NASHVILLE, Tenn. — Present and former regulators debated the costs and benefits of rooftop solar and the pros and cons of net metering in a spirited discussion at the National Association of Regulatory Utility Commissioners summer conference last week.
Charles Cicchetti, former chair of the Wisconsin Public Service Commission, and former Ohio Public Utilities Commissioner Ashley Brown led off the debate.
Cicchetti, a member of Pacific Economics Group and former economics professor at the University of Southern California, said regulators’ moves to curtail or reduce net metering payments and introduce new demand charges “greatly cut into the benefits that customers who installed rooftop solar expect to earn and use to pay for those systems.”
Cicchetti said regulators should require “vetted … neutral studies” to determine the costs imposed by solar customers and compare them with the benefits they provide.
“When you do that you’ll probably come away with the conclusion that, if anything, the extra costs that are being imposed by rooftop solar [are] far less than the extra benefits both in utility savings and societal benefits,” he said.
He said that time-of-use tariffs are more fair than demand changes, which he called “a blunt instrument.”
“If [rooftop solar customers] take electricity during expensive times, they should pay more. But they should also save more when they reduce electricity — as most of them do — during the time that those systems are operating.”
Brown, of the Harvard Electricity Policy Group, disagreed, saying solar customers under net metering are not paying their fair share of the system’s fixed costs.
The value of solar studies is incredibly subjective, Brown said. “Many states have done them; many interest groups have had them done and the findings are all over the map,” with some finding the value of solar is double the retail price and others finding a negative value. “Neither of those cases could possibly be true.
“Several things are always missing from these studies,” Brown continued. “One is, every single one of these values can be obtained from other sources. So why aren’t we disciplining the price we pay for those values by putting it into a marketplace with other sources? And many of these values are provided by other forms of generation who aren’t compensated for it because we don’t pay anybody based on value. We pay them based on market or we pay them based on cost.”
Nevada Public Utilities Commissioner David Noble spoke about the state’s bruising net metering battle last year, when the PUC conducted a ratemaking in response to a legislative mandate that rooftop solar result in “no unreasonable cost shifts.”
Noble said the commission was vilified by solar energy providers even though it rejected demand charges, implemented optional time-of-use rates and ordered a phase-in of “value-based” rates for excess energy.
“The rooftop solar companies decided to take an approach … that there should be no change from retail rates,” he said. “When you take an all-or-nothing approach, there’s a possibility that you’re going to lose. And that’s exactly what happened because they put on an inferior case.
“The CEO of SolarCity was claiming that he literally had a gun to his head and the commission was in the back pocket of” NV Energy, he said.
Solar companies bused hundreds of protesters to PUC headquarters, some of them exercising their open-carry rights to travel with guns, Noble said. There they attempted to alarm consumers by claiming utility rates would increase by 3% annually for the next 20 years.
“We haven’t had 3% increases year-over-year for any longer than three years,” he said. “In fact, over the last six years … rates have been flat in southern Nevada and they’ve gone down 20% in northern Nevada.”
Beverly Heydinger, chair of the Minnesota Public Utilities Commission, said the focus on net metering and rooftop solar is myopic, and that policymakers should also consider storage, electric vehicles and other emerging technologies.
“We’re not planning for today. We’re trying to develop a flexible enough template that we can use it and adapt as the times are changing,” she said.
RAPID CITY, S.D. — The SPP Board of Directors and Members Committee last week agreed to give transmission customers an extra 50 months to pay their Z2 bills while also creating a new task force to address complaints of members charged for costs that were not identified in service agreements.
The two actions illustrated the challenge of trying to ensure the equity of retroactively billing customers, the magnitude of the debts involved and the complexity of determining amounts to be billed and reimbursed under Tariff attachment Z2, which details how sponsors that fund network upgrades can receive reimbursements. Staff has identified $848.8 million in assigned costs from 158 creditable upgrade projects.
The board and members unanimously approved the Markets and Operations Policy Committee’s earlier recommendation to extend the Z2 payment timeline from 10 months to five years and dismissed waiver requests previously rejected by the MOPC. (See SPP MOPC Recommends 5-Year Timetable for Resolving $849M Z2 Bill.)
Stakeholders also agreed to a suggestion by SPP CEO Nick Brown and directors Phyllis Bernard and Larry Altenbaumer directing MOPC Chairman Noman Williams to assemble a task force to find “a more rounded solution to this problem,” as board Chairman Jim Eckelberger put it.
The actions all but ensure there will be an additional recalculation of Z2 credits and bills in the near future.
“Does that mean there’s a round two coming? I believe it does,” Eckelberger said. “We’ve got to find a way to be as inclusive and equitable as [the process] can be. We need to get this right.”
The agreement short-circuited another contentious discussion on an issue that dates back to 2008, when SPP was to have begun crediting and billing customers for system upgrades in accordance with attachment Z2. Years of incorrectly applied credits have complicated the task of trying to accurately compensate project sponsors and claw back money from members who owe debts for the upgrades.
“We feel we are owed a significant amount of credits … our concern is the same it’s always been,” said NextEra Energy Resources’ Mark Tourangeau, echoing comments by other members waiting on credit payments. “I would urge the board and all the stakeholders to think about equity from the folks who have to pay upgrade costs, the folks who are due credits and the folks who have to go back” and ask for payments.
“It’s fair to say that when we signed service agreements, there was no indication the charges would be as high as what they are. The fact [that] the payment plan was recently extended shows the board didn’t know either,” said Stuart Solomon, COO of American Electric Power’s Public Service Company of Oklahoma. “So as we were making decisions to enter power purchase agreements, we weren’t making informed decisions. Every indication we had at that time was the costs wouldn’t be at this level, as we were signing service agreements that didn’t reflect all of these creditable upgrades.”
“I feel like the red flag on the rope in a tug of war,” SPP Director Bruce Scherr said. “There are compelling arguments on both sides, but I haven’t moved. It leaves me really uneasy about how to vote.”
“Our primary concern is … what did we know, and when did we know it?” said Les Evans of Kansas Electric Power Cooperative. “Frankly, going forward, I have concerns about how to do business with SPP as a customer. I signed a contract saying I have no direct assigned costs. Four years later, I have a bill for $6 million.”
