FERC last week approved rule changes to improve the ability of energy storage resources to participate in CAISO’s markets (ER16-1735).
The changes will allow “non-generator resources” to submit their state-of-charge as a bid parameter in the day-ahead market and manage their own state-of-charge and energy limits for the purposes of bidding into the market.
Non-generator resources are those that can be dispatched to generate, consume or curtail consumption of energy to any operational level within their specified capacity range.
The non-generator resource model is the primary means by which energy storage devices currently participate in CAISO’s market, enabling batteries to continuously operate across a range that includes both charging and discharging. For bidding purposes, the ISO assumes that the available energy from a storage resource is a function of the resource’s state-of-charge — information the ISO obtains through telemetry.
While that approach is sufficient for real-time operations, CAISO contends that it does not provide a storage resource’s scheduling coordinator a “usable” bid parameter for the day-ahead market.
Under current day-ahead bidding practices, CAISO assumes that a resource’s initial state-of-charge is the ending value from the previous day’s day-ahead award. If there was no such award, the ISO assumes the charge to be 50% of the resource’s megawatt-hour limit.
The Tariff change will allow a scheduling coordinator to replace the ISO’s assumed state-of-charge values with its own bids “to better reflect actual conditions” for a storage resource, CAISO said in its proposal.
Sodium sulfur battery storage facility at Pacific Gas and Electric’s Vaca-Dixon substation. Source: California Energy Commission
“CAISO contends that non-generator resources choosing to self-manage their energy limits and state-of-charge will be able to maintain their states-of-charge at an optimal level through their bidding strategies, enabling resources to better account for dynamic needs in real time and avoid uninstructed imbalance energy settlements,” the commission’s order explained.
The commission’s ruling will also enable CAISO to implement a mechanism to allow energy storage devices to more effectively participate in the ISO’s demand response programs. Those programs measure demand reductions by comparing actual consumption relative to a baseline of expected consumption.
But when demand is offset by a behind-the-meter generation device — such as a storage resource — and “there is no sub-meter to separate consumption and energy produced on site, this approach fails to distinguish the cause of the demand response,” the ISO wrote. “The CAISO cannot tell whether the [DR provider] is curtailing consumption or serving its load from a behind-the-meter resource.”
To remedy the problem, the ISO consulted with stakeholders to develop special metering methodologies.
“These performance methodologies will accommodate sub-metering and allow the CAISO to ascertain demand response performance based upon the gross load [of a DR provider] independent of behind-the-meter generation, the behind-the-meter generator output itself or both,” the ISO said.
Acknowledging stakeholders’ criticism, PJM removed capacity-deficiency and administrative penalties it had proposed for its fuel-cost policy rules and instead offered a single formula-based one. The proposal was made in the compliance filing PJM submitted to FERC on Aug. 16 (ER16-372-002).
The filing was supposed to focus on improving flexibility for hourly generation offers, but PJM also proposed changes to its policy-approval rules and penalties that it said were “integral to the effective clearing of cost-based hourly offers.” The RTO announced it was simultaneously initiating a petition under Section 206 of the Federal Power Act to get the additional changes implemented in case FERC decided their inclusion was outside the scope of the compliance order.
The debate over the rules governing fuel-cost policies stems from a 2015 FERC order to allow day-ahead offers that vary by the hour and the ability to update offers in real time. (See Generators Balk at PJM Proposal on Fuel-Cost Policies.)
FERC wanted the changes made by November 2015, but PJM said at the time that the required revamp to its market system would make that timeline impossible.
Natural gas plants in PJM’s energy market, such as UGI’s Hunlock Creek Energy Center in Luzerne County, Pa., would be subject to the RTO’s rules on fuel-cost policies. Photo Source: Stantec
In this week’s filing, PJM requested an effective date of Dec. 1 for the penalty and policy-approval rules contingent on FERC issuing its approval by Oct. 17. Implementation on Dec. 1 would maximize the benefit of the rules, PJM said in the filing, because “winter is the season in which price volatility in the natural gas markets are most likely to occur.”
The Independent Market Monitor has requested a 10-day extension to the Sept. 6 deadline for submitting comments on PJM’s filing. The Delaware Public Service Commission filed comments in support of the Monitor’s request.
For the hourly offer market rules, PJM said it couldn’t accurately estimate an implementation date because it “will be one of the most in-depth and complicated undertakings in PJM’s recent history, as PJM’s systems have been designed and implemented on the basis of daily offers.” The RTO suggested it will take at least a year, but it requested approval of a timeline that gives it 30 days after FERC’s ruling to propose an estimated effective date and up to 30 days before that proposed date to determine a final effective date.
