MISO can use PJM’s technology-specific reference levels for market mitigation in its 2017/18 capacity auction, FERC has decided.
The commission’s Dec. 28 order said MISO’s use of PJM’s numbers “strikes a fair balance between reducing the burden of demonstrating and verifying facility-specific reference levels, and allowing a market participant to select the default technology-specific avoidable costs that best reflect its actual avoidable costs” (ER16-833-003).
Reference levels are intended to represent the non-fuel costs of operating different types of generation resources. Similar to a cost-based offer in the energy market, they will be used as a resource’s capacity offer when a capacity seller fails MISO’s market power tests.
MISO’s proposal was in response to FERC’s December 2015 ruling that the RTO’s use of estimated opportunity costs for exporting power into PJM resulted in excessive mitigated cost levels. (See FERC Orders MISO to Change Auction Rules.)
The commission ordered MISO to set the initial reference for offers into the capacity auction at $0/MW-day. Because the commission said the $0 default might generate more requests from capacity suppliers to establish facility-specific reference levels, the commission called for the technology-specific defaults to reduce the need to verify costs on a unit-by-unit basis (EL15-70, et al.).
MISO’s staff and Independent Market Monitor agreed to base the mitigation levels on PJM’s avoided cost numbers because the generation technologies in the two RTOs are similar and PJM’s values are already FERC-approved. (See MISO Moves Forward on Auction Design; Seasonal Filing Delayed Again.)
MISO’s approach diverges from PJM on several points, including use of the monthly Consumer Price Index to update values rather than the Handy-Whitman index. Because PJM’s figures do not include defaults for wind and nuclear generators, MISO developed its cost estimates based on data from the Energy Information Administration and the Nuclear Energy Institute, respectively.
MISO also will not include the 10% “adder” PJM uses to offset the uncertainty of estimating costs three years into the future. The commission rejected NRG Energy’s request that MISO be required to use the adder. Unlike PJM’s three-year forward auction, FERC said, MISO’s prompt auction does not require the same safeguard.
FERC also mandated separate values for multi-unit and single-unit nuclear resources, despite Exelon’s comments that the two values were not materially different.
FERC ordered MISO to review the reference levels every three years, rejecting the RTO’s proposal to update values only after PJM updated its own numbers. FERC said MISO’s review of its avoidable costs “should not be contingent upon the review schedule of another regional transmission organization.”
FERC’s order also approved MISO’s proposal that market participants intending to retire or suspend a unit must use either retirement- or mothball-based default avoidable costs, respectively. FERC said market participants wishing to take advantage of the retirement-specific values must have already submitted a notification of retirement to MISO. However, since MISO only included retirement-based and not mothball-based values for nuclear and wind units, FERC ordered the RTO to provide wind and nuclear mothball-based avoidable costs or explain why they should be exempted.
New England policymakers hope to reach agreement in 2017 on revised market rules to accommodate state clean energy policies, as three states seek to complete renewable procurements and Massachusetts readies for a new solicitation.
Although Donald Trump’s election threatens federal initiatives to reduce carbon emissions, New England is moving ahead with its plans to decarbonize through power purchase agreements, infrastructure improvements and potentially tighter emission caps under the Regional Greenhouse Gas Initiative.
Massachusetts, Connecticut and Rhode Island, which issued a joint solicitation combining their purchasing power, hope to file PPAs with state regulators in the spring, now that a temporary injunction sought by a small developer who challenged the program has been lifted. (See New England States Move Toward Renewables Contracts.)
While the initial contracts are for a modest 460 MW, Massachusetts is expected to issue another request for proposals for 2,800 MW in the spring. The state’s Energy Diversity law, enacted last summer, directs its electric distribution utilities to enter contracts for 1,600 MW of offshore wind and 1,200 MW of renewables, likely Canadian hydropower, over the next decade. (See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.)
Daniel-Johnson Dam and Manic-5 Generating Station | Hydro-Québec
Separately, Connecticut has selected 25 small clean energy and energy efficiency projects totaling 402 MW to negotiate PPAs with the state’s two electric distribution companies.
Transmission
In December, the region saw the nation’s first offshore wind farm — Deepwater Wind’s 30-MW project off Rhode Island’s Block Island — begin commercial operation. But without other, larger offshore projects to count on, importing Canadian hydropower appears to be the quickest solution for the states seeking to maintain momentum in emissions reductions.
Delivering that power will require major new transmission lines. The New Hampshire Site Evaluation Committee is expected to rule on the application by Northern Pass developer Eversource Energy in September. Opponents want the entire 192-mile route of the 1,090-MW line buried. The developers have proposed only 60 miles underground.
Two other transmission projects would import Canadian hydropower via cable buried under Lake Champlain. TDI New England’s Clean Power Link received a presidential permit in December to allow construction. Anbaric’s 400-MW Vermont Green Line is awaiting approval. All three transmission projects are expected to respond to the Massachusetts solicitation.
IMAPP
Meanwhile, the New England Power Pool’s Integrating Markets with Public Policy (IMAPP) initiative, launched last summer, is trying to find ways wholesale market rules can accommodate state policies without compromising reliability or dramatically increasing costs.
