FERC approved a CAISO Tariff revision expanding the definition of a “load-serving entity” to include organizations that purchase wholesale electricity to serve their own needs (ER17-218).
The ISO’s rules previously recognized as LSEs only those entities that sell electricity or serve load to end users, a description that covers utilities, federal power marketing agencies and community-choice aggregators.
CAISO’s LSE definition refinement eliminates a subcategory that previously covered California’s State Water Project, which will now fall under the newly expanded definition. | CDWR
The original definition also made a special provision for the State Water Project (SWP), a California agency that directly engages the wholesale market to cover its own energy requirements. The revision eliminates that subcategory, with SWP now covered under the newly expanded definition.
The ISO sought to broaden the definition to accommodate the San Francisco Bay Area Rapid Transit District (BART), which, like the SWP, serves its own load but did not meet the standard definition of an LSE. (See CAISO Issues Revised Proposal to Expand LSE Definition.)
BART’s transmission contract rights on Pacific Gas and Electric’s network, which predate the existence of the ISO, expire at the end of 2016. When those rights automatically convert to CAISO service, the agency will be exposed to congestion charges.
The definition change will permit BART to receive a free congestion revenue rights allocation in the ISO’s annual process in order to hedge the transmission costs of serving its load. The revised Tariff language also makes clear that BART — and any other entity choosing to serve its own load — will be subject to resource adequacy obligations.
| BART
“We find that the revised definition is a reasonable approach to encompass entities, such as BART, that are currently excluded but that nonetheless should be considered a load-serving entity, and avoids the need for CAISO to add carve-outs to the definition, as it initially did for State Water Project,” the commission said in its Dec. 30 ruling.
The revision also alters a provision requiring that any LSE must be authorized to serve load under California state or local law — deleting the reference to California. The change was intended to acknowledge the current membership of Nevada-based Valley Electric Association and to prepare the ISO for additional out-of-state members through regional expansion.
Fifteen years after it first opened, ERCOT’s competitive electric market is pretty much running on cruise control. It has ample low-cost electricity to meet Texas’ growing demand and continues to add renewable resources. And 2016 will go on record as having the lowest prices ever.
Sure, protocols always need tweaking, the ISO’s reliability-must-run practices still draw stakeholder complaints and there are congestion concerns in Houston, West Texas and the Rio Grande Valley. But otherwise, ERCOT enters 2017 with a grid those in power see as the envy of others.
“Nobody has a competitive market like ours,” Texas Public Utility Commission Chair Donna Nelson said during a July meeting. The PUC has regulatory oversight of ERCOT, and Nelson often trades quips during open meetings with her two fellow commissioners over the market’s success.
Load-weighted average wholesale prices for 2016 were less than $25/MWh, far below the 2008 high of $77.19/MWh. Average prices have stayed below $41/MWh in seven of the last eight years. Not surprisingly, customer complaints to the PUC fell to 4,835 complaints, down from 6,973 the previous year, according to the Texas Coalition for Affordable Power.
The ISO, which boasts more than 18,000 MW of installed wind capacity, set a new record for wind energy production Christmas morning with 16,022 MW.
With 7 million smart meters, the Texas Interconnection is also one of the more advanced grids around. “We’ve got a retail market that offers customers choice in a way that’s more mature and more fulfilled than any other retail market in the world,” ERCOT CEO Bill Magness said in November.
DER Focus
Much of the focus in 2017 will be on accommodating distributed energy resources and determining how those smaller power sources can be aggregated to predictably meet demand.
In preparation for the new year, ERCOT staff have been working to map the system’s smaller (greater than 1 MW that inject to the grid) registered distributed generation units and on a white paper addressing DER’s reliability. Both efforts are picking up on the work of the Distributed Resource Energy and Ancillaries Market (DREAM) Task Force, a two-year effort that ended last year with a report that made eight recommendations.
The ISO estimates it has 900 MW of DG in its competitive areas (which doesn’t include the cities of Austin or San Antonio). It expects DG to grow at 10% annually, which is why staff wants to account for the DER on the system in both competitive and noncompetitive areas.
“With an 80,000-MW system, that’s not a huge penetration at this point,” Magness said. “These resources don’t raise a long-term reliability issue — they’re not waving a red flag — but we expect to see a lot more, whether for environmental reasons or people wanting energy independence. If you don’t know you have a large cluster of DG, your load forecasts are not going to be right.”