SPP staff agreed that customers should not be obligated to pay Z2 costs for resources that were not designated in the agreements before service began. Staff also said that sponsored upgrade costs should be allocated based on rules in effect at the time a credit payment obligation is assigned, rather than the rules in effect when an upgrade became creditable.
Staff is working to provide historical billing results for stakeholder review before the October MOPC meeting. The first invoices are scheduled to go out in early November.
Edison International is maneuvering to capitalize on California’s effort to meet its greenhouse gas emissions goals and encourage the use of distributed energy resources.
The 2018-2019 rate case for subsidiary Southern California Edison will include a capital spending request “designed to help California achieve its low-carbon policy objectives and to enable customer choice,” Edison CEO Ted Craver said during a call with investors last week.
Edison’s second-quarter profits fell 27% to $276 million, in part because year-ago earnings reflected a $100 million income tax benefit.
The second quarter of 2015 also included revenue SCE later refunded to ratepayers after a delayed ruling from state regulators on its 2015 rate case.
As a result, the company said, any comparison between the two quarters was “not meaningful.”
Craver said SCE’s rate base is projected to grow 7% over 2016-2017 based on capital spending approved by the California Public Utilities Commission and expected spending on FERC-jurisdictional transmission projects.
While the company expects “relatively little variance” in the timing of its spending on CPUC-jurisdictional projects, it could experience some “variability” in the timing for its FERC projects, which Craver attributed to delays in routing decisions and state and federal permitting approvals.
“A recent example was the $1.1 billion West of Devers project, which has been something of a moving target with CPUC staff — even with CAISO support — but appears ready for final CPUC approval with a supportive alternate proposed decision pending,” Craver said.
Project delays could defer some spending planned for 2017 to subsequent years, he said, but SCE does expect to complete major transmission projects linking the utility’s service territory with renewable generation located farther inland.
Edison anticipates a future shaped by 2015 legislation that seeks to use the grid to help meet the state’s carbon reductions goals, including reducing vehicle emissions through electrification of the fleet. One byproduct of that law is a current CPUC proceeding that seeks to direct utility investment to facilitate the wider adoption of DER.
In response, capital expenditures will be “lumped into two buckets” in the rate case SCE intends to file with the CPUC on Sept. 1.
The first bucket will consist of “traditional” investments, such as replacing aging infrastructure, adding new customer connections, upgrading information technology and maintaining SCE’s generators. The second will reflect investments in the modernization of the utility’s distribution system to facilitate the growth of DER.
Craver said the CPUC has “provided only some early direction on preferred technologies and required investments” for modernization.
Through its upcoming rate case, SCE will be the first utility “to provide specificity for how this technology evolution should unfold,” Craver said.
While Craver said he wouldn’t divulge details ahead of the filing, he noted that some of the utility’s modernization investments amounted to reinforcing the existing system, such as upgrading low-voltage circuits to accommodate increasing amounts of DER.
“But other parts really have no precedent, and therefore we do not know how to handicap how much of our request might finally be approved,” Craver said.
NEW YORK — Speakers at Infocast’s 2nd NY Energy REVolution Summit last week pondered how New York’s Reforming the Energy Vision could deliver on its promise of cleaner and more distributed generation, with persistent low power prices.
The challenge is introducing transformative changes in an environment of already record-low prices, changes that would reduce margins for market participants while also requiring massive investments.
“The state of New York has embarked on two significant transformative issues simultaneously: the Clean Energy Standard driving toward 50% renewables [by 2030] and REV,” Michael Schwartz, CEO of advisory firm New Wave Energy Capital Partners, said during a panel discussion on the latest developments of REV. “If I have seen in the past the potential for stranded investment, this is it. If we’re going to achieve the CES, the state is going to [need to] create incentives for market signals to drive the construction of utility-scale renewables at the same time we’re driving down demand and moving [generation] behind the meter.”
Schwartz said regulators will somehow need to reconcile the initiatives.
“The fundamental change to move from cost-of-service to market-based [utility earnings] is conflicted with maintaining the financial integrity of electric utilities,” he said.
Utilities, while understanding the imperative to revamp their generation fleets, maintain infrastructure and preserve their financial viability, are wary, he added.
“Based on discussions I’ve had, the consensus in other jurisdictions is ‘we’re not doing that,’” Schwartz said.
New York is moving ahead on another legally uncertain path to create financial incentives for its struggling nuclear fleet until large-scale renewables are built to take their place. On Monday, the New York Public Service Commission approved a zero-emission credit for nuclear plants, at a projected cost of $7.6 billion over 12 years. (See related story, New York Adopts Clean Energy Standard, Nuclear Subsidy.)
A proposal earlier this year based the ZEC subsidy on the difference between the cost-of-service from the nuclear plants and the wholesale power prices in NYISO. A PSC staff proposal in July changed the formula to align with EPA’s calculation of the social cost of carbon. Generation owners, customers and some environmentalists object.
David Appelbaum, an attorney for the New York Power Authority, said the change was the result of the U.S. Supreme Court’s April decision in Hughes v. Talen, in which the court voided Maryland’s attempt to incent generation by using a contract for differences related to the PJM capacity market. (See Supreme Court Rejects MD Subsidy for CPV Plant.)
“The order has changed significantly. Before the change, it would have been open to challenge in the context of the [Hughes] decision,” Appelbaum said. “It’s less so, but there’s still risk.”
Whatever the eventual outcome, New York has gotten ahead of many places as it embarks on REV.
“Once you start looking at the regulatory paradigm, regulation was not intended to support this vision. Regulation is still cost-of-service-based,” said Paul DeCotis, a senior director at West Monroe Partners and panel moderator.
However, Jim Gallagher, executive director of the New York State Smart Grid Consortium, said the model is still relevant for now.
“We need to remember that utility cost-of-service regulation is still going to provide 96% of utility revenues for the foreseeable future and these initiatives are going to provide less than 4%,” he concluded.
