Powerex has signed an agreement with CAISO to become the first non-U.S. participant in the Western Energy Imbalance Market (EIM).
Vancouver-based Powerex markets the surplus generation of parent BC Hydro, Canada’s third largest utility. The company’s role is similar to that of U.S. federal power marketing agencies, such as Bonneville Power Administration and the Western Area Power Administration.
Powerex is wholly owned subsidiary of BC Hydro, responsible for marketing the utility’s surplus hydroelectric generation to customers throughout the West. | Kootenay Canal Generating Station image courtesy of BC Hydro
Mexican grid operator El Centro Nacional de Control de Energía (CENACE) last year announced that it was exploring having its Baja California Norte join the market, but it has not yet signed a participation agreement.
Powerex is slated to join the EIM in April 2018, an aggressive timeline compared with other utilities that have signed on to the market. Preparations typically take 18 months or longer, but the company has long experience selling into the ISO’s real-time market.
“Powerex has actively participated in the ISO’s five-minute market since 2005 through a dynamic scheduling arrangement, so joining the EIM is a logical extension of our intra-hour market participation,” Powerex CEO Teresa Conway said in a statement.
Conway noted that Powerex’s participation in the growing EIM footprint will allow the company to engage in sub-hourly transactions across multiple utility service territories, helping to integrate renewables and improve the region’s grid reliability.
With its access to BC Hydro’s ample hydroelectric resources, Powerex is well-positioned to provide EIM participants with the flexible ramping capacity increasingly needed to firm up the growing number of variable renewable resources coming to the region’s grid. That type of resource sharing is touted as a key benefit of the market.
The company also holds transmission rights on lines throughout the West, including the California-Oregon Intertie, a key transfer point between the Pacific Northwest and California. Constraints on that line periodically act as a chokepoint that isolates the PacifiCorp West and Puget Sound Energy balancing authority areas from the rest of the EIM, resulting in prices that diverge from the rest of the market.
Washington’s Puget Sound Energy — whose service area stretches from suburban Seattle to the Canadian border — began transacting in the EIM last October. (See Seattle City Light Signs EIM Membership Agreement.)
Other future participants in the EIM include Portland General Electric (October 2017), Sacramento Municipal Utilities District (April 2019) and Salt River Project (April 2020). CAISO also said that it expects the Los Angeles Department of Water and Power to soon announce a formal agreement to join the market.
Exelon announced Tuesday that it will retire Three Mile Island Unit 1 in September 2019 “absent needed policy reforms.”
The announcement was not unexpected after the company acknowledged May 24 that the plant had not cleared the PJM capacity auction for delivery year 2020/21, the third year in a row it had come away empty-handed.
In a filing with the U.S. Securities and Exchange Commission, Exelon said the plant has lost money for the last five years as a result of “prolonged periods of low wholesale power prices,” its failure to clear the last three PJM capacity auctions and “the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution while contributing to grid reliability.” As a single-unit plant, TMI also had high operating expenses, the company added.
The 837-MW reactor near Middletown, Pa., directly employs 675 workers.
“Today is a difficult day, not just for the 675 talented men and women who have dedicated themselves to operating Three Mile Island safely and reliably every day, but also for their families, the communities and customers who depend on this plant to produce clean energy and support local jobs,” CEO Chris Crane said in a statement. “Like New York and Illinois before it, [Pennsylvania] has an opportunity to take a leadership role by implementing a policy solution to preserve its nuclear energy facilities. … We are committed to working with all stakeholders to secure Pennsylvania’s energy future and will do all we can to support the community, the employees and their families during this difficult period.”
A Successful Strategy
In threatening to close the plant, Exelon is repeating the strategy that won approval of zero-emission credits for its troubled nuclear plants in New York and Illinois.
Last June 2, Exelon announced it would close the Clinton and Quad Cities plants in 2017 and 2018, respectively, because of “the lack of progress on Illinois energy legislation.” The company said the plants had lost a combined $800 million over the prior seven years, “despite being two of Exelon’s best-performing plants.”
Six months later, the Illinois legislature approved the ZEC program on the last day of its veto session. Gov. Bruce Rauner signed the bill Dec. 7. Following the passage of the Illinois legislation, Exelon revised the expected economic lives to 2027 for Clinton and 2032 for Quad Cities.
On June 12, Exelon told the New York Public Service Commission it would close its Nine Mile Point Unit 1 nuclear plant in spring 2017 if the state did not guarantee it a financial lifeline by September.
The company had also told regulators in October 2015 that its R.E. Ginna nuclear plant would not be financially viable following the expiration of a reliability support services agreement with Rochester Gas & Electric.
The PSC approved ZECs for Nine Mile Point and Exelon’s R.E. Ginna nuclear plants last Aug. 1. Receiving payments under the program in addition to Ginna and Nine Mile Point is the James A. FitzPatrick plant, which Entergy sold to Exelon in March after saying it would also close.
Next Steps
Exelon said it will send PJM and the Nuclear Regulatory Commission deactivation notices within 30 days. It complained that nuclear generation produces 93% percent of Pennsylvania’s emissions-free power but is not included in Pennsylvania’s Alternative Energy Portfolio Standard, which benefits solar, wind and hydropower.
The Pennsylvania General Assembly’s Nuclear Energy Caucus said in a statement that Exelon’s announcement shows “there are serious and consequential underlying issues in Pennsylvania’s energy sector that must be addressed.”
“As state lawmakers, we take seriously our obligation to set energy policies that help promote Pennsylvania’s economy,” the legislators said. “We equally are concerned about meeting the commonwealth’s environmental goals. The closure of Three Mile Island will make meeting these challenges even more difficult.”
The 79-member caucus has yet to introduce legislation.
