In a move that elated New Jersey’s ratepayer advocates, FirstEnergy announced Thursday it is withdrawing its request for state public utility designation for its all-transmission spin-off.
FE said it made the decision because it was unlikely to win approval in time to meet the its Jan. 1 target to begin investing more than $2.5 billion in transmission infrastructure in eastern Pennsylvania and New Jersey.
“At this juncture, nearly 15 months after the original petition was filed, there appears to be no prospect of resolving this matter” in time to accommodate that schedule, the company said in a letter to Richard Mroz, president of the New Jersey Board of Public Utilities.
FE has already received approval from FERC and the Pennsylvania Public Utility Commission to create a new public utility — Mid-Atlantic Interstate Transmission (MAIT) — by spinning off the transmission assets of Metropolitan Edison and Pennsylvania Electric. The company needed approval from the BPU to do the same with Jersey Central Power & Light, but faced opposition from the state Division of Rate Counsel. (See FERC OKs FirstEnergy’s Tx Spin-off; NJ, Pa. Approval Still Needed.)
Rate Counsel Director Stefanie Brand dismissed FE’s claims that the consolidation would reduce project costs by $135 million as “speculative.” She pointed to testimony her office submitted that argued the reorganization benefited stockholders at the expense of ratepayers.
The Rate Counsel said there were more appropriate ways to achieve the improved credit ratings that were at the heart of FE’s pitch to the BPU. As a regulated utility, JCP&L could have an excellent credit rating but has been mismanaged, Brand said.
Additionally, her office contended the proposal drastically undervalued the assets to be transferred, meaning the ratepayers who paid for them wouldn’t receive fair compensation.
Bad Precedent
The request would have also given the all-transmission company the powers of eminent domain and local-zoning pre-emption. FE’s plan originally faltered because MAIT didn’t have any distribution customers, as required for public utilities in New Jersey. In a bid to meet that requirement, FE amended its plan to give the subsidiary five customers.
Brand said that would set a bad precedent. “You can see merchant transmission companies lining up saying, ‘Oh, give me five customers; I’ll take eminent domain authority,’” Brand said in an interview.
MAIT will still consolidate the transmission assets for Met-Ed and Penelec and move forward under that name for Pennsylvania projects, FE spokesman Doug Colafella said. JCP&L will continue operating under its current structure, he said.
“We’re disappointed, but New Jersey regulators determined that a transmission company can’t be a public utility in New Jersey,” he said.
Colafella said the company will move forward with its transmission investments as planned, which are expected over the next five to 10 years. The New Jersey projects will be pursued under JCP&L’s formula rates.
Colafella wasn’t sure how the decision impacted the financials FE had originally calculated for the asset transfer to MAIT.
Brand was particularly pleased with the decision because it saved the time and expense of going to trial.
The decision was also welcomed by U.S. Rep. Frank Pallone Jr. (D-N.J.), through whose 6th District FE’s planned 10-mile Monmouth County Reliability Project would run. Pallone had previously submitted comments to the BPU on the case, in which he expressed concern about “numerous unresolved questions about the consequences of this transfer” and potential “unforeseen impacts.”
“I appreciate the work of so many of my constituents and the state Rate Counsel who stood against this transfer and its potential to hurt the quality of life in our communities,” he said in a news release.
SACRAMENTO, Calif. — Gov. Jerry Brown on Wednesday reaffirmed his commitment to an expanded CAISO, a month after asking state agencies to delay their efforts to complete enabling legislation.
Brown told the ISO’s annual stakeholder symposium that greater cooperation with balancing authority areas in neighboring states is essential to increasing the efficiency of the grid and meeting California’s ambitious renewable portfolio standard of 50% by 2030. The governor signed a bill Thursday to reduce the state’s greenhouse gas emissions to 40% below 1990 levels by 2030. (See California Legislature Approves Bill to Sharply Reduce GHG Emissions.)
“I think we recognize the imperative of making our electric system as efficient as it possibly can be,” Brown said. “The efficiency of a wider grid is unmistakable. And the imperative is greater efficiency, greater elegance and intelligence in the way we use and produce electricity, the way we market it and the way it goes around the system.”
Brown listed some of the dangers to California from climate change — including longer wildfire seasons and the potential for flooding in low-lying areas — and asked how California can work with other states “that have different perspectives” on dealing with climate change.
“That’s something I think you’re all here to figure out, because we’re not going to change differences in different states that have different needs and different experiences,” Brown said.
The governor noted that utilities in his own state at one time doubted the possibility that they could sustain a 20% RPS by 2020. But those companies are now on track to exceed that goal and are confident they will hit the 50% objective.
