Page 1402 – RTO Insider

May 9, 2016

MISO Market Subcommittee Briefs

MISO is seeking stakeholder input on how to revise its energy offer cap rule while awaiting guidance from FERC for developing a final rule.

“If we have some of the groundwork laid out for the final rule, we’ll be in better shape,” said Chuck Hansen, a MISO senior engineer.

The RTO has queried market participants about changing the operating reserve demand curve and whether to remove — or increase — the $3,500/MWh LMP cap.

This winter is likely to see a repeat of the “temporary” solution implemented the past two years, in which the RTO used revenue sufficiency guarantees to cover costs exceeding the offer cap. (See MISO: No Change to Energy Offer Cap this Winter.)

In January, FERC issued a Notice of Proposed Rulemaking that would require offers more than $1,000/MWh be verified before being used to calculate LMPs. Offers not verified in time for market clearing would become eligible for a make-whole payment. (See FERC Proposes Uniform Offer Cap Across RTOs.)

Market participants became concerned about the hard cap in 2014 when natural gas demand spiked during extreme cold. Although inefficient generators were called up, offers more than $1,000 never materialized.

“The MISO market is becoming more and more dependent on natural gas,” Hansen explained. “The problem with this is if we actually clear and commit these units,” their costs would be higher than offers allow.

While MISO generally supports FERC’s proposals, it prefers that administrative caps be gradually relaxed to provide incentives for competitive offers so the need for “artificial, administrative caps” would disappear, Hansen said.

“We thought [FERC’s NOPR] was a reasonable compromise between protecting customers and potential exercise of market power, [and it] sets appropriate prices during periods of high fuel cost,” Hansen said. “Eventually we’d like to see the offer caps be relaxed to the point where they’re not getting in the way of valid offers.”

MISO said that over time, new technologies and new demand response will supplant offer caps with more efficient pricing during scarcity situations.

MISO currently uses a $3,500/MWh LMP cap, which reflects the cost of firm load shedding. Hansen said that amount is adequate — for now.

“The $3,500/MWh works with the current experience, but there’s not a lot of room,” Hansen said.

Hansen said MISO must consider the different verifiable costs among external asynchronous resources, hydro, storage, demand response, imports and virtual supply.

‘Modest’ Price Impacts as Extended LMP Enters Phase 2

Extended locational marginal pricing (ELMP) will enter a second phase of implementation despite its limited effect on energy prices a year after its introduction.

ELMP is intended to improve the way the security economic dispatch (SCED) algorithm calculates LMPs and sets market-clearing prices. The practice was designed to reduce uplift charges by allowing certain fast-start resources that are either offline or scheduled at their limits to set clearing prices.

Clearing prices under SCED often fail to compensate fast-start units for their start-up costs, necessitating use of revenue sufficiency guarantees.

According to MISO market design engineer Congcong Wang, stakeholders generally support roll-out of the second phase, which will allow 30-minute fast-start resources into the program. Currently, only real-time scheduled units with 10-minute start times and an hour or less of minimum runtime are eligible to set real-time energy prices under ELMP.

Wang said the inclusion “captures more fast-start schedules.” Including resources with a 60-minute start time would not make as much of a difference on prices, she said.

Wang noted that stakeholders also want offline units included in the price-setting process if those units “appropriately reflect system conditions.”

In the meantime, MISO is studying cases from last winter to evaluate price impacts and determine if offline fast-start resources are “truly available and economic.” Wang also said MISO will create a “recommendation tool” that lists eligible ELMP offline fast-start resources for operators to manage shortages or congestions.

MISO will present its findings at the August Market Subcommittee meeting.

MISO Independent Market Monitor David Patton said ELMP’s impact on prices has been “modest.” (See MISO Monitor: Extended LMP Changes Minimal Thus Far.) The practice only lifted real-time prices by about a penny per megawatt-hour in spring 2015, and reduced them by almost 8 cents in summer and 3 cents in fall. Day-ahead market impacts were even lower.

That minimal effect was a product of the limited number of units eligible to set prices under ELMP, Patton said. Units with a 10-minute start time account for just 2% of total peaking resources.

Patton advocates expansion of ELMP, saying MISO could capture 90% of peaking units in the real-time market if it expanded the practice to include resources with two-hour minimum runtimes and 30-minute startup times, as well as those committed in the day-ahead market.

“There’s no clear reason for day-ahead units not to contribute to price setting,” Patton said. He said no software changes would be required if MISO allowed 30-minute fast-start resources — representing 12% of peakers — to be eligible in the second phase of ELMP.

However, the Monitor recommended suspending offline price-setting in LMP, saying that although the offline units are economic, “analysis indicates that the units setting prices are rarely utilized.”

Sunset on Financial Transmission Rights Working Group

The MSC approved retirement of the Financial Transmission Rights Working Group and will absorb tasks associated with financial transmission rights and auction revenue rights.

Working group Chair Brad Arnold said the group agrees with a MISO proposal last month to sunset the group.

“The only request was stakeholders continue to have access to FTR reports and continued MISO support,” Arnold said.

Zakaria Joundi, MISO liaison to the working group, said a decrease in agenda items and stable FTR funding prompted the move. He added that MISO will continue to post FTR and ARR reports on a monthly basis as needed.

Joundi also noted that MISO subject matter experts will respond to inquiries about the reports, and that the RTO could always create a task team in the future if a specific FTR issue arises.

— Amanda Durish Cook

May 9, 2016

Vermont Green Line Developers Seek New York Permit

By William Opalka

The developers of an underwater transmission project that would deliver hydroelectric and wind power into New England filed for permits last week for the New York section of the project (16-T-0260).

Anbaric Transmission and National Grid filed for a certificate of environmental compatibility and public need with the New York Public Service Commission for their Vermont Green Line. The project would connect 400 MW of wind generation to be developed in northern New York to Vermont through buried lines under Lake Champlain. The wind power would be supplemented by hydropower from Quebec, to provide firm power to ISO-NE.