Gov. Tom Wolf’s press office released a statement in which it “expressed a willingness to engage in conversations with state lawmakers about possible energy policy reforms.”
“Pennsylvania is a major supplier of energy and we need a diverse energy sector,” Wolf spokesman J.J. Abbott said. “… As we move forward, we expect a robust conversation about the state’s energy sector. Governor Wolf is open to these conversations and looks forward to engaging with the General Assembly about what direction Pennsylvania will go in regards to its energy sector, including the future of nuclear power.”
Legal Challenges
The ZECs in both Illinois and New York are being challenged in the courts and before FERC by plaintiffs including the Electric Power Supply Association, Dynegy, Eastern Generation, NRG Energy and Calpine.
Exelon’s motion to dismiss a federal lawsuit filed last October challenging the New York ZECs was the subject of oral arguments March 29 (U.S. District Court, Southern District of N.Y., 1:16-cv-08164). Thus far, the court has approved Exelon’s request to intervene, as well as requests to file amicus briefs by the Natural Resources Defense Council, the Environmental Defense Fund, PJM Independent Market Monitor Monitoring Analytics and a group including the New York Public Interest Group.
Independent power producers filed suit in February alleging that the law authorizing Illinois’ ZECs violates FERC jurisdiction over the wholesale electricity market (U.S. District Court, Northern District of Illinois,1:17-cv-01164). (See IPPs File Challenge to Illinois Nuclear Subsidies.)
The judge in the case has delayed action on a motion for a preliminary injunction while he receives a full briefing on Exelon’s motion to dismiss the cases. On April 24, the court invited FERC to file an amicus brief on the jurisdictional question.
In February, the IPPs also sought expedited rulings against the ZECs in FERC dockets initiated over earlier disputes.
Docket EL16-49 had been opened in 2016 to challenge subsidies Ohio regulators had awarded to FirstEnergy and American Electric Power fossil fuel generators. In EL13-62, opened in 2013, the IPPs asked FERC to broaden the use of the minimum offer price rule in New York.
FERC has been without a quorum since February and thus unable to take substantive action on the cases.
At a FERC technical conference May 1-2, NYISO CEO Brad Jones told the commission that the ISO is working on a plan that would incorporate the social cost of carbon into generation offers and reflect it in energy clearing prices. Observers differ on whether FERC — expected to have at least two new commissioners nominated by President Trump soon — will approve Tariff changes to implement the initiative. (See Carbon Adder to Test FERC’s Independence, IPPNY Panelists Say.)
TMI’s Place in History
Whether or not Three Mile Island shuts down in 2019, it will occupy a special place in nuclear power history.
The partial meltdown of TMI Unit 2 on March 28, 1979, the most serious accident in U.S. commercial nuclear power history, effectively ended nuclear power construction for decades and resulted in major changes regarding emergency response planning, operator training and radiation protection.
Unit 2, owned by FirstEnergy, never reopened following the accident. Exelon purchased half of Unit 1 in 1999 and became sole owner of the plant in 2003. The plant received a 20-year extension in 2009, allowing it to operate until 2034.
Financial Repercussions
Exelon said it is taking a one-time charge of $65 million to $110 million for 2017, and accelerating approximately $1 billion in depreciation and amortization through the shutdown date, terminating capital investment projects and canceling 2019 fuel purchases and outage planning, impacting about 1,500 outage workers.
It said there could be as much as $25 million in additional charges in each of 2018 and 2019.
The shale gas revolution that has undercut the economics of coal and nuclear plants doesn’t appear to be ending anytime soon.
Economists Craig Roach and Vincent Musco say the revolution will continue, despite evidence that “there is a limit to how low natural gas prices can go and for how long low prices can persist.”
In producing their seventh annual looking-forward report for SPP’s Board of Directors, Bates White Economic Consulting’s Roach and Musco say low gas prices will continue “if and only if” technological improvements continue to delay the search for more hard-to-find gas reserves.
Roach said they see two risks to the continued shale gas revolution: underground and aboveground risk.
“The underground risk is whether the technology for shale gas production will continue to improve, so that even as the U.S. turns to more difficult reserves, the price will continue to fall,” Roach said in a presentation to the Board of Directors/Members Committee meeting last month. “That is happening. All new wells drilled last year are producing more gas on average than the wells drilled in previous years.”
In the report, Roach and Musco note “proven reserves reflect not only the physical abundance of natural gas reserves but also estimates of whether those reserves can be produced at prevailing market prices.”
The economists say data indicate a floor of roughly $3/MMBtu, based on a recent 16.6% decline in proven reserves. According to the U.S. Energy Information Administration, Henry Hub spot prices fell 42.4% in 2015, from $4.37/MMBtu to $2.62/MMBtu, and the agency predicted a further 6.1% decline in 2016. April’s spot prices were $3.10/MMBtu, up from $2.88/MMBtu the month before.
“The bet is that big-data analytics of the massive amount of data captured on actual gas and oil wells will be what sustains the technologic improvement needed to keep prices moderate,” Roach and Musco write.
Six states in SPP’s footprint — Arkansas, Kansas, North Dakota, New Mexico, Oklahoma and Texas — account for 46% of the country’s total natural gas proved reserves.
Low gas prices have led to an increased investment in combined cycle resources, which, along with subsidized renewable generation and flattened energy demand, has led to low market prices and the early retirement of baseload plants, the report says.
Concerns over Nuclear Generation’s Viability
“You have people saying this is the markets working. You also have people saying this isn’t the markets working, because prices are artificially low,” Musco said. “The markets aren’t capturing the full value of nuclear generation. They’re not capturing the full reliability value and the zero-emissions value of nuclear generation.”
| U.S. Department of Energy Quadrennial Energy Review; Bates White Economic Consulting
The report notes that reductions in nuclear capacity could increase carbon emissions, citing EIA data that 28% of all U.S. nuclear generation has recently retired or is at risk of retirement by 2030.