CARMEL, Ind. — Increased natural gas prices and congestion in MISO South boosted energy prices 23% in June, according to the RTO. Day-ahead energy prices in June averaged $27.36/MWh; the real-time average price followed closely at $27.42/MWh.
MISO also reported that above normal temperatures in June drove the average load to 83.1 GW, a 3.5% increase in a year-over-year comparison. Load peaked at 112.5 GW on June 20.
“We did see above normal temperatures generally throughout the region, throughout most of the month, and we did issue several hot weather alerts in different parts of the footprint on various days,” Vice President of System Operations Todd Ramey said during a July 26 Informational Forum.
Ramey also said MISO tested its new emergency pricing structure on July 21 during a three-hour maximum generation event. Ramey said a Detroit-area thunderstorm and market participants self-deploying emergency resources upon the event declaration reduced peak load by “a couple thousand megawatts,” which resulted in “plenty of supply cushion as [MISO] moved across the peak that day.” MISO’s peak on the day was 121,000 MW, below the forecasted 126,000 MW.
A review by MISO’s pricing team of the emergency event uncovered a software logic error that required a fix from the vendor, Ramey said. MISO will review the event and post recalculated real-time prices for July 21 before the Aug. 2 Market Subcommittee meeting, at which RTO officials will explain the issue and the correction, he said. The RTO rolled out the new emergency pricing structure on July 1. (See “MISO to Set Two Emergency Pricing Offer Floors,” MISO Market Subcommittee Briefs.)
Ramey also said MISO plans to present its response to the eight new recommendations in the Independent Market Monitor’s State of the Market report at the September meeting of the Markets Committee of the Board of Directors. (See Monitor’s State of the Market Report Seeks Changes to MISO ELMP.) In the meantime, he said, the RTO is working with Monitor David Patton “to make sure we understand all of the new recommendations.”
MISO Asks Members to Consider Bylaw Changes
MISO is considering reducing or eliminating the service prohibition on members of its Board of Directors in revisions to its Transmission Owners Agreement and Bylaws.
Deputy General Counsel Eric Stephens said the RTO is considering “less onerous” restrictions on the directors, who currently have two-year pre- and post-service prohibitions from utility and wholesale energy market participants. Stephens said the rule could be eliminated or reduced to either one-year pre- and post-service prohibitions or a one-year pre-service prohibition and no post-service prohibition.
Easing the restrictions would improve director recruiting and be more consistent with other RTOs, Stephens said. Seats currently occupied by Chair Judy Walsh and members J. Michael Evans and Paul Feldman are up for election this year.
Other bylaw revisions could mean that MISO would no longer be required to hold its annual meeting on the second Thursday of December. The RTO also is considering holding board elections — currently held at the annual meeting — earlier to ensure consistency with the new board meeting schedule. The slate would be announced in September, with results announced as early as the Oct. 25 Informational Forum.
Another revision would clarify that a majority of the directors constitutes a quorum for calling a meeting or tallying a vote.
Stephens said MISO also is seeking to change the invoicing of the $1,000 annual membership fee from the current Jan. 1 to dates tied to the time of year each member joined.
The bylaw changes were suggested by MISO’s Corporate Governance and Strategic Planning Committee. Stephens said none of the revisions would impact transmission owner rights or obligations.
MISO is seeking stakeholder feedback on the proposed changes by Aug. 15. If stakeholders are in accord, the RTO could file revisions by the fourth quarter.
EPA Official Makes Case for CPP
Janet McCabe, EPA’s acting assistant administrator for the Office of Air and Radiation, made a case for the Clean Power Plan, saying MISO’s comments to the agency were “incredibly constructive.”
She also expressed confidence that the rule will survive legal challenges. Oral arguments on the challenge are scheduled before the D.C. Circuit Court of Appeals for Sept. 27.
EPA is accepting comments until Sept. 2 on its Clean Energy Incentive Program (CEIP), an optional early-action program that would help states meet their CPP emission targets through incentives for investment in demand-side energy efficiency and solar power generation in low-income communities. The program also encourages early investment in non-emitting wind, solar, geothermal and hydropower generation.
MISO Executive Director of External Affairs Kari Bennett said MISO and PJM plan to conduct a joint impact study on the CPP during the second half of this year. MISO stakeholders have asked for a similar study with SPP.
ARPA-E Program Director: Research Collaboration Discussion to Take Place at Symposium
Tim Heidel, program director of the Department of Energy’s Advanced Research Projects Agency-Energy (ARPA-E), previewed MISO’s Aug. 18-19 Market Symposium, which will focus on technology partnerships among researchers, startups and RTO stakeholders. Heidel will be a panelist at the session in Indianapolis. (See Energy Department’s ARPA-E to Join MISO for First-Ever Market Symposium.)
The New York State Energy Research and Development Authority is now the lead agency backing a proposed 90-MW offshore wind development south of Long Island. “Offshore wind is clearly a critical part to achieving Gov. [Andrew] Cuomo’s clean energy agenda of achieving 50% by 2030. The numbers offshore are huge, with us talking about 38 GW of potential near the downstate load centers,” NYSERDA CEO John Rhodes said.
Jamie Resor, CEO of solar project developer groSolar, said his peers need certainty, and a commitment from policymakers could be more valuable than a better credit rating for a project in a state where the likelihood of a failed deal may be higher. “New York surely is not the least expensive place to do business, and it certainly is not the sunniest … but you’re in a state that has big goals, and we have a [committed] partner, and while we’re not certain how we’re going to [reach those goals], we know that somehow we’re going to figure it out,” he said.
Doug McMahon, vice president of strategy for the New York Power Authority, said the Reforming the Energy Vision promise of customer-centric engagement between energy consumers and utilities has been slow to develop.
“We’re in for an interesting year, when we’ll have a clearer understanding if there are going to be long-term successes with REV,” McMahon said. “There is increasing frustration in the amount of progress that’s being made. The substance of REV is development of market forces, and at the moment, those forces aren’t strong enough to animate the consumer or the utility into integrated action. Until we see those forces become stronger, we’re not going to see a great deal of momentum.”
