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 denied Berkshire Hathaway Energy’s request to rehear a ruling prohibiting the company’s subsidiaries from selling electricity at market-based rates in four neighboring balancing authority areas in the West.
The commission’s June 9 decision restricted Berkshire-owned utilities PacifiCorp and NV Energy and 19 other affiliates from offering power at market rates in the PacifiCorp East (PACE), PacifiCorp West (PACW), Idaho Power and NorthWestern Energy areas based on concerns about horizontal market power. (See Berkshire Market-Based Rate Sales Restricted in 4 BAAs.)
FERC denied the Berkshire Hathaway Energy request to rehear a decision that revoked the ability of the company’s subsidiaries from selling power at market-based rates in the IPCO, NWMT, PACE and PACW balancing authority areas.
In its Dec. 21 order, the commission rejected Berkshire’s contention that the June ruling had denied the company due process because of FERC’s failure to convey “newly announced standards for determining market power” ahead of the company’s initial “change in status” filing, which was triggered by the 2013 acquisition of NV Energy (ER10-2475, et al.).
“We clarify that the June 9 order did not create new criteria for obtaining or retaining market-based rate authority,” the commission said. “Rather, in the June 9 order, the commission identified areas where the [Berkshire companies’] analysis fell short of existing requirements and, where appropriate, provided suggestions for meeting the requirements.”
The commission did approve the Berkshire subsidiaries’ revised market-based rate tariffs filed in compliance with the June order and clarified that the companies are entitled to propose new cost-based rates for making sales into the four areas, rather than being limited to relying on default cost-based rates.
The commission also terminated the Section 206 proceeding on the matter.
In its June 9 order revoking market-based rate authority, the commission found that the Berkshire companies failed to provide reliable delivered price test (DPT) analyses rebutting the presumption of market power in the four balancing authorities.
FERC policy allows companies to submit a DPT after failing the indicative “pivotal supplier” and “wholesale market power” screens for initially assessing horizontal market power within a balancing area.
The DPT offers a company the chance to provide more granular market power assessment that factors in native load commitments to determine a supplier’s “available economic capacity” — energy available for offer in the open market.
The commission’s decision to revoke Berkshire’s market-based rate authority ultimately rested on what the commission called a “flawed” DPT analysis from the company. The commission pointed to Berkshire’s failure to calculate unique season and load levels for each of the four areas, instead relying on assumptions based on data for only the PACE area.
In its July 11 request for rehearing, Berkshire countered the commission’s findings by arguing that each of its 57 “unique” DPT analyses “was prepared in accordance with the commission’s previously announced requirements and each was similar in form and substance to” analyses the commission had previously approved. (See Berkshire Contests Market-Based Sales Restriction in West.)
“The [Berkshire companies] failed to provide any historical transmission data, eTag or otherwise, to corroborate the results of their DPTs as required by section 33.3(c)(6) of the commission’s regulations,” the commission responded in its Dec. 21 order. Furthermore, based on its own review of transmission data, the commission said it was unable to corroborate the DPTs.
The commission also noted its longstanding policy of requiring companies to compare actual trade patterns with DPT results.
“This is not a new standard or a higher threshold test; it is the obligation the commission has required for DPTs since 1997,” the commission said.
The commission also rejected Berkshire’s contention that it had failed to follow past practice by not allowing the company opportunity to correct mistakes in its original submittal.
“The [Berkshire companies] were given many opportunities to correct errors in their DPT,” the commission said, citing a Dec. 9, 2014, order describing “multiple deficiencies” in the supporting data for the tests. The commission pointed out that FERC staff met the Berkshire representatives to discuss that order.
The commission additionally dismissed Berkshire’s claim that the commission failed to make a “definitive finding” that the company possesses market power in all four regions before revoking market-based rate authority, as required under FERC Order 697. After failing the initial market power screens, Berkshire, not FERC, had the burden of proof, the commission said.
“If the commission cannot revoke market-based rate authority in areas where sellers fail to rebut the presumption of market power created by a failure of the indicative screens, then sellers could deliberately submit inadequate evidence for the commission to analyze and thus be allowed to keep their market-based rate authority in perpetuity,” the commission said.
The New York Public Service Commission turned aside numerous challenges to its adoption of a Clean Energy Standard and its subsidy for upstate nuclear power generators, rejecting 17 petitions for rehearing and/or reconsideration.
Most of the petitions were dismissed by the commission. Several others, regarding “eligibility issues” for some resources, warrant further investigation by the PSC but do not warrant rehearing, the Dec. 15 order said (15-E-0302).