Nuclear generation has provided about 20% of the country’s energy each year and accounts for 60% of zero-emissions generation in the U.S. “Developers are turning almost exclusively to natural gas-fired combined cycle generation to replace retiring baseload capacity,” the report says, noting 100 GW of natural gas-fired combined cycle generation is under development. “However, it may also be argued that these retirements are part of the natural course of generation investments. As plants age, uneconomic plants give way for new, more efficient generation to take their place.”
That has already happened within SPP’s footprint. Last October, the Omaha Public Power District retired its 500-MW Fort Calhoun nuclear plant, saying it would save up to $994 million over the next 20 years. OPPD’s board blamed the retirement on low gas prices and load growth, among other factors. The plant’s operating license was good until 2033.
Fort Calhoun’s retirement leaves SPP with only two nuclear plants contributing to its generation mix: Nebraska Public Power District’s Cooper Nuclear Station (771.5 MW) and Kansas’ Wolf Creek (1,205 MW), which is owned by three separate companies.
Moody’s has reported that both plants “could face a ‘similar fate’” because they produce power at a cost that is often higher than SPP’s north pricing hub.
But Roach and Musco say they believe the plants won’t retire early, noting that Cooper and Wolf Creek have lower operations and maintenance costs than the smaller Fort Calhoun, their ownership has less available capacity to offset their loss and NPPD CEO Pat Pope expects a “‘capacity-short environment’ in SPP,” making the nuclear units a “good long-term strategy.”
The report notes efforts to address the problem through out-of-market payments in New York and Illinois, FERC’s Notice of Proposed Rulemaking on fast-start pricing, small modular reactors and other technological improvements.
It also warns of legal challenges to states considering “special action to ‘save’” baseload generation; the “direct impact” to SPP’s markets if FERC changes the way wholesale market prices are calculated and the threat posted to baseload generation as existing power purchase agreements expire.
Other Issues to Watch
The report also evaluates five other market and regulatory issues that could affect SPP’s markets or require the board’s special attention:
The changing utility model in the face of distributed energy resources and decentralization.
The U.S. Supreme Court’s ruling in cases involving PJM stakeholders and the states of New Jersey and Maryland, which held that the Federal Power Act “‘provides FERC with the authority to regulate wholesale market operators’ compensation of demand response bids,’” and other jurisdictional issues.
Lessons from the 2016 Electricity Policy Modernization Act, which died because of unresolved differences between the House and Senate versions but nonetheless raised legislative concerns over the “catastrophic consequences of long-term power outages.” Future legislation could include provisions on grid hardening and security and provisions related to markets and distributed energy resources, the report says.
The outcome of the Trump administration’s plan to undo the Obama administration’s Clean Power Plan. Because the Supreme Court has already ruled that EPA has the authority under the Clean Air Act to regulate carbon emissions, some observers say Trump can’t repeal the CPP without providing a replacement, such as a carbon tax.
Electric vehicles. Although EVs have not gained significant market share to date, the authors say the SHEAM model — shared, electric, autonomous mobility — can significantly reduce their payback period.
The report says while DER are not an “existential threat” to the grid, they are “likely to challenge generation-owning utilities in the production of electricity and could also emerge as alternatives to traditional grid investments.”
While the report was Roach and Musco’s seventh for SPP, it’s their first for Bates White Economic Consulting. The previous reports were done with Boston Pacific, which joined Bates White’s energy practice in November.
WILMINGTON, Del. — Mike Bryson, PJM’s vice president of operations, announced at last week’s Markets and Reliability Committee meeting that a scheduled vote on new pseudo-tie provisions would be postponed because of ongoing negotiations with MISO.
The proposal, developed through the Underperformance Risk Management Senior Task Force, would make deliverability requirements uniform for resources within and outside of PJM’s footprint and require feasibility studies for all pseudo-ties. Existing pseudo-ties would have five years to conform to the deliverability standards for internal resources.
Coal Replaced by Gas and Nuclear in 2020/21 BRA
PJM’s Jeff Bastian reviewed the Base Residual Auction results from May 23, noting that coal-fired generation cleared about 3,450 MW less than last year while gas and nuclear increased 3,700 MW and 1,500 MW, respectively.
“Here we see the reduced offerings of resources that might have a hard time because of their intermittency meeting the CP,” Bastian said.
Roy Shanker, an industry consultant, asked about negative megawatts of capacity transfer rights in the MAAC locational deliverability area, which cleared roughly $9.50 higher than the rest of the RTO at $86.04. The negative CTR megawatts mean there’s less load paying for the capacity in that region than there is capacity receiving the LDA’s price, Bastian said.
“[It’s] a function of that area’s share of the peak load forecast, which is a disconnect completely from the way the load is represented at the clearing of the auction, so you can have that kind of an outcome,” he said.
Exelon’s Jason Barker asked PJM to develop a written explanation of how CTRs were calculated to describe how negative megawatts can occur.
Bastian noted that the Duke Energy Ohio/Kentucky LDA, which cleared about $54 higher than the rest of the RTO at $130, was modeled individually “due to potential for deactivations in that area,” which might reduce the amount of power potentially deliverable to the LDA below the amount PJM feels is required for reliability.
“We find it prudent to model them from a reliability perspective,” he said, noting that it’s been done before in the PPL, BGE and ComEd LDAs. Of the three, only the ComEd LDA has ever separated from the rest of the RTO, he said.
American Electric Power’s Dana Horton asked how 119 MW of solar could clear as Capacity Performance, given that the sun usually isn’t shining during the morning and evening daily demand peaks in winter, when resources are most likely to be called. This auction was the first year in which all resource offers must comply with CP rules that require year-round availability and impose stricter nonperformance penalties if units fail to be available.
