AUSTIN, Texas — Texas regulators on Friday signed off on ERCOT’s plan to review its reliability standards and replace its loss-of-load expectation (LOLE) methodology for determining its reserve margin with one based on economics.
The Public Utility Commission agreed that a letter filed with the commission by ERCOT Director of System Planning Warren Lasher on Oct. 24 outlined a sound process. “Go forth and do good,” Chairman Donna Nelson said.
Commissioner Ken Anderson pointed out the project’s (Docket 43202) intention is to replace ERCOT’s LOLE methodology with the economic optimal reserve margin (EORM).
The LOLE is “not really baked into any of our rules, but it is baked into the protocols at ERCOT,” Anderson said.
ERCOT staff will go through its protocols to find language that needs to be modified and make changes “at the appropriate time,” Lasher replied.
In 2013, The Brattle Group and Astrapé Consulting conducted a study of the market’s EORM, which it defined as minimizing total system costs by weighing the cost of more generation to achieve higher reserve margins against decreasing scarcity-event-related costs.
Higher reserve margins help to avoid load shedding, reserve shortages, demand response calls and other emergency event costs, the study said.
The firms had to customize the study’s methodology, Lasher wrote, “to reflect the region’s unique energy-only deregulated wholesale market design and region-specific market behavior.”
The study simulated ERCOT’s recently implemented operating reserve demand curve. Lasher said that methodology and other study assumptions will need to be reviewed by ERCOT and stakeholders “if the results of future EORM studies are to be used in place of the existing target reserve margin.”
Lasher’s proposal involves conducting workshops with market participants in the first half of 2017 and completing its next EORM study in 2018 based on the documented methodology. He recommended future EORM analyses be conducted every other year coincident with NERC’s required LOLE studies.
Following the 2018 EORM study, Lasher said ERCOT would amend its market rules as appropriate to accommodate the move to a target reserve margin based on EORM criteria, and away from the one-event-in-10-years LOLE.
“Currently, NERC has two numbers that go to them,” Lasher told the PUC. “First, what the region says is an appropriate reserve-margin expectation. That’s whatever the region wants to define it as. Some regions use the economic optimal number.
“NERC also has a standing data request every year for the region to say, given our expectations for the reserve margin, what will actually be the expected unserved energy with that margin.”
Lasher said ERCOT conducted loss-of-load probabilistic studies in 2014 and 2016 to comply with data requests from NERC and the Texas Reliability Entity. The ISO worked directly with Astrapé to complete the studies, using the same models and assumptions comparable to those employed for the 2013 study.
The commissioners debated whether to have ERCOT continue providing its regular capacity, demand and reserves (CDR) report until the new reliability standards are in place, without coming to a decision.
“The CDR is at the heart of the problem, because its load assumptions are beyond four years,” Anderson said.
Anderson suggested ERCOT take the 2013 study results and incorporate them in the CDR, using the economical, optimal and expected equilibrium as information data points. Lasher noted ERCOT’s May CDR didn’t provide data for a target reserve margin, but he said staff could include the Brattle study’s results.
MISO is requesting a 4% increase in operating expenses for 2017 while moving away from a one-year forecast in favor of a five-year business plan.
The requested increase will bring the 2017 operating budget to $289.6 million, said Mitch Myhre, chair of the MISO Finance Subcommittee, who presented the budget to the Advisory Committee during an Oct. 26 conference call.
The operating budget includes:
$229.6 million in “base” spending;
$51 million in structural expenses (including amortization of membership integration costs, depreciation of cybersecurity investments and infrastructure upgrades and funding of the Independent Market Monitor and Organization of MISO States); and
$9 million for strategic initiatives, including the Competitive Retail Solution, seasonal and locational capacity, improving gas modeling, and automatic generation control enhancements.
MISO forecasts it will end 2016 with operating expenses of $225 million — its budgeted amount — to $227.3 million, which would be 1% over budget.
Myhre said MISO’s new five-year budget approach will be an “evolving, rolling” budget. The RTO is predicting a 1.9% compound annual growth rate for the next five years. The subcommittee and MISO staff are still working on the details of the five-year plan, Myhre added.
The plan projects an identical $289.6 million spend in 2018. In 2019, the figure increases to $293.5 million, then $299.5 million in 2020 and $306.7 million in 2021. In every budgeted year, MISO plans to spend exactly as much as it brings in.
MISO also is requesting a 2017 capital budget of $29.9 million — a drop from 2016’s $31 million — and an average capital spend of $32.9 million over the next five years.
However, the RTO said it might request out-of-cycle budget approvals in 2017 for initiatives in the works, including the construction of a new security operations center, more software quality control, improved server utilization, positioning an off-duty police officer at MISO control sites and insourcing some outside contracts. For those possible expenses, the Finance Subcommittee recommended MISO create business cases to present to the appropriate stakeholder groups.
American Electric Power’s Kent Feliks thanked Myhre and MISO for the budget work. “A lot of this work isn’t very exciting, but it’s vital to MISO,” he said.
Final approval of the 2017 budget and adoption of the five-year spending plan will take place at the Board of Directors meeting in December.