“But in order to get there, we need a grid that is highly sophisticated,” he said. “We need a grid that is conterminous with the technology and capability that is possible today.”
“So I hope you work all that out,” Brown added, humorously. “Make sure that those who love coal and those who love the sun can sit down and work in a totally seamless web of interconnection, interaction and happiness for all.”
Brown acknowledged the difficulty of advancing regionalization through the political process of multiple states. The governor last month postponed plans to present the legislature with a governance plan for an expanded ISO, saying there wasn’t enough time to complete the proposal before the legislative session ended Sept. 1. (See Governor Delays CAISO Regionalization Effort.)
“But the times are changing, and the technologies are forcing us to reexamine how things work,” Brown said.
Five New York City-area legislators, including the chair of the State Assembly Committee on Energy, wrote to state regulators last week questioning the ratepayer-funded nuclear power plant subsidy and requesting disclosure of the operating costs of the affected plants.
The New York Public Service Commission last month approved a Clean Energy Standard that includes a subsidy for upstate nuclear power plants. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.) In May, the commission granted Exelon’s request to keep the operating costs of its R.E. Ginna and Nine Mile Point 1 and 2 plants private (16-E-0270).
“Why should Exelon’s costs be blocked from public review when it is being given a government-directed and government-administered price subsidy?” the legislators wrote.
The zero-emission credits created by the order are expected to cost ratepayers $965 million in the first two years of their 12-year existence. Included in the subsidy is Entergy’s James A. FitzPatrick plant, which Exelon has agreed to buy. (See FitzPatrick Sale Filed with New York Regulators.)
The assemblymembers also said that Nine Mile Point 2 should be eliminated from ZEC payments and the cost of the program should be recalculated. They said the fact that Exelon refueled the plant in the spring indicates that that the facility is not financially stressed or in danger of closing.
“In the commission record, we take note that Entergy announced intentions to close FitzPatrick, and Exelon announced intentions to close R.E. Ginna and Nine Mile 1, but no formal announcement was made regarding intention to close Nine Mile 2, which produces 40% of the electricity of the four units. Without a publicly transparent cost review, and in light of the recent refueling of the unit, the payment should be removed from the commission’s order,” the letter said.
Nine Mile Point
The letter also states that downstate ratepayers will be paying a disproportionate share of the subsidy — 60% — while most of the energy generated by the plants will be used upstate, closer to the plants’ locations in western New York.
The assemblymembers also said that the subsidy is based on EPA’s projected social cost of carbon, which could increase as much as 10% every two years after the first two years of the program.
The letter was signed by Energy Committee Chair Amy Paulin, who represents Westchester County; James Brennan of Brooklyn; Jeffrey Dinowitz of the Bronx; and Steve Englebright and Charles Lavine of Long Island.
In a response on Friday, PSC Chair Audrey Zibelman said there are “a number of fundamental errors” in the lawmakers’ understanding of how the power system works and the CES’ role in it.
Zibelman said the price of renewable energy credits is set by a competitive bidding process, but with few participants, ZEC prices must be set administratively. The federal social cost of carbon is a more effective mechanism and accounts for the externalities associated with fossil fuel generation, she said.
“Second, it is simply wrong for anyone to suggest that we can achieve targeted emission reductions by 2030 if we were to lose the zero-emissions attributes of the three upstate nuclear plants. Experience and fundamental economics show that the zero-emissions attributes they produce and New York needs will be replaced by adverse air emissions from existing coal and new natural gas-fired fossil units that can be dispersed throughout the state or come from out-of-state imports,” Zibelman wrote
The cost of replacing all of the nuclear generation with renewables would be more expensive than the ZECs, she added.
Finally, she disputed the assertion that the New York City area is being treated unfairly. “The CES allocates the obligation to meet the 50% renewables goals and zero-emission credits to all of the consumers of the state because all consumers will benefit from reducing carbon emissions,” Zibelman wrote.
WASHINGTON — A public interest group and Connecticut officials asked a federal appellate court Tuesday to force FERC to rule on the legality of ISO-NE’s eighth Forward Capacity Auction, saying the commission abdicated its responsibility by refusing to take action.
In September 2014, the commission split 2-2 over whether it should reject the results from the RTO’s auction because of unchecked market power, allowing the 2017-18 auction results to become “effective by operation of law” (ER14-1409). Under the Federal Power Act, rates take effect 60 days after they are filed with FERC, absent a commission order to the contrary.
Commissioners Tony Clark and Norman Bay called for FERC to reject the auction results, but then-Chair Cheryl LaFleur and Commissioner Philip Moeller said the commission should seek only prospective changes in the auction rules. (See FERC Commissioners at Odds over ISO-NE Capacity Auction.)