Meeting these goals has proved a daunting challenge. Officials had hoped to develop an action plan by the beginning of December that could be presented to ISO-NE for action in early 2017, but now they don’t expect to do so until late in the first quarter at the earliest.
Proposals within the IMAPP collaborative have included various methods of pricing carbon. A carbon adder would be technology-neutral and provide market signals to both supply and demand while also creating a revenue stream for the states. There is also a proposal for a two-tiered Forward Capacity Market, with one reserved for clean energy resources. (See Markets vs. Climate Goals the Subject at NECA Conference.) Any market rule changes would require FERC approval.
Also considering rule changes is RGGI, which is conducting its quadrennial Program Review. Falling prices in the nine-state compact’s CO2 allowance auctions have renewed calls from environmentalists to tighten emission limits. Allowance prices dropped to $3.55 in December, the lowest in three years and about 53% lower than a year ago. Many stakeholders say the states should reduce the cap on emissions by 5% annually from the current 2.5%. (See RGGI Carbon Auction Prices Drop 22%.)
Although New England has been a national leader in reducing carbon emissions, it would still need an additional 25% cut from 2015 levels to meet the 2030 targets under the federal Clean Power Plan. The CPP would cap emissions from new and existing sources at 29.1 million tons in 2030. In a report by ISO-NE, carbon emissions showed a slight uptick to 40.3 million tons in 2015 compared to 2014, likely caused by the closure of the Vermont Yankee nuclear plant.
Have Capacity Prices Peaked?
One worrisome development that seems to have abated is the concern about steeply rising prices in the capacity market.
Clearing prices in last February’s FCA fell to $7.03/kW-month from 2015’s $9.55/kW-month, a 26% drop and the first decline in four years. (See Prices Down 26% in ISO-NE Capacity Auction.)
ISO-NE is seeking 34,075 MW for delivery year 2020/21. About 34,505 MW of existing and 5,958 MW of new resources are qualified to participate.
Natural Gas Infrastructure
As expected, 2016 proved crucial in efforts to expand the region’s natural gas infrastructure, with two major gas pipelines projects falling by the wayside.
The 342,000-dekatherm Algonquin Incremental Market project was completed in December, but it mostly serves local distribution companies’ heating customers and did little to aid generators.
The Massachusetts Supreme Judicial Court effectively killed Spectra Energy’s Access Northeast when it ruled against a subsidy by electric ratepayers. (See Mass. Supreme Court Vacates EDC-Pipeline Contract Order.) The state’s legislature appears reluctant to codify the requirement. Other states that were ready to commit to shared costs for infrastructure were dependent on the Bay State taking a leading position.
Without ratepayer-mandated support in Massachusetts, the region’s largest state, major pipeline construction appears to be at a standstill.
President-elect Donald Trump may trash the Clean Power Plan and walk away from the Paris Agreement on climate change. Congress may undo the coal mining and fracking regulations the Obama administration issued on its way out the door. Rick Perry may neuter the climate scientists in the Department of Energy.
But while President Obama’s energy legacy is uncertain, there appears no reversing the generation shifts that have occurred since his first election in 2008.
Cheap natural gas and the falling cost of solar and wind power are likely to continue driving electric industry investments over the next four years regardless of whether the Trump administration is able to reverse Obama-era federal policies. And as they have in the face of Congressional inaction over climate change, many states will continue their own efforts to reduce carbon emissions.
Renewables produced 17% of electricity generation in the first half of 2016, up from 9% in all of 2008.
Natural gas added 70.1 GW of capacity between 2008 and 2015, 42% of the total, according to a report by the American Public Power Association. Wind was second with almost 56 GW (33%), while solar added 13 GW (7.8%). Coal added 19.1 GW (11.4%) of new capacity but also retired 42.9 GW over that period for a net reduction of 23.8 GW.
New Bosses for Federal Agencies
It’s clear that environmentalists will be playing defense for the next four years.
Trump’s nominees for cabinet posts, including fellow climate change skeptics Rick Perry as secretary of energy and Oklahoma Attorney General Scott Pruitt as EPA administrator, are certain to face tough questions at their confirmation hearings, but the out-of-power Democrats will be unable to block them by themselves. Because of Democrats’ change of the Senate filibuster rule in 2013, Trump will need only a simple majority in the upper house to win approval for any administration position or any judge excluding the Supreme Court — not the 60 votes to end debate as before.
How much Trump’s appointees will try to turn back the clock is uncertain. While Perry and Pruitt have joined Trump in rejecting a scientific consensus that carbon emissions are warming the planet, Trump claimed after the election to have an “open mind” on the issue. (See Trump Sends Conflicting Signals on Climate Change.)
Perry, who had called for the Energy Department’s abolition as a presidential candidate, will be expected by Republicans to sharply reduce its spending, particularly the controversial loan guarantee program. But the department also has supported carbon-capture projects essential to making “clean coal” more than a slogan. And while Perry was a friend to the oil and gas industry as Texas governor, he also presided over the state’s transmission buildout to support its wealth of wind power.