AC to Approve One of Two Sets of 2017 Priorities
The Advisory Committee will adopt one of two revised sets of priorities for 2017, choosing between one that is a slight revision of existing priorities and another that takes its cues from subcommittee mission statements.
| MISO
Gary Mathis, representing MISO’s Transmission-Dependent Utility sector, said the committee’s approved priorities for this year are unclear and hard to remember. Mathis said the subcommittees’ mission statements could become the committee’s overarching priorities themselves. He presented five proposed priorities: implementing best planning practices; preserving and enhancing reliability; improving market efficiency; ensuring resource adequacy; and ensuring equitable cost allocation.
Advisory Committee Chair Audrey Penner presented the alternative, which was slightly changed from the 2016 priorities list. It moves the gas-electric coordination priority under a broader environmental policy and portfolio evolution priority. A strategic guidance priority was added in its place that includes hot topic discussions and a broad current issues subcategory. (See “Committee Endorses 5 Final Priorities,” MISO Advisory Committee Briefs.)
Penner said both priority documents capture “the essence of what the priorities should be.”
The committee will vote to adopt one of the two approaches at its December meeting. Penner said committee leadership hopes to keep the committee’s priorities on the books for multiple years while performing six-month “check-ins” to assess their continued relevance.
AC’s Strategic Session Prompts Possible ‘Hot Topic’ Change
Advisory Committee members noticed that the committee spent quite a bit of time on this year’s stakeholder redesign and said it looked forward to paying more attention to other issues in 2017, reported Penner, who gave an overview on the committee’s strategic planning session held at the end of September in San Antonio.
Penner also said the committee is looking to change its hot topic forum back to its original format, with wider stakeholder participation in drafting questions, instead of MISO facilitating the discussion. Director of External Affairs Kari Bennett said the RTO had no problem with re-establishing the old arrangement.
The Advisory Committee is considering holding hot topic conversations in 2017 that focus on transmission, including cost allocation, pseudo-ties and the competitive bidding process. Penner said the committee would solicit votes by email to its voting sectors to decide on a March topic. She added that the committee might suggest MISO hold an educational session prior to sectors submitting their written positions on hot topic subjects.
Penner also urged stakeholders to attend a Nov. 3 Stakeholder Governance Guide workshop. During the Oct. 26 Steering Committee conference call, Chair Tia Elliott said agenda items could include conference call logistics; meeting procedure education; an overview on Robert’s Rules of Order; criteria for establishing closed groups; and the creation of a definition for task teams with a process for creating and retiring them.
Xcel Energy reported an increase in earnings for the third quarter as the company said its “steel-for-fuel” strategy of replacing fossil fuel plants with wind turbines will provide a solid blueprint for future growth.
The company reported third-quarter earnings of $458 million ($0.90/share), up 7.5% from the $426 million ($0.84/share) a year earlier. The results bested analysts’ expectations of 87 cents, according to Zacks Investment Research.
“The whole premise of steel-for-fuel is you can do things on an economic basis cheaper than the fossil alternatives,” CEO Ben Fowke told analysts during a conference call Thursday. “In reality, the environmental benefits will be icing on the cake. So, when you’re not impacting customer builds and you’re driving environmental leadership, it’s really a unique position for us to be in.”
Xcel proudly points to its designation by the American Wind Energy Association as the nation’s No. 1 utility wind-energy provider for 12 years running. Wind energy accounted for 17% of the energy Xcel generated in 2015, and it projects that figure to grow to 24% by 2020.
| Xcel Energy
Much of that has been produced by long-term contracts with third parties, but the Minneapolis-based company announced earlier this week it would build four new wind farms in Minnesota and North Dakota with a total capacity of 750 MW.
In September, Colorado regulators approved Xcel’s plans to begin construction on its $1.1 billion, 600-MW Rush Creek Wind Project, allowing Xcel to claim $443 million in federal tax credits. The Rush Creek project is expected to come online in 2018.
“We expect [these] wind projects will generate hundreds of millions of dollars in fuel savings for our customers, which will more than offset the capital cost [to build them],” Fowke said.
CFO Bob Frenzel told analysts the company has updated its five-year capital forecast and now expects to invest $18.4 billion through 2021, including $3.5 billion on renewables. That includes the Rush Creek project and the Minnesota-North Dakota wind farms.
“When you look at the economic price point … that we are seeing with wind, I think we have opportunities potentially in Texas and New Mexico too, just on the economic merits alone,” Frenzel said.
Analyst Angie Storozynski of Macquarie Capital questioned whether adding renewables to the rate base in a time of no load growth is the “low-risk” growth strategy the company claims.
Vice President of Investor Relations Paul Johnson acknowledged that the company will be adding capacity that might not be needed until it retires coal plants. “We’re just taking opportunity to capture the full” production tax credit, he said.
“This is our resource plan. … We can build wind competitively, and I think we’ve earned the right to own wind in our backyard,” Fowke added. “It does require alignment with your regulators, but I think we have it.”
Xcel narrowed its 2016 earnings guidance to $2.17 to $2.22/share, down from the previous estimate of $2.12 to $2.27/share. “Our year-to-date weather-adjusted electric sales remain relatively flat,” Frenzel said, explaining the company’s caution.
The company’s stock price opened at $40.33/share before Thursday’s earnings announcement. It closed Friday at $40.68.
Earnings call transcript courtesy of Seeking Alpha.
LITTLE ROCK, Ark. — The SPP Board of Directors and Members Committee decided last week to take no further action on the contentious Z2 crediting issue, leaving unhappy stakeholders likely to seek redress from FERC or the courts.