Tuesday’s arguments before a three-judge panel of the D.C. Circuit Court of Appeals focused less on the auction itself than on whether the commission’s 2-2 deadlock constituted an “action” that should be subject to judicial review. FERC contends it was an exercise of the commission’s discretion and thus not subject to second-guessing (14-1244).
Remand Sought
Scott Nelson, attorney for plaintiff Public Citizen, said the court should remand the issue to FERC for consideration of whether the auction prices were just and reasonable, as he said is required by FPA Section 205 when a rate is challenged.
He cited a statement from LaFleur contending the commission lacked authority to review the auction results, an opinion FERC’s attorneys have not embraced. LaFleur said the ISO-NE Tariff is the “filed rate” and a review of the auction prices would violate commission precedent and subject auction participants to “regulatory uncertainty or after-the-fact ratemaking.”
“No one here actually defends that statement,” Nelson told the judges. “Here one of the determinative votes [on the auction results] rests on what is a clear error of law.”
The judges challenged Nelson’s arguments.
Brown Source: Judicial Council of California
Judge Janice Rogers Brown told Nelson his reliance on a precedent involving the Federal Election Commission is “somewhat flawed” because the FEC’s enabling act explicitly allows judicial review of deadlocks. “Where is that in the Federal Power Act?” she asked.
FERC Solicitor Robert H. Solomon also challenged the FEC precedent. With equal numbers of Democratic and Republican appointees, Solomon said, the FEC is “designed to deadlock.” In contrast, FERC is split 3-2, with the majority representing the party in the White House.
Judge Sri Srinivasan pressed Nelson on his use of another precedent, Amador County v. Salazar, noting that the FPA allows challenges under Section 206 if the commission fails to act under Section 205.
No ‘Backstop’
“That [Section 206] remedy is not an adequate alternative,” Nelson responded, noting that while ISO-NE must prove that its rates are just and reasonable under Section 205, the burden of proof flips to the plaintiffs in Section 206. In its brief, Public Citizen noted that the D.C. Circuit has previously ruled that Section 206’s burden of proof is “practically insurmountable” for private parties challenging rates.
“206 can’t be a backstop for the agency’s failure to exercise its authority under 205,” Nelson said.
John S. Wright, an assistant Connecticut attorney general, also argued for a remand. Connecticut’s challenge to the FCA 8 results (14-1246) was consolidated with the Public Citizen complaint.
“FERC has a duty to act,” Wright said. “FERC knew the rates were subject to the exercise of market power.”
The auction saw total capacity costs for 2017/18 rise to $3.05 billion — almost double the previous high — as the region’s capacity shifted from an expected surplus to a deficiency of more than 1,000 MW. The shortfall was because of plant retirements, including that of the 1,488-MW Brayton Point station in Massachusetts.
Brayton Point Source: Wikipedia
Wright said ISO-NE erred in the auction by treating capacity importers as “new” supply and not subjecting their bids to review, unlike existing resources. New resources in the Maine, Connecticut and Rest of Pool capacity zones were paid $15/kW-month, while existing resources in those zones received an administrative price of $7.025/kW-month.
However, FERC said its Office of Enforcement investigated Brayton Point’s retirement and determined it was justified.
In addition to announcing their deadlock in September 2014, the commissioners voted unanimously to open a new docket (EL14-99) calling for a Section 206 proceeding over the RTO’s process for reviewing importers’ offers and mitigating their market power. The commission approved Tariff changes addressing those concerns in December 2014 (ER15-117). (See FERC OKs Tightened ISO-NE Screening on Capacity Imports.)
‘Non-Order’
FERC’s Solomon said there is nothing for the court to review because the “commission made no decision.”
Statements issued by LaFleur and the other three commissioners were not official orders and thus not reviewable, he said. “What matters is whether anything has been articulated by the agency as an institutional body.”
The commission’s notice, he said, was a “non-order.”
Srinavasan Source: US Department of Justice
Srinivasan asked how often FERC has allowed rates to go into effect “by operation of law.”
“This is extremely rare, your honor,” Solomon responded, saying the commission has identified only six such instances in 80 years.
As evidence of the commission’s discretionary authority, Solomon quoted from subsections C, D and E of Section 205, which repeatedly use the word “may.”
Supporting FERC’s position Tuesday was Paul A. Mezzina, attorney for intervenor Electric Power Supply Association. Mezzina said that when market rules are followed, the results are “presumptively just and reasonable.”
Judge Brown pointed out that the settlement that led to the creation of ISO-NE’s capacity market says the commission “will” review the auction results.