The northern New York-Vermont border runs down the middle of the lake. The HVDC system would run from the New York Power Authority’s Plattsburgh substation in Beekmantown, Clinton County, to Vermont Electric Power Co.’s New Haven substation in Addison County. The New York portion of the project includes 6.7 miles of buried HVDC cable from a converter station to the shoreline of Lake Champlain at Point Au Roche State Park and about 4.9 miles underwater on the New York side of Lake Champlain.

The Vermont section of the project will include 35.2 miles of underwater HVDC cable, a converter station and 13.3 miles of buried line to the New Haven substation.

The project will also need approval from the Vermont Public Service Board. Bryan Sanderson, senior vice president of Anbaric Transmission, told RTO Insider on Wednesday that the companies plan to file with Vermont this summer.

Invenergy is developing the Bull Run Wind Energy Center in Clinton County, pending approval from state regulators. The proposed development would have as many as 140 turbines, with an in-service date projected for 2019.

The overall project, with energy also supplied by Hydro-Quebec, has been dubbed the “wind-hydro response” to the request for proposals solicited by three New England states to procure renewable energy for the region. The proposal is one of about 30 submitted to Connecticut, Massachusetts and Rhode Island now under review. (See State-Sponsored Energy Procurement Moves Ahead in NE.)

The hydro generation would flow into New York via a transmission connection between Hydro-Quebec and NYISO at Chateauguay, Quebec, according to Sanderson.

If the project is selected, the developers would then file with FERC for negotiated rate authority, he added.

“We think the Vermont Green project is well timed to provide the region with a reliable, clean energy source of hydro firming wind,” Sanderson said.

While the wind project is aimed at the New England market, developers say it will provide benefits to New York as well, including meeting the state’s goal to procure 50% of its energy from renewable sources by 2030.

“The project will provide an ‘energy bridge’ that will allow additional development of new wind energy in upstate New York that would otherwise be constrained and uneconomic given the existing infrastructure for delivery to load centers in New York,” according to an economic analysis filed with the NYPSC.

When the hydroelectricity from Canada is more than what is needed to firm the wind energy destined for New England, that excess would be available to the New York market, according to the analysis.

May 6, 2016

Absent Legislation, Exelon to Close Clinton, Quad Cities Nukes

By Suzanne Herel

Exelon said it will close the Clinton Power Station next summer and the Quad Cities facility the following year if Illinois legislators fail to pass a bill to shore up the money-losing nuclear plants and Quad Cities does not clear PJM’s 2019/20 capacity auction this month.

“Without adequate legislation, we no longer see a path to profitability and can no longer sustain ongoing losses,” CEO Christopher Crane said on Friday’s first-quarter earnings call with analysts.

Together, the plants have lost $800 million in cash flow from 2009 to 2015, he said.

“For reasons outside of our control, we have not seen progress in Illinois policy reform,” Crane said. “In order to reverse course, we would need Illinois to cover our cash costs and operating risk.”

exelon, clinton, quad cities — Clinton Nuclear Plant *Source: Exelon*

The Clinton plant would be shuttered June 1, 2017, and the Quad Cities station would cease operations one year later.

The closures would represent the loss of $1.2 billion in economic activity and 4,200 in direct and indirect jobs, Crane said. Together, the plants employ 1,500 workers.

The company last year deferred a decision on closing the generators pending the outcome of MISO’s 2016/17 Planning Resource Auction, held last month, and PJM’s Base Residual Auction, the results of which will be known May 24. Last year, for the second year in a row, the 1,819-MW Quad Cities plant did not clear the PJM auction. (See Reactor to Participate in 2016 Auction.)

While the 1,065-MW Clinton plant won contracts in the MISO auction, its clearing price is “insufficient to cover cash operating costs,” Crane said Friday, noting that power prices have fallen to a 15-year low.

“We are not covering our operating costs or our risk, let alone receiving a return on our investment capital,” he said.

Exelon last year backed legislation that would have ensured continued operation of its ailing nuclear power plants with a $300 million annual charge paid by Commonwealth Edison and Ameren customers.

Under the Low Carbon Portfolio Standard (SB1585, HB3293), 70% of the electricity delivered by ComEd, an Exelon subsidiary, and Ameren would have to be generated by “clean energy” sources, including nuclear. (See Exelon-Backed Bill Proposes Surcharge to Fund Illinois Nukes.)

Illinois legislators, however, declined to act on the bill, or on other energy legislation put forward by ComEd, Exelon or the Clean Jobs Coalition, environmental and consumer advocates who sought to boost energy efficiency and wind and solar power.

On Thursday, Exelon and ComEd announced they would be supporting new legislation, the Next Generation Energy Plan, which Exelon said contains parts of their previous legislation and the Clean Jobs bill.

A key new element in the plan, Exelon said, is a shift to a zero-emission standard.

“The zero-emission standard addresses stakeholder concerns by requiring full review of plants’ costs by state regulators and by ensuring that only those plants that can demonstrate that revenues are insufficient to cover their costs and operating risk will be entitled to receive compensation,” the company said in a release. The model is similar to Gov. Andrew Cuomo’s plan to save New York’s struggling nuclear plants, including Exelon’s R.E. Ginna. (See New Lifeline for FitzPatrick Nuclear Plant.)

Exelon Executive Vice President Joe Dominguez said on a call with reporters Thursday that Clinton and Quad Cities are expected to lose “well over $100 million” next year, signaling that that would be the amount of state assistance for the two plants.

The bill also would double energy efficiency programs in Illinois and provide $140 million per year in funding for solar development. The companies estimate the plan would result in a 25-cent monthly increase in the average ComEd residential customer’s bill.

Just as they were last year, legislators continue to debate the state budget, and their session ends this month.

Also Friday, Exelon announced its first quarter earnings following the $6.8 billion acquisition of Pepco Holdings Inc. (See Exelon Closes Pepco Merger Following OK from DC PSC.) Operating revenue dropped 14% to $7.57 billion. The company reported a profit of $173 million (19 cents/share), down from $693 million (80 cents/share).