Magness likes to joke about the Austin moving company that has the motto, “If we can get it loose, we can move it.”
“If we can see it, we can integrate it,” he says.
Ancillary Services
ERCOT is also looking to improve its visibility into ancillary services and inertia data. Its existing ancillary services framework was lifted from a market design developed in the 1990s, and staff and stakeholders have been working since 2013 to unbundle the services and improve the market’s ability to handle DG, fast-acting storage devices, smart-grid technologies and other new developments.
A staff proposal to separate responsive reserve service into fast-frequency response, primary frequency response and contingency reserve service categories did not receive sufficient stakeholder support to move forward. A Brattle Group report on these “future” ancillary services determined they would offer economic benefits “on the order of 10 times the [estimated $12 million to $15 million in] implementation costs.”
ERCOT currently spends about $500 million annually on these services.
The ISO could also face an RMR rulemaking (Project No. 46369) in 2017 from the PUC. The commission held a workshop on the practice in December, gathering feedback from market participants on how it might limit a practice that even Magness has acknowledged can be a “blunt instrument.”
Reliant Energy’s Bill Barnes, who failed to gain enough support this summer for a protocol change that would price RMR units at the end of the dispatch queue, said during the workshop that the process “indicates the market has failed to retain and attract sufficient resources to meet ERCOT’s reliability criteria. The best solution to RMR is to not have any.” (See “Board Rejects RMR Mitigated-Offer Appeal, Lets Stakeholder Process Move Forward,” ERCOT Board of Directors Briefs.)
Barnes, the PUC staff and other stakeholders discussed modifying the RMR-evaluation timeline, the ERCOT board’s approval of RMR agreements potential changes to the review methodology.
Currently, RMR units are subject to the same offer mitigation as other units.
The ISO this year should complete much of its technology “refresh,” a four-year, $48 million initiative updating its computer technology. The final three of the 11 refresh projects — remote access and two telecom efforts — are scheduled to begin in 2017. By the end of 2017, ERCOT will have updated its database servers and core network.
The project has already spent 40% of its budget, Magness said in December, and it is expected to come in under or at the $48 million target.
MISO’s 2017 will likely be filled with capacity auction changes, cost allocation debates, an updated interconnection queue and multiple transmission studies.
MISO spent much of 2016 reconciling the forward capacity market with the existing prompt capacity auction and utilities’ forward resource adequacy plans and bilateral contracts. “There was a rush to the finish line to file the Competitive Retail Solution,” Resource Adequacy Subcommittee Chair Gary Mathis said. “We’ll hopefully find out in early springtime” if the proposal passed FERC’s muster.
Assuming FERC approval, work to implement the forward auction alongside the prompt auction will continue through 2017 before the first bifurcated auction in April 2018 for the 2018/19 planning year.
MISO expects a FERC decision any day on its second attempt to reduce uncertainty and the amount of time it takes for projects to clear the interconnection queue. The late October filing proposes fewer restudies, optional “off-ramps” with fee refunds for withdrawing projects, a smaller initial milestone payment and subsequent milestone payments based on a percentage of upgrade costs. “It’s currently a two- to three-year process and is challenged by restudies,” said Jennifer Curran, MISO vice president of system planning and seams coordination.
If all goes as planned, queue changes will take effect in January. Although the new process has yet to be approved, MISO has begun to prepare for the transition, with all projects expected to follow the new rules after February 2017’s batch of interconnection applicants.
FERC rejected MISO’s first proposal in spring, telling the RTO it placed too much blame for the queue’s bottleneck on “speculative” projects and said its proposed milestone payments to move along the queue were prohibitively high (ER16-675).
Cost Allocation
MISO also will set aside some of 2017 to revise its cost allocation formulas for market efficiency projects and sub-345-kV economic projects. The RTO hopes to complete the revisions in 2017 and implement them by 2018, when Entergy’s integration transition period, which limits cost sharing in MISO South, expires. (See MISO Stakeholders Propose Changes to Market Efficiency Cost Allocation Process.)
“We all know cost allocation is a money issue where consensus is not likely to spring up like a flower,” outgoing MISO Director Judy Walsh said at the December Advisory Committee meeting.
“I think we’ve seen a lot of movement; no one is going to get what they want, but we are on a path,” Xcel Energy’s Carolyn Wetterlin replied.