Craig Lewis is executive director of the Clean Coalition, a nonprofit promoting a modernized grid to hasten the integration of renewable energy. He said failing to understand the way distributed wind, solar or storage add value to the system — in providing reactive power or resiliency to benefit system performance, for example — creates challenges.
“If you don’t understand how these resources are going to work together, there’s no possible way you can optimize them from a policymaker’s standpoint. You cannot go forward and design a market mechanism” that incentivizes participation, he added.
Mike DeSocio, senior manager of market design at NYISO, said the ISO is working on a distributed energy resources roadmap in order to determine how they affect the wholesale market.
“The questions we are trying to answer are: How do these resources interact with the ISO? What services can these resources provide, and what kind of configurations and uses are we thinking about to utilize these resources? … It’s going to be a little bit of a journey, so the way the ISO is thinking about this is in small stages of three to five years. We’re not trying to project out 20 years.”
ALBANY, N.Y. — The New York Public Service Commission on Monday unanimously approved its Clean Energy Standard, including a controversial plan to prop up struggling upstate nuclear power plants with a 12-year subsidy that opponents say could cost ratepayers $7.6 billion (15-E-0302).
The order creates a zero-emission credit for nuclear plants similar to the way states incentivize renewable resources with an additional above-market payment. ZECs were a feature added earlier this year to the CES, which will require New York to derive 50% of its energy from renewable sources by 2030. Nuclear power, which currently provides 30% of the state’s electricity, is seen as a bridge for its carbon-free attributes until renewable energy can be produced at scale.
“If these plants close abruptly, they in all likelihood will be replaced by the attributes of expanded fossil fuel base generation,” PSC Chair Audrey Zibelman said at the meeting. “This will impair our ability to achieve our environmental goals.”
Zibelman also disputed the estimates of the plan’s price tag, saying that opponents of nuclear subsidies are presupposing that record-low natural prices will continue, highlighting the differential from the relatively higher prices for nuclear. “By not effectively pricing in the cost to our environment of our electric choices, we are, in fact, causing economic inefficiencies,” she said.
An overflow crowd of union members, environmentalists and pro- and anti-nuclear activists filled the PSC meeting room, necessitating the use of four supplemental hearing rooms for videoconferencing.
“We’re very supportive of every effort to support renewable energy,” Jessica Azulay, of the Syracuse-based Alliance for a Green Economy, said after the meeting. “But we’re very disappointed by the decision to subsidize nuclear power and prevent the closure of nuclear reactors.”
“We have a new power market here, and that’s going to reflect the societal price of carbon, so we can’t really call this an above-market contract,” Phil Wilcox, representing the International Brotherhood of Electrical Workers Local 97, based in Buffalo, said after the meeting.
PSC staff recently revised its calculation for ZECs to base their value on EPA’s social cost of carbon instead of a previous proposal to value them on the difference between the cost of service for nuclear plants minus wholesale power prices in the NYISO market. (See Commenters Laud, Blast New York’s Nuclear Subsidy Plan.)
The ZECs will be worth $17.48/MWh for the first two years of the program, or about $965 million. The order mandates that electric distribution companies purchase ZECs representing a proportion of their annual load, based on annual forecasts.
The state-owned New York Power Authority and the Long Island Power Authority are exempt under state law, but Zibelman said that officials at both entities indicated that they will voluntarily comply with the CES, including the ZEC payments.
The plan has been favored by legislators in western New York, where the plants are located, labor unions, economic development proponents and some environmentalists.
“Today’s implementation of the CES is a momentous day for the state of New York, and more specifically, the upstate communities that have waited anxiously for months for this moment,” the Upstate Energy Jobs Coalition said in a statement.
The subsidy was opposed by other environmentalists, large commercial and industrial customers, power generators and marketers, and elected officials from other parts of the state. Some environmentalists dispute the clean energy attributes of nuclear. Customers objected to the plan’s cost, and generators and marketers said the plan interfered with the competitive power market.
The plan opens the door for Exelon to become the sole owner of the four plants on Lake Ontario — R.E. Ginna, Nine Mile Point Units 1 and 2 and James A. FitzPatrick, which it is seeking to acquire from Entergy. (See Entergy in Talks to Sell FitzPatrick to Exelon.)
Entergy previously said it would close FitzPatrick early next year. Exelon said it would close Ginna and Nine Mile Point 1 in March if it did not have a contract with New York by the end of September. (See Exelon Threatens to Close Nine Mile Point 1.)
“This is one of the largest corporate bailouts in New York’s history and it will benefit only one company, Exelon Corp.,” a coalition of elected officials and environmental organizations argued last week.
The other nuclear power plants in New York, Entergy’s Indian Point Units 2 and 3, are currently ineligible for the subsidies under the plan adopted Monday. However, under the staff’s revised proposal, Indian Point could become eligible for ZECs in the future if it could prove it was financially stressed. Gov. Andrew Cuomo has advocated the closure of Indian Point because of its proximity to New York City.
Zibelman said Indian Point was not excluded from possible eligibility so that the order would be “non-discriminatory.”
Exelon began a separate proceeding in the spring to seek cost-of-service-based compensation for its plants in the event that the PSC did not act in time to address its request to keep the nuclear plants viable. That proceeding was rolled into the larger CES case by the commission.
RAPID CITY, S.D. — Less than a year after enjoying a 2-cent reduction in SPP’s administrative fee, the RTO’s members are now facing the prospect of a 4-cent hike for 2017.
SPP’s Finance Committee announced the increase during last week’s Board of Directors and Members Committee meeting to minimal pushback. Members — with only three opposing votes — and the board approved the committee’s recommendation to hike the fee’s cap to 43 cents/MWh, which would allow room to raise it from its current 37 cents/MWh to a projected 41.1 cents/MWh.
The board’s approval means staff can file the necessary Tariff changes with FERC.
Staff said the move was necessary because the RTO expects 2016 expenses to exceed revenues by $6.7 million as a result of a 3.7% drop in peak loads since 2015.
SPP is forecasting revenue from the fee will be $5.4 million below budget for the year. Staff said raising the fee’s cap above 2017’s projected level would “accommodate any further reduction in peak load similar to what SPP utilities experienced in 2015.”