May 5, 2016

Dynegy to Shutter 3 Ill. Coal Plants; Blames MISO Market Design

By Amanda Durish Cook

Dynegy said it will idle at least three coal-fired units in Central and Southern Illinois beginning in the fall, saying the merchant units can’t recover their costs from MISO’s energy and capacity markets.

dynegy, miso, coal plants — Baldwin Energy Complex

Dynegy said the three 40-year-old coal units totaling 1,835 MW — Units 1 and 3 at the Baldwin Power Station and Unit 2 at the Newton Power Station — are unable to recoup their operating costs because of current energy and capacity market prices. In MISO’s Planning Resource Auction in April, Zone 4 cleared at $72/MW-day, a 50% drop from a year earlier. (See MISO’s 4th Capacity Auction Results in Disparity.)

The company also said it’s considering closing another 500 MW of coal-fired capacity in Zone 4, though it didn’t name specific plants, with a final decision due later this year.

Including Dynegy’s 465-MW Wood River Power Station — which it previously announced would shut down in June — the planned suspensions would remove 2,800 MW of generation, about 30% of the capacity in Southern Illinois.

At a Thursday meeting of MISO’s Resource Adequacy Subcommittee, Dynegy Director of Regulatory Affairs Mark Volpe clarified the company’s stance on the closures. “I want to be clear that we plan to suspend, not retire. Those units could come out of suspension given the right compensation,” he said.

The company said competitive generators in Zone 4 cannot cover their operating costs under the existing MISO market design because out-of-state generators receiving regulated revenues from their home states are suppressing capacity and energy prices. “If Newton and Baldwin were located in PJM, as Northern Illinois plants are, or Zone 4 was regulated as the other MISO generators outside of Illinois are, no shutdowns would occur,” the company said in its announcement Tuesday.

“This is a losing model that exports Southern and Central Illinois jobs and economic base to the surrounding states, resulting in a catastrophic economic outcome for downstate Illinois,” Dynegy CEO Robert Flexon said. “Central and Southern Illinois competitive units in MISO Zone 4 are wrongly grouped with out-of-state utilities rather than the competitive power producers in Northern Illinois and PJM. This must change.”

Dynegy said it was seeking relief from state policymakers because it wasn’t convinced MISO — whose “membership is overwhelmingly represented by out-of-state utilities that reap the benefits of the existing market design” — would make needed design changes.

In March, the RTO proposed a three-year forward capacity auction similar to PJM’s for its deregulated markets. (See MISO Proposes Adding Forward Auction for Retail Choice Zones.) Dynegy and Exelon had floated a similar idea in February, but Exelon has said MISO’s proposal falls short. (See Stakeholders React to MISO Proposed Auction Design.)

Unless MISO determines the units are needed for reliability, Dynegy said, Newton Unit 2 will stop operations in September, with Baldwin Unit 1 following in October and Unit 3 in March 2017. The shutdowns will leave one unit apiece still functioning at the Newton and Baldwin locations. Dynegy purchased the Newton plant from Ameren three years ago along with four other coal plants, as Ameren departed the Illinois market.

“In the limited time left before closures occur, we are ready to work quickly with MISO, the state of Illinois, union leadership and all stakeholders to rectify the situation and preserve the jobs and economic base in downstate Illinois,” Flexon said.

Flexon lamented that Illinois officials’ only response so far has been to file a complaint against the Houston-based utility over its bidding in the 2015 capacity auction. (See FERC Launches Probe into MISO Capacity Auction.)

May 5, 2016

Texas PUC Delays Rehearing Request on Oncor Acquisition

By Tom Kleckner

The Public Utility Commission of Texas agreed Wednesday to wait until no later than June 10 before determining whether to grant a rehearing on its decision to allow Hunt Consolidated’s acquisition of Oncor.

The commission granted the extension partly to allow time for review of the flood of filings that followed the May 1 announcement by Oncor’s debt-laden owner, Energy Future Holdings, that it had filed a new Chapter 11 reorganization plan. (See EFH Files New Chapter 11 Plan; Oncor-Hunt Deal in Doubt.)

The PUC will resume the discussion of whether to grant the Hunt group’s rehearing request at its May 19 open meeting. The intent is to make a decision then, rather than extending the timeline until its next meeting on June 9.

“I think we can make a decision on the 19th whether we can grant a rehearing,” Commissioner Ken Anderson said. “At the very least, we should discuss our position on the issues raised by the parties. I guess we’re probably decided on 80% of those issues now.”

The commission in March approved the Hunt group’s proposal to split Oncor into two companies, with a real estate investment trust (REIT) leasing the utility’s wires, poles and other assets to the second company. (See Texas Commission Approves Oncor REIT Structure.)

However, the commission’s requirements that the REIT’s tax savings be set aside for customers led to EFH’s investors pulling their support for the deal. That, in turn, led to EFH killing its original bankruptcy exit plan last weekend and filing a new one.

Anderson is widely seen as the swing vote in the three-person commission’s eventual decision. Chair Donna Nelson has often sided with the Hunt group’s position, while Commissioner Brandy Marty Marquez has supported the restrictions placed on the deal.

“Is there even a transaction for us to still approve?” Anderson asked.

Two opposing groups, the Steering Committee of Cities Served by Oncor (comprising about 150 Texas cities) and the Texas Office of Public Utility Counsel, argued the commission should dismiss the rehearing request.

“The [bankruptcy exit] plan is dead, according to the bankruptcy court,” Geoffrey Gay, lead attorney for the cities coalition, told the commission. “If I was in your position, my gut reaction is this case no longer exists. You’re being asked to proceed on a hypothetical basis.”

“We believe the transaction is null and void,” said Laurie Barker, deputy public counsel for the OPUC. “While the Hunts do have an opportunity to negotiate and possibly become the next plan, there are other potential investors and plans out there as well. If we allow one entity to come before you with their preferred plan, you would have to allow all.”

Richard Nolan, an attorney for the Hunt group, said turning Oncor and its assets into a REIT is still a viable option for the bankruptcy process. He said the door has been left open for creditors and the court to approve the structure under the reorganization plan, “and we intend to pursue that.”