North-South Bottleneck
MISO is also planning a study that will examine the benefits of building new transmission to supplement the constrained transmission interface linking the RTO’s North/Central and South regions. In January, FERC approved a seven-year settlement that stipulates MISO’s north-to-south flows using SPP’s transmission be restricted to 3,000 MW and 2,500 MW south to north. (See MISO Proposes Study to Measure Benefits of New North-South Tx.)
There’s “nothing so stark as the North-South constraint” to MISO system planners, Curran told the Markets Committee of the Board of Directors last spring.
The RTO will also embark on an ambitious long-term transmission overlay study looking at system needs under three future scenarios, with varying assumptions on carbon reduction targets, natural gas prices, coal generator retirements and renewables growth.
Beginning Jan. 31, the Economic Planning Users Group will review an initial set of transmission needs to design preliminary overlays, said Lynn Hecker, MISO manager of expansion planning. Long-term transmission needs are expected to be identified at the end of 2017. (See “Long-Term Overlay Study Scoped; MISO Asks for More Responses,” MISO Planning Advisory Committee Briefs.)
Competitive Transmission Development
Late last month, MISO selected LS Power subsidiary Republic Transmission over 10 other bids to build the Duff-Coleman 345-kV transmission project, the RTO’s first competitive project under FERC Order 1000. The work in Southern Indiana and Western Kentucky includes the construction of two substations and a 28.5-mile line connecting them. Republic will be delivering quarterly updates to MISO throughout 2017 on the $49.8 million project. (See LS Power Unit Wins MISO’s First Competitive Project.)
While that work progresses, the RTO’s stakeholders are expected to spend the first half of 2017 identifying improvements to the RTO’s competitive developer selection process.
IT Refresh Coming
| MISO
MISO, which estimates it will spend about $1.1 billion on information technology between 2015 and 2019, has hired consultants for another study to assess its aging system software. Results of the study will be reveal how well the RTO’s software can accommodate the effects of a changing resource mix, increased intermittent and behind-the-meter generation and increased combined cycle units.
MISO took time last month to reflect on its 15th anniversary of becoming an RTO. At the December board meeting, CEO John Bear noted that the RTO has grown from 21 employees in 2000 to about 900 in 2016.
“The beginning tested our tolerances. Without regular money coming in, it’s hard to see a path forward,” said Steve Kozey, senior vice president of compliance services and one of those hired in 2000. “In February 2002, when FERC approved our Tariff and MISO could start recovering costs on a regular basis, employees let out a sigh of relief because they knew from then on out, they could count on a paycheck each month.”
Coal-powered generation continues to decline in SPP’s market, accounting for only half the RTO’s total energy production this fall (September-November), according to the Market Monitoring Unit’s recently released State of the Market report.
Wind production and lower gas prices have combined to reduce the use of coal resources, which accounted for 60% of SPP’s energy production just two years ago. At the same time, wind energy has increased its share of production from 13% in fall 2014 to 20% in 2016.
Not surprisingly, coal resources only set real-time prices 37% of the time this fall, compared to 52% in 2015. Cheaper gas units (combined cycle and simple cycle) were marginal 53% of the time, with wind resources setting the price 9% of the time.
After record low prices in the spring, gas prices rose in the fall, with the average cost of $2.61/MMBtu at the Panhandle Hub, compared to $2.25/MMBtu in 2015. The real-time balancing market’s average LMP was $25.10/MWh, up from $19.98/MWh a year ago; the day-ahead market saw an increase from $20.73/MWh last year to $24.43/MWh this fall.
The report also noted virtual transactions have “steadily increased from year to year,” driven primarily by financial-only market participants. Financial players completed 2.1 million virtuals this fall, with resource and load owners accounting for just over 62,000.
SPP saw “marked” increases of 12.6% and 13.7% of load in October and November, respectively, bettering the previous high month of 10.8% last March. Virtual transactions as a percentage of load have increased from 7.1% two years ago to 11.7% in 2016.
The RTO filed the report with both FERC and the Arkansas Public Service Commission.
SPP Sets New Wind Generation, Winter Load Marks
SPP set a new record for wind generation Friday when the footprint cracked the 12,000-MW threshold for the first time, producing 12,141 MW. The latest record was its sixth in 2016 for wind generation, breaking the previous high of 11,305 MW on Nov. 17.