“The sun does shine in the winter,” Bastian said. “There was a recognition by the resource owners that there’s more risk involved with offering solar, so that the annual quantity is significantly lower than what those resources were required to offer in the past.”
Greg Carmean, the executive director of the Organization of PJM States Inc., asked if all nuclear units cleared, but Bastian declined to address the specific unit results. Barker confirmed for attendees that not all nuclear plants cleared, apparently referencing the company’s Three Mile Island, which the company announced earlier had not cleared for the second year in a row.
New Black Start Units Will Have New Annual Revenue Requirements
Stakeholders endorsed by acclamation changes to the annual revenue requirements for black start units. PJM and its Independent Market Monitor had previously come to an agreement on the time periods for member submission of data and review by the Monitor. They also agreed on having the revenue go into a non-interest-bearing account for each unit until its costs have been approved, at which point the RTO will conduct a true-up. (See “PJM to Review Black Start Prior to New RFP,” PJM Market Implementation Committee Briefs.)
The move comes as PJM prepares for its second request for proposals on black start units, which is scheduled for 2018 for projects to be available in 2020.
PJM Defends Interest in Paying for Frequency Response
Stakeholders endorsed by acclamation a problem statement and issue charge on analyzing generator requirements for primary frequency response, but not before renewing debate over compensation.
FERC issued a Notice of Proposed Rulemaking last November that would require primary frequency response for all new units except for nuclear plants. The NOPR did not address compensation. At previous meetings, the Delaware Public Service Commission’s John Farber has challenged PJM’s plan to investigate compensation and requested language be added to the problem statement and issue charge that allowed it only “if appropriate or necessary.”
“The intent is to ensure that it’s not a given that compensation is required,” Farber said on Thursday, responding to an inquiry from Public Service Electric and Gas’ Gary Greiner about why the text was added.
PJM staff reiterated the RTO’s desire to study whether units should be paid for maintaining primary frequency response capabilities.
“Back at the [Operating Committee meeting] in the fall, PJM made a statement about how we didn’t think compensation was necessary,” Bryson said. “We’re clearly more open minded about that now, and the wording of the issue charge is intended to imply that.”
Stakeholders eventually agreed on discussing potential compensation mechanisms and recommending compensation changes “if appropriate or necessary.”
FTRs to Get a Longer Perspective
Members endorsed by acclamation a proposed problem statement and issue charge to consider changes to long-term financial transmission rights modeling.
PJM’s Regional Transmission Expansion Plan looks out up to three years into the future in ordering upgrades, but approved projects aren’t captured in FTR analyses because they are only able to capture information on a six-month horizon.
“It is concerning to PJM that today, the current process is not capturing these upgrades. Because what this means to us is that they’re not fully transparent to the market participants,” PJM’s Asanga Perera said.
In the documents, PJM guaranteed that FTR-capability allocations would be made “without violating firm transmission customer priority rights.”
Other FTR changes developed in response to the FERC order impacting the annual revenue rights and FTR process also were endorsed during the meeting, though not without some modifications.
PJM requested endorsement for Manual 6 revisions, which prompted Mike Cocco of Old Dominion Electric Cooperative to request that the phrase “no longer viable” describing transmission paths be clarified.
Monitor Joe Bowring questioned PJM’s planned changes for the FTR forfeiture process.
“I would ask that you give it more thought,” he said.
Steve Lieberman of American Municipal Power followed Bowring’s comment with a motion to defer a vote on that language until next month. (The Monitor is not a member and could not make the motion on its own behalf.)
Stakeholders worked on the proposal, and PJM’s Brian Chmielewski returned later in the meeting to seek endorsement of the revised package. Per Bowring’s request, the forfeiture changes were removed, he said, and “no longer active” was substituted for “no longer viable,” along with a definition of the phrase that matched the definition in the Tariff.
Stakeholder Approvals
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 14D: Generator Operational Requirements. Revisions to develop requirements for solar generation facilities, in compliance with FERC Orders 828 (Requirements for Frequency and Voltage Ride Through Capability of Small Generating Facilities), issued July 21, 2016, and Order 764 (Integration of Variable Energy Resources), issued June 22, 2012. (See FERC Issues Ride-Through Requirement for Small Generators.)
Manual 36: System Restoration. Revisions developed in response to a periodic review.
Manual 13: Emergency Operations. Attachment E updated with 2017/18 load forecast and Mid-Atlantic load shed allocation information; Attachment F updated with 2017/2018 load shed capabilities and allocation percentages. The data in the attachments affects only transmission owners and has been validated by them.
An updated charter for the Incremental Auction Senior Task Force, which was created in response to a problem statement by Direct Energy that was approved by the MRC in November 2016. The revisions reflect an increase in scope resulting from a problem statement by NRG Energy on replacement capacity that was approved in March 2017. The revisions set a target for completing work and making recommendations to the MRC by January 2018. (See “Stakeholders Approve Variety of Actions,” PJM Markets and Reliability and Members Committees Briefs.)
MISO’s Steering Committee recommended that all but one of a handful of the Independent Market Monitor’s oft-repeated recommendations be included on the 2018 Market Roadmap as potential market rule changes.
Most of the recommendations have already been brought up in Market Subcommittee meetings or are part of past State of the Market reports.
MISO’s 2016 stakeholder redesign process dictates that for issues to be discussed in stakeholder meetings or added to the Market Roadmap list, they must first be submitted to the Steering Committee for a committee assignment. The Market Roadmap is a prioritized and tracked list of market revision goals that stakeholders and the RTO agree to pursue in stakeholder meetings.