The board discussed the Markets and Operations Policy Committee’s recommendation to “follow the Tariff” and reject requests that $114.1 million in directly assigned Z2 network upgrades be allocated to SPP’s base plan. However, it took no votes on the matter Oct. 25, which let stand the MOPC’s decision, which was supported by 83% of members voting. (See MOPC Rejects Z2 Waivers; Task Force Seeks Changes.)
The board in July formed a task force to review requests from members who SPP staff had said didn’t qualify for waivers from $36.9 million in directly assigned upgrade costs, while also addressing “equity concerns.” The group also reviewed another $77.2 million in direct costs from members who didn’t request waivers.
Les Evans, COO of Kansas Electric Power Cooperative (KEPCo), one of the companies requesting a waiver, once again expressed his dissatisfaction with the process after being “wrongly assigned” $6.2 million because its resource-to-load ratio exceeded a 125% threshold.
“The 83% that voted to follow the Tariff does indicate that 17% of us feel disenfranchised and that things are not equitable,” Evans said.
Evans argued KEPCo was granted four transmission service requests from a 2012 aggregate study, and that there were no directly assigned costs in the agreements.
Pointing to the directly assigned costs he said KEPCo was assessed four years later, Evans said SPP’s treatment of his company fails the RTO’s “but-for” test, which requires transmission customers to fund transmission improvements that would not be required but for their additional load. The test is triggered by a 3% increase on a line’s directional flow in the same direction as the power flow that caused the upgrade.
“Under the process we’re using right now, a sponsored upgrade can be put back into a model from years ago, and if I have a 3% flow on that facility, I would be responsible for directly assigned upgrade costs under that possibility. I would say that is not fair, it’s not equitable and I don’t think there’s anybody that can stand here with a straight face and say that passes a ‘but-for’ test.”
Evans worked with staff to draft language for two different motions addressing his arguments. One required transmission reservations assigned a payment obligation for an upgrade be included in the original aggregate study model. The other would mandate that service agreements explicitly include directly assigned upgrade costs in order to be directly assigned to a transmission customer.
Evans failed to get a second on either motion, the only two offered up by the board and committee.
“We have an opportunity here, as a group, to solve the problem,” Evans said. “If the problem’s not solved [today], from my perspective and KEPCo’s perspective, we’ll seek other solutions. SPP loses control of how the problem is resolved. This is the place to do it.”
Staff pointed out either motion would cause about a six-week delay to calculate the historic Z2 credits and obligations, which date back to 2008. Invoices settling charges and credits under Attachment Z2 for the March 2008-August 2016 period are to be issued this week.
“Following the Tariff should be clear, but how clear can 5,275 pages be?” Director Phyllis Bernard asked. “Perhaps it’s time for … alternative dispute-resolution with a possible third party, or to go to FERC.”
“We’ve been waiting eight years to get this done. Let’s get it done,” said The Wind Coalition’s Steve Gaw, noting SPP’s transmission-dispute resolution process could still provide an avenue for members to plead their case. “I would encourage us to move forward.”
“I’d love for consensus to be unanimous, but that’s not what we have,” SPP CEO Nick Brown said. Reversing the MOPC’s endorsement would mean “we’ll be supporting 17% at the expense of 83%.”
“Bottom line, this will go to FERC,” Brown said. “I have no doubt what KEPCo’s response to this will be.”
Evans’ response was terse. “KEPCo is evaluating all possible venues for a remedy to its issues,” he told RTO Insider on Friday.
Staff told members Thursday it is billing almost $110 million in regionwide, aggregate net payable historic amounts. It said $94.8 million will be invoiced as a lump sum, and the remaining $15.1 million will be billed in 20 installments through August 2021 to those members who chose the payment plan approved in April.
Duke Energy Renewables has signed a five-year deal to provide remote monitoring, control and dispatch services to Block Island Wind Farm — the nation’s first offshore wind facility.
The 30-MW wind farm, located off the coast of Rhode Island, is expected to begin producing electricity in November.
Duke Energy presently provides control and monitoring services to non-Duke projects totaling about 2,000 MW.
PG&E Applies for Rate Increase Spurred by Diablo Canyon Closing
Pacific Gas & Electric is applying to the California Public Utilities Commission for a 1.6% rate increase after promising earlier this year that closing its Diablo Canyon nuclear facility would not raise customers’ rates.
The proposed increase amounts to $1.766 billion to be collected over an eight-year period.
PG&E spokesman Blair Jones said last week that the “short-term rate increase will be offset in the long term.”
Sunrun Partners with LG Chem to Offer Solar Panels with Batteries
Sunrun will offer solar arrays paired with in-home batteries thanks to a partnership announced last week with LG Chem, which supplies batteries to 16 of the world’s largest automakers.
The Korea-based battery builder will supply lithium-ion batteries for Sunrun’s BrightBox system, which allows homeowners to store solar energy generated during the day for use in the evening.
Sunrun began offering BrightBox this year in Hawaii, using batteries made by Tesla Motors. It wants to expand the system into California beginning in 2017.
Sims to Serve on Pinnacle West, Arizona Public Service Boards
Paula Sims has been elected to Pinnacle West Capital’s board of directors and also will serve on the board of directors of Arizona Public Service, Pinnacle West’s principal subsidiary.
The appointment is effective immediately and increases the number of Pinnacle West directors from 10 to 11 members, 10 of whom are independent.
Sims is a former senior executive at Progress Energy.