PJM kept much of its original submission for real-time offer regulations, but it proposed several definitions and revisions. Among them are:
Prohibiting generators from oscillating between market-based and cost-based offers;
Increasing the cutoff for real-time offers from 60 minutes to 65 minutes prior to the applicable clock hour to account for PJM’s ancillary services optimization engine; and
Prohibiting increases to a generator’s incremental energy offer, but allowing it to increase its market-based offers in real time to reflect increases in costs. (PJM proposes defining incremental offers as those pairing price and megawatt quantities, in dollars per megawatt-hour, which combine to include all of the energy segments above a resource’s economic minimum. It excludes no-load costs.)
The fuel-cost policy rules are designed to provide clarity for how policies will be reviewed, delineate submission requirements, define consequences and outline the role of the Monitor.
Sellers without a PJM-approved fuel-cost policy could only be price takers, making offers of $0/MWh. They would also be subject to the penalty, which is up to 75% of the product of the LMP paid to the seller and the unit’s capacity during the hour. The percentage starts at 5% on the day the seller is notified about not having an approved policy and increases 5% each day until a policy is approved. It caps out at 15 days, after which the seller continues to be penalized at that rate.
PJM proposes using the same penalty for a seller who submits an offer that doesn’t comply with its existing policy. The penalty structure is based on a formula used by ISO-NE.
Sellers who have policies rejected by PJM or the Monitor would revert to a previously approved policy until the rejected policy is satisfactorily amended. The RTO also proposed a procedure to revoke a seller’s policy altogether — meaning it would no longer have any approved policy — but said it would only be used in cases of fraud or when a policy doesn’t “remotely reflect” applicable fuel costs.
PJM also proposed an annual review process, in which sellers would have to submit by June 15 of each year any updated policies or confirm that the existing policy remains compliant. PJM would then have until Nov. 1 to provide the seller with a compliance determination.
Solar, storage and run-of-river hydro would be required to have a cost of $0, while wind would need to account for energy and tax credits. Waste-to-electricity resources, such as landfill gas and biomass facilities, would have to include fuel costs even if the facility is paid to accept the waste — meaning their fuel costs would be negative.
The policies would also need to include maintenance adders, heating requirements, unit-specific performance factors and start-up cost calculations.
The filing also detailed PJM’s understanding of the Monitor’s role, noting stakeholder confusion over its involvement in initial policy approval and ongoing oversight. In previous discussions on the topic, the Monitor has questioned PJM’s proposed regulations, saying they cross into its authority.
FERC “has made clear that the act of approval or disapproval of fuel-cost policies is one to be undertaken by PJM and not the IMM,” PJM said in its filing. Penalties would only be assessed if both PJM and the Monitor agree on it. In the event that they disagree, PJM proposed that the matter be referred to FERC’s Office of Enforcement.
During a conference call last week to review the filing, PJM staff clarified that specific implementation processes would be outlined later in changes to Manual 15. The changes will be reviewed by the Market Implementation Committee.
If FERC approval allows for an effective date prior to the beginning of the annual review process, PJM plans to concentrate initially on generation units without any policies or ones that received tacit PJM approval based on negotiations with the Monitor. It would then rely on the annual review process to ensure all units had approved policies. Under PJM’s existing protocols, some units have not been under any requirement to get a policy approved and others have undergone lengthy negotiation processes with the Monitor.
Both PJM and the Monitor described “significant philosophical differences” in their perspectives on the correct oversight scheme.
The “fundamental difference,” according to Monitor Joe Bowring, is his group’s role in the process. PJM made some “significant mistakes” in the filing and isn’t “correctly observing that division of labor set forth in the Tariff,” he said.
Ed Tatum of American Municipal Power asked about the differences in opinion on how short-run marginal costs should be handled.
Bowring responded that PJM’s proposed protocols should be adjusted. PJM’s Jeff Schmitt said that would be addressed in changes to Manual 15.
Jason Cox of Dynegy suggested that the penalty have tiered levels corresponding to whether a noncompliant offer affected the market price, but PJM said that was not part of the filing.
Entergy and Exelon filed a petition with New York regulators Monday seeking approval of Exelon’s $110 million purchase of the James A. FitzPatrick nuclear plant (16-E-0472).
Fitzpatrick Nuclear Plant Source: Entergy
The companies asked the Public Service Commission to approve the acquisition by Nov. 18. The PSC has a regularly scheduled meeting on Nov. 17.
“Prompt approval is warranted here because … the transfer does not raise any issues regarding retail energy sales to captive ratepayers, it does not raise any market power concerns in the competitive wholesale markets in New York or the adjoining regions and it is consistent with commission precedent,” the companies said.
The petition says an “investment decision” on refueling the plant must be made soon, as FitzPatrick’s current fuel cycle is expected to end about Jan. 31, 2017.
Entergy said last year it would close the money-losing plant in early 2017. Exelon agreed to purchase the generator after the PSC adopted a subsidy for the no-carbon emission attributes of nuclear power. (See Entergy Sells FitzPatrick to Exelon.)
FitzPatrick, which produces an average 7 million MWh annually, is licensed to operate through 2034.