“We’ve receive a lot of interest from investors,” Nolan said. “To the extent we can make this work … that offers the opportunity to avoid going through another six months of proceedings. We realize the plan that was selected will have to conform to whatever the final order is.

“We think if that’s done, that would be the quickest way for the debtors to exit the bankruptcy proceeding without going through another six months and delay the process. That also gives the commission an opportunity to shape, to some degree, a plan that would be workable and approved by the [bankruptcy] court.”

Commission staff also requested an extension, saying “new developments in the EFH bankruptcy proceeding raise new issues that may affect this … proceeding.” Staff said they needed sufficient time to “identify and address any new issues.”

“I think you maintain maximum flexibility with your options if you extend time for the rehearing,” PUC attorney Sam Chang said.

EFH, saddled with $42 billion in debt following its leveraged buyout of TXU Corp. in 2007, filed its first bankruptcy exit plan in Delaware two years ago. In December, a U.S. bankruptcy judge approved the company’s plan to split into separate companies — Oncor, Luminant and TXU Energy — wiping out the buyout sponsors’ equity. The Luminant and TXU Energy businesses would go to senior lenders owed about $24 billion.

May 2, 2016January 18, 2024

Company Briefs: May 2, 2016

Southern Co. subsidiary Mississippi Power said its repeatedly delayed Kemper Project, now scheduled to become operational on Sept. 30, continues to mount up expenses.

In the latest tally, Mississippi Power spent another $61 million, pushing the total up to $6.7 billion. The low-carbon-emitting plant was initially estimated to cost $2.9 billion. The company is eating $2.7 billion of the cost overruns, but customers may eventually be on the hook for as much as $4.3 billion.

More: The Associated Press

Exelon Agrees to Help Fish Through Dams

In an attempt to restore threatened populations of American shad and herring, Exelon Generation said it will make improvements to four of its hydroelectric plants to allow the fish to more easily pass through for breeding.

Exelon Power President Ron DeGregorio called the agreement “a significant step toward the Fish and Wildlife Service’s goals to restore American shad and river herring populations on the Susquehanna River.” While Exelon improves the fish-lift system at the dam, the “trap and transport” program will allow fish from both species to bypass the barriers on their upstream migration.

The U.S. Fish and Wildlife Service has set a goal of restoring 2 million American shad and 5 million herring above four Susquehanna River dams.

More: Central Penn Business Journal

Cisco Systems Buying Clean Energy from Duke

Cisco Systems is buying renewable energy from Duke Energy for its Research Triangle campus near Raleigh through Duke’s Green Source Rider program.

Cisco is the second major technology company, after Google, to join the program. Cisco will purchase power and renewable energy credits for two 5-MW solar projects near Charlotte.

Duke spokesman Randy Wheeless said a third client has signed up for the program, but the company isn’t ready to release information on that customer.

More: Charlotte Business Journal

Oil Company Scraps Plans For Using 98-Year-Old Pipeline

A Houston-based pipeline company said it will scrap plans to repurpose 98-year-old pipelines running under the St. Clair River in Michigan after community protests and officials expressed concerns about the reliability of the conduits.

Plains LPG said it has withdrawn its request to use the pipelines running beneath the St. Clair River between Marysville, Mich., and Sarnia, Ontario. It had applied to use the pipelines to transport crude oil. The pipelines were built in 1918 and upgraded in the 1970s. Few comments were lodged during the public comment session, but a public outcry resulted after the Detroit Free Press reported on the plans.

U.S. Sen. Gary Peters and Reps. Candice Miller and Debbie Dingell got involved and asked U.S. Secretary of State John Kerry to intervene because the pipeline crosses an international boundary.

More: Detroit Free Press

Dominion Shareholder Resolution Questions Financial Risk

The Securities and Exchange Commission won’t block a Dominion Resources shareholder resolution calling for an analysis of the financial risks investors face if the company is unable to complete a new nuclear reactor.

The resolution will be presented at the May 11 annual meeting. It calls for Dominion to prepare an analysis by Nov. 30 reporting on the potential financial impacts if the Virginia State Corporation Commission denies a permit and the recovery of costs for the North Anna 3 project.

The North Anna 3 reactor has already cost more than $600 million. The SCC estimates the total project cost at $19.3 billion.

More: Virginia Citizens Consumer Council

Mississippi Power Breaks Ground on Second of Solar Project Triad

Mississippi Power and Silicon Ranch broke ground on a 50-MW solar farm in Hattiesburg, Miss., last week. The $100 million, 450-acre solar farm will supply enough electricity for about 6,500 homes.

The 600,000-solar-panel project is the second of three planned Mississippi Power solar farms. The company and Origis Energy will begin work this month on a 52-MW utility-scale photovoltaic project in Sumrall, Miss. Construction has been underway since March on the company’s 3 to 4 MW project on the Naval Construction Battalion Center in Gulfport, Miss., in conjunction with the U.S. Navy and Hannah Solar.

More: Mississippi Power

Austin Energy’s Search for GM Narrows to 4

The City of Austin released its short list of finalists for Austin Energy’s top job and City Manager Marc Ott said he expects to appoint a nominee by mid-May.

The four candidates for the general manager’s position are Deborah Kimberly, an executive at Austin Energy; Jacqueline Sargent, general manager of the Platte River Power Authority in Fort Collins, Colo., and a former Austin Energy executive; Terrance Naulty, who oversees the Owensboro Municipal Utilities in Owensboro, Ky.; and James West, assistant general manager of the Snohomish County Public Utility District in Everett, Wash.

Austin Energy, which has nearly 450,000 customers, has come under intense scrutiny from state officials over its management and rates, and the utility is preparing to ask for a rate hike this summer. Its last general manager, Larry Weis, departed in January to run Seattle’s electric utility.

More: Austin American-Statesman

PNM Energy Efficiency Programs Lead to Big Electric Savings

Public Service Company of New Mexico’s energy efficiency programs have saved enough electricity since 2007 to power about 274,000 homes a year, according to the company’s latest annual report. The company has also paid out $55 million in rebates to customers, helping offset the cost of installing energy-efficient appliances and systems.