Dominion Virginia Power Sees Peak Demands for Electricity
Dominion Virginia Power is seeing peak demands for electricity, with its customers having used 28.2 million MWh from July 1 to Sept. 30 — breaking an 11-year record.
“We are now seeing peak demands for electricity in both the summer and winter,” said Robert M. Blue, president of Richmond-based Dominion.
The company has proposed building a transmission line over the James River from its Surry Nuclear Power Station to address increased demands.
EnergySource Testing Process to Extract Lithium from Geothermal Brine
EnergySource is testing a new five-step process to extract lithium from underground brine at its Featherstone geothermal plant by the Saltine Sea in California.
The company purchased several existing extraction techniques and is using its knowledge of the Saltine Sea brine to tweak those technologies, CEO Eric Spomer said.
A Texas investment firm just purchased a 38.5% interest in EnergySource and is funding more thorough testing of the extraction project, which Spomer expects will take about six months.
Xcel Energy Planning Four Wind Farms for Minnesota, North Dakota
Xcel Energy announced last week that it plans to build four new wind farms in Minnesota and North Dakota — a move that will increase its wind generation capacity by 60% in the Upper Midwest.
The four wind farms, which still require regulatory approval, will generate 750 MW.
The projects are part of a plan that Xcel announced in September to invest $2 billion to add 1,500 MW of new wind generation — or eight to 10 wind farms — by 2020.
Shareholders File Suit to Stop Spectra’s Merger with Enbridge
Shareholders have filed five separate lawsuits against Spectra Energy to stop its $28 billion deal to sell itself to Enbridge.
The suits, which were filed in the U.S. District Court in Houston, all allege that Spectra should have sought other merger partners who might pay more for the company.
Under the deal, Spectra stockholders would trade each of their shares for a 0.984 share of the combined company, which will keep the Enbridge name.
Idaho Power Project Lowers Temperature of Snake River
Idaho Power is lowering the temperature in areas of the Snake River in order to comply with regulations.
In July, the utility began work to narrow and deepen a channel by widening two islands just downstream of Walters Ferry. It will replace noxious weeds on the two islands with native trees that will help cool the water.
The project is the first of many planned for areas along the Snake River and is expected to end this month.
Idaho Power Requests Early Exit from Nevada Coal Plant
Idaho Power filed a request with state regulators on Oct. 21 to accelerate its exit to 2025 from the coal-powered North Valmy Generating Station near Battle Mountain, Nev.
The utility, which owns 50% of the power plant, previously said it wanted to wean itself off of Unit No. 1 by 2031 and Unit No. 2 by 2035.
The accelerated exit would result in a $28.5 million cost increase, which would include decommissioning costs and capital investments forecast for the remaining life of the plant, Idaho Power said in its filing with the Public Utilities Commission.
New Reliant Plan: No Panels Needed to Purchase Solar in Texas
Reliant Energy is offering Texas customers the opportunity to purchase solar energy for 12 months at a fixed rate without installing solar panels. Reliant’s 100% Solar 12 plan allows the company to procure the rights to solar energy through renewable energy credits.
The Obama administration provided a $28 million infusion of federal grants last week to 13 coal-producing states to assist workers affected by job losses in the declining coal industry.
The money is part of the POWER Initiative, which provides federal funding for locally created programs that support new economic activities in coal regions as the nation moves toward cleaner energy. More than $66 million has been awarded to 71 projects this year.
$3.6B Loan Program Will Fund Rural Electrification Projects
Vilsack
The Agriculture Department has announced a $3.6 billion loan program to fund rural electrification projects nationwide.
The program will benefit 82 projects in 31 states, Agriculture Secretary Tom Vilsack said, and it will add or upgrade 12,500 miles of rural electric transmission and distribution lines.
OSHA Investigates Hydrogen Sulfide Exposure at Big Ox Plant
The Occupational Safety and Health Administration began an inspection Oct. 19 of Big Ox Energy’s biomass plant in South Sioux City, Neb., after an employee of a contractor was hospitalized for hydrogen sulfide exposure.
The investigation is expected to take 60 to 100 days, said Darwin Craig, assistant area director at OSHA’s Omaha office.
When the incident was reported, several homeowners who share a sewer system with the plant were reacting to foul odors that have since been traced to sulfides originating from the facility.
Two judges on the 4th U.S. Circuit Court of Appeals last week grilled the attorney for the former Massey Energy CEO Don Blankenship, who is seeking to have his criminal conviction overturned in connection with the deaths of 29 workers.
Blankenship was convicted of conspiring to violate mine safety and health standards after an April 2010 explosion at Massey’s Upper Big Branch Mine, in Raleigh County, W.Va.
Judge James Wynn Jr. and Senior Judge Andre Davis raised issues about Blankenship’s central arguments on appeal. Wynn repeatedly stated that he didn’t think he agreed that the trial court wrongly instructed jurors on what constitutes a “willful” violation of federal mine safety and health laws.
IEA Raises Forecast for 2021 Renewable Energy Production
In 2021, renewable energy sources will provide 28% of the world’s electricity production, compared with 23% in 2015, the International Energy Agency forecasted last week.
The estimate is 13% higher than what the IEA forecasted last year.
The IEA attributed the change to increased government support in the U.S., China, India and Mexico and expected cost reductions of about 25% for solar panels and 15% for onshore wind.