If approved, Exelon would own all of the upstate nuclear fleet in New York: FitzPatrick, R.E. Ginna and Nine Mile Point 1 and 2. They total 2,267 MW, or 5.9% of the generating capacity in NYISO, according to the companies.
Entergy would still own the only other nuclear plant in the state, Indian Point in the Lower Hudson Valley.
Concern over Subsidy Payments
In a separate filing Monday, Exelon asked the PSC to guarantee subsidy payments for Ginna and Nine Mile Point in the event that its purchase of FitzPatrick plant falls through (15-E-0302).
The company said language in the Clean Energy Standard adopted Aug. 1 by the commission could be interpreted to end the subsidy in March 2019 if not clarified. The order directed the purchase of zero-emission credits (ZEC) in six two-year tranches from 2017 to 2029. (See New York Adopts Clean Energy Standard, Nuclear Subsidy.)
The CES anticipated the FitzPatrick sale after negotiations between Exelon and Entergy were announced in mid-July.
“The FitzPatrick purchase condition [of the CES order] is unclear as to whether the 12-year duration of the R.E. Ginna facility’s, the Nine Mile Point facility’s and the FitzPatrick facility’s respective ZEC contracts are conditioned on the sale of the FitzPatrick facility by Sept. 1, 2018, or whether the 12-year duration language applies only to the FitzPatrick facility’s ZEC contract,” the petition states.
The petition says there is ambiguity in the order and its Appendix E, which states: “If the sale and closing does not occur, there will be no commitment for the program to continue beyond Tranche 1 and the commission will have six months before the otherwise planned commencement of Tranche 2 to determine a future course of action, if any.”
Exelon is asking for specific language to limit the two years of ZEC payments only to FitzPatrick if the sale is not completed.
It asks for a clarification or limited rehearing order by Nov. 18, the same date it has requested for approval of the sale.
Thomas Broderick, the director of utilities for the Corporation Commission, is leaving after a little more than a year on the job. Broderick provided no reason for his departure and said he was not taking another job.
Broderick
Broderick was hired last summer after a nationwide search to replace the longtime agency staffer who previously held the position, which manages 60 regulatory experts and oversees a $5.5 million budget. Commission Chair Doug Little said he was “truly disappointed” to see Broderick go.
His departure comes as the commission considers a pending rate case for Arizona Public Service, the state’s largest utility.
The Imperial Irrigation District (IID) will inaugurate a $38 million battery storage facility next month, the largest power storage unit in the western U.S.
The 30-MW facility will be capable of discharging as much as 20 MW in an hour. The massive battery will help the publicly owned utility to firm up intermittent output from the region’s renewable resources and to support the grid in the face of unexpected problems.
“The energy industry is ever-changing and fast-paced, and regulations are changing daily almost, it seems like,” IID spokesman Robert Schettler said. “So this is a way we’re trying to get ahead of an issue.”
The Boulder City Council voted unanimously to approve the annexation of 16 properties adjoining the city, overcoming an obstacle in its bid to municipalize the electric distribution system of Xcel Energy.
The annexation eliminates the need to build separate distribution facilities to serve those customers after Boulder takes ownership of Xcel’s local system. The state Public Utilities Commission had ordered the city to pay for construction of separate facilities to allow Xcel to continue to serve the customers in unincorporated Boulder County.
The annexation prevents “a lot of unnecessary, expensive additional construction,” according to the city staff.
Kentucky Utilities ratepayers will pay an additional surcharge to cover the utility’s environmental upgrades through 2024 under a settlement approved in early August by the Public Service Commission.
The PSC said the surcharge amount increases over time, beginning with 30 cents in 2016 and climbing to $1.37/month in 2017 and $2.32 in 2018. The amount crests in 2022 at about $3.32/month.
KU and Louisville Gas & Electric asked the PSC for permission to spend more than $900 million on pollution-control measures at their coal-fired plants to comply with federal coal ash storage requirements and to limit emissions under EPA’s Mercury and Air Toxic Standards.
The Public Service Commission has approved new notification requirements for service terminations after a Princess Anne family that was using a generator inside their home for heat died of carbon monoxide poisoning last year.
Delmarva Power had removed the home’s electric meter after it discovered that it had been stolen and terminated service to the home.
Under the new regulations, customers whose service is terminated because of allegations of theft or hazardous conditions must be notified by the utility, either in person or in writing, and the notice must include safety precautions. The utility must also notify the commission within one day of the cancellation. The PSC would then add the address to a database for use by local governments, so they can provide assistance to the customer.
Regulators Say No Reason to Shut Down Mackinac Pipelines
State regulators say they found no evidence to support an order to shut down Enbridge’s Line 5, a pair of underwater petroleum pipelines that go under the Straits of Mackinac, and ordered more studies into their integrity.