The report, released last week, details a variety of programs that help customers lower consumption, such as rebates for replacing inefficient refrigerators, cooling equipment and appliances with more modern models. The company also partially reimburses efficiency upgrades for businesses and new energy-efficient construction.

PNM and New Mexico’s other public utilities began adopting measures nearly 10 years ago to comply with the state’s Efficient Use of Energy Act, which requires the companies to reduce 2005 retail sales by 5% by 2014 and 10% by 2020.

More: The Albuquerque Journal

Pedernales Co-Op to Build Solar Sites in Texas Hill Country

Texas’ Pedernales Electric Cooperative will begin developing several solar generation sites across its service territory in the Hill Country west of Austin. The projects are expected to produce 15 MW.

PEC is working with Renewable Energy Systems and its subsidiary, RES Distributed, to develop and construct the sites. RES will also operate the facilities, the first of which is expected to go online later this year.

More: KVUE

CPS Slashes Prices for Community Solar

CPS Energy has begun construction on a community solar farm, but after going almost nine months without signing up paying customers, the San Antonio-owned utility’s “roofless solar” program was forced to slash its prices by almost one-third. The utility discounted its initial price for a panel from $406 to $289.

In June 2015, CPS entered into a deal with Colorado-based Clean Energy Collective to develop a roofless solar program that would supply 1.2 MW of electricity to San Antonio’s grid. CEC agreed to build the farm and sell the rights to individual solar panels to CPS residential customers for a flat fee. Those who buy the panels would receive a monthly credit on their electric bill based on their panel’s solar energy output and their consumption.

Hundreds of people signed up for information about the program. But with an initial price point of $406 to save an average of $1.90/month, CPS said the program had failed to attract many customers. Even at the discounted price, customers would need more than 12 years to recover their investment.

More: San Antonio Business Journal

Duke Energy Sets Higher Goal for Renewables

A Duke Energy report on the achievements of its sustainability program proposes to increase its renewable energy goal by 33%, with plans to own or buy at least 8 GW of mostly wind and solar power by 2020.

“Renewable energy will continue to be a growing part of our generation mix in the future,” said Cari Boyce, vice president for policy, sustainability and stakeholder strategy.

By the end of last year, the report said, Duke owned or purchased 4.4 GW of renewable energy in its commercial and utility businesses.

More: Charlotte Business Journal

Wind Power Has Strong First Quarter

American wind generators added 520 MW of capacity in the first quarter of the year, the best quarter since 2012, according to the American Wind Energy Association.

According to AWEA’s 2016 Market Report, construction has started on another 2,000 MW of wind generation in the country, bringing the total of wind capacity under construction to 10,100 MW.

AWEA said there are now more than 48,800 wind turbines turning in 40 states, Puerto Rico and Guam. Another 5,100 MW of wind capacity are in advanced stages of development, or nearing completion, the association said.

More: AWEA

Oracle Buying Opower for $532M

Energy analytics company Opower said Monday that it has accepted Oracle’s $532 million purchase offer, a deal that values Opower’s shares at a 30% premium to Friday’s close.

More than 100 utilities use Opower’s data services, which track household energy-use trends, to help meet state energy efficiency standards.

Last year, Opower reported an operating loss of almost $45 million on $145.7 million in revenue. Founded in 2007, the company went public in 2014.

More: The Washington Post

May 2, 2016

FERC Planning Review of Access Northeast Pipeline

FERC announced Friday its staff will prepare an environmental impact statement for the Access Northeast pipeline project that would move natural gas from New Jersey to Massachusetts (PF16-1).

The commission said the EIS will determine the potential impacts of Algonquin Gas Transmission’s project to determine if it is in the public interest.

The 925-dekatherm/day project includes pipelines and storage facilities along the route of an existing pipeline. Its developers say the project will be able to serve 5,000 MW of gas-fired power generation in New England.

Project sponsors Spectra Energy, Eversource Energy and National Grid say the pipeline will help alleviate supply constraints in New England as the region becomes more reliant on natural gas. (See Algonquin Submits Pre-Filing Request for Access Northeast Pipeline.) They expect to file a formal application later this year and hope to put the first phase of the project in service by November 2018.

The commission said comments should be filed by May 30. A series of public scoping meetings will be held at various locations in New York, Connecticut and Massachusetts from May 16-19.

The project would replace 45 miles of existing 26-inch-wide pipeline with 42-inch pipe; expand six existing compressor stations; and build new pipeline loops and laterals or expand the capacity of existing ones. The project also includes an 84.6 million-gallon LNG storage facility in Massachusetts.

– William Opalka

May 2, 2016

SPP Board of Directors Briefs

SANTA FE, N.M. — The SPP Board of Directors’ approval last week of the RTO’s first reduction in its planning reserve margin since 1998 almost left members wanting more.

Lanny Nickell, SPP, Apr 16 board of directors — Nickell © *RTO Insider*

The board accepted the Capacity Margin Task Force’s recommendation to reduce the margin from 13.6% to 12% April 26 following a unanimous vote by members. SPP said the smaller margin, amounting to a 900-MW capacity reduction, would save its load-serving members about $86 million a year in capacity costs, or about $1.35 billion over 40 years.

Lanny Nickell, SPP’s vice president of engineering, said the reduction was made possible by the RTO’s expanding footprint, its ability to dispatch more than 700 resources as a single balancing authority and $6 billion in transmission expansion during the last decade. He said another $5 billion of approved projects have yet to be built.

“Looking ahead, we need a longer-term vision,” said David Hudson, president of Xcel Energy’s Southwestern Public Service subsidiary. “If all this transmission we’re building creates benefits for our consumers, we have to see if we can achieve further savings.”

Board Chair Jim Eckelberger agreed, saying, “This is one more step in getting savings out of our transmission investment.”