FERC
Although FERC has not traditionally been marked by partisan divisions, the agency will be reshaped by Trump’s election with Commissioner Norman Bay, a Democrat, likely to lose the chairmanship to a Republican. Commissioner Colette Honorable also is likely be replaced by a Republican after her term expires in June. The five-member commission has been all Democrats since the departures of Republicans Philip Moeller and Tony Clark. The president gets to appoint members of his party to three of the five seats and pick the chairmanship. (See CPP, FERC’s Bay, Honorable Among Losers in Trump Win.)
Because Republicans maintained their control of the Senate, Sen. Lisa Murkowski (Alaska) will remain chair of the Energy and Natural Resources Committee, the gatekeeper for FERC nominees.
Last month, state attorneys general from West Virginia and other anti-CPP states suggested Trump immediately issue an executive order directing EPA not to enforce the rule. Their counterparts from states supporting the CPP have vowed to fight a move to remand the CPP back to EPA before a court ruling.
State, Corporate Actions
Regardless of what happens with the CPP, utilities, major corporations and some states are likely to continue their efforts at decarbonizing the generation mix.
D.C. and several states increased their renewable portfolio standards in 2016: D.C. (50% by 2032); Oregon (50% by 2040); Rhode Island (38.5% by 2035); and New York (50% by 2030). In Ohio, Republican Gov. John Kasich last month vetoed a bill that would have made its RPS (12.5% by 2025) voluntary, saying the bill “amounts to self-inflicted damage to both our state’s near- and long-term economic competitiveness.”
According to the American Wind Energy Association, more than 80 companies, including General Motors, Amazon and Microsoft, have pledged to move to 100% renewable power. In addition to the “halo effect” of promoting their green credentials, the companies are also motivated by costs. For example, storage and information management company Iron Mountain signed a 15-year power purchase agreement for wind last year that it says will save it up to $500,000 in power costs annually.
Even some of the nation’s biggest coal-burning utilities are shuttering coal-fired plants and replacing them with natural gas and renewables. In announcing its third quarter earnings in November, for example, American Electric Power said it would add 5,400 MW of wind and 3,400 MW of solar power through 2033 through long-term PPAs (along with 3,000 MW of natural gas). No new coal.
Below is a status report on the changing generation mix since 2008 and prospects for the future.
Solar
2016 was a watershed year for solar, which for the first time will be the No. 1 source of new generation, according to the Energy Information Administration. EIA reported that the U.S. added more than 26 GW of utility-scale capacity last year, with solar (9.5 GW), natural gas (8 GW), and wind (6.8 GW) responsible for 93%. There were no new coal plants.
The U.S. trends are representative of those worldwide. Solar PV prices have fallen by about 70% since 2010 and are now cheaper than wind, natural gas or coal in emerging markets, Bloomberg New Energy Finance reported in December. In August, a contract in Chile priced at $29.10/MWh, about half the cost of coal.
BNEF says worldwide fossil-fuel use for electricity may peak within the next decade. “Renewables are robustly entering the era of undercutting” fossil fuel prices, BNEF chairman Michael Liebreich said.
Wind
U.S. nameplate wind capacity has tripled to more than 75 GW since 2008.
The first offshore wind farm, the 30-MW Deepwater Wind farm off Block Island, R.I., went into commercial operation in October.
Although offshore wind remains more than twice as expensive as land-based turbines, costs are expected to drop with more development and production economies. Massachusetts lawmakers have authorized the purchase of 1,600 MW of offshore wind by 2027. (See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.)
Last month, Norway’s Statoil bid $42.5 million for the right to develop almost 80,000 acres off Long Island, enough space to install up to 1 GW of turbines. The company said it will initially develop 400 to 600 MW. The Bureau of Ocean Energy Management has now leased more than 1.2 million acres and plans another lease auction off North Carolina in 2017.
Coal
Trump’s promises to “save” the coal industry won him votes in Appalachia, but there is scant evidence that any policy shift will bring jobs there.
Attorneys at LeClairRyan say Trump’s promise to remove the Obama administration’s moratorium on new coal leases on federal lands will help producers in the Powder River Basin of Wyoming and Montana.
Congressional Republicans are likely to invoke the Congressional Review Act in a bid to reverse the Interior Department’s Dec. 19 rule requiring coal companies to restore their land to its condition before mining began, an effort to prevent mining debris from contaminating streams. The act, which has only been used once in the past, could target any regulations finalized after May 30, according to the Congressional Research Service. (Also at risk of a CRA reversal is a Nov. 15 Interior rule requiring oil and gas producers to use “currently available technologies and processes” to cut methane flaring in half at oil and gas wells on federal and Native American lands.)
But none of these policy changes will be enough to reverse coal’s decline.
U.S. coal production is its lowest in three decades and three of the country’s biggest producers, Alpha Natural Resources, Arch Coal and Peabody Energy, have filed for bankruptcy.
More than 21 GW of coal generation retired in 2015 and 2016, largely as result of the Mercury and Air Toxics Standards, and EIA says another 14 GW is at risk of retirement by the end of 2028.
Nor is growth likely to come from exports, which fell for the third consecutive year in 2015. Through September 2016, exports dropped another 30% below the previous year.
The International Energy Agency predicts exports will continue to decline due to reduced demand from China and low-cost foreign supplies.
Prospects for new plants are fanciful. The levelized cost of a new coal generator with carbon sequestration — required under EPA rules finalized in 2015 — is about double the cost of new solar PV and wind, according to EIA.