The committee said it will review the fee’s billing determinants to see “if a more predictable and equitable basis exists to allocate SPP’s costs of operations to its customers.”
“The admin fee is one of the places where the rubber hits the road,” said Oklahoma Gas & Electric’s Greg McAuley. “We just got done with a rate case, and I can tell you it is very, very difficult to raise rates.”
SPP’s addition of the Integrated System last October was expected to help keep the fee stable. However, the system’s reported loads have been 10% below expectations; SPP projected a 12% increase in transmission load last year with the system’s membership. (See SPP Board Approves Budget, SPC Expansion.)
“We thought we would bring the number down 5 cents with IS, but it actually brought them down by 3,” Board Chairman Jim Eckelberger said.
“The costs in all of this equation didn’t change very much,” SPP CEO Nick Brown said. “The load in the footprint changed a lot, so what we’re collecting from each market participant will be roughly the same, regardless of what that rate is. It’s just the denominator” that changed.
This year’s budget assumed transmission volume of 407.2 million MWh. SPP’s draft 2017 budget projects 395 million MWh.
The Finance Committee said the 2017 budget still includes “several unknowns,” primarily because SPP has just started its 2017 planning process. A final budget will be presented to the board during its December meeting, when members will also vote on next year’s administrative fee.
Committee Chairman Harry Skilton noted that one favorable variable is the scorching summer heat that’s settled over the Great Plains. Skilton said SPP’s manpower costs have resulted in a $1.2 million hit above costs, “but we will carry on.”
Cybersecurity Insurance
Skilton also said cybersecurity insurance is becoming an available product, remarking, “Anything can be insured.” He said his committee will meet with Little Rock-based Stephens Insurance “once that market is a little solidified” as part of SPP’s overall insurance package.
Following the committee’s recommendation, members unanimously approved the selection of SPP’s controls, financial and benefit plan auditors KPMG, BKD and Thomas & Thomas. Members also authorized Brown and CFO Tom Dunn to negotiate the origination of a $30 million line of credit.
First Competitive Tx Project Pulled; ND 345-kV Line Approved
The group also approved modifying Basin Electric Power Cooperative’s notice to construct (NTC) for a 33-mile line between two substations in western North Dakota. The modification will allow Basin Electric to build the Kummer Ridge-Roundup project — part of a larger project that is already under construction — as a 345-kV line, a motion rejected two weeks ago by the Markets and Operations Policy Committee.
The project is expected to cost $45 million as a 345-kV line, compared to $24.9 million at 115 kV. Staff determined the 345-kV version performed better over a 10-year planning horizon, given projected 2.5% annual load growth driven by the nearby Bakken shale play.
Mike Risan, Basin Electric’s senior vice president of transmission, called the region the “sweet spot of the Bakken,” though field loads have proven to be volatile with the price of oil.
“The load is still coming here,” he said. “We have a pent-up demand from a number of wells already drilled and waiting to frack.”
Several members questioned whether Basin Electric was trying to run around SPP’s planning process by having the project — which was planned before the utility joined the RTO last year as part of the Integrated System — zonally allocated when it could be considered a regional project.
“We’re not trying to beat the system,” Risan said, saying the company was balancing serving load, planning for the future, transitioning to SPP and understanding new processes at the same time.
Bob Harris, senior vice president and regional manager of the Western Area Power Administration’s Upper Great Plains Region, stuck up for his fellow new member.
“The IS facility inclusion process was more restrictive than the SPP planning process,” he said. “I would submit if we had been part of SPP and part of SPP’s planning process back when we began this plan, it would have been in the SPP plan. It’s only because of the transition [to SPP] that we’re in this dilemma.”
SPP’s vice president of engineering, Lanny Nickell, said staff did not previously identify Kummer Ridge-Roundup as a “regionally needed” project, and it believes the project should be treated as a sponsored upgrade. “We didn’t determine any regional needs in the study.”
However, Nickell acknowledged that with its increased capacity, the line could have benefits that address regional needs identified in SPP’s Integrated Transmission Planning’s 10-year assessment.
“As I understand our model-build process, this project was not assumed to be built at 345, so it’s possible some of those ITP10 needs will go away.”
Most members agreed with the 345-kV solution. “I think that’s the best plan of action,” Xcel Energy’s Bill Grant said.
The board altered another MOPC recommendation from two weeks ago when it delayed until next quarter a decision to withdraw an NTC for American Electric Power’s $31 million rebuild of a 69-kV line in West Texas. Nickell said SPP is working to confirm AEP’s contention that the line suffers from congestion, saying reliability coordinators have not been able to observe the congestion in real time.
“AEP has addressed congestion on the line locally. Our findings may not necessarily change our recommendation to the board, but the situation warrants further investigation to accurately identify the frequency and significance of the congestion,” Nickell said.
The board and members also unanimously approved issuing an NTC for AEP’s rebuild of a 138-kV line near Shreveport, La. The project was initially expected to require a reactor, but that NTC was withdrawn, saving $3.55 million.
SPP Making FERC-Directed Changes to MMU
Oversight Committee Chairman Josh Martin told the board and members that SPP’s Market Monitoring Unit is well into the process of implementing changes recommended by FERC’s recent audit of the unit’s independence.
Martin said the committee has begun holding “MMU-only” meetings, “consistent with the direction we got from FERC.”
He also said SPP has begun plans for the physical separation of the MMU from RTO staff, also recommended by FERC. Martin said it would be similar to the Regional Entity’s setup with SPP’s headquarters building, which requires key-card access and only allows RTO employees entrance when accompanied by an RE employee.
“There were a number of findings and recommendations that frankly were minor, in my opinion, considering the length of time and resources that went into this audit,” Martin said. “We were able to demonstrate we have a good structure and operate efficiently.”
CEO Brown noted FERC found no instances of the RTO “exerting inappropriate influence” on the MMU.
The committee has also begun discussing plans to replace MMU Director Alan McQueen, who has agreed to delay his retirement until 2017.
MMU Shares Draft State of the Market Report
McQueen shared a draft report of the MMU’s 2015 State of the Market report, the second such evaluation since the Integrated Marketplace went live in 2014.