Nickell said stakeholders have told him the task force’s work included “the most robust study” they have seen. Staff conducted more than 300,000 simulations and three different analyses of three test years to determine loss-of-load expectations (LOLE) at various reserve-margin levels. The so-called “limbo study” indicated SPP could go as low as 8.7% before exceeding its LOLE criteria. (See SPP Capacity Margin Task Force Shares ‘How Low’ Reserve Margin Can Go.)

The task force’s recommendation included approving a package of policies defining a load-responsible entity and its obligations, planning reserve assurance and deliverability. The package had previously been approved by the Regional State Committee, the Markets and Operations Policy Committee, the Strategic Planning Committee and the Cost Allocation Working Group.

“From my perspective, this proposal is a great platform to move forward and make improvements,” Dogwood Energy’s Rob Janssen said.

“We learned a lot from this,” Nickell said. “We debated a lot, but at the end of the day, there was a high degree of consensus. Our entire region will now benefit from improved reliability and capacity savings.”

Board Approves 2016 ITPNT

Transmission buildout will continue with the board’s approval of the 2016 Integrated Transmission Planning Near-Term (ITPNT) assessment, which recommended 86 upgrades representing $362.6 million in new engineering and construction costs. The approval is pending further evaluation of seven projects, five projects totaling $74.7 million resulting from a scenario assuming summer wind generation of almost 10 GW that some stakeholders said was unrealistic.

(A sixth project in the high-wind summer scenario, a full rebuild of a 115-kV line in a West Texas load pocket that came in at $17.7 million, was excluded from the re-evaluations.)

“Pulling these off to re-evaluate is the prudent thing to do,” said Jason Atwood, the Northeast Texas Electric Cooperative’s vice president of engineering and operations. “I just think [the] scenario pushes these projects up to the near term.”

“Those projects may be fine, but I’d like to take a second look at those projects before we issue [notices-to-construct],” Eckelberger said. “I’d like to make sure we’re not being driven by the way the model is set up. Rather than spend 92 million bucks with some questions, I’d rather get some answers.”

The board also approved requests by Basin Electric Power Cooperative and American Electric Power to conduct “accelerated reviews” of their proposed projects in North Dakota and northwest Louisiana, respectively. Staff said it could complete the further evaluations of the seven projects by the July board meeting.

The annual near-term reliability assessment included the re-evaluation of 15 projects at the transmission owners’ request. Seven of the NTCs were modified and eight withdrawn, resulting in $133.4 million in costs being pulled out of the study.

The planned development includes a $20.5 million project to address needs in the Tulsa, Okla., area; a $30.5 million project to address needs near Woodward, Okla. through the construction of a new substation and a 138-kV line; and a $145.7 million project to construct new substations and 115-kV lines to address “substantial load increases” in North Dakota’s Bakken shale formation.

Nickell said that by using a winter-peak case to reflect the Integrated System’s addition, the staff models solved many constraints before considering the effects of contingencies. He said most zones experienced a load reduction, but certain pockets — North Dakota, western Kansas and the Golden Spread Electric Cooperative and SPS’ Panhandle area — saw increases. The bulk of the ITPNT’s new investment ($261.5 million) is targeted for New Mexico, North Dakota, Oklahoma and Texas.

Staff said it would continue to consolidate planning efforts with “real” operations when determining whether projects can solve operational issues. “I would hate to ignore assumptions that go into these projects,” Nickell said. “If we can find a project that solves some of these issues, I would hate to not pursue it.”

MOPC Chair Noman Williams, COO for South Central MCN, recommended the Transmission Working Group take a second look at the high-wind summer scenario and bring it back to the board. His motion passed.

At the MOPC’s recommendation, the board also endorsed the 2017 ITPNT’s score, which will evaluate as potential violations NERC TPL-001-4 planning events that do not allow for nonconsequential load loss or curtailment of firm transmission service. (See “MOPC Approves TWG, ESWG Recommendations,” ITP Work Continues as Transmission Planning Improvements Loom for SPP.)

Eckelberger asked members to opine on how TPL events should be handled in future planning studies. The MOPC removed consideration of TPL events from the 2017 ITP 10-Year assessment during its meeting two weeks earlier.

“Essentially, this takes future requirements NERC has placed on us … out of the ITP10,” he said. “The real question: Is that something we can wait on, or do we need to incorporate it now?”

NextEra Energy Transmission’s Brian Gedrich, chair of the Transmission Planning Improvement Task Force (TPITF), said his team has included the TPL standards in its work.

“It should be incorporated in the TPITF work, and let them sort it out,” said Phil Crissup, vice president of utility technical support for Oklahoma Gas & Electric.

The task force is scheduled to present its final set of recommendations to the board, MOPC and SPC for their approval in July.

Board Approves Z2 Level Payment Plan

The board approved the Z2 Payment Plan Task Force’s recommendation to use a level-payment plan resolving years of incorrect credits for transmission upgrades, despite continued stakeholder angst over the size of payments due.

Under the level-payment plan, each entity with a net payable will be given the option to pay the entire amount at once or in equal installments every three months, beginning in November, with the final installment due in August 2017. FERC’s interest rate for refunds will apply to the outstanding balances. (See “MOPC Accepts Z2 Task Force’s Level-Payment Plan,” SPP Markets and Operations Policy Committee Briefs.)

“Our general philosophy is we’re putting the cart before the horse on this issue,” Hudson said. “A lot of this is recovered through a rate case; that’s why we think a longer payback period is more appropriate. We don’t know the potential liability for our customers … it’s hard to agree to a payment plan when [you] don’t know what the payment is.”

Asked whether it would be wise to wait until July to make final decisions, OG&E’s David Kays, chair of the task force, said the financial information will not be available for stakeholder review until July anyway, and that postponing a vote until July would slide FERC responses into October or later.

Kays said software systems would be production-ready by June 1 and historical data will be available for MOPC review in October. SPP has promised stakeholders will be able to review their data and the software calculations at SPP headquarters in late May.

“Two pieces you won’t know” in May, SPP COO Carl Monroe said. “How many waivers get approved to go in … the amount of credits due on point-to-point reservations to pay for usage and, as the TO, how much we have to claw back from revenue paid previously to pay for credits.”