Six U.S. senators from the Pacific Northwest asked the Energy Department last week to choose the Oregon coast as the site for the nation’s first grid-connected wave energy device test center.
Northwest National Marine Renewable Energy Center proposed the facility, which would consist of four berths for testing wave energy converters in big-wave conditions. It would include a subsea cable to carry up to 20 MW of power ashore.
Other than a potential project proposed for California, it is unknown whether other sites are vying for federal funding, which could cover up to 80% of the facility’s cost.
Staff of the New York Public Service Commission released a report on Thursday recommending a transition from net energy metering (NEM) to a compensation scheme that provides more accurate, granular values for distributed energy resources (15-E-0751).
“With a more accurate, market-based approach to compensate consumers for the value of their distributed clean energy investments, we will continue to take positive steps towards making these clean resources a core part of our energy system,” PSC Chair Audrey Zibelman said in a statement. “Under this cutting-edge framework, consumers, utilities and energy developers will be rewarded for investment decisions based on the full value that clean energy and other distributed energy resources provide to our electric system.”
Phase One of the transition will seek to apply values “that were able to be considered and discerned with currently available data,” the report says.
The mechanism will compensate customers using a tariff based on calculations of specific value sources. These value sources — including energy, capacity, reduced environmental impacts, demand reduction, locational system relief and distribution voltage support — would comprise a “value stack.”
Phase One will apply to all projects and technologies eligible for NEM under current rules, including solar photovoltaic generation, wind and micro hydroelectric generation, where the operator has no ability to control the facility’s output.
Also included would be dispatchable technologies such as fuel cells, farm waste generators and micro combined heat and power and energy storage paired with eligible generation facilities.
The report acknowledges that establishing these values will evolve and that utilities will need time to develop tools to calculate the impact of a resource’s location, the services it provides and its time of use to fully compensate homeowners.
Staff is proposing interim measures for community distributed generation (CDG) projects — sometimes called shared renewables — that are in the advanced stage of development. The interim rules would allow a specific number of projects to be compensated under current net metering rules for 90 business days. After that period, future CDG projects would be valued under the new methodology.
| The New York Public Service Commission
The report also envisions “virtual generation portfolios” codeveloped by utilities and DER providers.
Existing rooftop solar facilities would be paid at net metering rates for 20 years from the date of their installation. Since 2012, solar facilities in the state have grown from a little more than 78 MW to the current 669 MW, the PSC says. Owners of the systems would have the option to drop net metering and sign up for updated compensation plans.
Public comment will be accepted on the report, part of the state’s Reforming the Energy Vision initiative, until Dec. 5. Initial PSC action is expected in January.
Phase Two of the process, which would further refine the development of DER metrics, is slated to begin with a collaborative later this month. A final order is anticipated by the end of 2018.
Net Metering’s Shortfalls
The report said that while it “has been an important and effective tool in fostering the growth of” DER, “when combined with traditional volumetric rate structures, NEM provides an imprecise and incomplete signal of the full value and costs of DERs.”
“NEM therefore provides insufficient information on which to base informed investment and usage decisions that could benefit both the system and customers under REV,” the report continues. “As a result, investment in new DER capacity is often made without regard to how the design, siting and operation of those resources can maximize benefits to the electricity system overall.”
Failing to properly identify and compensate DERs for their value limits incentives for adding technologies such as smart inverters.
“At low levels of DER penetration, the economic inefficiencies resulting from the incomplete price signals embedded in NEM are less consequential, but as adoption increases, these potential misalignments — and the uneconomic effects associated with them — will increase,” the report said.
The LMP applied in the wholesale markets does not separate ancillary services, load shifting and environmental and performance benefits “that are essential design features of a fully optimized bidirectional power system and decarbonized network,” it said.
Collaborative
A collaborative effort involving utilities, consumer advocates, environmentalists, solar and DER providers that started last December was the first step in providing input for the new market framework. The report also builds on several REV-related efforts including the development of a benefit-cost analysis framework and utility distributed system implementation plans.
“Today, the customer side of the grid represents an enormous and largely untapped resource to optimize value throughout the electricity system. REV will establish markets so that customers and third parties can be active participants, to achieve dynamic energy management on a systemwide scale, resulting in a more efficient and secure electric system, including better utilization of bulk generation and transmission resources,” the report says.
CARMEL, Ind. — MISO presented a different perspective at its Oct. 25 Informational Forum, inviting cultural anthropologist Gretchen Bakke to talk about shifting attitudes toward electrical infrastructure.
Bakke | McGill University
Bakke, assistant professor of anthropology at McGill University in Montreal and author of “The Grid: The Fraying Wires Between Americans and Our Energy Future,” has studied failing systems in Cuba, the Soviet Union and Yugoslavia. She said the grid is as much of a cultural creation as a technical one. “As such, it moves with us. We think of it as solid and rebar, [towers] and copper, but the truth is it grows with us.”
The current grid is a poor fit for a new generation of customers who want carbon-free electricity, Bakke said. The grid’s reliability becomes more “fragile” with increasing investment in intermittent renewables, and Bakke calls for “a serious reimagination of the grid” beyond simply repairing aging infrastructure.
“People right now are moving against the grid,” Bakke said. She pointed to the development of phones with ultra-low power transistors that can function for years without a battery, Elon Musk’s self-driving cars, Iceland digging a 3-mile hole into magma to tap geothermal power and Democratic presidential candidate Hillary Clinton’s push for 500 million solar panels in the U.S.