According to the report, the Integrated Marketplace is a “significant maturing” market reflected in high levels of participation, lower levels of make-whole payments and mitigation compared to other markets, and a modest level of scarcity pricing. The MMU said the market was affected by continually declining natural gas prices, increasing wind generation capacity and output, and declining levels of overall congestion, but with increased congestion in wind-generation areas.
Golden Spread Electric Cooperative’s Mike Wise disagreed with the report’s assertion that a “vast majority” of market participants running combustion turbines are able to recover their avoidable operations and maintenance costs.
“That is just not true. One of the reasons make-whole payments are so low is because you’re not allowing combustion turbines to get those start-up charges,” Wise said. “You have the view these are long-term charges. Is there an opportunity for us to continue this dialogue, not just Golden Spread, but all market participants?”
“We’ve had this discussion about the differences between what’s being used in mitigation and what’s being collected by any resource,” McQueen responded. “My disagreement with your interpretation of variable O&M is different when it comes to short run.
“I’ll reiterate my offer to look at specific units,” he continued. “If someone wants to come forward and have us look at those costs and see whether there’s adequate revenue on an annual basis, we’d love to have that conversation. The MMU can’t do it alone.”
Eckelberger closed the discussion by suggesting to McQueen that the final report include language indicating “the membership doesn’t agree with your conclusion.”
Board Approves Maher, Whitley as New RE Trustees
The board doubled the size of the RE’s trustees by approving the nomination of industry veterans Mark Maher and Stephen Whitley. The two were selected from an initial field of 22 candidates and will join Dave Christiano, the trustees’ chair, and fellow trustee Gerry Burrows.
“The two best candidates we thought we had,” Christiano told the board and members.
Both new trustees bring ample RTO leadership experience, Maher as former CEO of the Western Electricity Coordinating Council, and Whitley as NYISO’s former president and CEO and ISO-NE’s former COO.
Maher retired from WECC in 2014 after eight years of service. Before that, he was vice president of transmission services for PacifiCorp, where he was responsible for strategic and operational planning, developing transmission policy and ensuring FERC compliance. He also served as senior vice president at the Bonneville Power Administration. He is a graduate of the University of Washington.
Whitley served as NYISO’s CEO between 2008 and 2015 and was the COO and a senior vice president at ISO-NE from 2000 to 2008. He also spent 30 years at the Tennessee Valley Authority after earning an electrical engineering degree from Tennessee Technological University. He is a retired colonel in the U.S. Army Reserve.
Brown: Market Savings to Top $1B Before Year’s End
Brown said the Integrated Marketplace is on track to top $1 billion in accumulated savings by year-end. During his regular report, Brown said the markets yielded $802 million in net savings in 2014-15, after having opened in March 2014.
SPP did not add any new market participants during the quarter. The markets currently have 172 participants, with 110 registered as financial-only and 62 as asset-owning.
Brown also said SPP has responded to the Mountain West Transmission Group’s request for proposal to develop an organized market. The group consists of a number of SPP members. (See Mountain West RTO Could Pose Competition for CAISO.)
Consent Agenda
The board’s consent agenda included issuing an NTC for a 17-mile, 115-kV line in West Texas (Mustang-Seminole) that was identified as a short-term reliability project in the 2016 ITP Near-Term assessment. The project could have been competitively bid, but because it has short-term reliability needs, it was awarded to the incumbent.
The board also re-set the baseline costs for a pair of projects both more than 20% under budget: a 69-kV Westar Energy rebuild and a 138-kV Mid-Kansas Electric transmission project.
The board also approved modifications to NTCs for four network upgrades, reducing the required emergency ratings, and approved a modification to a Nebraska Public Power District NTC for a new 345/115-kV transformer and a 22-mile, 115-kV line that resulted in no price change.
Eight revision requests were included on the consent agenda:
MWG-RR 7 MPRR155, revising instructions for dispatching generators out of merit order into two categories: reliability issues and emergency conditions.
MWG-RR 153, eliminating the requirement that market participants make two separate submissions for a single intraday change.
MWG-RR 161, changing the method for calculating make-whole payments for multi-configuration combined cycle resources; the new rules allow use of a netting approach in calculating the commitment-level costs eligible for recovery.
MWG-RR 166, removing references from the protocols and Tariff to the interim transmission congestion rights process developed for the transition into the Integrated Marketplace.
MWG-RR 167, avoiding Tariff violations resulting from the incorrect submission of annual revenue rights or TCRs.
ORWG-RR 159, moving requirements regarding the outage-coordination function into SPP Operating Criteria Appendix OP-2 “Outage Coordination Methodology,” eliminating redundant language elsewhere.
RTWG-RR 160, clarifying the ITP manual to note which generation interconnections and associated upgrades are required to be modeled in ITP assessments.
RTWG 163, correcting Tariff language to specify that the ITP manual includes references to requirements.
RR 165, which removes references to the retired Mitigated Offer Task Force from the Tariff’s Appendix G, was removed from the agenda because it does not require board approval.
A new report by the Acadia Center says that carbon emissions in the nine-state Regional Greenhouse Gas Initiative compact have dropped 37% since the program began in 2008.
Part I of group’s “RGGI Status Report” found that emissions have decreased in each of the last five years. Electricity prices across the region have decreased by 3.4% on average since RGGI took effect, while electricity prices in other states have increased by 7.2%, according to the report.
RGGI states have reduced emissions by 16% more than other states and seen 3.6% more economic growth since the initiative launched, the report adds.
Survey Shows Most Residents Support Climate Measures
A majority of likely voters say they are willing to pay more for electricity generated by renewable resources to help reduce global warming, according to a survey by the Public Policy Institute of California.
The survey also found that voters approve of the 10-year-old law requiring the state to reduce greenhouse gas emissions to 1990 levels by 2020 and would support additional efforts to curtail emissions. Still, more than half of those surveyed had never heard of the state’s cap-and-trade program.
Group Wants Waste Storage Included in San Onofre Review
A citizens group is asking the State Lands Commission to expand its environmental impact review of the San Onofre nuclear station’s decommissioning to include plans for long-term storage of nuclear waste at the shorefront facility.