But Mezzina said the settlement didn’t “take away any of the commission’s discretion to determine what the review consists of.” He said the commission has “broad discretion” and “no unequivocal obligation to act.”
FERC Chief of Staff Larry Gasteiger was among the FERC officials in the audience for the arguments. Also in attendance were representatives of some of the other intervenors supporting FERC: NRG Power Marketing, H.Q. Energy Services, Calpine, the New England Power Generators Association and the New England Power Pool Participants Committee.
Ruling
The FCA 8 rates will take effect June 1, 2017.
If the court rules that it has jurisdiction to review the commission’s inaction, it will have to decide whether the FPA allows a protested rate filing to go into effect when the commission cannot issue an order by majority vote.
Nelson said after the hearing he expected a ruling by March. Solomon said it could be as long as a year.
Were the issue to be remanded to FERC, Moeller, who left the commission last year, and Clark, who is stepping down this month, would have no role.
Following Clark’s departure, the commission will be short two members, with only LaFleur, Bay and Colette Honorable, who joined in January 2015.
Meanwhile, the capacity dispute has attracted the attention of the New England congressional delegation, which won House approval in March of a bill that would amend the FPA to allow court review of any inaction by the commission that allows a rate change to go into effect (HR 2984).
Canadian pipeline giant Enbridge is buying American pipeline company Spectra Energy in a $28 billion deal that will create North America’s largest energy infrastructure company.
Enbridge, which specializes in pipelines moving crude oil, will be moving into the natural gas transportation business with the all-stock transaction. Enbridge said in its news release that the acquisition will allow it to diversify both regionally and operationally.
The deal will give Enbridge a continent-wide system of natural gas, gas-liquid and crude oil pipelines, as well as terminals, gas distribution operations and a stable of wind, solar and geothermal generation.
Source: Enbridge
“Over the last two years, we’ve been focused on identifying opportunities that would extend and diversify our asset base and sources of growth beyond 2019,” Enbridge CEO Al Monaco said. “We are accomplishing that goal by combining with the premier natural gas infrastructure company to create a true North American and global energy infrastructure leader.”
11.5% Premium
Monaco will remain at the helm of the combined companies. Spectra CEO Greg Ebel will move over to serve as non-executive chairman of the Enbridge board. “The combination of Enbridge and Spectra Energy creates what we believe will be the best, most diversified energy infrastructure company in North America, if not the world,” Ebel said.
Spectra shareholders will get Enbridge shares valued at about $40.33 each, a premium of about 11.5% from Spectra’s closing price Friday. At closing, which the companies expect to be completed by the first quarter of 2017, Enbridge shareholders will hold about 57% of the new company, and Spectra shareholders will hold 43%. Headquarters of the new company will be in Calgary.
The deal comes at a time when natural gas producers and transporters are struggling with low commodity prices even as they are constructing large numbers of new pipelines and extending older ones to accommodate the increased production from shale gas plays. Existing pipelines are especially valuable, considering the costs and regulatory hurdles facing new pipeline construction.
Setbacks
Both Spectra and Enbridge have recently had setbacks in pipeline construction projects. The Massachusetts Supreme Judicial Court ruled that power utilities that would become customers of the Spectra-proposed Access Northeast in New York and New England cannot pass on additional construction costs to customers. In June, a Canadian court blocked Enbridge’s proposed Northern Gateway oil pipeline that was to run from Alberta — home of Canada’s tar sands fields — to terminals on the Pacific Coast.
Enbridge’s 450-acre Superior Terminal at Superior, Wisconsin Source: Enbridge
And just days ago, Enbridge announced it was suspending pursuit of regulatory approval for its proposed $2.6 billion Sandpiper pipeline in Minnesota, citing a drop in projected crude oil production in South Dakota and shifting of customer capacity needs to the Dakota Access line.
The Dakota project is garnering notice because of protests from the Standing Rock Sioux Tribe, which is blocking access to a construction site near the border between the Dakotas. The tribe has filed a lawsuit against the U.S. Army Corps of Engineers for approving the pipeline crossing the Missouri River upstream from the tribe’s reservation. The suit claims that the pipeline threatens both the tribe’s drinking water source and its sacred lands.
Fires — possibly arson — caused an estimated $1 million in damage to Dakota Access construction equipment in Iowa last month.
Spectra is not Enbridge’s first acquisition of the summer. Last month, it announced that it and Marathon Petroleum were investing in Dakota Access, with the two companies acquiring 49% equity interest in the Bakken Pipeline System from Energy Transfer and Sunoco Logistics. Enbridge put up $1.5 billion for its 37% share of the 1,168-mile, $3.78 billion pipeline, which is to run from North Dakota to terminals in Illinois.
