.1 million in funding. Energy Secretary Ernest Moniz said the Binational Industrial Research and Development Energy Program will help both countries develop cleaner energy.
The projects include remote metering and analytic tools for smart grids by Jerusalem-based Ayyeka Technologies and Michigan-based UIS Holdings ($1 million); and the development of software that would assess threats to birds by wind farms, by The Hebrew University of Jerusalem and New York-based Applied Biomathematics ($500,000).
Just three months after admitting that its push into green energy wasn’t producing returns for shareholders, NRG Energy CEO David Crane announced his resignation. Chief Operating Officer Mauricio Gutierrez will assume the role.
Under Crane’s helm, NRG launched a billion-dollar push into rooftop solar, wind energy and car charging stations. But the company in September announced plans to return to its core conventional generation business. NRG stock has plummeted 60% so far this year.
Crane took over as CEO in 2003, when it was a regional power producer in bankruptcy. It became one of the nation’s largest owners and operators of solar facilities.
NRG Energy said it is selling two power plants for $138 million to reduce debt and improve cash flow.
In one of his last official announcements before resigning, NRG CEO David Crane said the plant sales are part of a “reset” process. “By streamlining our fleet, we can create additional value for our shareholders and meet the needs of our customers with reliable, efficient and economic power,” he said.
NRG is selling its 535-MW, waste coal-fired Seward plant in Pennsylvania to Robindale Energy Services and its 352-MW, natural gas-fired plant in Shelby County, Ill., to The Woodlands-based Rockland Capital. NRG said the two plants would need about $17 million in maintenance in the next three years.
Alliant has said it will close its Dubuque Generating Station on Iowa’s eastern border in June 2017. The Mississippi River plant, which used coal as a fuel source before being converted to gas four years ago, only ran occasionally and was not necessary to maintain system reliability.
Alliant this year settled EPA allegations of Clean Air Act violations, agreeing to close the plant in 2019 or face fines. The facility’s 13 employees will be offered positions at other plants.
Alliant has no plans to sell the property, where a power plant has been in operation for more than a century. If it does, the city of Dubuque has first rights to buy it.
Google announced it has signed six deals on three continents to buy 842 MW of clean energy, bringing its worldwide renewable power purchases to more than 2 GW. Google said it now supplies 37% of its power needs with renewable energy, and the company eventually wants to power all 14 of its data centers with green energy.
“We’re going to get renewable energy any way we can, no matter what it takes,” said Michael Terrell, who leads energy policy and market strategy for Google’s global infrastructure team. The new purchase of solar and wind energy is enough, as Wired pointed out, to power two cities the size of San Francisco.
Duke Energy was involved in several deals with the search giant: One in North Carolina for 61 MW of solar from a project in Rutherford County; and two others in Oklahoma for 401 MW of power.
FirstEnergy named Brian A. Farley vice president of sales, where he will be responsible for strategic planning and day-to-day operations. The division includes the governmental aggregation, large commercial and industrial, and residential and municipal channels.
Farley, who joined FirstEnergy in 1989, most recently was director of wholesale and provider-of-last-resort transactions.
He holds a bachelor’s in electrical engineering from Cleveland State University and a master’s in business administration from Baldwin Wallace University.
The law firm of Frost Brown Todd is opening a Pittsburgh office with the addition of 10 attorneys formerly with law firm Burleson. The attorneys will join the firm’s energy industry practice.
The office is the firm’s 12th and expands its presence to eight states. Kevin Colosimo is the member-in-charge of the new office.
Energy Future Holdings won bankruptcy court approval last week to shed about $30 billion in debt and split into two separate companies.
The bifurcated EFH can exit bankruptcy in a few months, provided that Texas regulators bless the reorganization and the company wins an Internal Revenue Service endorsement of the tax structure behind the deal. Luminant, the company’s unregulated generating business, will go to senior lenders, who are owed about $24 billion. Oncor, the regulated transmission unit, will go to a coalition of lower-ranking creditors and Hunt Consolidated, a Dallas-based energy and real estate company.