Southern California Edison’s application to the agency makes no mention of its plans to indefinitely store spent fuel in containers located 100 feet from the beach. “It’s just in a really bad spot,” Ray Lutz, of Citizens Oversight, told the commission at its first public hearing on the decommissioning process. “And now we find out that that isn’t even part of the review of this project.”
A SoCalEd representative said the U.S. Nuclear Regulatory Commission has approved a license for a new storage facility at the site. The utility has proposed the EQR cover only two of four phases of the process; spent fuel storage is addressed in phase 3.
The City of Boulder’s Planning Board voted unanimously last week to recommend the annexation of 16 city-adjacent properties, part of the city’s effort to create its own municipal electric utility.
The bid to annex the properties, containing Xcel Energy facilities and customers, stems from a Public Utilities Commission ruling in November that partially rejected Boulder’s municipalization application. The commission ruled that the city could not force Xcel to sell or share facilities that also served residents outside the city’s limits.
The annexation package now goes before the City Council as the city prepares a new application for the PUC. However, Boulder and Xcel are also engaged in settlement negotiations that could bring an end to the city’s plan, which was spurred by its desire to get all of its electricity from renewable resources by 2030.
Groups Criticize Natural Gas Conversion at Bridgeport Plant
Environmental groups criticized the $550 million conversion of a coal-fired power plant in Bridgeport to natural gas, saying it may actually be worse for the climate.
Environmental and community groups across New England said in a report that using natural gas until more renewable energy is available provides no gains and may actually worsen climate change. The report claims that the amount of methane leaked into the atmosphere from the extraction of natural gas is worse for the climate than burning coal.
PSEG Power has agreed to replace the coal-powered Unit 3 of Bridgeport Harbor station with a 485-MW gas-fired plant.
The Institute for Energy Economics and Financial Analysis is recommending that a coal-fired power plant in the state be closed as soon as possible.
In a study, the organization said both units at the Elmer Smith Station in Owensboro should be shut down because the plant is “long past its prime” and is a financial drain on Owensboro Municipal Utilities ratepayers. The report was completed at the request of the Ohio River Valley chapter of the Sierra Club’s Beyond Coal Campaign.
“Tens of millions of dollars of new investment will be needed to keep the plant running and, using the utility’s own analyses, shows that retail rates will increase by 20% by 2018 and 80% by 2025 if both units at Elmer Smith are not retired,” IEEFA Director of Resource Planning David Schlissel said.
EKPC Files with PSC to Build 60-Acre Solar Facility
East Kentucky Power Cooperative has submitted an application with the Public Service Commission for permission to build an 8.5-MW solar energy facility in Clark County.
The proposed $17.7 million project calls for the installation of 32,000 photovoltaic panels on 60 acres next to EKPC’s offices.
A utility spokesperson said the solar facility would be funded through New Clean Energy Renewable Energy Bonds from the U.S. Energy Department, and retail customers will be able to receive monthly bill credits if they buy a 25-year, $460 license in exchange for a share of the facility’s generating capacity.
State Energy Agency Backs ATC Plan for Removal of SSR
The state Agency for Energy said it backs a plan from American Transmission Co. to reconfigure its system in the Upper Peninsula, which would eliminate payments to a 60-year-old coal-fired power plant that it says costs ratepayers $7.3 million each year.
The agency, in a letter to MISO, endorsed ATC’s plan, which would also revise its system operating guide for the UP. The plan would eliminate the need for a system support resource (SSR) agreement to the White Pine power plant.
UP ratepayers have been making SSR payments for the operation of White Pine Unit 1 for more than two years and would be slated to continue payments until 2020. The state has challenged several other SSR agreements, which provide for payments to generators to continue running for reliability.
The Saline County Commission granted Aksamit Resource Management’s request to build a 74-MW wind farm southwest of Lincoln.
Construction is expected to begin after harvest this fall, with the turbines operational by Nov. 1, 2017. Aksamit is in negotiations to sell the wind farm’s power, but the company has declined to say with whom.
It is the first of three wind energy projects Aksamit plans for the state. The company plans to spend about $440 million on a nearby 300-MW farm and a 76-MW project.
NV Energy last week asked the Public Utilities Commission to allow some rooftop solar customers to receive the more generous net metering rates that were phased out at the start of the year.
Under the proposed change, customers who installed their panels or receive application approvals before the end of 2015 would be eligible to get compensated under the original net metering terms for a period of 20 years.
The utility’s request to grandfather some projects under the old rules comes as the state Supreme Court prepares to hear arguments over whether to allow a ballot initiative that would restore the original rates to all current and future customers.
Politicos, Regulators Fear More Coal Plants to Close
Great River Energy’s announcement that it would close a coal-fired power plant in the next year is just the first blow against the state’s coal industry, warned a congressman and a state utility regulator.
“I don’t think we can presume this is an outlier,” said U.S. Rep. Kevin Cramer, a former state utility regulator and an energy adviser to presidential candidate Donald Trump. He said he feared what has happened in the Appalachian region, where local economies have been hurt by the coal plant closures, will happen in the state.
Public Service Commissioner Randy Christmann acknowledged that low natural gas prices contributed to Great River’s decision to close its plant, but he pointed to competition from “heavily subsidized” wind energy. “I just think we’ve gotten to a point where they’re overly subsidized,” Christmann said.
El Paso Electric will withdraw its proposal to charge customers with rooftop solar panels an additional $11/month under a settlement with a coalition of solar-energy companies and environmental advocates and the city of El Paso. The agreement was filed with the Public Utility Commission.
EPE withdrew the proposal after almost a year of claiming solar customers were more expensive to service and should be subject to an additional fee. Approval of the agreement by the PUC is likely to happen in the next couple months.
The battle between consumer advocates and the investor-owned utility began last year when EPE filed a rate case seeking to cover $1.3 billion in infrastructure investments. Among the proposals was an additional charge for the more than 1,770 Texas solar power users in the company’s service area.