Environmental advocates who have called for a shutdown accused the state of dragging its feet. They complained that the studies by the Department of Environmental Quality could take 18 months to complete. The department said it was unable to shut the pipeline down without “clear violations” of environmental easements and evidence that there is “imminent threat” of pipeline failure.
The State Legislature’s Energy and Telecommunications Interim Committee has drafted seven bills that would impose millions of dollars in fees on the Colstrip power plant’s owners for 10 years following the closure of two of the plant’s units.
The committee will decide next month whether to file the bills for the 2017 legislative session. Closure of the units by 2022 is required in a legal settlement filed last month.
NorthWestern Fails Again to Recover Costs from Outage
The Public Service Commission has rejected NorthWestern Energy’s second attempt to pass on costs related to a 2013 outage at the Colstrip power plant to consumers through a rate increase. The PSC rejected the company’s appeal of an earlier decision by a 3-2 vote.
NorthWestern had to buy $8.2 million of electricity on the market when a malfunction shut down Colstrip’s Unit 4 three years ago. The commission in March found that the outage was avoidable and NorthWestern didn’t meet requirements for the replacement costs to be passed along to consumers.
“I’m not sure what part of ‘no’ NorthWestern doesn’t understand,” Commissioner Roger Koopman said in a press release.
Land Board Approves Lease For Potential 70-MW Wind Farm
The Land Board approved the lease of 450 acres near Billings for a possible 70-MW solar development. The lease includes a two-year option to MTSun while regulators conduct an environmental study.
Regulators Approve PNM’s Energy Contract for Facebook Data Center
The Public Regulation Commission last week unanimously approved a special services contract between Facebook and Public Service Company of New Mexico outlining how the state’s largest utility would supply power to the technology giant’s proposed data center.
The contract, approved Aug. 17, describes a mechanism for providing renewable energy to the data center, which would include the construction of three solar facilities and a high-voltage electric line. Under its terms, PNM would receive about $31 million a year for providing electricity to the data center.
The Los Lunas Village Council has already approved up to $30 billion in industrial revenue bonds for the project.
Erin Brockovich Points to State In Call to Set Toxin Standard
Famed environmental activist Erin Brockovich cited the ongoing coal ash dispute in the state in a request to EPA to set groundwater standards for hexavalent chromium.
A state toxicologist had warned residents living near Duke Energy coal ash storage sites that tests showed unsafe levels of the compound, a finding disputed by Gov. Pat McCrory’s administration. Brockovich pointed to the dispute in a letter she and the Environmental Working Group sent to EPA calling on the agency to set safety levels of the compound.
“It is clear that the delay [in setting safety levels] is sowing confusion among state and local regulators, utilities and the public about how much hexavalent chromium is safe in drinking water,” the letter reads. The current federal level for the compound is 100 parts per billion. It was set 25 years ago and is considered by many to be outdated.
The Corporation Commission approved a $30 million settlement that allows Oklahoma Gas and Electric to recover some lost revenues from its popular SmartHours energy efficiency program. More than 110,000 residential OG&E customers have signed up for the program.
OG&E will recover $30.3 million for lost revenue from 2013 to 2015, when the case was first filed.
The settlement among the utility, the commission’s public utility division and the OG&E Shareholders Association resolves a dispute in calculating the amount of lost revenue under SmartHours. The division said the annual amount was closer to $5 million.
Refunds Start Flowing from Polar Vortex Settlements
Utility customers are beginning to see refunds as state officials conclude their cases with energy suppliers accused of misleading consumers about energy prices during the polar vortex of 2014.
Customers of Pennsylvania Gas and Electric, IDT Energy and Hiko Energy will receive $15.6 million. Respond Power will pay $4.1 million. One case, against Blue Pilot Energy, is pending.
State Considers Increasing Nation’s Only Wind Output Tax
A proposal by lawmakers to raise the state’s tax on wind output is meeting resistance from a large wind farm developer.
Bill Miller, CEO of the Power Company of Wyoming, which has proposed building two wind farms rated at 3,000 MW total, is attempting to thwart the tax increase. “Just about every legislator we’ve met with asks us, ‘You tell us how much we can tax you before we put you out of business,’” said Miller. “I just shake my head and say, ‘Zero.’”
The state is the only one in the country that taxes output from wind turbines, currently collecting $1 for every megawatt-hour produced. The state’s take since implementing the program: $15 million. Power Co.’s proposed Chokecherry and Sierra Madre projects could potentially triple revenues.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider. The Members Committee does not meet in August.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
PJM Manuals (9:10-9:40)
Members will be asked to endorse the following manual changes:
Manual 12: Balancing Operations. Administrative and conforming updates align with NERC reliability standard BAL-001-02, which went into effect July 1, and with the frequency bias calculation in BAL-003-1.