The Steering Committee made the decision to move the following recommendations forward during a May 24 conference call:
Establishing regional reserve requirements and cost allocation through expansion of a 30-minute reserve product. MISO stakeholder relations staff member Justin Stewart said the issue might be too similar to a project already on the Roadmap that will create short-term capacity reserves, so the Steering Committee added the Monitor’s recommendation to the existing project candidate.
Changing the day-ahead margin assurance payment and real-time offer revenue sufficiency guarantee (RSG) payment rules and performance incentives to reduce gaming. The Monitor last year suggested some wind generators were deliberately over-forecasting to collect more RSG payments; the issue is expected to surface in this year’s State of the Market report. (See IMM Report Highlights Outages, Wind Over-Forecasting.) Stewart said the issue was similar to an existing Roadmap project to tighten thresholds on uninstructed deviations from dispatch orders, which is currently in the software development phase. Steering Committee members nevertheless assigned the Monitor’s suggestion new candidate status.
Creating a method for validating wind suppliers’ forecasts and using the results to alter dispatch instructions if needed, and improving forecasting incentives by modifying deviation thresholds and settlement rules. The two wind recommendations were added to an existing Roadmap candidate covering dispatchable intermittent resource modifications.
The one recommendation not added to the Roadmap was that MISO consider the economic cost of congestion, not just reliability, before granting planned outages. We Energies’ Tony Jankowski said the issue has existed “for over 10 years.”
The Monitor’s suggested operating reserve demand curve in blue. | Potomac Economics
“You’re venturing down a road here of what’s acceptable congestion or excessive congestion. … I don’t see this as being a simple Roadmap item,” he said.
Other stakeholders agreed to table the issue, with some predicting the topic will be raised again in the next State of the Market report. Last month, MISO stakeholders took up a separate outage issue, debating whether resources on extended outages should be barred from participating in future Planning Resource Auctions. (See MISO May Bar Units on Extended Outage from Capacity Auctions.)
The deadline for submitting candidates for consideration in the 2017 Market Roadmap project selection was May 11. Market improvements submitted after the deadline will be considered for prioritization in the 2018 Market Roadmap process.
ANCHORAGE, Alaska — State policies, market forces and technological advancements will continue the decarbonization of the electric industry regardless of the fate of EPA’s Clean Power Plan, current and former utility regulators said last week.
“I think the Clean Power Plan is pretty much dying,” Doug Little of the Arizona Corporation Commission said during a panel discussion on environmental policy in the “aftermath” of the CPP at the annual meeting of the Western Conference of Public Service Commissioners last week.
“It’s only a question of how it’s going to die. Right now it’s on life support. The question in my mind is, over the next several months, will the EPA pull the plug on the life support and see if it lives in any form, or will they drive a stake through its heart?”
Arizona on Path to Compliance
Little said what happens to the CPP under the Trump administration will make little difference to his state, which opposes implementation of the policy.
The final rule from EPA was “actually something that was achievable” and the state’s utilities “did a tremendous job” of incorporating the emissions targets in their integrated resource plans, Little said.
“And, they’re not, in my view, going to essentially take that whole planning process that they spent the last two years working on and just throw it away,” he said. “The direction that they’re going to continue to take is the direction that they’ve been planning to take over the last couple years.”
Tim Echols of the Georgia Public Service Commission echoed Little’s take.
“To continue with Doug’s analogy about the hospital, I really think the Clean Power Plan is going to die — [but] not from the stake. I think it’s going to die from a lack of payment on the hospital bill. And they’re going to have to unplug it because in the regulatory hospital, not everybody gets service regardless of the situation in the emergency room,” Echols said.
The “non-payment” is the Trump administration’s proposed 31% cut to the EPA budget, Echols said.
“I don’t know how they do corporal punishment in Alaska or Hawaii, but I think President Trump is taking the EPA out behind the woodshed, putting them in timeout, whatever you want to call it,” Echols said. “And you know what? That’s not unusual for a president to make those kind of decisions. Think about what President Obama did to the [Nuclear Regulatory Commission] and to Yucca Mountain when he got elected.”
Political, Practical Concerns in Georgia
Already speaking of the CPP in the past tense, Echols said that he had two problems with the plan, one political and the other practical.
The political issue: that the CPP would have turned the appointed head of Georgia’s Environmental Protection Division (EPD) into an “energy czar.”
“Now I’m not appointed by the governor, nor are my four colleagues, and this was going to put the EPD administrator essentially in charge of the energy plan for the state,” Echols said. He noted that Georgia’s rural electric cooperatives are nonprofits “that don’t take their orders from the EPD,” leaving the burden for compliance on the state’s major investor-owned utility, Georgia Power.
Echols’ practical concern: “How it picked winners and losers. The big winner, of course — natural gas.”
To comply with the rule, states would be forced to close coal-fired plants. That — along with the trend of nuclear plant closures — would leave the power sector exposed to increase gas prices in the future, Echols contended.
“Personally, I’m glad the EPA’s in timeout. I’m not saying I don’t like clean air. I’m not saying I don’t value clean water. But this agency went way too far, and the president is sending a message, and frankly I think it’s the right message.”
Robert Kenney, vice president of state regulatory relations at Pacific Gas and Electric, California’s largest utility, said he could grasp both sides of the CPP debate.
“California has been very explicitly, vocally and unabashedly supportive of the Clean Power Plan. PG&E in particular has been vocally supportive of the Clean Power Plan. And I think that’s probably not surprising when you think about California’s position relative to taking steps to combat climate change,” said Kenney, a former Missouri regulator.
PG&E is ahead of schedule in meeting California’s 33% by 2020 renewable portfolio standard. Including hydroelectric and nuclear, the company’s portfolio is already 70% greenhouse gas free, so “the Clean Power Plan wasn’t viewed as a barrier,” Kenney said.