Natural Gas
Coal has suffered from lower natural gas prices as well as competition from renewables. Since June 2008, Henry Hub prices have fallen from $12.69/MMBtu to an average of $2.49/MMBtu in 2016.
EIA said in December that natural gas production averaged 77.5 Bcfd in 2016, a drop of 1.3 Bcfd, and the first annual decline since 2005. EIA predicts production will rebound by 2.5 Bcfd in 2018.
Citing rising domestic demand, and increasing exports to Mexico and via LNG, EIA sees Henry Hub spot prices rising to $3.27/MMBtu in 2017.
EPA’s December report that improper fracking practices can cause groundwater contamination was blasted by industry and is unlikely to persuade the Trump administration to initiate tougher federal regulations. But it may provide ammunition for tougher state regulations that could increase production costs. (See EPA: Poor Fracking Practices Have Harmed Drinking Water.) Maryland is considering replacing a moratorium against fracking with regulations that industry says would be the most restrictive in the country.
Nuclear
The nuclear industry, which has seen five plants retire in the last five years, celebrated some wins in 2016, as state policymakers in New York and Illinois approved zero-emission credits to keep plants operating and the Tennessee Valley Authority completed its long delayed Watts Bar 2 nuclear plant.
Watts Bar 2 dedication | TVA
But nobody is talking any longer about a nuclear power “renaissance.”
The 1,150-MW Watts Bar 2 went into service in October, completing a project begun in 1973 and mothballed for decades.
Like Southern Co.’s Vogtle and SCANA’s V.C. Summer nuclear plants under construction, the TVA project was marked by the same kind of delays and massive cost overruns that stopped new plant construction following the Three Mile Island and Chernobyl accidents.
Fort Calhoun | NEI
The latest nuclear plant to go dark was the Fort Calhoun plant near Omaha, Neb. — at 478 MW the smallest in the U.S. — which closed in October, citing economic reasons. Fort Calhoun’s output is expected to be replaced by wind and natural gas.
State-backed ZECs may save the Clinton, Quad Cities (Illinois) and James A. FitzPatrick (New York) plants from imminent retirement, assuming the initiatives survive court challenges. But there will be no preventing the retirements of Oyster Creek (2019), Pilgrim (2019) or Diablo Canyon (2025).
In addition to cheerleading the state-backed ZECs, the Nuclear Energy Institute has launched an initiative to spread use of best practices to make the industry more compatible. NEI said the first year of its “Delivering the Nuclear Promise” identified more than $600 million in projected savings in 2016.
“Effecting an overall change in mindsets and culture is a huge undertaking but absolutely indispensable to the survival and success of our industry,” NEI Chief Operating Officer Maria Korsnick said. “We value the importance of safety and reliability and, while we maintain the high levels we have achieved, we also can focus on improving efficiency.”
Dynegy says it will sell generation in PJM and ISO-NE if necessary to address FERC’s market power concerns over the company’s acquisition of ENGIE’s power generation unit.
The commission conditionally approved the sale Dec. 22 but said the company had to mitigate its market power in the two regions’ capacity markets (EC16-93).
The commission’s order found the $3.3 billion acquisition for 9 GW of generation assets will not have an adverse effect on competition in NYISO, MISO or CAISO, nor in the PJM or ISO-NE energy or ancillary services markets.
Dynegy would acquire a 50% interest in the Bellingham Energy Center | NextEra Energy Resources
But FERC said it was concerned the transactions could harm capacity market competition in PJM’s Commonwealth Edison locational deliverability area and ISO-NE’s Southeast New England (SENE) capacity zone. FERC said that existing market power concerns in ISO-NE would be exacerbated by the acquisition absent mitigation.
The sale also includes the sale of the France-based ENGIE’s plants in ERCOT, which are not subject to FERC jurisdiction.
Dynegy and partner Energy Capital Partners proposed to buy 17 fossil fuel plants of ENGIE subsidiary GDF Suez North America (GSENA) and named the joint venture Atlas Power Finance. In June, Dynegy said it would pay $750 million to buy out ECP’s 35% stake. (See Dynegy Buying out Energy Capital’s Stake in ENGIE Deal.)
FERC found that the acquisition would increase the Herfindahl-Hirschman Index for the “highly concentrated” ComEd LDA — currently 2,021 points — by 49 points.
Although Atlas Power would not currently be a pivotal supplier in ComEd, the planned retirements of the Will County Generating Station (May 2020) and Exelon’s Quad Cities nuclear plant (June 2018) would reduce capacity available to bid in the 2020/21 Base Residual Auction by 2,223 MW in the LDA.
“Factoring in the 2,223 MW of planned retirements leaves an insufficient supply of unforced capacity available to meet the ComEd LDA minimum annual resource requirement, which means that Atlas Power’s capacity is needed,” FERC said. “With all other factors held constant, we calculate that Atlas Power will be pivotal in the ComEd LDA for the 2020/2021 Base Residual Auction.”
FERC in its merger order invited Dynegy to describe how the Elwood transaction would impact the mitigation analysis. The commission only said the Illinois legislation “may affect” Quad Cities’ status.