IRVING, Texas — SPP’s two newest stakeholder groups are taking a look at the future, while also stepping almost a decade into the past to resolve the sticky issue of Tariff Attachment Z2.
The Z2 Task Force last week began its work overseeing waiver requests from entities billed for sponsored transmission upgrades dating back to 2008. Meanwhile, at Gulf Coast Power Association’s third annual SPP Regional Conference last week, Strategic Planning Committee Chairman Mike Wise said that his committee has formally launched the Export Pricing Task Force, which will study how SPP can maximize its ample renewable resources.
The latter group’s charter charges it with evaluating “mechanisms to establish equitable and not unduly discriminatory prices for exports and imports of electricity.” SPP has more than 22,000 MW of renewable resources in its interconnection queue, a luxury considering the RTO’s low load growth and ample reserve margins — but a tantalizing energy source for other markets.
“The question is, how do you get this renewable energy outside SPP to those areas that really need it, and how do you price for it?” said Wise, senior vice president of commercial operations and transmission for Golden Spread Electric Cooperative. “The majority of transmission for the good of the load in the footprint has been approved for building or is in construction right now.”
To illustrate his point, Wise said he compared the population growth over the past 25 years in SPP’s 10 largest cities with that of the Dallas-Fort Worth area. He said SPP’s cities have grown by 2.2 million, while the DFW area has added 3.3 million new residents during that same time.
“Our load growth is on zero, or barely north of zero, with an abundance of natural resources coming in,” Wise said.
Asked if the task force would work with other RTOs, Wise told RTO Insider, “We don’t know yet.”
The task force, which has yet to meet, will focus for the time being on recommending rates that can recover the costs of incremental transmission needed for exports and imports.
The group will evaluate Tariff and FERC rules on pricing transactions across seams and the “business case” for exports. It is scheduled to sunset by July 2017.
Joining Wise on the task force are SPP Director Graham Edwards and members Wes Berger (Southwestern Public Service), Blaine Erhardt (Basin Electric Power Cooperative), Dennis Florom (Lincoln Electric System), Greg McAuley (Oklahoma Gas & Electric), John Olsen (Westar Energy) and Richard Ross (American Electric Power).
The group will address the equity concerns of the so-called Group B members, whose requests to escape direct assignments for upgrades totaling $42.6 million were rejected by the MOPC in July. The five Group B members said the charges should be allocated to the base plan and included in regional and zonal charges under SPP’s Tariff.
The task force also will consider the $113 million in upgrade costs assigned to entities that did not request waivers (Group C).
“We’re actually talking about less than 10% of the overall cost of credits in the waivers,” said task force Chair Denise Buffington, corporate counsel for Kansas City Power and Light. “Hopefully, everyone can see the long-term benefits of a solution everyone can live with.”
Following the October presentations, the task force will evaluate the existing Z2 process and recommend how to compensate upgrade sponsors in the future. It could also be asked to evaluate and recommend improvements to the Tariff attachment going forward.
The task force includes Meena Thomas, a senior market economist with the Public Utility Commission of Texas and the only non-SPP member on the 15-person group. Thomas is also a member of the regulatory-driven Cost Allocation Working Group, whose members are not allowed to serve on other working groups. That exception doesn’t apply to task forces.
“To the extent I can consult with CAWG members in advance, I’ll be voting as a CAWG member,” Thomas said. “Otherwise, I’m voting as a representative of Texas.”
Wisconsin regulators began considering electric competition in 1994 but closed the docket in 2000, deciding not to implement retail choice. Now, with the state’s rates the highest in the Midwest, some big power users are calling for another look.
Wisconsin’s large manufacturers are asking state regulators to grant them retail choice, warning that high power prices may otherwise cripple the state’s economic growth. Companies and manufacturing groups filed comments with the Wisconsin Public Service Commission in response to the PSC’s Strategic Energy Assessment (SEA) 2022, a biennial report finalized late last month that forecasts Wisconsin’s power needs six years into the future (5‐ES‐108).
The 70-page report notes that Wisconsin electric rates are the highest among Midwestern states and higher than the national average. In 2015, average industrial rates in the state were 7.77 cents/kWh, versus 6.86 cents/kWh for the Midwest and 6.89 cents/kWh for the U.S. Across all electric use, Wisconsin residents and businesses pay an average 10.93 cents/kWh, compared to the Midwest’s average of 9.66 cents/kWh and the national average of 10.42 cents/kWh.