Monroe said much of that information won’t be available until September. “We have to get through that puzzle, before we can determine the rest of it.”

Board Pays Tribute to Ex-RE Chair Meyer

SPP CEO Nick Brown and Eckelberger led the board in paying tribute to John Meyer, the first chairman of the Regional Entity’s Board of Trustees. Meyer resigned his position earlier this year because of a conflict with the bylaws of Western Interconnection reliability coordinator Peak Reliability, where he is vice chair. (See SPP Briefs: New Trustee Chairman, Wind Record.)

Meyer remembered his early years with the RE, which began in 2007 after his retirement from Reliant Resources, with just four employees and facing a FERC audit.

“One of the strengths I see with SPP is its willingness to solve problems together,” Meyer said. “I’m really sad to be leaving, but I’ll be back to visit on occasion.”

The RE doesn’t expect to fill Meyer’s position until July, at the earliest.

FERC’s Bay Takes in Order 1000 Discussion

FERC Chair Norman Bay at Apr 16 SPP board of directors — Bay © *RTO Insider*

FERC Chairman Norman Bay was a special guest at the board meeting, attending the morning session for about 90 minutes. Given his tight schedule, the board rearranged its agenda to ensure Bay could listen to the discussion surrounding SPP’s first competitively bid transmission project under the commission’s Order 1000.

“I look forward to hearing your experiences with Order 1000,” Bay said.

Bay took note of SPP’s recent achievements, including the Integrated Marketplace’s implementation and the addition of the Integrated System, and called them a “national leader” in integrating renewable energy.

“You’re helping make the case markets drive reliability and efficiency, driving benefits for consumers,” he said. “Fifty percent wind penetration … that’s pretty amazing. Just a few years ago, people were wondering whether you could get 20%, and now you’re almost at 50%.”

Bay, a former New Mexico resident, also complimented SPP on holding its board meeting in Santa Fe. “Obviously, it shows they have good taste and judgment.”

RE Report Shows 40% Drop in Violations

New RE Trustees Chairman Dave Christiano noted that SPP’s registered entities saw a nearly 40% drop in violations of NERC standards during a rolling 12-month period that ended March 31. . The RE recorded 48 violations in the current period, compared to 78 in the previous 12 months.

The systems security management, electronic security parameters and personnel and training categories showed some of the greatest improvements.

“The registered entities have this figured out,” Christiano said. “We’ll take some credit, but most of the credit goes to them.”

He stressed the importance of CIP 5 compliance, sharing a presentation the RE viewed on the recent cyberattack against three Ukranian distribution companies. (See How a ‘Phantom Mouse’ and Weaponized Excel Files Brought Down Ukraine’s Grid.)

“This wasn’t a bunch of 15-, 16-year-old hackers in their basements,” Christiano said. “This was a very well planned-out attack over a number of months. It’s pretty scary stuff.”

The RE has scheduled a CIP workshop in Little Rock, Ark., May 24-25.

Tx Project Pulled from Consent Agenda

SPP Board of Directors — Eckelberger *© RTO Insider*

The board approved its consent agenda following a unanimous members’ vote, but only after pulling the Project Cost Working Group’s recommendation to reset the baseline value for a 110-mile, 345-kV transmission line in Nebraska and Missouri. It was valued at one time at more than $403 million, but received MOPC approval to reset its baseline value to $336.4 million.

“I thought we had a policy against resetting the baseline, unless it’s a different project,” Eckelberger said.

Staff was unable to recall any discussion of the project during the MOPC meeting, where it was part of the consent agenda. They promised to return the issue to the board with additional information.

The consent agenda included the addition of Basin Electric’s Mike Risan and the Missouri River Energy Services’ Ray Wahle to the SPC, reflecting the Integrated System’s addition. It also approved six revision requests from the Market and Operating Reliability working groups.

Annual Report Focuses on Relationships

As is the custom, SPP staff handed out the organization’s 2015 annual report before the board meeting began.

This year’s report focuses on SPP’s relationships, both internal and external. “We choose to highlight our relationships as a critical component of all we do and a binding agent, drawing together our staff, stakeholders and customers we serve to add value to our region,” the introduction says.

— Tom Kleckner

May 2, 2016

Stakeholders Wary of CAISO Contingency Modeling

By Robert Mullin

CAISO stakeholders last week expressed misgivings and confusion about a new issue paper exploring how the ISO can resolve certain generator and transmission contingencies currently handled by out-of-market operations.

Questions about the generator contingency and remedial action scheme modeling enhancements paper largely stemmed from uncertainty about the potential scope of the effort. Market participants also sought to understand how such an effort would differ from CAISO’s Contingency Modeling Enhancements (CME) initiative, which is nearing completion.

CAISO Diagram - Stakeholders - Contingency Modeling Initiative — The diagram above shows transmission path AB being overloaded when the loss of generator G1 is replaced by low-cost contingency reserves procured from the network – what CAISO calls “transmission infeasible” procurement. The diagram assumes that there are no contingency reserve eligible resources at buses A, B or C.

“I’m curious as to why this stakeholder process is arising at this point in time,” Ellen Wolfe, a consultant representing the Western Power Trading Forum, said during an April 25 stakeholder conference call. “Especially in relation to CME and where that is.”

“This just seemed like a good time to get a jump-start on this,” responded Perry Servedio, CAISO senior market design and policy developer. “It was always the thought that these two [initiatives] would overlap.”

CAISO kicked off the CME initiative three years ago to address a Western Electricity Coordinating Council reliability provision requiring grid operators to return a critical transmission path — such as Path 15 linking Northern and Southern California — to its system operating limit within 30 minutes of a destabilizing event, such as the loss of a generator or transmission line.

The ISO’s present approach to managing those contingencies relies on out-of-market interventions coupled with day-ahead market measures that procure a “bucket” of responsive capacity resources based on a flat megawatt rating of the line in question, an approach that ISO staff considers to be inefficient.