If the commission still requires mitigation, Dynegy proposed divesting generation units equal to or above the 327 MW it is acquiring in ComEd and using cost-based capacity market offer caps until generation is divested.
New England
In SENE, FERC said GSENA was pivotal before the transaction with approximately 1,273 MW of qualified capacity. After the acquisition, Dynegy’s assets in the SENE capacity zone will grow to 1,497 MW.
“Applicants argue that because GSENA is pivotal prior to the proposed transactions and Atlas Power will remain pivotal after the proposed transactions, the proposed transactions will have no adverse effect on competition. We disagree,” the commission wrote. “Being pivotal implies that a seller has the ability to unilaterally increase the market price, and the seller’s incentive to do so increases as it becomes more pivotal.”
FERC said mitigation was necessary through either a plant sale or a commitment to keep certain plants operating.
“Specifically, we are concerned with a seller’s ability to exercise market power in the ISO-NE Forward Capacity Auction when its resources enter or exit the market, and thus, applicants should tailor mitigation to address that concern. For example, applicants may consider, among other steps, divestiture of generation units or a commitment to keep resources in the ISO-NE capacity market for a specified period of time.”
Dynegy responded that it will divest generation equal to or above the 224 MW it is acquiring in SENE and would limit capacity bids in interim capacity auctions to no greater than the FCA clearing price until any divestiture. It also promised not to retire any units until the sales are completed.
The company asked for expedited approval by Jan. 30.
Public Citizen had protested the transaction because of two FERC investigations into allegations of Dynegy misconduct in a PJM 2015 capacity auction and a separate audit. (See Dynegy: No Evidence of Misconduct in Auction.) FERC said those issues were beyond the scope of its review of the acquisition’s effect on the public interest.
FERC ordered hearing and settlement procedures in a dispute over capacity obligations in an area of Northern Maine separate from ISO-NE (ER17-192).
The dispute concerns the Northern Maine Independent System Administrator, whose transmission system is not directly connected with the rest of New England and whose market participants are not subject to ISO-NE’s jurisdiction and do not participate in the New England Power Pool.
At issue is the ISA’s request to eliminate a requirement that market participants prove the deliverability for resources located outside Northern Maine but within the New Brunswick balancing authority area, of which the ISA is a part.
NMISA said the deliverability assurance requirement in its market rules is no longer needed because its rebuild of Line 691 and planned spring 2017 upgrade of the Tinker transformer at the New Brunswick-Northern Maine interface will eliminate the transmission constraint into the area.
The request was protested by ReEnergy Biomass Operations, which owns the 37-MW Fort Fairfield and 39-MW Ashland generating plants in Aroostook County, within the NMISA control area.
Ashland Generating Station | ReEnergy Holdings
ReEnergy contends that even after completion of the upgrade, as much as 140 MW of load in Northern Maine could be reliant on 98 MW of available transmission capacity from New Brunswick. It said the upgrade was required to support 74 MW of existing firm reservations, meaning the upgrade would only add 24 MW of additional firm transmission capacity. Eliminating the deliverability requirement would impact reliability and distort price signals, it added.
NMISA disputes ReEnergy’s calculations, saying its 140-MW load estimate includes Eastern Maine Electric Cooperative, which should not be counted because it is not connected to New Brunswick via the Emera Maine-New Brunswick interface.
It said that the total Emera Maine capacity requirement for summer 2016, including reserve margin, was 124 MW, below the 129-MW total summer transfer capability from New Brunswick to Northern Maine once the upgrade is complete.
The authority said ReEnergy opposes the changes because it wants to maintain a competitive advantage in the area. If the requirement were maintained, market participants would be incented to hoard firm transmission capacity, preventing other resources from competing in the market, it said. The authority’s position was backed by the Maine Public Utilities Commission, which also said it feared reduced competition and higher prices if the rule remained.
FERC’s Dec. 22 order accepted NMISA’s proposed change subject to refund but suspended it, saying it needed more information to resolve the factual dispute over how much capacity will be provided by the upgrade.
“NMISA has not demonstrated that the Tinker upgrade located at the New Brunswick-Northern Maine interface will relieve the constraint at this interface, or that capacity located inside and outside of the Northern Maine transmission system is capable of meeting Northern Maine’s peak load capacity requirements before and after the Tinker upgrade,” the commission said.
FERC has issued a deficiency notice requesting more information from PJM on its proposal to incorporate more seasonal resources under Capacity Performance (ER17-367).
PJM has until Jan. 22 to respond to the Dec. 23 notice, which asks for more detail and specific examples about its plan to integrate seasonal resources into capacity auctions and incorporate them into operational protocols. The proposal would relax the current prohibition on seasonal resources aggregating across locational deliverability areas. In October, the RTO angered some stakeholders when staff announced at the annual meeting of the Organization of PJM States Inc. that it was filing its proposal despite a lack of stakeholder consensus. (See PJM to Seek FERC OK for Seasonal Capacity Proposal.)
Unadilla Solar Project | Allco Renewable Energy
“The proposed [Open Access Transmission Tariff] revisions appear unclear as to how PJM will determine which Seasonal Capacity Performance Resource offers clear an auction and which do not, and how PJM will ensure least-cost capacity procurement,” the commission wrote.