State, Japanese Partner to Research Clean-Coal Technology
Mead
Gov. Matt Mead signed a memorandum of understanding last week with the president of the Japan Coal Energy Center, calling for cooperation between the consortium of Japanese companies and state experts in researching clean-coal technology.
Mead says he expects to see a conference in the state within a year that would allow Japanese researchers to work with researchers from the University of Wyoming School of Energy Resources on coal issues. The state has been pushing to try to gain access to ports in the Pacific Northwest to export coal to Asia.
Mississippi Power said last week its Kemper County coal-gasification plant will tally up another $9 million in overruns, a cost that the company promised to absorb.
The coal gasification plant now carries a $6.8 billion price tag, more than double its original estimate. Parent entity Southern Co. is responsible for $2.5 billion of the overall cost and wrote off $38 million before it announced its quarterly earnings last week. Southern said it spent $23 million on the Kemper plant in the second quarter.
Mississippi Power said the plant, designed to capture carbon dioxide emissions from coal, is scheduled to be completed by Sept. 30, but the company said it could announce further delays later this month. The plant is currently generating electricity by burning natural gas.
Consumers Proposes Charging Station Network in Rate Request
Consumers Energy is proposing to construct a statewide electric vehicle charging network as part of its pending rate increase request before the Michigan Public Service Commission. The utility wants to install more than 800 charging stations at a cost of $15 million to its ratepayers.
Consumers spokesman Brian Wheeler said the plan would address the lack of public charging stations, earn Michigan recognition in renewable transportation and make residents more comfortable with the idea of purchasing an EV.
While stakeholders are generally supportive of the plan, advocates say Consumers should structure charging rates so EV owners see a savings over purchasing gasoline. Some also question whether general ratepayers should subsidize utility investments, including EV infrastructure.
Ameren to Fund $2M in Clean Projects Under Settlement
Ameren Missouri and the Sierra Club have reached a settlement over the environmental group’s allegations that Ameren had repeatedly violated the Clean Air Act at three coal-fired plants.
The agreement, filed in U.S. District Court, requires Ameren to create a $2 million fund for “environmentally beneficial projects.” The Sierra Club said that the money will be split among community solar projects and a clean electric bus program in the St. Louis area.
The Sierra Club alleged that Ameren committed nearly 8,000 emission violations at its Labadie, Meramec and Rush Island plants from 2009 to 2013. The group said it settled partly because Ameren promised to take steps to retire the Meramec plant by 2022.
ICF Signs $11M Deal to Help KCP&L Customers Go Green
Global consulting and technology service provider ICF International has signed a three-year, $11 million contract with Great Plains Energy to support subsidiary Kansas City Power and Light’s residential energy-efficiency programs.
ICF will educate customers about the programs, which include heating and cooling rebates, a LED discount and income-eligible multifamily rebates.
“ICF helps us get [the] word out to customers in hopes of changing that behavior,” a KCP&L spokesperson said.
FirstEnergy on Friday demolished an 854-foot concrete stack and the last remaining building at the former coal-fired R.E. Burger Power Station in Ohio.
The company plans to transfer the property to PTTGC America if the latter decides to construct an ethane gas cracker plant on the site.
The Burger plant, which began operating in 1944, was retired in 2011.
NIPSCO Expands Indiana Car Charging Station Network
Northern Indiana Public Service Co. installed a public electric vehicle charging station last week at the offices of the Northwestern Indiana Regional Planning Commission in Portage.
The charging station is part of the utility’s two-year-old IN-Charge Around Town program, which encourages drivers to go electric. The utility has installed 80 stations throughout northern Indiana. The commission’s new charging station is free to use.
The developers of what is billed as Iowa’s largest wind energy project reached agreements with major customers, including Google, Facebook and Microsoft, that will allow the facility to go forward.
Commercial customers had objected to some terms of the development, including the return on equity demanded by MidAmerican. The developer wanted 11.5%, the customers proposed 9.5% and they settled on 11%.
A final decision from state regulators on the 2,000-MW Wind XI project is expected in September, with construction to begin in December. Construction must begin by Dec. 31 in order for the project to receive the maximum federal production tax credits.
Part I of group’s “RGGI Status Report” found that emissions have decreased in each of the last five years. Electricity prices across the region have decreased by 3.4% on average since RGGI took effect, while electricity prices in other states have increased by 7.2%, according to the report.
A majority of likely voters say they are willing to pay more for electricity generated by renewable resources to help reduce global warming, according to a survey by the Public Policy Institute of California.
Environmental groups criticized the $550 million conversion of a coal-fired power plant in Bridgeport to natural gas, saying it may actually be worse for the climate.
East Kentucky Power Cooperative has submitted an application with the Public Service Commission for permission to build an 8.5-MW solar energy facility in Clark County.
The state Agency for Energy said it backs a plan from American Transmission Co. to reconfigure its system in the Upper Peninsula, which would eliminate payments to a 60-year-old coal-fired power plant that it says costs ratepayers $7.3 million each year.
The Saline County Commission granted Aksamit Resource Management’s request to build a 74-MW wind farm southwest of Lincoln.
The coal gasification plant now carries a $6.8 billion price tag, more than double its original estimate. Parent entity Southern Co. is responsible for $2.5 billion of the overall cost and wrote off $38 million before it announced its quarterly earnings last week. Southern said it spent $23 million on the Kemper plant in the second quarter.
Consumers Energy is proposing to construct a statewide electric vehicle charging network as part of its pending rate increase request before the Michigan Public Service Commission. The utility wants to install more than 800 charging stations at a cost of $15 million to its ratepayers.
Ameren Missouri and the Sierra Club have reached a settlement over the environmental group’s allegations that Ameren had repeatedly violated the Clean Air Act at three coal-fired plants.
Global consulting and technology service provider ICF International has signed a three-year, $11 million contract with Great Plains Energy to support subsidiary Kansas City Power and Light’s residential energy-efficiency programs.
FirstEnergy on Friday demolished an 854-foot concrete stack and the last remaining building at the former coal-fired R.E. Burger Power Station in Ohio.
The developers of what is billed as Iowa’s largest wind energy project reached agreements with major customers, including Google, Facebook and Microsoft, that will allow the facility to go forward.