Page 1337 – RTO Insider

January 3, 2017

CAISO Expansion in Question as EIM Grows

By Robert Mullin

CAISO rang in 2016 with a strong push to expand its operation into PacifiCorp’s sprawling six-state service territory, but the project hit a stumbling block by mid-year as skeptics called on the ISO to slow its regionalization effort.

A 2015 state law requires the grid operator and state energy agencies to explore ISO expansion to help California meet its 50% renewable energy mandate.

The ISO last year kicked off a set of initiatives considered to be “central” policy elements of expanding into a region with dozens of balancing areas subject to multiple state and municipal rules.

Those efforts — still ongoing — dealt with the complex and often contentious issues of allocating transmission costs, maintaining adequate regional resources and accounting for greenhouse gas emissions. (See CAISO Refines Cost Allocation Proposal for Expanded BA and CAISO Kicks Off Effort to Track GHGs Under Regionalization.)

But the most challenging initiative was the effort to develop governing principles that would assuage concerns about California dominating the policies and management of a Western RTO.

Particularly contentious is California’s requirement that the state’s utilities track carbon emissions from generation serving their loads in order to ensure compliance with emissions caps. CAISO’s provision of generation data is key to that effort, which means that every generator in an expanded ISO would be subject greenhouse gas reporting requirements in order to track deliveries to California — regardless of whether the unit is located in a coal-heavy state disinclined to impose such a requirement.

When industry participants across the West expressed concerns that an initial governance proposal threatened to compromise the energy policies of “non-California,” CAISO returned in July with a revised document that emphasized the preservation of state authority. (See Governance Plan Fails to Dispel Western RTO Concerns and Revised Western RTO Governance Plan Highlights State Authority.)

By late July, critics within California — fearing the loss of CAISO as an instrument of the state’s renewable and emissions goals — were calling for a slowdown in regionalization, saying that the ISO was moving too quickly to get a governance plan to the State Legislature before the end of its summer session. (See Governance Plan Critics Urge Slowdown of Western RTO Development.) Gov. Jerry Brown heeded their concerns, directing state agencies to take more time to develop a proposal. (See Governor Delays CAISO Regionalization Effort.)

While the ISO plans to submit a governance plan to lawmakers this winter, President-elect Donald Trump’s vow to cancel the Clean Power Plan is another roadblock for CAISO-led regionalization. Under the CPP, interior West states such as Utah and Wyoming would confront the requirement of sharply reducing carbon emissions from coal-fired generation, an objective made less costly by access to low- and zero-emission electricity made available through a regional market. With the Trump administration likely to pull the rug from under the CPP, coal-heavy interior West states contemplating an RTO will be less motivated to give ground to California’s environmental mandates in order to gain the emissions benefits of membership.

That, in turn, could prevent California legislators from signing off on a governance plan that risks the state’s ability to meet its goals.

“California will want to protect its environmental objectives,” retiring California Public Utilities Commissioner Mike Florio, a strong supporter of regionalization, told RTO Insider.

Ann Rendahl, commissioner with the Washington Utilities and Transportation Commission, said the success of regionalization will depend on how California’s lawmakers deal with the governance issue.

“It’s really in the hands of California,” Rendahl said.

EIM Accelerates Growth

The future looks brighter for the Energy Imbalance Market, the West’s only real-time energy market. Unlike in the ISO, members are not required to turn over control of their transmission and generator day-to-day participation is voluntary.

The market last year extended its north-south reach with the integration of Arizona Public Service and Puget Sound Energy, expanding membership to four balancing authority areas, in addition to CAISO. The two utilities began transacting in the market in October after what officials called a largely uneventful implementation. (See Smooth EIM Transition for Arizona Public Service, Puget Sound Energy.)

“I’ve been through three sets of transitions, and I would say that each one is getting smoother,” Mark Rothleder, the ISO’s vice president of market quality and renewable integration, said during an Oct. 5 meeting of the EIM’s governing body.

Another transition is scheduled for October 2017 when Portland General Electric will join the market, the last fall entry before the ISO moves to a spring implementation schedule to avoid overlap with annual market software updates.