The RTO also set a new winter load peak of 40,323 MW on Dec. 19, marking the first time its winter load surpassed 40,000 MW.
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.
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.
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.”
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?”
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.
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.
MISO can use PJM’s technology-specific reference levels for market mitigation in its 2017/18 capacity auction, FERC has decided.
The commission’s Dec. 28 order said MISO’s use of PJM’s numbers “strikes a fair balance between reducing the burden of demonstrating and verifying facility-specific reference levels, and allowing a market participant to select the default technology-specific avoidable costs that best reflect its actual avoidable costs” (ER16-833-003).
Reference levels are intended to represent the non-fuel costs of operating different types of generation resources. Similar to a cost-based offer in the energy market, they will be used as a resource’s capacity offer when a capacity seller fails MISO’s market power tests.
MISO’s proposal was in response to FERC’s December 2015 ruling that the RTO’s use of estimated opportunity costs for exporting power into PJM resulted in excessive mitigated cost levels. (See FERC Orders MISO to Change Auction Rules.)
The commission ordered MISO to set the initial reference for offers into the capacity auction at $0/MW-day. Because the commission said the $0 default might generate more requests from capacity suppliers to establish facility-specific reference levels, the commission called for the technology-specific defaults to reduce the need to verify costs on a unit-by-unit basis (EL15-70, et al.).
MISO’s staff and Independent Market Monitor agreed to base the mitigation levels on PJM’s avoided cost numbers because the generation technologies in the two RTOs are similar and PJM’s values are already FERC-approved. (See MISO Moves Forward on Auction Design; Seasonal Filing Delayed Again.)
MISO’s approach diverges from PJM on several points, including use of the monthly Consumer Price Index to update values rather than the Handy-Whitman index. Because PJM’s figures do not include defaults for wind and nuclear generators, MISO developed its cost estimates based on data from the Energy Information Administration and the Nuclear Energy Institute, respectively.
MISO also will not include the 10% “adder” PJM uses to offset the uncertainty of estimating costs three years into the future. The commission rejected NRG Energy’s request that MISO be required to use the adder. Unlike PJM’s three-year forward auction, FERC said, MISO’s prompt auction does not require the same safeguard.
FERC also mandated separate values for multi-unit and single-unit nuclear resources, despite Exelon’s comments that the two values were not materially different.
FERC ordered MISO to review the reference levels every three years, rejecting the RTO’s proposal to update values only after PJM updated its own numbers. FERC said MISO’s review of its avoidable costs “should not be contingent upon the review schedule of another regional transmission organization.”
FERC’s order also approved MISO’s proposal that market participants intending to retire or suspend a unit must use either retirement- or mothball-based default avoidable costs, respectively. FERC said market participants wishing to take advantage of the retirement-specific values must have already submitted a notification of retirement to MISO. However, since MISO only included retirement-based and not mothball-based values for nuclear and wind units, FERC ordered the RTO to provide wind and nuclear mothball-based avoidable costs or explain why they should be exempted.
New England policymakers hope to reach agreement in 2017 on revised market rules to accommodate state clean energy policies, as three states seek to complete renewable procurements and Massachusetts readies for a new solicitation.
Although Donald Trump’s election threatens federal initiatives to reduce carbon emissions, New England is moving ahead with its plans to decarbonize through power purchase agreements, infrastructure improvements and potentially tighter emission caps under the Regional Greenhouse Gas Initiative.
Massachusetts, Connecticut and Rhode Island, which issued a joint solicitation combining their purchasing power, hope to file PPAs with state regulators in the spring, now that a temporary injunction sought by a small developer who challenged the program has been lifted. (See New England States Move Toward Renewables Contracts.)
While the initial contracts are for a modest 460 MW, Massachusetts is expected to issue another request for proposals for 2,800 MW in the spring. The state’s Energy Diversity law, enacted last summer, directs its electric distribution utilities to enter contracts for 1,600 MW of offshore wind and 1,200 MW of renewables, likely Canadian hydropower, over the next decade. (See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.)
Daniel-Johnson Dam and Manic-5 Generating Station | Hydro-Québec
Separately, Connecticut has selected 25 small clean energy and energy efficiency projects totaling 402 MW to negotiate PPAs with the state’s two electric distribution companies.