Manual 14D: Generator Operational Requirements. Changes include updates to the cold weather generation resource preparation section. Amends cold weather testing process effective with winter 2016/17. Generators that cleared as Capacity Performance in the current delivery year will no longer be eligible for compensation for conducting the exercise but may test and receive compensation as a self-scheduled resource. (See “PJM Plans to End Compensation for CP Units Participating in Winter Testing,” PJM Operating Committee Briefs.)
MISO is working to coordinate its generator retirement studies with PJM without changing the RTOs’ Tariffs.
“We’re not going to overhaul the individual Tariffs,” Neil Shah, MISO advisor of seams administration, said during an Aug. 16 meeting of the Planning Subcommittee. “The coordination will align to the extent possible with the Tariffs. We don’t see the need to change anything in the Tariff requirements just yet.”
FERC ordered that MISO coordinate its generator retirement studies with PJM in response to a complaint by Northern Indiana Public Service Co. (EL13-88). (See “MISO Outlines Work Plan for PJM Retirement Coordination,” MISO Planning Subcommittee Briefs.)
Shah said MISO will continue to exchange retirement notification and study information with PJM. “We’ve been doing that before the FERC order came out, so there’s nothing new there,” he said.
MISO is proposing to consult with PJM on how it uses its 30-day window to study generators seeking deactivation for adverse reliability impacts so MISO can consider incorporating those methods in its own reliability impact studies. MISO also wants to exchange study models with PJM as they are updated.
Shah also said MISO plans to use the Interregional Planning Stakeholder Advisory Committee to discuss impacts to the RTOs and analyze upgrades proposed in place of the retiring generator.
Shah said MISO’s suggested approach allows for RTOs to conduct their own studies “with inputs and common assumptions of adjacent system conditions.”
He said MISO will comb through the RTOs’ joint operating agreement to see if any language needs to be revised to include the proposed coordination. MISO is asking for stakeholder feedback on its proposal by Sept. 7 to shape the draft JOA language. Before then, stakeholders will offer opinions on the JOA language at a Nov. 15 Joint Common Meeting. A final filing in the NIPSCO order is due Dec. 15.
Shah said a key difference between the RTOs’ retirement obligations is that PJM cannot force a resource owner to stay online, while MISO can order system support resource agreements.
The RTOs’ retirement timelines are also mismatched. PJM requires 90 days’ notice before retirement while MISO requires twice as long.
Shah also noted that MISO keeps retirement information confidential unless there’s a need for SSR designation while PJM announces retirement notifications.
“That’s not as much of a concern,” Shah said of addressing the confidentiality issue.
Possible MISO-PJM Joint Model in Works
In the NIPSCO ruling, FERC also ordered MISO to explore the potential for a joint regional model with PJM with the same assumptions and criteria to coordinate the two regional transmission planning processes.
MISO started the process at last week’s subcommittee meeting by asking stakeholders to envision what a MISO-PJM joint model would look like.
MISO engineer Adam Solomon said it is possible to model power flow and economic models that contain both MISO and PJM assumptions. However, Solomon said MISO is opposed to creating common assumptions such as production cost models.
“Our approaches are so different that it doesn’t make sense,” he said.
An informational filing on a possible joint model is due Oct. 18. Solomon said MISO isn’t certain of the action it would have to take after that.
“If [FERC] likes our answer, they might require us to incorporate some of the things into our joint operating agreement, but for now, it’s just informational,” he said.
MISO Releases Minimum Requirements for Competitive Tx Projects
MISO released the first revision of Business Practices Manual 029, which governs requirements for competitive transmission projects.
MISO principal adviser Matt Tackett said the Minimum Design Requirements Task Team added minimum normal rating requirements that borrow from current minimum emergency ratings. Tackett also said the manual includes a default table for minimum transmission circuit ampere ratings.
“The biggest trick was coming up with a default table based on typical percentages,” Tackett said.
MISO has also developed what it calls adequacy validation ratings to verify that the circuit conductors specified by developers provide adequate load capacity.
The ratings factor in wind speeds along with ambient temperatures. MISO North assumes an ambient temperature of 35 degrees Celsius in the summer and 0 degrees in the winter; all other MISO regions will use 40 degrees Celsius in the summer and 10 degrees in the winter.
Tackett said BPM 029 will undergo more refinements based on stakeholder feedback before another presentation at the October PSC. It is set to become effective in January.
Meanwhile, Tackett said BPM 020, which guides use of non-transmission alternatives and describes how storage can qualify for interconnection, needs another monthlong round of vetting in the subcommittee before final language is reviewed before the Planning Advisory Committee.
Transfer Limits Range from 1,400 to 4,500 MW in MTEP16 Analysis
MISO senior engineer Scott Goodwin announced preliminary linear thermal limits for MISO’s 2016 Transmission Expansion Plan transfer analysis:
MISO North to SPP has a transfer limit of 3,600 MW;
Two paths from Manitoba Hydro to MISO North have limits of 1,400 MW or greater;
MISO North to PJM Ohio has a limit of 4,000 MW;
Limits from Missouri and Illinois to PJM Ohio range from 2,800 to 3,600 MW depending on different contingencies;
SPP to Southern Co.’s territory has a limit of 4,100 to 4,500 MW depending on different contingencies; and
Michigan is asking for another assessment from MISO, this time to study grid improvements across the state’s peninsulas and Canada.