With lower debt, the two companies should be in a better position to weather the difficult market conditions that caused the $48 billion leveraged buyout to flounder about seven years after it was completed under the leadership of KKR and TPG Capital. The new plan wipes out the buyout sponsors’ equity.
EFH Agrees to $2M Settlement over New Mexico Uranium Mines
Energy Future Holdings has agreed to pay $2 million to help EPA clean up closed uranium mines it owns in northwest New Mexico.
The agreement, filed Dec. 1, settles a dispute with the Justice Department, which objected to the company’s bankruptcy plans, claiming EFH was trying to skirt its environmental responsibilities. According to court papers filed by the government, EPA found uranium contamination was still present decades later after a now shuttered subsidiary extracted uranium from four New Mexico mines in the 1970s and 80s.
The agency estimated the cost of the cleanup at $23 million.
Luminant Acquiring 2 Gas Plants for $1.6B from NextEra Energy
Luminant, the power generation subsidiary of Energy Future Holdings, is buying two Texas gas-fired power plants for $1.6 billion from NextEra Energy Resources. The deal is expected to close in the first quarter of 2016.
Luminant said its purchase of the 1,912-MW Forney Energy Center and the 1,076-MW Lamar Energy Center in Paris have been approved by the U.S. Bankruptcy Court in Delaware, which is overseeing the reorganization of EFH.
Southern Co. Buys 51% Interest in Texas’ Largest Solar Farm
Southern Co. is buying the controlling interest in a 157-MW planned Texas solar farm, its first solar investment in the Lone Star State.
The Atlanta energy giant said it bought a 51% stake for an undisclosed sum in the planned Roserock solar facility in West Texas near Fort Stockton. Canadian Solar Inc., which is developing the project, will retain 49% ownership through its Recurrent Energy subsidiary.
The Roserock solar farm will provide power to the city of Austin and surrounding areas through a 20-year power purchase agreement with municipally owned Austin Energy. Roserock is one of the largest solar facilities planned in Texas.
El Paso Customers Oppose Proposed $71.5M Rate Increase
About 20 people gave El Paso Electric’s proposed $71.5 million rate increase a thumbs down at an El Paso City Council hearing Dec. 2. The utility is seeking a 10.15% rate of return.
Most of those speaking at the hearing were solar advocates. They included homeowners with solar rooftop systems who said their rates would increase more than other residential customers, and solar system installers who said the utility’s proposed new rate class for residential solar customers would discourage consumers from embracing renewable energy.
Representatives of Western Refining’s El Paso refinery, the utility’s largest customer, said the proposed increase has prompted the company to begin exploring the possibility of generating its own electricity.
Aksamit Resource Management announced plans to build three wind farms generating 449 MW in southeastern Nebraska, representing a $725 million investment.
The developer said it has filed with SPP for permission to hook up two of the wind farms to transmission lines owned by the Nebraska Public Power District. The projects include a 150-turbine farm spread over 30,000 acres with a capacity of 300 MW and a 76-MW project with 40 turbines on 8,000 acres.
Aksamit said a third project, a 40-turbine farm in Saline County that can produce 73 MW, will be up and running within the next two years.
CARMEL, Ind. — MISO would reduce the price tag to enter its generator interconnection queue and provide “off ramps” for canceled projects under a final proposal presented Monday to the Planning Advisory Committee.
RTO officials said they reduced a proposed $60,000 refundable deposit for study models based on stakeholder feedback. Instead, interconnection customers would have to pay a non-refundable $5,000 study deposit.
Vikram Godbole, senior manager of MISO’s generator interconnection planning group, said the non-refundable charge facilitates trust between the RTO and interconnection customers. “We need to have a relationship with interconnection customers before providing models because there’s a lot of non-public information in these models,” Godbole explained in a presentation during a special PAC meeting.
Discussions on the proposed reforms will continue at the Dec. 16 PAC meeting, after which the proposal will open to a final round of stakeholder comments. MISO plans to file Tariff changes by the end of the year, Godbole said.