Transmission
In December, the region saw the nation’s first offshore wind farm — Deepwater Wind’s 30-MW project off Rhode Island’s Block Island — begin commercial operation. But without other, larger offshore projects to count on, importing Canadian hydropower appears to be the quickest solution for the states seeking to maintain momentum in emissions reductions.
Delivering that power will require major new transmission lines. The New Hampshire Site Evaluation Committee is expected to rule on the application by Northern Pass developer Eversource Energy in September. Opponents want the entire 192-mile route of the 1,090-MW line buried. The developers have proposed only 60 miles underground.
Two other transmission projects would import Canadian hydropower via cable buried under Lake Champlain. TDI New England’s Clean Power Link received a presidential permit in December to allow construction. Anbaric’s 400-MW Vermont Green Line is awaiting approval. All three transmission projects are expected to respond to the Massachusetts solicitation.
IMAPP
Meanwhile, the New England Power Pool’s Integrating Markets with Public Policy (IMAPP) initiative, launched last summer, is trying to find ways wholesale market rules can accommodate state policies without compromising reliability or dramatically increasing costs.
Meeting these goals has proved a daunting challenge. Officials had hoped to develop an action plan by the beginning of December that could be presented to ISO-NE for action in early 2017, but now they don’t expect to do so until late in the first quarter at the earliest.
Proposals within the IMAPP collaborative have included various methods of pricing carbon. A carbon adder would be technology-neutral and provide market signals to both supply and demand while also creating a revenue stream for the states. There is also a proposal for a two-tiered Forward Capacity Market, with one reserved for clean energy resources. (See Markets vs. Climate Goals the Subject at NECA Conference.) Any market rule changes would require FERC approval.
Also considering rule changes is RGGI, which is conducting its quadrennial Program Review. Falling prices in the nine-state compact’s CO2 allowance auctions have renewed calls from environmentalists to tighten emission limits. Allowance prices dropped to $3.55 in December, the lowest in three years and about 53% lower than a year ago. Many stakeholders say the states should reduce the cap on emissions by 5% annually from the current 2.5%. (See RGGI Carbon Auction Prices Drop 22%.)
Although New England has been a national leader in reducing carbon emissions, it would still need an additional 25% cut from 2015 levels to meet the 2030 targets under the federal Clean Power Plan. The CPP would cap emissions from new and existing sources at 29.1 million tons in 2030. In a report by ISO-NE, carbon emissions showed a slight uptick to 40.3 million tons in 2015 compared to 2014, likely caused by the closure of the Vermont Yankee nuclear plant.
Have Capacity Prices Peaked?
One worrisome development that seems to have abated is the concern about steeply rising prices in the capacity market.
Clearing prices in last February’s FCA fell to $7.03/kW-month from 2015’s $9.55/kW-month, a 26% drop and the first decline in four years. (See Prices Down 26% in ISO-NE Capacity Auction.)
ISO-NE is seeking 34,075 MW for delivery year 2020/21. About 34,505 MW of existing and 5,958 MW of new resources are qualified to participate.
Natural Gas Infrastructure
As expected, 2016 proved crucial in efforts to expand the region’s natural gas infrastructure, with two major gas pipelines projects falling by the wayside.
The 342,000-dekatherm Algonquin Incremental Market project was completed in December, but it mostly serves local distribution companies’ heating customers and did little to aid generators.
The Massachusetts Supreme Judicial Court effectively killed Spectra Energy’s Access Northeast when it ruled against a subsidy by electric ratepayers. (See Mass. Supreme Court Vacates EDC-Pipeline Contract Order.) The state’s legislature appears reluctant to codify the requirement. Other states that were ready to commit to shared costs for infrastructure were dependent on the Bay State taking a leading position.
Without ratepayer-mandated support in Massachusetts, the region’s largest state, major pipeline construction appears to be at a standstill.
President-elect Donald Trump may trash the Clean Power Plan and walk away from the Paris Agreement on climate change. Congress may undo the coal mining and fracking regulations the Obama administration issued on its way out the door. Rick Perry may neuter the climate scientists in the Department of Energy.
But while President Obama’s energy legacy is uncertain, there appears no reversing the generation shifts that have occurred since his first election in 2008.