The latest request, signed by Gov. Rick Snyder, asks MISO to study the reliability and affordability benefits of transmission and generator expansion in the northern part of the RTO’s footprint.
“Since Michigan has some of the highest prices for transmission in the MISO footprint, it makes sense to ask whether, in the long term, we can all spend less while increasing reliability by strengthening our ties to each other and our neighbors,” Snyder said.
The Michigan Agency for Energy (MAE) also joined in on the request.
“Michigan is in the middle of a transformation of our energy infrastructure in both peninsulas, and Ontario’s generation has changed a great deal, including the area just across the Soo,” said Valerie Brader, executive director of the agency, referring to the region encompassing the twin Sault Ste. Marie cities in Michigan and Ontario. “This study will help us identify whether, due to all these changes, there are new opportunities for infrastructure that will make Michigan more adaptable.”
MISO spokesman Jay Hermacinski said the RTO has contacted Michigan officials to discuss the governor’s request and the state’s Aug. 9 call for a reliability analysis that assumes simultaneous outages at the Palisades and Fermi 2 nuclear plants. (See Michigan Asks: Will the Lights Stay on If Nukes Go Dark?)
“At this early stage in the process, it is too soon to comment on the substance of requests or to establish a definitive timeline,” Hermacinski said.
The new request asks the RTO to study:
Connecting Sault Ste. Marie, Ontario, to Michigan’s eastern Upper Peninsula in Zone 2;
Strengthening the connection between the Upper Peninsula and the northern Lower Peninsula in Zone 7 at the Straits of Mackinac down to “the northernmost part of the existing 345-kV transmission line near Gaylord, Mich.”;
Production cost savings, reliability, resource adequacy and power flows assuming a large natural gas plant is built in Otsego or Kalkaska County in the northern Lower Peninsula. Michigan officials say that the area is ripe for a natural gas plant, as pipelines and storage in the area have available capacity, and an adequate transmission network exists.
MISO last completed a study of its northern footprint in 2012, but the connections to Canada were not analyzed, MAE said.
This time, Michigan is asking MISO to work with Ontario’s Independent Electricity System Operator and pointed out that the province’s next Long-Term Energy Plan process begins this summer. Since the 2012 study, the agency said, the area has experienced “significant infrastructure changes” with more to come. The letter points out that “many fundamental characteristics of the Bulk Electric System have evolved over the last five years on both sides of the international border, and change to the system is expected to accelerate within Michigan.”
Ontario ended coal-fired generation in 2014. Nuclear power, now 60% of the province’s generation output, is expected to drop to 40% by 2025. The province expects to add as much as 3,000 MW of capacity between 2021 and 2032. (See Ontario: Clean — and Expensive.)
NV Energy and PacifiCorp returned nearly $95,000 to generation customers after FERC revoked market-based rate authority for Berkshire Hathaway Energy affiliates in four neighboring Western balancing authority areas and imposed cost-based rates.
NV Energy and PacifiCorp refunded $95,000 to generation customers in the PACE, PACW, IPCO, and NWMT areas represented on the map.
The refunds were disclosed in confidential documents released under a Freedom of Information Act request by Clearing Up, an energy newsletter covering the Pacific Northwest.
The documents show that NV Energy refunded $77,073 — with interest — to its customers, which included about $50,000 to Idaho Power, $20,000 to TransAlta Energy Marketing and $5,000 to Shell Energy. PacifiCorp refunded a total of $17,646.10, including nearly $6,900 to Morgan Stanley Capital, $6,100 to Tucson Electric Power and $3,900 to NorthWestern Energy.
The commission restricted Berkshire’s market-based rate authority in June after ruling that the company’s affiliates failed to disprove that they collectively exercise horizontal market power in the PacifiCorp East, PacifiCorp West, Idaho Power and NorthWestern balancing areas (ER10-2475, et al.).
The affiliates failed the indicative “pivotal supplier” and “wholesale market power” screens for initially assessing horizontal market power in the four regions, as well as a more thorough “delivered price test” analysis designed to enable companies to rebut a presumption of market power. (See Berkshire Market-Based Sales Restricted in 4 Western BAAs.)
FERC ordered the Berkshire companies to revise their tariffs for the the four areas and issue refunds for the period between Jan. 9, 2015, and April 9, 2016.
The modest sums involved reflect persistent weakness in regional wholesale electricity prices. A source close to the matter told RTO Insider that many of the sales during the period were transacted below Schedule Q — or cost-based — rates because of market conditions.