In a joint comment, the Wisconsin Paper Council and the Wisconsin Industrial Energy Group, which represents more than 30 large industrial ratepayers, said “energy and capacity are not available at reasonable prices in Wisconsin.”
“This trend is of grave concern and results in more industrial load being at risk of expanding or relocating in states with greater market access and/or much lower rates. Action needs to be taken now to prevent the situation from deteriorating further,” the groups said.
The manufacturing advocates also proposed a hybrid solution as an alternative to total retail choice. It calls for competitive bidding on transmission and generation construction projects, incentive-based demand response programs and real-time pricing for all utilities.
Charter Steel, whose Saukville, Wis., manufacturing facility is the largest single-site customer of We Energies, said the utility’s “above-market” rate increases are to blame for the “largest percentage increase in electric rates of any state in the nation” from 1997-2015. The PSC’s assessment did not contain that claim, but the report notes that in the late 1990s, Wisconsin entered a two-decade electric construction boom and utilities “are now recovering associated construction costs in rates.”
Charter blames “a massive level of excess electric generating capacity” from WE for the hikes and says that electricity expenses are higher than labor costs at its Saukville plant. The company said the state should open a retail market for at least the largest electric customers.
“Every lapsed year with the status quo is an unnecessary tax on southeast Wisconsin electric users measured in hundreds of millions of dollars,” Charter wrote.
The Retail Energy Supply Association, a trade group of competitive retail electric and natural gas marketers active in nearby Michigan and Illinois, echoed Charter in comments, calling for a “well structured” competitive market.
RESA spokesman Bryan Lee said the Wisconsin veto of market restructuring can be contrasted with Illinois’ outcome.
“In the late 90s, when just about every state in the country was considering the failure of monopoly regulation and introducing competition, Wisconsin was the leading state. In those days, Wisconsin was the low-cost state. The regulators said Wisconsin was low-cost and decided against it while the then-high-cost state of Illinois decided to adopt it. To make a long story short, it’s a tale of two states. The states have flipped: Illinois is one of the least-cost states and Wisconsin is one of the highest cost states.”
Lee said it is a “disservice” not to have retail choice. “There’s no question that competition works,” he said. “We use competition in every other segment in our economy.”
The Wisconsin PSC opened generic docket 05-EI-114 in 1994 to collect stakeholder comments on the issue and created a 22-member advisory panel to explore the issue. By 1996, a PSC report to the state legislature suggested that competition could be introduced in Wisconsin as soon as 2001. However, the commission’s 2002 SEA concluded that “the competitive market is not providing a reliable source of capacity at a reasonable price.”
The Illinois Energy Professionals Association, an organization of consultants to industrial, commercial, government and aggregated residential electricity customers, filed comments saying the Wisconsin PSC should consider retail choice as their state had, saying it can reduce rate increases.
The group said retail choice results in more accurate and timely price signals. The regulated format “is inherently incapable of responding to prevailing conditions that are distinctly different from those for which the regulated vertical monopoly was originally designed,” it wrote.
A spokesman for Wisconsin’s Department of Agriculture, Trade and Consumer Protection said the department had no position on the matter.
Legislation Required
Jeffrey Ripp, an administrator of the Wisconsin PSC’s Division of Energy Regulation, said it would require legislative approval to switch to deregulation, even if it was recommended by the PSC. “There isn’t a whole lot we can do because we do what the Legislature tells us to do,” Ripp said.
In the SEA, the commission said it “continues to investigate ways to mitigate electric rate increases to ensure Wisconsin remains competitive in a global marketplace.” The report also said the PSC is considering allowing generators to sell excess capacity into the MISO markets.
The Citizens Utility Board (CUB), a consumer group, urged the PSC to allow utilities to sell excess capacity elsewhere. “For ratepayers to receive value from their investment, the commission and utilities must prioritize decreasing retail rates through cost control in rate cases and other measures, and utilities with existing and forecast excess capacity and energy must work to monetize this surplus through market sales, the revenues of which are returned to ratepayers through the ratemaking process.”
The CUB said the PSC’s main focus going forward should be cost control, “decreasing rate levels whenever possible.”
‘Little Evidence’
Not everyone buys the idea that retail choice results in lower prices. A study released earlier this year by Christensen Associates Energy Consulting for the Electric Markets Research Foundation concluded, “Nearly two decades later, there is little evidence that retail choice has yielded any significant benefits.”
The study also cited a lack of demand elasticity, saying customers’ short-term response to electricity prices was small and that customers’ willingness to be curtailed was “even smaller.”
According to the study, 14 states and D.C. currently allow retail choice, while eight states have since suspended or rescinded it.