Cheap natural gas and the falling cost of solar and wind power are likely to continue driving electric industry investments over the next four years regardless of whether the Trump administration is able to reverse Obama-era federal policies. And as they have in the face of Congressional inaction over climate change, many states will continue their own efforts to reduce carbon emissions.
Renewables produced 17% of electricity generation in the first half of 2016, up from 9% in all of 2008.
Natural gas added 70.1 GW of capacity between 2008 and 2015, 42% of the total, according to a report by the American Public Power Association. Wind was second with almost 56 GW (33%), while solar added 13 GW (7.8%). Coal added 19.1 GW (11.4%) of new capacity but also retired 42.9 GW over that period for a net reduction of 23.8 GW.
New Bosses for Federal Agencies
It’s clear that environmentalists will be playing defense for the next four years.
Trump’s nominees for cabinet posts, including fellow climate change skeptics Rick Perry as secretary of energy and Oklahoma Attorney General Scott Pruitt as EPA administrator, are certain to face tough questions at their confirmation hearings, but the out-of-power Democrats will be unable to block them by themselves. Because of Democrats’ change of the Senate filibuster rule in 2013, Trump will need only a simple majority in the upper house to win approval for any administration position or any judge excluding the Supreme Court — not the 60 votes to end debate as before.
How much Trump’s appointees will try to turn back the clock is uncertain. While Perry and Pruitt have joined Trump in rejecting a scientific consensus that carbon emissions are warming the planet, Trump claimed after the election to have an “open mind” on the issue. (See Trump Sends Conflicting Signals on Climate Change.)
Perry, who had called for the Energy Department’s abolition as a presidential candidate, will be expected by Republicans to sharply reduce its spending, particularly the controversial loan guarantee program. But the department also has supported carbon-capture projects essential to making “clean coal” more than a slogan. And while Perry was a friend to the oil and gas industry as Texas governor, he also presided over the state’s transmission buildout to support its wealth of wind power.
FERC
Although FERC has not traditionally been marked by partisan divisions, the agency will be reshaped by Trump’s election with Commissioner Norman Bay, a Democrat, likely to lose the chairmanship to a Republican. Commissioner Colette Honorable also is likely be replaced by a Republican after her term expires in June. The five-member commission has been all Democrats since the departures of Republicans Philip Moeller and Tony Clark. The president gets to appoint members of his party to three of the five seats and pick the chairmanship. (See CPP, FERC’s Bay, Honorable Among Losers in Trump Win.)
Because Republicans maintained their control of the Senate, Sen. Lisa Murkowski (Alaska) will remain chair of the Energy and Natural Resources Committee, the gatekeeper for FERC nominees.
Last month, state attorneys general from West Virginia and other anti-CPP states suggested Trump immediately issue an executive order directing EPA not to enforce the rule. Their counterparts from states supporting the CPP have vowed to fight a move to remand the CPP back to EPA before a court ruling.
State, Corporate Actions
Regardless of what happens with the CPP, utilities, major corporations and some states are likely to continue their efforts at decarbonizing the generation mix.
D.C. and several states increased their renewable portfolio standards in 2016: D.C. (50% by 2032); Oregon (50% by 2040); Rhode Island (38.5% by 2035); and New York (50% by 2030). In Ohio, Republican Gov. John Kasich last month vetoed a bill that would have made its RPS (12.5% by 2025) voluntary, saying the bill “amounts to self-inflicted damage to both our state’s near- and long-term economic competitiveness.”
According to the American Wind Energy Association, more than 80 companies, including General Motors, Amazon and Microsoft, have pledged to move to 100% renewable power. In addition to the “halo effect” of promoting their green credentials, the companies are also motivated by costs. For example, storage and information management company Iron Mountain signed a 15-year power purchase agreement for wind last year that it says will save it up to $500,000 in power costs annually.
Even some of the nation’s biggest coal-burning utilities are shuttering coal-fired plants and replacing them with natural gas and renewables. In announcing its third quarter earnings in November, for example, American Electric Power said it would add 5,400 MW of wind and 3,400 MW of solar power through 2033 through long-term PPAs (along with 3,000 MW of natural gas). No new coal.
Below is a status report on the changing generation mix since 2008 and prospects for the future.
Solar
2016 was a watershed year for solar, which for the first time will be the No. 1 source of new generation, according to the Energy Information Administration. EIA reported that the U.S. added more than 26 GW of utility-scale capacity last year, with solar (9.5 GW), natural gas (8 GW), and wind (6.8 GW) responsible for 93%. There were no new coal plants.