The commission granted a petition by Exelon seeking the elimination of a condition related to its acquisition of the James A. FitzPatrick nuclear plant, noting that the sale has already been approved. (See FERC Approves FitzPatrick Sale to Exelon.)
The CES mandates New York to acquire 50% of its energy from clean resources by 2030 and seeks to further that goal by providing zero-emission credits to support nuclear plants, which were in danger of closing.
Generators and some environmental advocates said the ZEC program — which some critics say will cost more than $7 billion over its 12-year lifespan — goes beyond the authority granted to the PSC by state law. (See CES Under Attack on Multiple Fronts in Rehearing Requests.)
The commission disagreed, saying “the ZEC requirement the commission adopted in the CES order is the best way to preserve the affected zero-emissions attributes while staying within the state’s jurisdictional boundaries.”
Complaints that the ZEC program intrudes on wholesale markets under FERC jurisdiction were similarly dismissed. “As explained in the CES order, neither the ZEC requirement nor any other aspect of the CES program inappropriately intrudes on the wholesale market or interferes with interstate commerce,” the PSC said.
Tannery Island Hydroelectric facility | Ampersand Energy Partners
Owners of existing resources, including hydropower developers, said the CES order failed to properly measure their environmental benefits under the state-operated market for renewable energy credits. New large-scale hydropower projects are ineligible for ZEC payments under the order. Some smaller hydropower, wind and biomass resources built before 2015 that are eligible for smaller REC payments under previous state programs said they were in danger of closing because of extraordinarily low natural gas prices.
Staff has been directed to further study eligibility requirements, the order states, instead of waiting for a triennial review as established in the CES order in August.
The commission also dismissed petitions that claimed that state procedures were violated during the compressed time frame under which the ZEC program was open for public comment.
RENSSELAER, N.Y. — The NYISO Management Committee on Wednesday approved an agreement with PJM to end the 1,000-MW Con Ed-PSEG wheel next year while maintaining an operational base flow (OBF) of 400 MW that will be reduced to zero by 2021.
Consolidated Edison said it would not renew its contract with PJM when the current agreement expires next spring because it is no longer needed to deliver upstate power into New York City. But the OBF is needed to maintain system reliability in northern New Jersey, says PJM. (See “Con Ed-PSEG ‘Wheel’ to Reach 0 MW Baseflow by 2021,” PJM PC/TEAC Briefs.)
| PJM
The vote was unanimous with five abstentions, one from Public Service Enterprise Group.
“We don’t agree with PJM that the operational baseflow is needed,” PSEG’s Ken Carretta said.
NYISO COO Rick Gonzales declined to respond to that objection, which was raised repeatedly. “I’m not going to opine on what PJM has determined,” he said.
The wheeling service was implemented by modeling 1,000 MW flowing from NYISO to PJM over the JK (Ramapo-Waldwick) interface and from PJM to NYISO over the ABC (Hudson-Farragut and Linden-Goethals) interface.
Under draft language for the NYISO-PJM Joint Operating Agreement, the wheel will be temporarily replaced by an operational base flow — “an equal and opposite megawatt offset of power flows” over the Waldwick and ABC phase angle regulators to account for natural system flows over the JK and ABC interfaces.
Last week’s modifications more definitively set the size of the OBF and fixes the start and end date. “The initial 400-MW OBF, effective on May 1, 2017, is expected to be reduced to zero megawatts by June 1, 2021,” it says.
An annual review of the baseflow will be conducted starting next year, which then gives the grid operators two years’ notice to end it, unless they establish an earlier date.
PJM has said that the 2021 deactivation target materialized because it was the date that planning analyses determined the OBF was unnecessary. “With the projects that are expected to go into service, we aren’t seeing any operational need for an OBF,” PJM’s Paul McGlynn said at the Dec. 15 Transmission Expansion Advisory Committee meeting.
The revised JOA was reviewed Thursday at PJM’s Markets and Reliability Committee meeting. PSEG’s Alex Stern confirmed that PJM would clarify in the meeting minutes that the JOA can’t supersede the PJM transmission operators’ agreement.
A joint filing is expected at FERC next month with implementation starting May 1.
Con Ed decided in April to end the wheel following a dispute with PJM over the allocation of transmission upgrade costs. (See Con Ed-PSEG ‘Wheel’ Ending Next Spring.)
— PJM correspondent Rory D. Sweeney contributed to this article.
CAISO has kicked off an initiative to explore how it can procure resources equipped to automatically respond to disturbances in grid frequency.
The effort will examine implementation of a new market mechanism to compensate resources for providing primary frequency response — sending power into the grid within moments of a potentially destabilizing frequency event.