Sarah Barry, executive director of Wisconsin energy consumer group Customers First Coalition, said her organization opposes deregulation efforts. Barry said rates for average consumers in deregulated states are about “30% higher than states with traditional utility regulation.”
“Wisconsin addressed this issue in the late 1990s and has successfully avoided the pitfalls of deregulation that customers in many states like Texas, California, Illinois and Michigan have faced and continue to face,” Barry said.
MISO plans to file a waiver with FERC on its winter energy offer cap policy while it waits for the commission to work out whether a soft cap will replace the current $1,000/MWh hard cap, RTO officials told the Market Subcommittee last week.
The waiver, to be filed Sept. 30, is the same approach used in the last two winters since natural gas prices spiked and drove energy offers above the cap during the polar vortex in early 2014. Cost-based offers above $1,000/MWh will be verified by MISO’s Independent Market Monitor, and the costs above the cap can be recovered via the RTO’s Revenue Sufficient Guarantee payments.
Chuck Hansen, of MISO’s market evaluation design group, said it was unlikely that offers would climb above $1,000/MWh from Dec. 1 to April 30, the length of MISO’s requested waiver. “Given the current low prices and the improved understanding of gas and electric coordination, it seems remote that offers will exceed the cap this winter,” he said.
MISO said it continues to wait on FERC before filing revised Tariff language and new Business Practices Manuals. “Until that point, we’ll just repeat the approach we’ve used over the last two winters,” Hansen said. Last year, MISO said it would have a permanent offer cap solution worked out in time for the 2016/17 season. (See MISO: No Change to Energy Offer Cap this Winter.)
In January, the commission proposed that offers in all RTOs be capped at the higher of $1,000/MWh or an RTO-verified cost-based offer. (See FERC Proposes Uniform Offer Cap Across All RTOs.)
MISO Developing Make-Whole Payments for Pseudo-Tie Units
John Weissenborn, MISO’s director of market services, said the RTO is seeking to develop a market mechanism to make pseudo-tie units whole when they contribute to local reliability needs.
“We’ll start investigating approaches for compensation and cost allocations for commitments of certain pseudo-tie units,” Weissenborn said.
Weissenborn said MISO doesn’t have any provisions in its Tariff to determine appropriate compensation of make-whole payments to pseudo-tie units. “So we really need to think about an appropriate level of compensation for the commitment,” he told stakeholders.
MISO says offline pseudo-ties can be used to relieve congestion, particularly at market-to-market coordinated flowgates. MISO’s research will include commitments outside of market-to-market congestion, Weissenborn said.
“We haven’t really faced this issue to date, but it’s a possibility and something we need to look at,” Weissenborn said.
MISO is in preliminary discussions with PJM on how to coordinate the effort. Weissenborn said he would return later in the year to the Market Subcommittee with a draft approach.
American Electric Power’s Kent Feliks said the issue would open up “a very large can of worms” and asked if there would be cost responsibilities when pseudo-tie units don’t meet commitments. Weissenborn responded that MISO would have to further define the issue before drafting a mechanism.
CAISO last week launched an initiative to develop a greenhouse gas accounting system suitable for an expanded ISO.
The challenge for the ISO is to strike a balance between the requirements for California’s load-serving entities, which face increasingly stringent GHG emission limits under the state’s cap-and-trade program, and the needs of out-of-state utilities not subject to that mandate.
CAISO is seeking to determine how it can modify its market dispatch process under a regionalized footprint to ensure that energy transactions serving load in California reflect GHG compliance costs, while at the same time allowing deliveries outside the state to exclude any emissions component.
“As the ISO explores a transition from a predominantly single-state balancing authority area to a multistate balancing authority area, the ISO will need to model and identify market flows between market nodes subject to GHG compliance and nodes that are not subject to GHG compliance,” CAISO said in an issue paper.
Before expanding into other Western states, CAISO must develop a GHG accounting system that enables the ISO market to track and price emissions from all participating resources (such as the Jim Bridger plant shown above) while allowing bids from out-of-state generators to exclude GHG costs when not serving California demand Photo Source: PacifiCorp
At present, all energy serving ISO load regardless of its geographical source is subject to cap-and-trade. Internal and external generators alike embed their GHG compliance costs within their day-ahead and real-time market bids, including start-up and minimum load costs. During market runs, the ISO’s market software selects from among those bids to determine the least-cost dispatch to cover all load.
In other words, the energy cost component of the market’s LMP, which is the same for all nodes within the ISO, always reflects a GHG compliance cost.
Complications
While that works for a California-only market, it becomes problematic for an expanded ISO in which LSEs in other states would effectively be forced to pay a premium for compliance with rules that do not apply to them.