The U.S. trends are representative of those worldwide. Solar PV prices have fallen by about 70% since 2010 and are now cheaper than wind, natural gas or coal in emerging markets, Bloomberg New Energy Finance reported in December. In August, a contract in Chile priced at $29.10/MWh, about half the cost of coal.
BNEF says worldwide fossil-fuel use for electricity may peak within the next decade. “Renewables are robustly entering the era of undercutting” fossil fuel prices, BNEF chairman Michael Liebreich said.
Wind
U.S. nameplate wind capacity has tripled to more than 75 GW since 2008.
The first offshore wind farm, the 30-MW Deepwater Wind farm off Block Island, R.I., went into commercial operation in October.
Although offshore wind remains more than twice as expensive as land-based turbines, costs are expected to drop with more development and production economies. Massachusetts lawmakers have authorized the purchase of 1,600 MW of offshore wind by 2027. (See Massachusetts Bill Boosts Offshore Wind, Canadian Hydro.)
Last month, Norway’s Statoil bid $42.5 million for the right to develop almost 80,000 acres off Long Island, enough space to install up to 1 GW of turbines. The company said it will initially develop 400 to 600 MW. The Bureau of Ocean Energy Management has now leased more than 1.2 million acres and plans another lease auction off North Carolina in 2017.
Coal
Trump’s promises to “save” the coal industry won him votes in Appalachia, but there is scant evidence that any policy shift will bring jobs there.
Attorneys at LeClairRyan say Trump’s promise to remove the Obama administration’s moratorium on new coal leases on federal lands will help producers in the Powder River Basin of Wyoming and Montana.
Congressional Republicans are likely to invoke the Congressional Review Act in a bid to reverse the Interior Department’s Dec. 19 rule requiring coal companies to restore their land to its condition before mining began, an effort to prevent mining debris from contaminating streams. The act, which has only been used once in the past, could target any regulations finalized after May 30, according to the Congressional Research Service. (Also at risk of a CRA reversal is a Nov. 15 Interior rule requiring oil and gas producers to use “currently available technologies and processes” to cut methane flaring in half at oil and gas wells on federal and Native American lands.)
But none of these policy changes will be enough to reverse coal’s decline.
U.S. coal production is its lowest in three decades and three of the country’s biggest producers, Alpha Natural Resources, Arch Coal and Peabody Energy, have filed for bankruptcy.
More than 21 GW of coal generation retired in 2015 and 2016, largely as result of the Mercury and Air Toxics Standards, and EIA says another 14 GW is at risk of retirement by the end of 2028.
Nor is growth likely to come from exports, which fell for the third consecutive year in 2015. Through September 2016, exports dropped another 30% below the previous year.
The International Energy Agency predicts exports will continue to decline due to reduced demand from China and low-cost foreign supplies.
Prospects for new plants are fanciful. The levelized cost of a new coal generator with carbon sequestration — required under EPA rules finalized in 2015 — is about double the cost of new solar PV and wind, according to EIA.
Natural Gas
Coal has suffered from lower natural gas prices as well as competition from renewables. Since June 2008, Henry Hub prices have fallen from $12.69/MMBtu to an average of $2.49/MMBtu in 2016.
EIA said in December that natural gas production averaged 77.5 Bcfd in 2016, a drop of 1.3 Bcfd, and the first annual decline since 2005. EIA predicts production will rebound by 2.5 Bcfd in 2018.
Citing rising domestic demand, and increasing exports to Mexico and via LNG, EIA sees Henry Hub spot prices rising to $3.27/MMBtu in 2017.
EPA’s December report that improper fracking practices can cause groundwater contamination was blasted by industry and is unlikely to persuade the Trump administration to initiate tougher federal regulations. But it may provide ammunition for tougher state regulations that could increase production costs. (See EPA: Poor Fracking Practices Have Harmed Drinking Water.) Maryland is considering replacing a moratorium against fracking with regulations that industry says would be the most restrictive in the country.
Nuclear
The nuclear industry, which has seen five plants retire in the last five years, celebrated some wins in 2016, as state policymakers in New York and Illinois approved zero-emission credits to keep plants operating and the Tennessee Valley Authority completed its long delayed Watts Bar 2 nuclear plant.