“Now contrast that to my experience in Missouri, where 80% of our generation was coal-fired, and the Clean Power Plan presented significant challenges,” Kenney said. “Many of the utilities that I regulated were vocally opposed to the Clean Power Plan on a variety of different legal grounds and on practical economic grounds.”
Those utilities were faced with possibly having to strand coal-fired assets in which they had invested billions to comply with EPA’s Mercury and Air Toxics Standards. That, said Kenney, was “difficult to get your brain around” as a regulator.
“I think what you will see in the aftermath of the Clean Power Plan is that states will continue to individually determine how [they] are going to deal with climate change depending on the particular state,” Kenney said.
Low gas prices in Missouri are already leading to the retirement of some of those coal-fired plants, regardless of the CPP, a development Kenney expects to continue.
Lorraine Akiba of the Hawaii Public Utilities Commission noted that although her island state is exempted from the CPP, the state’s attorney general has weighed in to support the plan against court challenges. Hawaii has enacted the most ambitious RPS in the country — 100% by 2045.
She predicted there will be “big fights” in Congress over the CPP and the EPA budget.
“This is what democracy is about. You know, last time I looked, we’re not an oligarchy and not a dictatorship. That’s the beauty of democracy. You see four different commissioners up here, with four similar but different viewpoints,” Akiba said.
Market Forces
With or without the CPP, the panelists agreed, market forces will continue the drive away from coal and toward gas and renewables.
“What really is affecting the direction towards renewables — and the direction away from some of the fossil fuels like coal — is sub-$3 gas,” said Little, who also touted the fact that his state enjoys more than 300 days of sunshine a year, making it fertile ground for the continued expansion of utility-scale solar.
Still, Little said that he’s “very concerned” about what FERC and the wholesale markets will do to “more properly value” baseload resources such as coal and nuclear to ensure grid reliability.
“I’m going to be interested to see what happens after my friend Rob Powelson and Neil Chatterjee get onto FERC and see how they’re going to address this with some of the changes in the market,” Little said. (See related story, No Fireworks for FERC Nominees at Senate Hearing.)
Kenney said technological advances are key drivers of both the market forces and environmental policy leading to decarbonization. Included among those advances: the improvement in natural gas fracking techniques and advances in PV solar cell production that has dramatically reduced costs.
“We’ve got technological advances that are giving us the tools to” execute low-carbon policies, Kenney said.
Akiba said she agreed that market forces will help determine the future. “I disagree with some of my colleagues that coal is coming back. Coal’s never coming back. Coal’s not economically viable for this country,” she said.
The fight against climate change will continue outside D.C., Akiba argued.
“States are the leaders in this. Cities are the leaders. And I shout out to Atlanta, Ga.,” Akiba said, referring to Echols’ home state. “The City Council and mayor there just adopted a 100% renewable portfolio standard for their city.”
Akiba also encouraged the conference to consider the economic benefits of reducing GHG emissions, saying “the rest of the world is going to decarbonize regardless of the rhetoric coming out of Washington, D.C.”
“There are opportunities for economic growth in renewable energy technology, new developments in electrification of transportation [and] alternative transportation. If we let that opportunity go, China is right there.”
Proclaiming that he wanted to get in his “2 cents” as a former politician, panel moderator Norman Rokeberg of the Regulatory Commission of Alaska offered some sobering personal observations of climate change in his state.
“Alaska is an oil and gas state. It pays the freight up here,” Rokeberg said. “As a result, it’s been difficult to not favor the use of fossil fuels, particularly natural gas. We have 305 trillion cubic feet of natural gas stranded on our North Slope.”
He turned to his point.
“I do want to take this moment to make clear and declare that climate change and global warming is real, and you see the signs of it everywhere in this state.”
Rokeberg listed the evidence: the recorded warming of the Arctic, which is melting sea ice and increasing acidification of the ocean, affecting Alaska’s fisheries; melting permafrost undermining the foundations of the state’s roadways and infrastructure; and a changing habitat in which more plants and shrubs are growing in Arctic areas.
“I’m a gardener — a green-thumber — and I’ve lived in Alaska all my life,” Rokeberg said. “And in the last 25 years, I’ve seen the growing season extend as much as two to four weeks — that is to say from approximately four months to five months in a short period of time. That’s pretty extraordinary when you think about it.”
Rokeberg then took off his politician’s hat and replaced it with that of a regulator.
“It’s real, but make your own decisions about causation, or things like that,” he said. “We don’t need to get into that — not as regulators.”
WESTBOROUGH, Mass. — ISO-NE is working to adopt clustering methodology, already used by every other ISO/RTO in the country, to speed the development of new transmission capacity, particularly to help free wind power trapped in Maine.
Transmission bottlenecks that prevent Maine’s wind generation from reaching load centers in Massachusetts and Connecticut could be relieved by allowing large and small generators to pool their interconnection requests, Al McBride, director of system planning, told the Planning Advisory Committee on Wednesday.
Mars Hill Wind Farm in Maine
McBride presented a Maine Resource Integration Study that showed how generators in the western and northern parts of the state could combine their interconnection applications and thus share costs on required upgrades. The grid operator could also analyze the combined interconnection requests in the same system impact study (SIS).
Interconnection Queue Backlog
ISO-NE has experienced a persistent backlog of interconnection requests in Northern and Western Maine, where several thousand megawatts of proposed resources have requested interconnection. In March, the RTO said it would not issue a competitive solicitation for the proposed Keene Road market efficiency transmission upgrade because the cost would be greater than the production savings. (See ISO-NE Nixes Keene Road Tx Upgrade.)