CAISO is seeking a way to extract the GHG compliance cost from energy bids by resources serving load outside California while retaining it for in-state loads within the state, all within a single market run.
Because California thermal generators must include a GHG cost in their bids regardless of the location of the sink, however, the only deliveries excluded from the cost will be those in which both source and sink are outside the state.
Another complication is that CAISO currently uses e-Tags to track GHG compliance obligations for energy imported into California. But as the ISO absorbs neighboring balancing authority areas, it will discontinue tagging of transfers from those areas as what were once considered imports become internal ISO transactions.
The Western Energy Imbalance Market (EIM) could provide a model for an expanded ISO, with some limitations.
Rather than embedding GHG costs within energy bids, the EIM allows a participating resource to submit a secondary “GHG adder” — in addition to the bid — to signal its willingness to deliver power into California. If the adder is set to zero, the resource’s output is ineligible for delivery into the ISO but can still serve load in other balancing areas.
“The ISO designed the [EIM] so that the GHG compliance costs will not affect the price in an EIM balancing authority area when load is met from generation external to the ISO,” CAISO said.
Leakage
But California’s Air Resources Board (ARB), which oversees the cap-and-trade program, has expressed worry that the EIM’s dispatch model is inadvertently facilitating carbon “leakage.”
Leakage occurs when the emissions program logs a reduction, despite the fact that no actual decrease in atmospheric GHGs has occurred because of a secondary dispatch: The model attributes balancing energy from a low-emitting out-of-state resource to CAISO, while not accounting for the dispatch of a higher emitting resource serving external demand that would have been covered by the first resource absent the EIM. (See CAISO, ARB to Address Imbalance Market Carbon Leakage.)
CAISO has acknowledged ARB’s concerns and is working with the agency to address the problem. The ISO also wants the board to consider the counteracting effect of atmospheric emissions reductions that occur when the EIM displaces out-of-state thermal generation with renewable exports from California, an approach that could inform GHG accounting in an expanded ISO.
The ISO’s effort to address the GHG accounting is taking shape amid uncertainty about the adoption of cap-and-trade in the West at large. Any design has to be “mindful of the potential need to support multiple GHG trading programs” in the region, the ISO said.
“As more trading models are supported, the complexity will increase and transparency will decrease, which is very likely to lead to a less efficient achievement of carbon reduction goals,” CAISO said, adding that it seeks input that “can foster regional cooperation.”
CAISO will discuss the issue paper during a stakeholder call today. Written comments on the initiative are due by Sept. 20.
All storage resources wanting to qualify as capacity should register as behind-the-meter for the 2017/18 planning year, MISO said at last week’s two-day Resource Adequacy Subcommittee meeting.
The AES Corporation partnered with Indianapolis Power and Light to open the first battery storage facility in MISO in June.
Manager of Resource Adequacy John Harmon said the requirement is a way to accredit storage resources using MISO’s existing framework for load-modifying resources while the RTO develops more comprehensive definitions for storage.
MISO said it is attempting to “clarify the framework” for allowing storage that can provide four hours of continuous energy to offer capacity while also participating as Stored Energy Resource (SER) in the regulation market.
Harmon said more discussion is needed for qualifying storage resources that do not wish to be classified as behind-the-meter. MISO also has yet to develop procedures to support sustained power from storage resources, Harmon said.
“We worked through that [research and development] process and found it would not be feasible for registration in time for the 2017/18 planning year,” Harmon said.
In preparation for next year’s auction, MISO is proposing to certify the capability of storage as capacity based on data from the Generating Availability Data System. Class or fleet averages will be used for storage with less than 12 months of GADS data.
The RTO is asking stakeholders this week for input on incorporating storage using the existing qualification process.
Kent Feliks, manager of regulatory and RTO policy at American Electric Power, asked how many storage resources are going to be able to register as capacity in the near future.
“It’s pretty small. It’s probably less than 100 MW, and that’s being generous,” Harmon said.
Consumers Energy’s Jeff Beattie asked how many megawatts of storage are currently in the interconnection queue.
“I can’t answer that, but I do hear interest from individual market participants. From what I see, we’re at the early stages. That’s why we have rules dealing in the short term and are talking about developing solutions to get ahead of this as much as we can,” Harmon said.
RASC to Take Up Gas-Electric Coordination
Renuka Chatterjee, MISO executive director of resource adequacy and transmission access planning, told the RASC to send ideas and comments on a plan to improve gas-electric coordination.
Chatterjee also said the RASC would probably take over management of MISO’s winter fuel survey, which was previously handled by the now-closed Electric and Natural Gas Coordination Task Force.