Bakke said regulators have made electricity so reliable and so cheap that consumers can “unwittingly” ignore it. Consumers tend to think that energy storage is a panacea, forgetting that producing batteries causes pollution and batteries cannot be charged by renewable power alone, she said.
“The way that solar PV has been presented is as this free power source that you can get money back on. And that contributes to this 21st century [attitude],” Bakke said.
Customers’ desire for more local distributed energy resources are at odds with their preference for renewable generation, which often requires tapping remote sources via transmission.
“All of these dreams rely on a deep ignorance of infrastructure,” Bakke said. “It’s this upswing in wanting to eat food grown from a local farmer,” Bakke explained. “Iowa wind is fine to power the Twin Cities.”
Bakke said MISO stakeholders are the edge of the consumer “push and pull,” but she said resource owners should nevertheless pay attention to what consumers are demanding.
LITTLE ROCK, Ark. — Mike Wise, Golden Spread Electric Cooperative’s senior vice president of commercial operations and transmission, once again argued against a revision request funneled through the SPP Market Working Group that replaces the terms “head-room” and “floor-room” with “instantaneous load capacity.”
Wise told the Board of Directors and Members Committee that with MRR173, part of a compliance package responding to FERC Order 825, procuring rampable capacity through the reliability unit commitment (RUC) process “masks shortage conditions in a manner inconsistent with the requirements of FERC’s shortage-pricing rule.”
“We’re RUCing them left, we’re RUCing them right, we’re RUCing them all the time. [That] dampens prices and dampens the market,” Wise said. “It’s just an advanced form of an [energy imbalance service] because of all the RUCing that’s going on.
“There are so many new resources … that are rapidly coming on that make appropriate price signals even more important. Our main goal should be to allow resources to clear based on market offers, not cost, in the dispatch model itself. The process needs to be improved substantially.”
Not so fast, said American Electric Power’s Richard Ross, the MWG’s chair. He said the claim that SPP is “RUCing things as they see fit couldn’t be further from the truth.”
“We could change the rules and say we don’t even need the reserves, but we’d have more scarcity events,” Ross said. “Being a balancing authority comes with obligations. It is unacceptable to go into real-time operations; not only unacceptable, but it’s not compliant to go in short. This revision is clarifying exactly what staff should be doing.”
Ross said MRR173 and MRR175, which seeks to comply with Order 825 by using shortage pricing for any interval in which energy or operating reserves are short, would address Wise’s concerns. Both revisions are necessary for SPP to make a planned FERC compliance filing in January.
A third revision, MRR188, gives staff the option to include as much as 100% of instantaneous load capacity (as opposed to the current 0% of capacity) in clearing the day-ahead market. The revision is a protocol change, so it did not need board approval.
The three revisions “are all tied together,” Ross said. “What’s happening with this change, and the change in 188, is to move that procurement into the day-ahead market. It’s an improvement. We don’t want scarcity events. We want right pricing.”
“I don’t believe there are any cost implications at all. I believe it’s a practice we have to live with at SPP,” said COO Carl Monroe, pointing to the Price Formation Task Force as another group addressing the ramping issue. The task force is expected to wind down its work by year-end and then hand it over to the MWG.
“The entire MWG is sympathetic to you,” Ross said to Wise. “I absolutely feel you should recover all costs for generating energy out of those [quick-start] resources. The answer is to set prices at the cap, frequently, in order to allow that to happen. We think shortages happen and are being priced appropriately, but this is a first step. We need to … be in position to comply with the FERC order and after that, we can improve on it.”
Wise said he was encouraged by Ross’ comments.
“To the extent we can eliminate RUCs, I really want us to get there,” Wise said. “It’s not an issue that’s going away. We should be procuring through the market and the bid-stacking process.”
Still, Wise wound up casting the lone opposing vote against MRR173. He was joined in opposing MRR175 by Dogwood Energy’s Rob Janssen, who said he objected to staff inserting language the week before October’s Markets and Operations Policy Committee meeting calling for a $5,000 spike in the operating reserve demand curve (ORDC) during a scarcity event.
“I look at pricing to have the right price at the right time for the right reason,” Janssen said, paraphrasing an SPP motto. “Going straight to $5,000 in an event like this is unnecessary. The single highest price we’ve seen at our node is $2,000. It’s an excessive change, in my opinion. If we can have further discussion about reducing the number, I’d appreciate that.”
Richard Dillon, SPP’s director of market design, responded that the ORDC will go straight to $5,000 “because it’s a demand curve, and we have run out of ramp at that point.”
“We set it at $5,000 so we don’t choose to do other things and cause reliability issues,” he said. “If we’re short all the reserves in the [load zones] and the region, the prices have the potential to be at $3,400, so we needed this one to be higher than that value.”
The MWG “will make the language as appropriately flexible as we can,” Ross said. “We have some implementation time before the compliance filing is put into effect.”
The board also approved two other revision requests brought forth by the MWG:
RR183, which updates the violation-relaxation limits’ operating constraint to allow additional redispatch to solve cases with fewer violations, passed with two opposing votes.
RR193, which adds rules for solar resources to the market protocols and Tariff, including incorporating a solar forecast in SPP studies, increasing the solar forecast’s accuracy and including solar resources in dispatchable variable energy resource registration. The revision received two abstentions.