It asked if offers will be put in auctions individually or paired with a resource from the opposite season with an aggregated offer price. FERC also asked how PJM’s optimization algorithm will compare seasonal and annual resources, at what price the algorithm would stop clearing seasonal resources and how it will break ties if multiple seasonal resources submit identical offer prices.
The RTO’s proposal would allow resources to aggregate beyond LDA borders, with unmatched resources moving up to the next LDA level until a match is found.
FERC wanted more detail on how PJM’s cross-LDA aggregation concept would affect operational procedures, noting that the current proposal allows a seasonal resource to clear an auction, be counted toward the reliability requirement of an LDA other than the lowest level one in which it’s located and receive a clearing price less than that of the lowest-level LDA.
The commission also asked how a resource could be subject to a performance assessment hour in the LDA where it’s located, but receive the clearing price and help with the reliability requirement for the LDA in which it cleared the auction. It wanted to know how PJM plans to apply performance-related charges and credits and what rates will apply.
FERC also asked if the RTO intends for fixed resource requirement capacity plans that include seasonal resources to have equal quantity of summer and winter resources.
The commission wondered why PJM created a way for summer demand response to offer into auctions, but not for winter resources. “Why does PJM propose to exclude a winter-period demand resource from participating as a seasonal Capacity Performance resource?” it asked.
FERC also showed interest the differences between seasonal resources, asking PJM to opine on whether resources from one season or the other make a bigger difference on system reliability. It asked about any documentation PJM has on the topic.
WILMINGTON, Del. — A proposed revision to credit requirements for financial transmissions rights participants received significant stakeholder debate before the Markets and Reliability Committee and withered under the scrutiny.
The proposal was supported by FTR holders who complained that the “undiversified credit adder” applied to net counterflow portfolios caused over-collateralization of some FTR portfolios. The proposal, approved by the Credit Subcommittee, eliminates the adder in exchange for increasing the historical adjustment factor in underlying credit calculations for historically counterflow paths from 10% to 25%.
The adder was created following the $52 million credit default by Tower Research Capital’s Power Edge hedge fund in 2007. Members agreed to review it following a 2013 survey of issues of concern to the Credit Subcommittee.
Exelon’s Sharon Midgley had complained at the Dec. 14 Market Implementation Committee meeting that the change would increase her company’s credit costs, but the committee approved the change 88-34. (See “Credit Limit Changes Pass Despite Exelon Objections,” PJM Market Implementation Committee Briefs.)
That changed in the sector-weighted vote at the MRC on Dec. 22, where it won a majority of only one sector (69% of Other Suppliers), scoring only a 1.25 out of 5.
Exelon’s Jason Barker criticized how the credit increases would be implemented, saying it would be taking large “chunks” of credit from overcollateralized portfolios and “peanut-buttering” it over other undercollateralized ones. “We think that the balance is certainly off,” he said.
“From a customer perspective, I think it’s difficult to take the chance as we know the facts today,” said Susan Bruce of the PJM Industrial Customer Coalition. “I’m not in a position to take a chance, but I’m willing to talk more about this.”
PJM’s Stu Bresler said the RTO “doesn’t have a dog in the fight” over whether members are willing to accept potential defaults. But he said it does have a long-term concern.
“Even if the members are willing to accept additional risk … we have to consider the effect and potential ramifications,” he said. “I think it goes beyond reputation. It goes to the confidence to participate in the markets if [a default] were to occur again.”
Under current rules, collateral held by PJM would have covered all of the $52 million in FTR net counterflow portfolio losses in 2007-8. Under a proposed rule change, only $8 million of the losses would have been covered, leaving PJM members to reimburse $44 million, according to stress tests by the RTO.
Opponents of the changes, including the Independent Market Monitor, preferred to maintain the current protections against events like the Tower default. “I’d prefer that something like that never occur again,” American Municipal Power’s Ed Tatum said. “I haven’t seen an upside for the stakeholders but for those who are performing these transactions.”
Bruce Bleiweis of DC Energy called the proposed changes “good policy” that “right-sizes” credit portfolios. He also questioned whether the incident that precipitated the changes could occur again given rule changes that have been implemented in the interim.
“We don’t think that’s an accurate stress test because we don’t think that the Tower portfolio would have occurred,” he said. Tower wouldn’t have taken the position because its bid collateral would be more than $35 million today, he theorized.
FERC rejected a request to rehear its order blocking Tariff changes that would have exempted PJM capacity resources from nonperformance charges under certain circumstances.
The commission’s Dec. 22 order said the challenge by the PJM Utilities Coalition — American Electric Power; Buckeye Power; Dayton Power and Light; Duke Energy Kentucky; East Kentucky Power Cooperative; and Virginia Electric and Power — “does not offer any information or arguments that are new to this proceeding and primarily reiterates arguments advanced in PJM’s prior pleading” (ER16-1336-001).
| PJM
The changes, approved by stakeholders following months of debate, would have exempted a capacity resource from penalties if it was following PJM’s dispatch instructions and operating at an acceptable ramp rate during periods of high load. The changes were designed to discourage generators from self-scheduling prior to a performance assessment hour in order to avoid nonperformance charges — behavior that PJM said would pose operational challenges and reliability risks.