The proposed clustering methodology comprises two phases. In the first phase, the RTO will identify the initial designs of cluster-enabling transmission upgrades (CETU) in the regional system planning process. In the second phase, the RTO will conduct the cluster SIS to study the interconnection of the individual projects, together with the identified CETU.
New England is going to be looking at applying the clustering methodology to both AC and HVDC solutions. One speaker expressed concern that having two options would mean neither would reach critical mass, saying, “Sounds like you could have two undersubscribed” solutions.
Driven by the Wind
Wind resources looking to be included in such a cluster will have to join the transmission interconnection queue by about August. The study proposes that transmission owners prepare cost estimates by the PAC meeting in June, after which ISO-NE will calculate cost allocations and issue a draft report for comment.
As is currently the case, none of the shared or individual interconnection transmission upgrade and facility costs will be incorporated into regional transmission rates.
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In June 2015, the American Wind Energy Association petitioned FERC to initiate a rulemaking process to address “complex, time-consuming technical disputes” in the interconnection queue process that “undermine the ability of new generators to compete.”
In response, FERC last December issued a Notice of Proposed Rulemaking that would change the pro forma large generator interconnection rules to increase certainty and transparency for new resources (RM17-8). (See FERC Proposes Changes to Interconnection Rules.)
New Circuits
The Maine Resource Integration Study assesses new 345-kV AC transmission circuits that could connect to the areas with the largest number of interconnection requests. Evaluations include interconnecting with, or bypassing, existing lines and substations.
The New England Power Pool Participants Committee in February supported Tariff changes for the proposed interconnection clustering methodology. Two or more interconnection requests requiring common new transmission infrastructure would trigger the clustering methodology.
Participants in a cluster would be allocated a percentage of costs for shared upgrades and assume sole responsibility for facilities needed solely for their project.
WESTBOROUGH, Mass. — New England will have only enough natural gas capacity to supply about half of its gas-fired generation in winters 2025 and 2030 in most scenarios, according to an analysis presented to the ISO-NE Planning Advisory Committee on Thursday.
Mark Babula, ISO-NE system planning manager for resource adequacy, said the study showed the region will have sufficient pipeline and LNG capacity to supply all the gas generation with capacity obligations during the summer. But in the winter — when generators must defer to firm gas heating customers — the region won’t have sufficient capacity under most circumstances to run all the gas generation that could be economically dispatched.
“When we’re talking about dispatch, what we’re looking at from the natural gas system perspective is meeting the contractual requirements to the [local distribution companies],” said Michael Henderson, ISO-NE director of regional planning and coordination. “That then gives you some extra gas available that can potentially serve natural gas-fired generation. It’s just different looks at how much natural gas-fired generation can be brought on.”
The ISO-NE study considered six natural gas system topologies and six “resource expansion” scenarios to determine whether there is sufficient “spare” gas for electric generation after meeting all firm customers’ needs:
Installed Capacity: All gas-fired generation with capacity supply obligations — a summer focus that represents the upper band of gas consumption by the electric sector. Even under the minimum gas infrastructure case, there is enough spare gas to fuel all gas-fired generation in the summers of 2025 and 2030, but there is only enough spare gas in the winters to serve about half of the gas-fired installed capacity.
Dispatched Capacity: Gas-fired dispatched capacity requirements on the winter peak gas day, when only a portion of installed gas capacity is needed to serve electric demand.
Energy Generation: Whether there is enough gas to satisfy the maximum hourly electric energy production by gas-fired generation on the summer and winter peak gas-days. The analysis found sufficient gas for all summer generation needs. For winter 2025, however, there would be sufficient gas for only 6.8 to 9.6 GW of generation, representing 42 to 59% of the projected installed capacity. By winter 2030, the gas could run between 5.3 and 10.1 GW — as little as one-third of the installed capacity.
Only one of six resource expansion scenarios (“Renewables Plus”) meets the dispatched capacity and energy generation requirements for winters 2025 and 2030, even assuming the “maximum gas infrastructure” — reflecting pipeline expansions, increased peak shaving by LDC, and LNG from offshore and ENGIE’s Distrigas terminal in Everett, Mass.
“In the summertime, we’re good. There’s actually leftover gas: We could actually run another 12,000 to 15,000 MW, there’s so much excess pipe available,” Babula said. “When you get into those polar vortex sort of days, we often hear from generators that have just been called by the gas pipe to get back on their ratable take and shut off the valve.”
Babula pointed out that the analysis studied only winter and summer peak days. ISO-NE is also conducting a Fuel Security Analysis that will quantify the operational risks of insufficient fuel for the entire 90-day winter period. ISO-NE on May 22 published a summary of the analysis, which is expected to be completed this fall.
While the RTO’s analysis looks at the system’s maximum, short-term capability, the ISO-NE study will determine how often the system likely to be stressed during the winter under different scenarios.
LNG’s Role
LNG from Distrigas, the Canaport terminal in Saint John, New Brunswick, and offshore floating storage regasification units are critical for meeting the peak gas-day requirements of the electric sector, according to the study. Without these gas supply sources, approximately ~1.5 Bcfd (~214,300 MWh/d) would be taken out the market.
Management consultant Richard Levitan asked whether the floating storage wouldn’t better be classified as a commodity, considering how inflexible the arrival of LNG carriers can be. Babula said that in the past couple years there have been “ships at the buoy” on most peak gas days, so they included them in the study.
[EDITOR’S NOTE: An earlier version of this article mistakenly said the analysis was conducted by the New England Power Pool. It was conducted by ISO-NE.]
Six Resource Expansion Scenarios
The resource expansion scenarios were:
S1 = RPS + Gas: Physically meet renewable portfolio standards and replace generator retirements with natural gas combined cycle units.
S2 = ISO Queue: Physically meet RPS and replace generator retirements with new renewables and clean energy.