Watts Bar 2 dedication | TVA
But nobody is talking any longer about a nuclear power “renaissance.”
The 1,150-MW Watts Bar 2 went into service in October, completing a project begun in 1973 and mothballed for decades.
Like Southern Co.’s Vogtle and SCANA’s V.C. Summer nuclear plants under construction, the TVA project was marked by the same kind of delays and massive cost overruns that stopped new plant construction following the Three Mile Island and Chernobyl accidents.
Fort Calhoun | NEI
The latest nuclear plant to go dark was the Fort Calhoun plant near Omaha, Neb. — at 478 MW the smallest in the U.S. — which closed in October, citing economic reasons. Fort Calhoun’s output is expected to be replaced by wind and natural gas.
State-backed ZECs may save the Clinton, Quad Cities (Illinois) and James A. FitzPatrick (New York) plants from imminent retirement, assuming the initiatives survive court challenges. But there will be no preventing the retirements of Oyster Creek (2019), Pilgrim (2019) or Diablo Canyon (2025).
In addition to cheerleading the state-backed ZECs, the Nuclear Energy Institute has launched an initiative to spread use of best practices to make the industry more compatible. NEI said the first year of its “Delivering the Nuclear Promise” identified more than $600 million in projected savings in 2016.
“Effecting an overall change in mindsets and culture is a huge undertaking but absolutely indispensable to the survival and success of our industry,” NEI Chief Operating Officer Maria Korsnick said. “We value the importance of safety and reliability and, while we maintain the high levels we have achieved, we also can focus on improving efficiency.”
Dynegy says it will sell generation in PJM and ISO-NE if necessary to address FERC’s market power concerns over the company’s acquisition of ENGIE’s power generation unit.
The commission conditionally approved the sale Dec. 22 but said the company had to mitigate its market power in the two regions’ capacity markets (EC16-93).
The commission’s order found the $3.3 billion acquisition for 9 GW of generation assets will not have an adverse effect on competition in NYISO, MISO or CAISO, nor in the PJM or ISO-NE energy or ancillary services markets.
Dynegy would acquire a 50% interest in the Bellingham Energy Center | NextEra Energy Resources
But FERC said it was concerned the transactions could harm capacity market competition in PJM’s Commonwealth Edison locational deliverability area and ISO-NE’s Southeast New England (SENE) capacity zone. FERC said that existing market power concerns in ISO-NE would be exacerbated by the acquisition absent mitigation.
The sale also includes the sale of the France-based ENGIE’s plants in ERCOT, which are not subject to FERC jurisdiction.
Dynegy and partner Energy Capital Partners proposed to buy 17 fossil fuel plants of ENGIE subsidiary GDF Suez North America (GSENA) and named the joint venture Atlas Power Finance. In June, Dynegy said it would pay $750 million to buy out ECP’s 35% stake. (See Dynegy Buying out Energy Capital’s Stake in ENGIE Deal.)
FERC found that the acquisition would increase the Herfindahl-Hirschman Index for the “highly concentrated” ComEd LDA — currently 2,021 points — by 49 points.
Although Atlas Power would not currently be a pivotal supplier in ComEd, the planned retirements of the Will County Generating Station (May 2020) and Exelon’s Quad Cities nuclear plant (June 2018) would reduce capacity available to bid in the 2020/21 Base Residual Auction by 2,223 MW in the LDA.
“Factoring in the 2,223 MW of planned retirements leaves an insufficient supply of unforced capacity available to meet the ComEd LDA minimum annual resource requirement, which means that Atlas Power’s capacity is needed,” FERC said. “With all other factors held constant, we calculate that Atlas Power will be pivotal in the ComEd LDA for the 2020/2021 Base Residual Auction.”
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.
Wind production and lower gas prices have combined to reduce the use of coal resources, which accounted for 60% of SPP’s energy production just two years ago. At the same time, wind energy has increased its share of production from 13% in fall 2014 to 20% in 2016.
After record low prices in the spring, gas prices rose in the fall, with the average cost of $2.61/MMBtu at the Panhandle Hub, compared to $2.25/MMBtu in 2015. The real-time balancing market’s average LMP was $25.10/MWh, up from $19.98/MWh a year ago; the day-ahead market saw an increase from $20.73/MWh last year to $24.43/MWh this fall.