The commission rejected the change in May, saying PJM had not shown that its operational concerns justified the proposal, which it said undercut Capacity Performance rules designed to ensure resources are available during a crisis. (See FERC Rejects Ramp Rate Exception in PJM Capacity Rules.)
The commission reiterated its conclusion in rejecting rehearing, saying “the existing incentives in the threat of a nonperformance charge and risk of losses due to self-scheduling were robust enough for resource owners to both properly maintain their units and follow PJM dispatch.”
Rejecting criticism over employee salaries and a lack of detail on other spending, FERC approved PJM’s requested rate increase, saying it was “adequately supported” (ER17-249).
The Dec. 22 order allows PJM to increase its composite rate from $0.3349/MWh to $0.36/MWh for 2017 and 2018, with a 2.5% annual increase in subsequent years through 2024, when the charge will reach $0.41/MWh. The first increase is effective Jan. 1.
The commission said that the financial statements questioned by Public Citizen are “subject to adequate independent review” by stakeholders on the Finance Committee and noted the committee may reject unjustified expenditures and direct refunds to ratepayers.
Public Citizen also complained that the RTO provided no support for its spending on outside services, which the group said may include expenses related to political advocacy. FERC did not address the advocacy question but noted PJM testimony that outside labor services “includes building and ground maintenance, utilities, outside legal fees and cybersecurity monitoring” and said it provided sufficient detail justifying the expenses.
“PJM has implemented cost-control measures, including reducing the number of full-time equivalent contractors, renegotiating telecommunications and utility contracts, expanding PJM’s vendor pool to increase supplier competition, increasing PJM employees’ share of medical insurance costs and modifying PJM’s retirement benefits,” FERC wrote. “PJM further supported the increased compensation levels, documenting that compensation levels were in line with industry averages, and identifying increased staffing requirements.”
The commission acknowledged PJM’s concerns that it needed to restore its depleting financial reserves.
“Nearly two-thirds of the estimated 7.5% increase in the 2017 stated rate proposed by PJM is to restore the reserve to its prescribed level of 6% of annual revenues, with a 2.5% annual increase in 2019 through 2023 and a 0.7% increase in 2024, while 2018 will see no increase,” the order read.
WILMINGTON, Del. — Just a month after approving changes that PJM and its Independent Market Monitor felt stripped away important market protections, the Markets and Reliability Committee approved new revisions to reinstate them.
The new revisions are similar to an amendment the Monitor and PJM had proposed for the original changes developed by Citigroup Energy. The amendment never received a stakeholder vote, however, because Citigroup’s proposal passed the MRC in November with enough support to avoid considering alternatives. (See “PJM, IMM Partner on Capacity-Replacement Revision,” PJM Market Implementation Committee Briefs.)
At issue is how quickly after a bid clears an Incremental Auction that the bidder can take credit for the purchase and flatten its position. Citigroup’s Barry Trayers said the change was necessary to allow his company to reconcile its books sooner and avoid excessive credit requirements.
PJM said the change to Manual 18 widened a loophole that allows participants to arbitrage price differences between the BRA and IAs by reselling the replaced capacity. The IMM had filed a complaint with FERC on the change, which several stakeholders credited for convincing them to reconsider their initial support.
The revisions were approved by a sector-weighted vote of 4.39 out of 5, winning near unanimous support from all sectors except for Other Suppliers. The IMM has since filed to withdraw its complaint with FERC.
The approved revisions included a friendly amendment from Mike Cocco of Old Dominion Electric Cooperative that requires PJM to respond to requests for early replacement capacity within 15 days.
Trayers attempted to defend his original changes, reading from a statement that carefully outlined his intentions and explained that the new revisions would reinstate the obstacles he had attempted to address in the first place. Trayers said an anomaly that can result in double counting of PJM participants’ capacity balances would require them to maintain collateral after they no longer have a position to collateralize. “The proposal here today would reinstate double counting,” he said.
Although Citigroup does not participate in the BRA or IAs, it provides receivables financing by purchasing the offsetting capacity positions and the future payment obligations of PJM, Trayers said. The change approved in November “does not alter the responsibility of all capacity market participants to meet their obligations with true physical capacity,” he said.
Task Force on Uplift Directed to Vote Again
Members directed the Energy Market Uplift Senior Task Force to seek consensus on ways to reduce uplift and address cost allocation concerns by revoting on five proposals that had previously received the most support.
While two proposals on uplift and volatility have received majority support, none of the more than 20 proposals on allocation has received such an endorsement.
Although the task force couldn’t agree on a path forward, PJM’s Dave Anders said the voting process indicated “overwhelming support for making a change.” He said several proposals successfully address the cost allocation issue but met resistance from stakeholders pushing for “backtesting” to determine how each package of changes would affect billings.
Anders said backtesting has been done on a few packages, but it would be “extremely complicated” for others. He urged members to focus on overall market design rather than how much each package is going to cost participants. But some stakeholders said they would oppose any reconsideration of the packages without some sort of backtesting.
Monitor Joe Bowring called for action. “There are some participants who have benefited from a delay, continue to benefit from a delay. It’s time to decide,” he said.
Others, including FirstEnergy’s Jim Benchek and Carl Johnson of the PJM Public Power Coalition, also urged the process forward.