Brown Says Cybersecurity Biggest Challenge
SPP CEO Nick Brown said during his president’s report that cybersecurity issues will be SPP’s — and the industry’s — biggest challenge in 2017.
“Our ability to rely on the Internet of things is being challenged,” he said. “That makes us rethink how we operate our businesses and how we rely on the Internet going forward.”
Brown said SPP’s organizational groups will all spend time at their next meetings gathering feedback “to decide the appropriate level of cybersecurity for this organization.”
“Our systems are there to serve you,” he said, “but the cost to comply … goes up.”
Brown also talked about several other initiatives. He reminded members and the board that he had labeled 2016 as “The Year of the Audit” back in January. He said SPP completed SERC Reliability compliance and FERC financial audits without findings, and he hopes a Critical Infrastructure Protection Version 3 audit begun in 2013 will be completed soon.
An internal initiative to reward employees for finding disparities between SPP’s 5,275-page Tariff and actual operating practices resulted in 10 self-reports to FERC, Brown said. He said the commission took no action on the reports.
FERC’s recommendations to “improve the appearance of independence” of the Market Monitoring Unit have been “implemented or are in the process of being implemented,” he said. The commission issued an audit report of the MMU in July, saying SPP executives had “inappropriate” involvement in the MMU’s oversight and called on the RTO to “strengthen its independence.” (See FERC Calls for Changes to Protect SPP Market Monitoring Unit Independence.)
The Integrated System’s first year of SPP membership resulted in $67 million in net savings to the RTO’s footprint, including $27 million to original members “that otherwise would not have been there.”
Finally, Brown said revenues are down 3.9% because of low loads. SPP budgeted the 2016 administrative fee using 2015 coincident peak loads, which were projected at 407 million MWh. The peak load forecast is now 394 million MWh.
Directors, Trustees, Members Re-elected
Members and directors re-elected several incumbents to the board, Regional Entity trustees and Members Committee during SPP’s Annual Meeting of Members.
Stuart Solomon (AEP) and Kelly Harrison (Westar Energy) were re-elected to represent the investor-owned sector; Stuart Lowry (Sunflower Electric Power) and Mike Risan (Basin Electric Power Cooperative), cooperative sector; Jeff Knottek (City Utilities of Springfield), municipal sector; Janssen, independent power producer/marketer sector; and Brett Leopold (ITC Great Plains), independent transmission companies.
Directors Julian Brix and Phyllis Bernard were re-elected to new three-year terms on the board. Bernard was first elected to the board in 2003 and Brix in 2008.
Stephen Whitley was elected to an additional three-year term as an RE trustee. Whitley completed former trustee John Meyer’s unexpired term following the latter’s resignation in March over a conflict with the bylaws of Western Interconnection reliability coordinator Peak Reliability, where Meyer is vice chair.
Ross Forgoes Razor for Charity
Ross, an often outspoken presence at SPP and ERCOT stakeholder meetings, has made himself even more noticeable with the recent addition of facial hair.
Ross began growing his beard following SPP’s board and MOPC meetings in July. There, he issued a challenge to his fellow stakeholders: If they contribute more than $1,000 to the United Way organizations of Tulsa, Okla., and Little Rock, he would not shave until Thanksgiving.
“And if you contribute more than $2,000, I will go full Duck Commander,” Ross said, referring to the popular “Duck Dynasty” television program.
Ross was unable to meet the higher goal, but his neatly groomed beard attests to what he was able to raise.
Consent Agenda Adds Working Group, Approves IEP Panel
The unanimously approved consent agenda included chartering the Supply Adequacy Working Group, which will take on tasks from the Generation Working Group and Capacity Margin Task Force; adding the Nebraska Public Power District’s Traci Bender to the Strategic Planning Committee; expanding the Oversight Committee to five independent directors; and accepting the Oversight Committee’s 11 candidates for the Industry Expert Pool that will evaluate and recommend competitive-upgrade projects.
The board and members also accepted the SPC’s recommendations to improve the competitive transmission process, the Project Cost Working Group’s recommendation to reset the baseline for an AEP 345-kV project in southeastern Oklahoma and staff’s recommendations to accelerate one project and withdraw the notice-to-construct for another. (See SPP Panel OKs Changes to Competitive Transmission Process, “AEP Project’s 41% Overrun Approved” and “Members Vote to Cancel 69-kV line in West Texas,” SPP Markets and Operations Policy Committee Briefs.)
Other rule changes approved by MOPC were:
MWG-MRR178: Specifies that SPP’s Market Monitoring Unit will review the costs included in each mitigated resource offer, on an ex post
MWG-MRR179: Aligns the protocols with FERC-approved language (ER15-2265) to ensure long-term congestion rights are not affected by potential resource hub terminations, and that resource hubs used in bilateral contracts can’t be unilaterally terminated by the hub’s owner.
MWG-MRR181: Corrects outdated references in the Tariff and protocols related to the allocation of annual auction revenue rights, an oversight noted by FERC (ER16-13).
MWG-MRR185: Clarifies which document — SPP Planning Criteria or SPP Operating Criteria — is referenced when used in the market protocols and Tariff.
ORWG-RR168: Requires transmission owners to provide the highest available emergency ratings and specifies SPP’s interpretation of those ratings.
TRR88: Modifies the time of day when unscheduled firm transmission is released for sale as hourly, non-firm transmission service for those members wishing to coordinate next-day scheduling with the Western Electricity Coordinating Council.