The CME initiative would update CAISO market rules to instead procure those resources based on expected flows, with the process first run in the day-ahead market and then rerun in real-time. In addition, that process would be more closely integrated with the general procurement for locational ancillary services. That is expected to reduce the overall pool of reserves receiving compensation, reducing costs.

Last week’s issue paper looks to zero in on a different, if related, aspect to an emergency response: the system’s ability to gain access to contingency reserves while at the same time keeping all affected transmission paths below their emergency ratings. The ISO calls it the “transmission feasibility” of those reserves.

“We’d want to ensure that, given a generator loss, we don’t overload any lines and we can rely on the reserves,” Servedio said.

The newer initiative would also formulate a market-based response to transmission losses stemming from the triggering of remedial action schemes (RAS) — emergency plans designed to prevent one transmission outage from setting off a series of cascading outages.

Servedio noted that CAISO currently has more than 20 RAS modeled within its own system, a figure that does not include schemes elsewhere in the Western Interconnection. While the ISO currently factors RAS into its market operations through adjustments to its market software — including the use of nomograms to avoid exceeding transmission line limits — it thinks that approach comes up short.

“Even with all that modeling, you can end up with real-time exceptional dispatch [out-of-market intervention] because we don’t have a way to model the RAS in the day-ahead market,” he said.

That statement prompted one stakeholder to seek clarification about exactly what the current process entails.

“So you’re saying there is some sort of ad hoc change in modeling that takes place in both day-ahead and real-time?” asked Bonnie Blair, speaking for the “Six Cities” — municipal utilities serving Anaheim, Azusa, Banning, Colton, Pasadena and Riverside. “I’m not sure I follow, but I’ll think about it.”

Another stakeholder questioned whether the changes being contemplated by the ISO would be worth the investment.

“When you look at this [initiative] from an economic perspective, would you say this is more economic than what you do today?” asked Wei Zhou, senior project manager with Southern California Edison.

“We expect it to be the more economic solution — clearly,” said George Angelidis, principal with CAISO’s Power Systems Technology Development group.

“We currently don’t have in the market the ability to model generator contingencies,” Angelidis later added. “Without the capability to model the RAS, your market solution is a more conservative and costly solution.”

However, CAISO staff could provide no figures for how often contingency reserves have been inaccessible in past, in part because the current manual intervention process requires system operators to rely on only those resources that are accessible in real time.

“I can’t give you data on what megawatts weren’t deliverable, because our operators are working to ensure that the megawatts are deliverable [through exceptional dispatch],” Servedio said.

Other stakeholder concerns focused on the proposal’s technical details. Call participants asked questions about how many RAS would be incorporated into a possible proposal, the duration of emergency ratings and the workings of the complex flow models CAISO staff used to determine the transmission feasibility of contingency reserves.

“I’m just trying to figure out the scope of this effort,” said Seth Cochran, manager of market affairs and origination at DC Energy.

CAISO staff took pains to assure stakeholders that the issue paper did not represent an actual proposal — despite an outlined schedule proposing a Fall 2017 implementation date for any measures resulting from the process.

“We’re not really proposing anything yet, we’re just trying to flesh out the issue,” Servedio said.

May 2, 2016

FERC OKs Entergy LBA Agreements

By Amanda Durish Cook

FERC last week approved 11 Entergy local balancing authority (LBA) agreements stemming from the utility’s 2013 integration into MISO.

Entergy Transmission (Entergy) - LBA agreements — Entergy Transmission *Source: Entergy*

Entergy Services and Entergy Arkansas sought the agreements with entities embedded within the LBA areas to ensure accurate coordination and communication of operational and metering information. The agreements identify load and/or generation of counterparties located within each area as well as specifying operational responsibilities and meter specification and data sharing requirements.

The April 26 order (ER14-693, et al.) found that Entergy “demonstrated that the LBA agreements will assist in ensuring reliable operations” of the utility’s electric system.

The commission required Entergy to submit a compliance filing showing that cost allocations for residual loads — the amount of over- or under-claimed energy in an LBA area — will rely on cost-causation principles where possible, replacing the company’s proposed pro rata cost allocation.

Entergy’s original 2013 LBA agreements included a provision that counterparties report their metering data to help the utility correct errors responsible for producing residual loads within the LBA areas.

A revised batch of agreements the next year proposed to instead allocate residual load costs and credits based on a pro rata methodology in order to “simplify the burden associated with meter corrections.” Entergy contended that some embedded entities were too small and their contribution too insignificant to directly assign costs, leaving costs to be allocated according to overall energy injections and withdrawals within an LBA.

Entergy last year offered an additional update to that provision, proposing to work with counterparties to maintain adequate metering equipment to directly assign residual load cost responsibility to a specific company. That process would incentivize “embedded entities to maintain adequate metering and robust processes for reporting data,” the utility said.

Last week’s decision said Entergy’s pro rata cost allocation provision suffered from the same flaws as a similar MISO plan rejected in 2006, which FERC said “failed to allocate unaccounted-for energy to the load that caused it.” However, FERC said Entergy’s efforts to directly assign residual load costs when possible was a sufficient improvement to align with cost-causation principles.

FERC also sided with Entergy in ruling that the utility should not bear the entire cost of residual loads within the LBA areas “because such costs are caused by the accumulated actions of all embedded entities within the LBA areas.”

Counterparties Dow Chemical, Union Carbide, Occidental Chemical, Calpine, Tenaska and Sabine Cogen had questioned the residual load cost allocation proposal and objected to the creation of the LBAs, contending that the agreements do not accomplish anything not already covered by the MISO Tariff and required by the RTO.

FERC said the noncompulsory application of LBAs does not make them any less useful.

“We disagree that, because no commission or MISO rule or policy mandates agreements such as the LBA agreements, they are unnecessary and unjust and unreasonable,” FERC wrote.

The commission also rejected arguments that the agreements too closely resembled generation interconnection agreements and said it was “unpersuaded by arguments that Entergy does not need the LBA agreements in order to carry out its responsibilities as an LBA area administrator.”