The benefits of NV Energy’s December 2015 integration into the EIM became evident in early 2016, after CAISO officials observed that the increased transfer capacity between the ISO and PacifiCorp East unified what had previously been a fractured market; California had found a real-time export market for its surplus solar and avoided curtailing a significant amount of renewable generation. (See CAISO EIM Boosts Market for Renewables in Q1.)

Last year also saw announcements from four utilities that said they intend to join the EIM.

In April, Idaho Power signed an implementation agreement that would make it the sixth BAA to join the market in spring 2018. Inclusion of the utility will bring an additional 4,800 miles of transmission into the market while improving trading access to an area of Wyoming that renewable developers — including EIM pioneer PacifiCorp — seek to tap for wind projects intended to serve the West Coast. (See Idaho Power Inks Agreement to Join EIM.)

Seattle City Light is slated to become the first publicly owned utility to join the EIM after signing an implementation agreement in December. (See Seattle City Light Signs EIM Membership Agreement.) City Light’s membership is contingent on satisfying the concerns of the Seattle City Council, which asked the company to flesh out the findings of an EIM benefits study showing the hydropower-rich utility could earn an additional $4 million to $23 million annually as an exporter of the flexible ramping capability needed to smooth out intermittent renewables. (See Council OKs Seattle City Light Bid to Explore Joining the EIM.)

The Sacramento Municipal Utility District said in October that it would begin negotiations to join the EIM, with some of the six other members of the Balancing Authority of Northern California — all publicly owned — to follow, depending on the outcome of cost-benefit assessments. (See Sacramento Utility to Join EIM; Other BANC Members May Follow.)

CAISO and El Centro Nacional de Control de Energía (CENACE), Mexico’s grid operator, announced an agreement in October to explore having the Baja California Norte region join the market as the first non-U.S. participant. (See Mexico’s Grid Operator to Explore Participation in the EIM.) While the region has no transmission connections with the rest of Mexico’s grid, it does boast 800 MW of transfer capacity with California through two 230-kV links at the Imperial Valley and Otay Mesa substations, and also offers promising potential for wind energy development.

2016 also saw the EIM begin to chart a course more independent of the ISO with the appointment of the market’s governing body and a clearer outline of governance. (See CAISO Board Appoints Western Energy Imbalance Market Governing Body.) At the body’s first meeting, Chairwoman Kristine Schmidt noted that a decade ago, nobody in the industry would have believed that the West would produce an organized real-time market.

“We’re now seeing a regional market take shape in the West,” Schmidt said.

In December, EIM and CAISO leaders approved a guidance document that provides solutions to the overlapping authority between the ISO’s Board of Governors and the EIM governing body resulting from the EIM’s delegation of a portion of its authority over Federal Power Act Section 205 filings to CAISO. (See EIM Leaders OK Governance ‘Guidance’ Proposal.)

The document outlines how ISO staff should interact with the EIM, providing a schedule for notifying the governing body about ISO initiatives and laying out the processes by which body members and EIM participants will provide feedback on proposed policy changes.

“I think this is an important step forward,” CAISO board member David Olsen said. “It really helps to clarify the scope of responsibility of the EIM board.”

January 3, 2017

SPP Seeks to Manage Wind Riches, Improve Order 1000 Process

By Tom Kleckner

SPP and its stakeholders enter 2017 seeking ways to integrate the massive amounts of renewables in the RTO’s interconnection queue, while also completing the painful Z2 project, improving the Order 1000 competitive transmission process and implementing more sophisticated combined cycle modeling.

Expiring tax credits and reduced costs for renewable energy has led to a rush of generation projects that threaten to overwhelm RTO transmission planners.

Wind Rush

“We’re embarking on an era we’ve never seen before,” Mike Wise, chair of SPP’s Strategic Planning Committee, said during the RTO’s Board of Directors/Members Committee meeting in December. “We’re trying to figure out, one, how do we deal with the issue and, two, how do we take advantage of the issue at the same time?”

order 1000 spp wind power — Wise in the foreground with SPP’s Carl Monroe behind him | © *RTO Insider*

David Osburn, general manager of the Oklahoma Municipal Power Authority, agreed with Wise, saying, “It wasn’t very long ago we were arguing about how much wind might be on the system, and we’ve already blown through that.”