In addition to reducing the study fee, MISO has also cut its proposed M4 milestone by half; the new M4 cap will be set at $5,000/MW instead of $10,000/MW. The proposed $2,000/MW floor remains intact. MISO said it was responding to stakeholder comments that existing milestones are high and act as a barrier to entry.
Additionally, MISO has relaxed some rigidity surrounding its queue, allowing interconnection customers to receive M2, M3 and M4 refunds on projects that withdraw before the first decision point, which doesn’t occur until customers have the results of a system impact study.
Customers can also request provisional interconnection service up until their first decision point. Interconnection customers that request provisional interconnection service can now cancel their request, forgoing money spent on studies up to the cancellation date, and enter the definitive planning phase cycle.
“I think what we’ve done here is made this more flexible. If you want to proceed, that’s fine. If you don’t want to proceed, that’s fine too,” Godbole said. “The fact that we have these off-ramps built in; we expect that some interconnection customers will use them. I’m hoping these off-ramps will really help interconnection customers decide whether to get their M2 back.” MISO’s current queue doesn’t allow for the refund of M2 payment for withdrawing projects.
MISO has also eliminated the potential for restudies after customers execute a generation interconnection agreement.
“If any conditions change, we’re not going to rope you back into a restudy,” Godbole said.
“With the queue reform, one of the main goals was certainty,” MISO Director of Interconnection and Planning Tim Aliff said, explaining that if interconnection customers “have done their homework” on project feasibility and economics before entering the queue, M2, M3 and M4 payments will come back to them.
Aliff added that projects that withdraw and forfeit milestone payments will benefit other projects that complete generation interconnect agreements. “Your costs are offset by what others have left in the bucket,” he said.
Godbole said MISO has explored three transition options to the new queue rules, which are expected to take effect in February. In all three, MISO will grant existing projects priority over projects that have yet to join the queue. Interconnection customers will have the opportunity to request provisional agreements during the transition period to the new queue rules.
Godbole said MISO will produce a study calendar of pertinent dates after a transition plan is finalized.
“It’s in our best interests to do everything as quickly as possible,” Godbole said. He added that MISO plans to file Tariff changes by the end of the year. Discussions on queue reform will continue on Dec. 16’s Planning Advisory Committee where no formal action is anticipated. The queue reform proposal will then move into a stakeholder comment period.
WASHINGTON — Having achieved a settlement with Mayor Muriel Bowser’s administration, Exelon and Pepco Holdings Inc. tried to persuade the D.C. Public Service Commission over the course of three days of hearings last week that their nearly $7 billion merger is now in the public interest.
Carim Khouzami, chief integration officer for Exelon, and David Velazquez, Pepco’s executive vice president for power delivery, were among those whom Chairman Betty Ann Kane and Commissioner Joanne Doddy Fort questioned on the details of the settlement. Commissioner Willie Phillips did not ask any questions.
Regulators unanimously rejected the deal in August, finding that it was not in the public interest. The Bowser administration brokered the settlement, which was filed in October. D.C. is the last jurisdiction needed to close the deal, with New Jersey, Maryland, Virginia, Delaware and FERC all having given their approval. (See Mayor’s Settlement Puts DC PSC on the Spot in Exelon-Pepco Deal.)
“In retrospect, we realize that our failure to present a settlement agreement made it a very difficult task for this commission to find the merger was in the public interest,” Peter Meier, vice president of legal services for Pepco, said in an opening statement. “We’re here today because a settlement was agreed to.”
Rate Impact
The D.C. commissioners questioned the officials about the logistics of the settlement: how rate credits would appear on customers’ bills, what the structure of the new company would look like and whose overdue bills would be forgiven.
DC Commissioners at the hearing, left to right: Commissioner Joanne Doddy Fort, Chairman Betty Ann Kane, Commissioner Willie L Phillips (Source DC PSC)
Kane was interested in how the promised credits would protect against rate shock. Exelon promised $14 million in direct credits to residential customers and $25.6 million in credits to offset future rate increases the company expects to file. Kane estimated that the distribution portion of customers’ bills would jump 20 to 30% in 2019 after the $25.6 million ran out.