The new initiative is in response to NERC reliability standard BAL-003-1, which requires each balancing authority area (BAA) to carry sufficient capability to respond to a frequency event.
System operators seek to maintain the grid at a frequency of 60 Hz to maintain network stability. An uncontrolled drop in frequency creates the danger of cascading blackouts.
Under NERC’s standard, primary frequency response is the ability to respond to a deviation within about 20 to 52 seconds of occurrence. Such a rapid reaction requires that the resource automatically detect under-frequency and autonomously ramp its output without receiving a market signal or manual instructions from the ISO.
CAISO is seeking stakeholder input on developing a market mechanism to compensate resources for responding to frequency dips during the “primary” control horizon — just moments after the onset of the event.
While the initiative is primarily intended to help CAISO meet NERC’s requirement, the ISO hopes the effort will head off an issue expected to become more problematic as California moves to fulfill its ambitious renewable energy mandate.
“The ISO expects frequency response will worsen as nonconventional technologies increase,” Cathleen Colbert, senior market design and regulatory policy developer at CAISO, said during a Dec. 22 stakeholder call to discuss the initiative.
Nonconventional technologies typically have little or no inertial response to momentary changes on the grid; conventional generators have the ability to automatically vary their turbines’ rotational speed and output based on the pull of load. That built-in capability functions as a kind of damper for frequency excursions.
“The goal of introducing a primary frequency service would be, in the short term, to continue to support compliance with NERC’s frequency response requirement, which, without changes, will be more difficult in the long term as the generation mix changes to accommodate a renewable portfolio standard of 50% renewables by 2030,” the ISO said in an issue paper describing the initiative.
Last month, FERC proposed revising the pro forma generator interconnection agreements to require all newly interconnecting facilities, including renewable generators, to have primary frequency response capability (RM16-6). (See FERC: Renewables Must Provide Frequency Response.)
CAISO’s initiative will focus on whether the ISO should compensate resources for capital expenses associated with the equipment necessary to provide the service. It will also examine making payments for opportunity costs related to holding frequency response capacity in reserve and for operating expenses associated with providing response during an event.
Approved by FERC in 2014, BAL-003-1 requires each BAA to achieve specific performance measures to meet its “frequency response obligation” (FRO), which is calculated as the BAA’s portion of the overall obligation for the interconnection — referred to as the “IFRO.” (See FERC OKs Rules on Geomagnetic Disturbances, Frequency Response.)
The IFRO represents the minimum response needed to halt a decline in frequency resulting from the loss of two of the interconnection’s largest generators — the response necessary to head off reaching the “under-frequency load shedding” threshold of 59.5 Hz.
Based on an assessment of its generation and load relative to the rest of the Western Interconnection, CAISO says that its share of the region’s IFRO stands at about 23% — translating into 196 MW/0.1 Hz next year.
In 2015, CAISO determined that it would likely come up short of its obligation under NERC’s requirements, which took effect Dec. 1. To address the shortfall, the ISO filed Tariff revisions enabling it to enter annual contracts to acquire “transferred frequency response” — the transfer of frequency response performance across BAAs within an interconnection.
At the same time, the ISO committed to FERC that it would evaluate whether it could develop a market mechanism to cultivate a diverse set of resources to help the ISO meet the frequency response criteria.
The ISO is proposing a set of guiding principles for developing a primary frequency response market, which include:
Creating an environment in which the ISO fleet is positioned to provide sufficient frequency response;
Eliminating barriers to entry in order to allow all technologies to participate;
Producing price signals that incentivize adequate response; and
Ensuring compensation for frequency response-related capital investments if the capability becomes an interconnection requirement.
Stakeholders are being asked to consider whether the ISO’s existing ancillary services market generates sufficient compensation to enable the ISO to meet the NERC’s new reliability requirements.
The most significant argument in favor of developing a new market structure is that the ISO does not currently procure primary frequency response but must still meet NERC’s standard. The existing ancillary services market covers only the requisition of frequency regulation that qualifies as NERC’s “secondary” and “tertiary” control mechanisms following a frequency event — both of which respond to an explicit ISO market signal.
In addition to contracting for transferred response, the ISO relies on unloaded frequency response capability acquired through the current ancillary services procurement, Colbert said. However, resources procured during that process may not have the capability for a sufficiently fast response.
Additionally, the ISO has observed a “deteriorating trend” in its frequency response performance over the past two years when comparing its average capability with its obligation.
“We believe we have received guidance [from FERC] to explore other options,” Colbert said.
Stakeholders must submit comments on the issue paper by Jan. 12, 2017.