The expected future impact of FERC’s ruling got only brief mention in Berkshire’s second-quarter filing with the Securities and Exchange Commission. “The specified [Berkshire] subsidiaries affected in the order do not believe the order will have a material impact on their respective consolidated financial statements,” the company wrote.
Nevertheless, Berkshire last month requested a rehearing on the decision, contending that the commission “did not provide sound reasoning, nor did it show a path to how it arrived at its decision.” (See Berkshire Contests Market-Based Sales Restriction in the West.)
LITTLE ROCK, Ark. — SPP’s engineering staff updated members on the RTO’s current regional and interregional transmission planning studies during an engineering summit last week.
In return, the engineers asked for stakeholders’ input.
“It was very important that we are able to get in the feedback at the front end of the process,” SPP Director of Transmission Planning Antoine Lucas told members, who spent much of the day delving deep into the 2017 Integrated Transmission Planning’s 10-Year Assessment (ITP10). “Most of you will be pleased with” the process.
“As soon as you guys can provide feedback, please do it,” requested SPP’s Juliano Freitas, manager of economic planning.
ITP10
SPP plans to present its final 2017 ITP10 to the Markets and Operations Policy Committee in December.
Staff is using three futures for the study: regional compliance with EPA’s Clean Power Plan; state-level CPP compliance; and a reference case that assumes the CPP will not be implemented.
The two CPP studies will eventually be combined into a single portfolio, with the reference case also moving forward for additional benefit calculations, using multiple model years and costs derived from the RTO’s annual transmission revenue requirement formulas.
Transmission projects would be deemed to satisfy economic needs by meeting up to 25 constraints with greater than $50,000 in annual congestion costs.
SPP will also produce a near-term reliability assessment early next year. Staff is currently working on a needs assessment but doesn’t expect to produce a final portfolio recommendation and report until March.
Adam Bell, SPP’s interregional coordinator, updated members on the status of SPP’s work with three of its interregional partners: MISO, Associated Electric Cooperatives Inc. (AECI) and Southeastern Regional Transmission Planning (SERTP).
SPP and MISO have both voted to pursue a joint study this year, using their regional planning as a starting point. Bell told members they would be able to propose solutions for the final set of needs, currently being developed.
The RTOs are scheduled to meet again Sept. 7. “We want to get this scope approved so we can get this study done,” Bell said.
SPP and AECI are determining the scope of a study of five target areas: potential overloads and voltage issues in northeast Oklahoma and Brookline, Kan.; potential low voltage issues in mid-Missouri and east of Kansas City; and potential upgrades in Wheaton, Kan. They expect to produce a final report and recommendations in January.
Bell said SPP had its annual meeting with SERTP representatives in June. The staffs reviewed their regional plans to “see if anything made sense,” Bell said, adding later, “it’s more coordination than joint planning or joint study.”
“There could be potential here as we move forward,” he said.
A group of Upper Peninsula electric users plans to ask FERC to investigate Wisconsin Electric Power Co. for allegedly falsifying records to increase its revenues under the Presque Isle power plant system support resource agreement.
“The numbers presented by MISO and WEPCo going back to 2014 were inflated, and part of that was falsifying documents,” Todd Chapman, spokesman for Cloverland Electric Cooperative, said Monday.
Chapman said that the organization expects to file a brief later this week or next week detailing the allegations, which were included in Administrative Law Judge Michael Haubner’s initial decision last month saying WEPCo had overcharged ratepayers by $17 million over the SSR (ER14-1242-006, et al.).
Last week, meanwhile, FERC approved nine out of ten SSR process revisions proposed by MISO.
“Evidence shows that the invoice for services was originally executed and sent to WEPCo on Oct. 9, 2014. Then, a WEPCo employee requested the consultant resubmit the invoice with a later date, Oct. 16, 2014,” Haubner said.
Presque Isle Power Plant Source: WEPCo
According to Haubner, the invoice dates were changed after WEPCo learned that a new version of its SSR agreement with MISO would cover costs incurred from MATS upgrades under a revised fixed-cost component. MATS upgrades were ineligible for recovery under the previous SSR agreement.
“This evidence demonstrates that WEPCo changed the date on the consulting services invoice to one day after the replacement SSR agreement became effective. It appears this manipulation was done by WEPCo to include these costs under the later agreement,” Haubner concluded.
WEPCo issued a statement insisting the company was not seeking to recover MATS compliance costs through the SSR payments. “Beyond that, the company will not comment on cases currently being litigated. The issues that are in contention in the initial ALJ decision, including this issue, will be addressed by our future filings in this case,” it said.
Chapman said the $1.4 million worth of back-dated invoices was “carved out” in the judge’s estimated refunds and contributed to Cloverland lowering its expected amount owed to MISO for the Presque Isle SSR to “the neighborhood of $9.8 million,” instead of the original $11.7 million, for 2014.