“Ultimately the rate cases are the determination of the commission [and] what they see as reasonable and prudent,” Khouzami said. But “with this commitment, $25.6 million worth of rates will never be paid by customers.” Without the merger, Pepco would still seek similar levels of rate increases and “customers would still be subject to that without an offset,” he said.
Fort asked how $5.2 million in contributions to district workforce development programs constituted a “direct and tangible benefit” to ratepayers, required to prove the merger is in the public interest.
In a pre-hearing brief, Velazquez said the contribution will provide training to district residents in “sustainable jobs.”
At the hearing, however, the executives were vague about the types of jobs residents would be trained for in the workforce development programs, and what exactly was meant by “sustainable.”
Residents would get “a skill set needed to get a good-paying, secure, sustainable job in the district that will help benefit them for years to come, so I think there’s a true benefit here,” Khouzami said. The companies have not made a firm commitment to hiring residents who participate in the programs, he said in response to a question from Fort. The funds are “really intended to provide the job training needed so that individuals can actually select the job that they want, whether it’s at Pepco or somewhere else in the district.”
“It is my hope that through this program, we’ll also be working with the district and having a discussion about the type of jobs that Pepco will need as we move forward with the grid of the future,” Velazquez said. “These are jobs that are related to helping drive renewable energy, driving energy efficiency, driving microgrids, driving the smart grid. All those things are going to help create a more sustainable electric grid and a more sustainable use of electric energy.”
District Official also Questioned
The director of the district’s Department of Energy and Environment, Tommy Wells, was the first witness questioned by the commission on Wednesday.
The commissioners peppered Wells with questions about how money in the district’s Renewable Energy Development Fund and the Sustainable Energy Trust Fund has been used to make up for shortfalls in the district’s general fund. Under the settlement, Exelon will contribute $3.5 million to each fund.
DC’s Tommy Wells testifies (Source DC PSC)
Wells admitted that transfers from the energy funds, which must be approved by the D.C. Council, are not prohibited under the settlement. But, Wells said, “it is completely in alignment with the plans and vision for this administration to expend those funds exactly as they’ve been negotiated.
“I can’t speak to the whims of the council, but I believe the council” will respect the intent of the administration, Wells said.
Wells, like Khouzami and Velazquez, was also vague about the workforce development funds. Fort asked what agency would receive them.
“That’s a great question because we’re working on that now,” Wells answered. He mentioned the University of the District of Columbia and the Department of Employment Services as possible candidates, but it’s not clear yet if the money would even go to the government, he said. If it does, City Administrator Rashad Young would ultimately decide which agency receives the funds, he said.
Wells also said “sustainable” jobs was meant to refer to both green and long-lasting jobs.
Wells was questioned first at the request of the D.C. government, as he had to catch an afternoon flight to Paris, where he accepted an award for green energy on behalf of the district from the C40 Cities Climate Leadership Group. The group, comprising 78 cities around the world, honored the district for its 20-year power purchase agreement with Iberdrola Renewables that will supply 30% of the government’s electricity through wind power.
The announcement of the award — which was followed by applause in the room — came during the hearing on Thursday, as Pepco cross examined Bruce Burcat, executive director of the Mid-Atlantic Renewable Energy Coalition. Iberdrola is a member of MAREC, which opposes the merger.
Looking Ahead
With the administration and the district’s public advocate on its side, Exelon’s chances appear to hinge on winning over Kane or Fort.
Phillips had issued a partial dissent in August, saying that he would have supported a merger that would have brought “benefits for ratepayers, the local economy and the environment.”
The settlement brokered by the Bowser administration includes $78 million in customer benefits, up from $14 million in the company’s original offer.
Post-hearing briefs are due Dec. 16, with reply briefs due Dec. 23. The record will then close, starting the countdown to a commission decision.
On Monday, four councilmembers sent an 11-page letter to the PSC urging it to reject the deal, saying it offers “short-term benefits that in the long-term have detrimental costs.”
The cost allocation of three of the projects would change significantly in the absence of the wheel.