S3 = Renewables Plus: The region retires older generating units, physically meets all state RPS and adds renewables/clean energy, energy efficiency, solar PV, plug-in electric vehicles and storage.
S4 = No Retirements (beyond FCA 10): Meet RPS with new resources under development and use alternative compliance payments (ACPs) for shortfalls. Add natural gas units.
S5 = ACPs + Gas: Meet RPS with new resources under development and use ACPs. Replace all retirements with natural gas units.
S6 = RPS + Geodiverse Renewables: Scenario 2 with a more geographically balanced mix of on/offshore wind and solar PV.
MISO and PJM are evaluating eight proposed interregional market efficiency projects, but a supplemental project by American Electric Power could undermine most of the proposals.
MISO and PJM received three upgrade and five greenfield proposals for three congested flowgates ranging from $1 million to $198 million.
Proposals were due at the end of February on interregional projects for constraints MISO and PJM previously identified. (See “2017 MEP Identification Underway,” FERC Signals Bulk of NIPSCO Order Work Complete.)
MISO and PJM will evaluate the proposals’ benefits based on the first 15 years of service, benefit-cost ratios and the cost split between RTOs, Eric Thoms, MISO manager of planning coordination, said at a May 23 Joint and Common Market meeting. AEP-Exelon, NextEra, Northern Indiana Public Service Co., AEP-NIPSCO, WPPI Energy and Northeast Transmission Development submitted proposals, most offering 138-kV projects and a few submitting 345-kV solutions.
All but two of the project proposals focus on the Olive–Bosserman constraint near the western Indiana-Michigan border. Transource Energy also submitted an interregional proposal to correct congestion along the southern Indiana-Ohio border with a new 138/345-kV substation and lines, and NIPSCO presented a new 138-kV line proposal to relieve congestion along the northern Illinois-Indiana border.
Complicating matters, AEP also announced plans for a supplemental project — a project type funded wholly by the transmission owner and therefore not requiring PJM approval — that diminishes the severity of the Olive–Bosserman constraint.
AEP would increase voltage and reroute nearby PJM circuits dating back to the 1930s, with two new 138/120-kV distribution stations to replace lower-voltage stations. The project is still in conceptual stages, AEP said.
PJM staff said the AEP project would relieve some of the congestion on Olive–Bosserman but that the interregional proposals could still provide benefits. MISO and PJM have yet to study the effects of the supplemental project on the six interregional proposals.
At a May 26 Interregional Planning Stakeholder Advisory Committee conference call, NIPSCO’s Miles Taylor asked if the supplemental project would be included in the RTOs’ evaluations of the interregional proposals. PJM interregional planning manager Chuck Liebold said PJM will put the project into a base case scenario if AEP decides to pursue the project. Stakeholders reminded RTO staff at the meeting that developers spent a lot of time and money on the interregional proposals, expressing concern that they could be negated by AEP’s project.
“This [supplemental] project is happening to get attention now because of its impact on interregional projects. We get many, many supplemental projects all the time,” said Liebold, adding that RTO staff has no control over which are built.
The RTOs hope to have preliminary benefit numbers on the interregional projects by the end of June.
Project evaluation will continue for each RTO individually and in the IPSAC through the end of September. Selection of the interregional projects is expected to begin in the fall.
Thoms said that if any projects arise out of the two-year interregional process, they will be sent before the RTOs’ boards for approval by December.
Meanwhile, MISO has asked FERC for an 18-month extension to settle on an internal cost allocation approach under the commission’s directive last year that the RTO allow interregional market efficiency projects as low as 100 kV (ER16-1969). Stemming from a 2013 NIPSCO complaint, FERC’s order also directed MISO to remove its $5 million cost floor for interregional projects with PJM. (See FERC Signals Bulk of NIPSCO Order Work Complete.)
VALLEY FORGE, Pa. — PJM’s Planning Committee on Wednesday held its first special session on cost caps and other cost-containment provisions for competitive transmission bids. The RTO expects that any recommended procedure changes that are identified by the sessions will be incorporated in the new Manual 14F: Competitive Planning Process, which received its third “first” reading at the Markets and Reliability Committee meeting last week.
At the initial meeting, PJM provided several examples of cost-recovery and cost-containment mechanisms that have been proposed. Stakeholders indicated an interest in a standardized lexicon for cost-containment descriptions to aid in comparing project proposals.
Ruth Ann Price of the Delaware consumer advocate’s office urged keeping the process simple and argued for allowing very few exemptions to cost caps.
Sharon Segner of LS Power suggested that there’s a role in the discussion not only for FERC, whose Order 1000 opened up transmission development to competition, but also for the regional planning organizations to encourage cost containment proposals.
Following a technical conference in June reviewing the first five years under the order, the commission asked for comments in response to a series of questions on cost-containment provisions (AD16-18). (See FERC Calls for Post-Conference Comments on Order 1000.)
FERC asked for information on how transmission providers compare proposals with and without cost-containment provisions; whether it should provide guidance or requirements on the use of such provisions; suggestions for ensuring the transparency of evaluations; and whether there should be standardization of cost-containment provisions or exclusions of certain costs to facilitate comparison of proposals with differing containment provisions. The commission also asked what types of performance-based rates it could accept to reduce “asymmetrical risk.”
The next big question for PJM’s initiative is to determine if the focus should be on capital costs or annual revenue requirements. Stakeholders noted that PJM’s focus has historically been on capital costs.
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Through PJM’s 13 competitive windows since 2013, about 18% of 650 proposals included cost-containment provisions. Of those, two projects were selected.
Cost caps have been more common in other regions. Of 12 competitive windows including CAISO, SPP and MISO, 54% of the 56 proposed projects and 55% of the selected projects included cost-containment provisions.
The committee’s next special session is scheduled for July 18.