Chapman said Cloverland is waiting on a larger decision from FERC in order to verify the $9.8 million figure.
Cloverland will be joined in its request for an investigation by mining company Cliffs Natural Resources, Upper Peninsula Power Co., paper producer Verso Corp., the City of Mackinac Island and the Sault Ste. Marie Tribe of Chippewa Indians, Chapman said.
If FERC decides to investigate, a probe from its Office of Enforcement could take years, Chapman said.
“None of that is going to wipe it all out and completely dismiss the amount we owe,” Chapman said, adding that the outcome of a possible investigation “probably” wouldn’t further reduce the amount owed. “If FERC agrees that it was fraudulent, then we’re back to the same lower number,” he said.
MISO Confused by Refund
Meanwhile, MISO complained in an Aug. 16 brief that Haubner’s ruling was inconsistent and confusing.
MISO said Haubner used two “inconsistent” methods to determine variable compensation under the two separate Presque Isle SSR agreements. The RTO also said the judge at times mixed up fixed compensation and clawback values. Finally, MISO said Haubner did not outline a procedure for calculating the total amount owed to ratepayers.
“MISO is unable to determine the amount of refund that should be made by the Wisconsin Electric Power Co.,” the RTO wrote to FERC. It also said it “hoped for an initial decision that would contain internally consistent findings that MISO could implement in its role as Tariff administrator.”
FERC Accepts Changes to MISO SSR Process
In a related order on Aug. 19 (ER16-1758), FERC accepted nine out of ten SSR process revisions proposed by MISO, which affect the execution, filing and compensation of SSR units.
MISO proposed that while it would still file SSR agreement terms and conditions, SSR owners in “all cases” would make separate filings for compensation. MISO previously only had SSR members resort to a FERC filing when it couldn’t agree on compensation.
FERC agreed. “Given that many recent SSR filings have set compensation issues for settlement and hearing procedures, the advantage of requiring that MISO and the market participant undergo preliminary compensation negotiations prior to executing an SSR agreement is limited and outweighed by the administrative burden of conducting such negotiations,” the commission said.
The Michigan Public Service Commission supported MISO’s proposal, saying it would allow customers and regulators to offer input before MISO and SSR owners reach an agreement.
Chapman said it was better that MISO not take generators’ cost numbers at face value. “I think MISO will learn their lesson, but not before this happens again,” he said, referring to future coal plant retirements.
Inappropriate Limit
The order also allows MISO to enforce a 30-day notice period before retirement on forced outage units and units that are pseudo-tied out of the RTO. Pseudo-tied units now also have a 36-month maximum suspension period in a five-year time frame before their interconnection service is pulled. Black start-designated units must now fill out an Attachment Y notice, which triggers a reliability study, before retiring. Finally, all retirements can be made public by MISO once their retirement date passes.
However, FERC rejected MISO’s proposal that a return to service on a retired former SSR would be defined at the point that the unit re-enters the interconnection queue, saying it would “inappropriately limit” situations where a generator would have to refund certain costs. FERC called MISO’s existing Tariff language on refunds “appropriately broad.”
Cliffs-WEC Deal
Chapman blames a Michigan exemption that allows mining companies to choose electricity suppliers for the creation of the disputed SSR. Mining company Cliffs Natural Resources took advantage of the exemption, leaving Presque Isle for an estimated $20 million to $30 million annual savings.
“Nobody thought anything of the exemption at first. At the time, it protected the mines, and Cliffs is the largest employer in Marquette,” he said.
Cloverland now has a new concern, spawned by Cliffs’ announcement last week that it has entered a 20-year power purchase agreement with WEC Energy Group to power its Tilden mine. The contract would result in the construction of two natural gas-fired plants on the Upper Peninsula totaling 170 MW.
He said Upper Peninsula ratepayers would be on the hook if Cliffs should go out of business, as the Upper Peninsula’s transmission network isn’t able to reliably export power to Wisconsin and the Lower Peninsula.
Cliffs CEO Lourenco Goncalves said the new generators are a “strategic energy solution for the Upper Peninsula [that] optimizes affordability and improves reliability for all ratepayers for decades to come.”
The $255 million plan will need to be approved by the Michigan PSC.
The Imperial Irrigation District (IID) will inaugurate a $38 million battery storage facility next month, the largest power storage unit in the western U.S.
The State Legislature’s Energy and Telecommunications Interim Committee has drafted seven bills that would impose millions of dollars in fees on the Colstrip power plant’s owners for 10 years following the closure of two of the plant’s units.
Famed environmental activist Erin Brockovich cited the ongoing coal ash dispute in the state in a request to EPA to set groundwater standards for hexavalent chromium.
The Corporation Commission approved a $30 million settlement that allows Oklahoma Gas and Electric to recover some lost revenues from its popular SmartHours energy efficiency program. More than 110,000 residential OG&E customers have signed up for the program.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