“If we come out of this with nothing else, I would like to go to FERC with something that causes them to take action,” Johnson said. “I’m not sure it matters what we suggest to FERC. What matters is getting a [Section] 205 [of the Federal Power Act] action in front of them.”
After PJM committed to providing as much backtesting as possible, members approved directing the task force to revote on the top five packages. Its next meeting is Jan. 25.
Stakeholders Remain Skeptical of Campaign to Revisit CP
American Municipal Power’s Ed Tatum took to the MRC floor for what he noted was his “fourth first read” on a problem statement calling for a holistic review of PJM’s capacity construct.
For several months, Tatum has represented a coalition of stakeholders requesting a review. His arguments have often been met with ambivalence and a reluctance to tinker with the complex market, which is still incorporating the introduction of Capacity Performance requirements. (See No End in Sight for PJM Capacity Market Changes.)
The coalition took a month off after receiving substantial feedback in October, but Tatum said it decided to return to the MRC after being contact by RTO officials. “We got a call from PJM, and we answered the phone,” he said. The feedback resulted in several changes to the proposed problem statement and issue charge, including transferring the focus from addressing potential state public-policy action to generalized governmental action.
Stakeholders suggested a variety of potential revisions that might help gain their support, including word choice.
“I don’t mean to sound like a broken record … but [consider] approaching this from less of a defensive posture and thinking that the states are out to get us, because I don’t think that’s actually what’s going on,” EnerNOC’s Katie Guerry said. “I don’t think that’s a fair representation.”
James Wilson of Wilson Energy Economics suggested reviewing the ISO-NE and NEPOOL documents founding the Integrating Markets and Public Policy (IMAPP) process, which he said are more focused on trying to accommodate state policies.
PJM’s markets don’t reflect the costs of carbon emissions and some states might want to address it, he said. “To the extent that you accept that [carbon is harmful], then PJM’s markets aren’t efficient because they don’t reflect this externality, and what the states are doing is pushing things toward a more efficient result,” he said.
Others asked the coalition to better define its intended scope. “You’re saying, ‘Take everything we do here every day and change it,’” Gabel Associates’ Mike Borgatti said. “If we’re talking all of it, I’m not sure where I’d want to start.”
The Industrial Customers’ Susan Bruce questioned the problem statement’s timeline. “This is a lot of stuff, and to look at having deliverables [by] the third quarter of 2017, that’s ambitious.” she said.
Tatum acknowledged the additional feedback but expressed concern that the focus seems to be moving away from the proponents’ original intent. He solicited stakeholder help in making supportable revisions, but Exelon’s Jason Barker said the proponents needed to better clarify their goals. “We’re stepping on a slippery slope is all Exelon is saying,” he said.
Stakeholders Balk at Applying Tougher External Capacity Rules to Past Auctions
Stakeholders expressed concern that a PJM proposal tightening eligibility requirements for external capacity resources might violate FERC prohibitions on retroactive ratemaking.
The proposal, which won 68% support in a vote of the Underperformance Risk Management Senior Task, would require external resources to have firm transmission service with rollover rights from their native region and to meet “specific operational and market modeling requirements” to ensure that the resources can deliver energy without imposing congestion costs on PJM members.
Stakeholders expressed concern over PJM’s intention to apply the tightened requirements to capacity resources that have cleared in prior auctions. The proposal would allow existing resources that fall short to either build the transmission upgrades required to qualify under the new rules or to be relieved of their requirements without penalty.
“I think everybody should pay an awful a lot of attention to how this is being handled as far as grandfathering or not grandfathering” resource contracts, said consultant Roy Shanker. Calling it “horrible policy,” he said the proposal creates the potential to disqualify a cleared resource and reduce the amount of capacity cleared without adjusting the clearing price.
Other stakeholders, including Johnson and Barker, joined Shanker in voicing concern that it could result in retroactive ratemaking. They suggested that the rules be implemented going forward from the next BRA.
Bowring opposed “PJM’s continued inadequate approach to ensuring that capacity imports be substitutes for internal capacity resources,” including grandfathering existing long-term contracts with external resources and extending the current exceptions for two additional BRAs.
PJM had indicated it would seek votes of the MRC and Members Committee in January.
Changes to the residual auction revenue rights process received little discussion and were endorsed with one objection and two abstentions. (See “Stakeholders Debate ARR Changes,” PJM Market Implementation Committee Briefs.)
Members also endorsed by acclamation revisions to manuals 10, 13 and 14D that were largely administrative in nature. The Manual 13 changes were the result of a periodic review and included updating the Mid Atlantic Dominion primary reserve requirement from a static 1,700 MW to 150% of the area’s largest single contingency. It includes a note permitting the use of deliverable resources outside of the area to satisfy the requirement.
“It really just aligns it with the [rules for the] RTO,” PJM’s Chris Pilong said.
The Manual 14D changes align it with the planned changes to Manual 13 and include revisions to the fuel-limitation reporting section to update seasonal reporting procedures, add a periodic reporting process and remove details on real-time reporting. The reporting focuses on fuel-inventory and environmental-limitations issues. “The reason for the change to both manuals is to better clarify the reporting process,” PJM’s Augustine Caven said.