Whether or not the pun was intended, Osburn made his point. SPP has been able to add more wind to its system than many would have thought possible a few years ago, and now it looks to be facing the same issue with solar power.

SPP currently has 15,728 MW of installed wind energy with another 21,535 MW in the interconnection queue — adding up to more than half of the balancing authority’s coincident peak load (50,622 MW in July). The system set a new record for wind generation Friday with 12,141 MW, and for some hours in April, almost half of the generation came from wind sources. SPP expects to set new records in April 2017, with wind exceeding 60% penetration. (See SPP Coal Generation Continues Decline; Wind, Load Records Set and Wind Growth Causes SPP to Take 2nd Look at Tx Projects.)

3,000 MW of Solar Coming

The RTO currently only has 215 MW of solar energy on the system, but more than 3,000 MW of solar is planned. That has Board Chair Jim Eckelberger sounding the alarm.

“That’s what wind looked like 10 years ago, and solar is getting cheaper and cheaper and cheaper,” he said. “We’re going to have quite a need to refocus on the mechanics of the market to make this work, or negative pricing is really to going to have a long-term change in the way electricity is used in our footprint.”

SPP says all that wind generation has a high impact on system congestion. Wind energy also causes headaches for grid operators by not showing up during high demand — or by providing too much power during periods of low demand. Wind power on the margin resulted in 160 hours of negative clearing prices in 2016. SPP staff notes some wind farms are voluntarily curtailing their production because of low prices.

“We have to figure out a way to either use the wind, control for the wind or figure out a way to allow other folks in this country to get access to this wind,” Wise said. “This is really a dilemma … a growing dilemma.”

The problem is, when the wind picks up in SPP, it’s also picking up in neighboring MISO and ERCOT, dampening demand for imports.

But SPP can point to studies that show UHVAC networks and HVDC links could deliver surplus wind power to markets in the east, helping them meet renewable portfolio standards.

The Strategic Planning Committee created the Export Pricing Task Force last summer to evaluate the business case for exports and create a rate structure “to address the recovery of the incremental transmission and the underlying facilities necessary” to support exports. The group met twice in 2016 but has scheduled monthly meetings for this year. Its charter calls for making recommendations by the end of July.

If all the pending wind projects are brought online, SPP Manager of Operations Analysis and Support Casey Cathey told the committee, the lack of an export strategy might force the SPP Reliability Coordinator to allow more wind energy to sink within the balancing authority, while at times increasing curtailments.

Cathey’s team is also responsible for the 2017 Variable Generation Integration Study, which stressed the SPP system to a point of instability in analyzing the effect of high-wind/low-load scenarios on reliability. A workshop has been scheduled for Feb. 14-15 in Little Rock to discuss the study’s results.

spp wind power order 1000 — Iowa find farm after harvest | *Theodore Scott, Creative Commons*

“It’s going to fall on SPP to really figure out what we’re doing in the future and how we’re going to resolve this issue,” Wise said to the board and members. “I encourage all the great thinkers at your companies to be attentive to the issue … and help us come up with solutions, because this is not an easy task.”

Z2 Project Lingers

Accommodating and planning for more wind generation is not the only difficult task facing SPP in 2017. Members and stakeholders continue to work on improving the troublesome Z2 crediting process for network upgrades, which was a bone of contention for much of this past year.

Under Attachment Z2 of the SPP Tariff, staff was to assign financial credits and obligations for sponsored upgrades. However, staff had not applied the credits for years dating back to 2008, complicating the task of trying to accurately compensate project sponsors and claw back money from members who owed debts for the upgrades.

Staff and members agreed on a process to compensate everyone properly, but it wasn’t until November that staff was able to compile the historical data from 2008 through August 2016. Members will be invoiced almost $95 million in lump sum payments, with another $15 million billed in 20 installments through August 2021.

SPP CEO Nick Brown said last January that Z2 would be “the focus of the organization this year.” That will still be the case this year, as the Z2 Task Force will meet before January’s Markets and Operations Policy Committee to evaluate staff and stakeholder proposals to improve the process. SPP has proposed using incremental long-term congestion rights as one replacement for Z2 credits.