RTWG-RR164: Updates Tariff Attachment O to correctly reflect the current near-term planning process schedule, which is now conducted in the April-March timeframe.
RTWG-RR174: Revises Attachment AQ of the Tariff to eliminate a requirement that transmission customers submit a request for changes in delivery point facilities when there is no corresponding change in load.
RTWG-RR176: Corrects and clarifies responsibilities and requirements under the process that allows generation resources to be compensated for reactive support.
TRR88: Modifies the time of day when unscheduled firm transmission is released for sale as hourly, non-firm transmission service for those members wishing to coordinate next-day scheduling with WECC.
MISO said it generally agrees with the recommendations its Independent Marker Monitor laid out in its 2015 State of the Market report, but the RTO won’t implement a few recommendations and wants additional analysis on some others.
On a conference call of the Market Committee of the Board of Directors on Oct. 24, MISO said there is only a “minority of problems identified where [it] believes additional analysis is necessary to confirm [the] problem or to identify alternative solutions.”
Under their Tariff, the RTO has 120 days to respond to the Monitor’s recommendations.
Software Changes Required
MISO Executive Director of Market Design Jeff Bladen said the RTO is working on expanding eligibility for online units to set prices in extended locational marginal pricing (ELMP), but changes to the software would be difficult and it wanted to focus on other Market Roadmap projects first. However, MISO still breaks with the Monitor on suspending offline pricing in ELMP. (See “MISO to Expand ELMP Price Setting, but not to IMM’s Specs,” MISO Market Subcommittee Briefs.)
Bladen said implementing the Monitor’s full suggestion would require a complex software modification. “There are no simple code changes to the software at this point. It certainly isn’t a one-day change,” he said.
Market Monitor David Patton said the difficult software change stems from software vendors “hard coding” software where it cannot be opened later to expand design parameters.
Bladen said although it agrees with the Monitor that it should implement firm capacity delivery procedures with PJM, MISO has been unable to move the solution through the two-party approval process because of resistance from PJM earlier this year and has put its proposed solution on hold. (See “Ready for Pseudo-Tie Switchover,” MISO/PJM Joint and Common Market Meeting Briefs.)
“It’s PJM that requires resources external to PJM to be pseudo-tied,” Patton agreed. He said he and MISO are considering asking FERC to open a Section 206 proceeding against PJM to force a change in its Tariff.
‘Weaponizing’ FERC Filing
MISO Director Michael Curran said he would rather not build a relationship with PJM by “provoking” them with a 206 proceeding and cautioned against “weaponizing” FERC filings. CEO John Bear said MISO is developing alternatives to firm capacity procedures to present to PJM.
Bladen said the Monitor’s advice to improve the modeling of transmission constraints in the Planning Resource Auction was not prioritized by stakeholders as a key concern, but MISO would work on scoping a study.
The RTO also said it agreed with the expansion of temperature-adjusted and short-term emergency ratings for transmission facilities and will work with its transmission owners on improvements.
However, MISO is unlikely to increase physical withholding mitigation measures in the PRA by addressing uneconomic retirements. The RTO said the concept of uneconomic retirements itself is a problematic, as such instances would be difficult to determine.
Patton countered that the problem could crop up when a large generator clearly retires to give affiliates a higher clearing price. Bladen said the threat of an entity’s permanent loss of injection rights if it is found to be gaming the market is “sufficient deterrent” to such retirements. He said the RTO is working on a suggestion from 2013 to subject suspended resources to withholding rules, but he didn’t see the need to include retiring generation.
However, MISO has committed to expanding withholding mitigation in the PRA by recognizing affiliates’ connections. Bladen said MISO and Patton will discuss the issue with stakeholders. “We think it’s important to look at the affiliate nature of resources and examine them for physical withholding,” Bladen said.
On the other hand, MISO sees gray areas around a few of Patton’s recommendations. MISO says it is awaiting further details from the Monitor on how to improve the modeling of transmission constraints in the PRA and is looking for changes that can be achieved in the near term.
Transfer Constraint
MISO took a similar wait-and-see stance on Patton’s suggestion to increase the transfer constraint between the RTO’s South and North regions in the PRA. The RTO said it is holding stakeholder discussions and has support for a study to examine the benefits of developing its own transmission to link the interfaces, as an alternative to SPP’s transmission. (See MISO Proposes Study to Measure Benefits of New North-South Tx.)
The study will be rolled into other analyses as part of MISO’s 2017 Transmission Expansion Plan. MISO said the annual cost to maintain constraints under the SPP settlement can be as much as $38 million.
The RTO also has mixed feelings about modeling its voltage and local reliability requirements in the day-ahead market, saying it already models the requirement but doesn’t include it in the day-ahead market. However, it said it would discuss potential advantages of an automated market process with the Monitor
Bladen said it will take five to seven years to implement all of the 2015 solutions MISO agrees with, calling the timeframe in line with the RTO’s “robust stakeholder process.”
Bladen also said all recommendations made prior to 2011 have been resolved. It takes MISO an average of 2.3 years to close out suggestions, according to the RTO.
Patton said implementation of software fixes for his recommendations are sometimes slowed by difficulty scheduling work with MISO’s software vendors or getting the attention of RTO executives responsible for multiple market improvements.
The 30-MW wind farm, located off the coast of Rhode Island, is expected to begin producing electricity in November.