At the same time, the legal and regulatory battles over Z2 have just begun. In November, the Kansas Electric Power Cooperative became the first SPP member to pursue legal action over the Z2 revenue-crediting process when it filed a complaint with FERC. KEPCo said in its Nov. 22 filing that SPP’s direct cost assignment of approximately $6.2 million to it violated the RTO’s Tariff, the filed rate doctrine and the Federal Power Act. The complaint seeks relief from directly assigned Z2 obligations and a refund for payments already made.

Order 1000

Staff and members are also working to improve the RTO’s competitive bidding process under FERC Order 1000. The first go-round last year resulted in one competitive project being bid out, only to have it pulled for re-evaluation shortly thereafter.

The Competitive Transmission Process Task Force hopes to change that by offering recommendations this year to improve the process. The group has already modified documents and templates while reviewing the entire competitive bidding process. Two Tariff revision requests have already begun to wind their way through the stakeholder-approval process, and more could be on the way if the MOPC and board approve changes to the scoring criteria in January.

Enhanced Combined Cycle Modeling

SPP will see one of its first major projects since the Integrated Marketplace come to a conclusion March 1 when software allowing multiple configurations of combined cycle units goes live. With the new functionality, market participants can register and submit separate offers for each configuration, leading to a more economic commitment and dispatch of the resources.

Participants completed structured testing of the software in December. The technology also played a role in SPP’s successful timeline changes for coordinated gas-electric scheduling practices in September as a result of FERC Order 809.

January 3, 2017

FERC OKs MISO Use of PJM Cost Estimates for Mitigation

By Amanda Durish Cook

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.

January 3, 2017

New England to Charge Ahead on Clean Energy Makeover in 2017

By William Opalka

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.)

iso-ne clean energy canadian hydropower 2017 — 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.

Kinder Morgan halted its Northeast Energy Direct project in the spring, citing its inability to secure enough commitments from New England power generators to reserve capacity. (See Kinder Morgan Board Suspends Work on Northeast Energy Direct Pipeline.)

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.

January 3, 2017

Cost Trends Favor Renewables Despite Coming Policy Shifts

By Rich Heidorn Jr.

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.

Clean Power Plan

Pruitt is expected to lead the effort to dismantle the Clean Power Plan, though it’s uncertain how the new administration will accomplish its goal. (See CPP, FERC’s Bay, Honorable Among Losers in Trump Win.)

One question is whether the D.C. Circuit Court of Appeals, which heard arguments on legal challenges to the rule in September, will act before Trump is sworn in. (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)

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.

SPP and ERCOT broke wind generation records repeatedly through 2016, and SPP says it could manage wind penetration of 60%. (See related stories, SPP Seeks to Manage Wind Riches, Improve Order 1000 Process and ERCOT Looks to Incorporate DG, Improve Ancillary Services, RMR in 2017.)

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.

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.

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.”

December 29, 2016

UPDATE: Dynegy Files Mitigation Plan for Purchase of ENGIE Plants

By William Opalka

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.”

In its Dec. 27 response, Dynegy said changes in circumstances in Illinois since the transaction was first proposed make mitigation no longer necessary. It cited the sale of its 50% interest in the 1,350-MW Elwood gas generation plant approved by FERC in November and Illinois’ enactment of a subsidy to support nuclear power, which led Exelon to cancel its plans to close the Quad Cities plant. (See Illinois Lawmakers Clear Nuke Subsidy.)

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.

December 29, 2016

FERC Orders Hearing in Maine Dispute over Capacity Rules

By William Opalka

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.

December 28, 2016

FERC Wants More Detail on PJM’s Seasonal Capacity Plan

By Rory D. Sweeney

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.)

pjm ferc seasonal capacity performance resource — 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.

December 27, 2016

PJM Credit Adder Fails upon Heightened Review

By Rory D. Sweeney

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.

MRC Meeting at Chase Center, Wilmington, Del. | © *RTO Insider*

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.

December 27, 2016

FERC Upholds Berkshire Market-Based Rate Ruling

By Robert Mullin

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.