CARMEL, Ind. — Manitoba Hydro will reimburse MISO for providing extra contingency reserves during May, when maintenance outages are expected to reduce transfer capability between the Canadian utility and the RTO.
The MISO/Manitoba Hydro Contingency Reserve Sharing Group has a 2,000-MW contingency reserve requirement, with MISO ordinarily supplying 1,850 MW and Manitoba Hydro responsible for 150 MW.
Although Manitoba Hydro expects bountiful water supplies for May, maintenance outages will reduce the transfer limit between it and MISO below normal minimum cleared energy levels for the month, officials told the April 6 Reliability Subcommittee (RSC) meeting.
Following discussions between MISO staff and the Manitoba Hydro Electric Board, the RTO agreed to clear the utility’s share of contingency reserves, resulting in an additional 60 MW of spinning reserves and 90 MW of supplemental reserves.
“Much of the [maintenance] work is on the U.S. side of the border, but the MISO-Manitoba transfer capability will be reduced … during the work,” said Steve Swan, MISO senior manager of dispatch and scheduling.
Swan said Manitoba Hydro will still have reserves but might not be able to supply them because of the outages. “I think rather than saying they have reserves, they’ll have water,” Swan said.
A Manitoba Hydro representative confirmed the utility will have sufficient water to supply reserves but could encounter difficulties delivering them because of insufficient transmission capacity.
The utility has agreed to reimburse the MISO loads charged for contingency reserves through a miscellaneous charge in settlements for the entire month because transfer capability will be difficult to forecast.
“We will be carrying them for the entire period, and they will be reimbursing us for the entire period,” Swan said. “This was the best solution we could come up with.”
Manitoba Hydro will post updated limits during maintenance to MISO’s OASIS site. Swan said changes to the RTO’s clearing requirement will begin April 31.
Stakeholders at the RSC meeting did not appear to have a problem with MISO’s plan.
“That’s what I think the market is for,” RSC Chair Tony Jankowski joked.
At this year’s Gulf Coast Power Association MISO South Regional Conference, MISO CEO John Bear said he wished the RTO boasted more hydro power in the footprint and that one of its biggest contingencies is the transmission line connecting it to Manitoba Hydro.
Slave Falls Generating Station | Manitoba Hydro
Manitoba’s hydro exports to MISO are expected to increase in 2020 when the 500-kV line Great Northern Transmission Line between the province and Minnesota is scheduled to go into service. (See Manitoba-Minnesota Tx Line Granted Rate Incentives.)
Belt-Tightening
Manitoba Hydro, which underwent a management restructuring in February, last week began offering voluntary buyouts in an effort to cut 15% of its workforce and save about $60 million, CBC reported. The utility’s debts — $13 billion debt as of late 2015 — could increase to $25 billion over the next three years, according to CBC.
WASHINGTON — The Trump administration may not succeed in killing EPA’s Clean Power Plan — and it doesn’t matter anyway because the power industry’s decarbonization will continue without the rule, speakers told the Energy Bar Association’s annual meeting last week.
The Natural Resources Defense Council’s David Doniger, utility attorney William M. Bumpers and J.P. Morgan investment banker Ian C. Connor gave a general session audience their predictions on how the power industry will respond to President Trump’s March 28 executive order directing EPA to undo the CPP.
David Doniger, director of the NRDC’s Climate and Clean Air program, said that most of the players in the electric industry have adjusted to the CPP’s goals and are unlikely to reduce decarbonization efforts because of Trump’s executive order. (See Trump Order Begins Perilous Attempt to Undo Clean Power Plan.)
“We’re now entering what I’ve started to call the ‘Trumpocene,’ which … I hope [will be] a very short geological era with a maximum life of four years,” Doniger said. “Many people in the industry have to be thinking, ‘How long is the Trumpocene? Do I change my plans because of this coal industry- and ideologue-driven executive order and attempt to roll back the Clean Power Plan? Do I bet that that will succeed?’
“Because executive orders don’t actually do it,” he continued. “When it comes to changing rules that have been adopted under the Clean Air Act … you can’t tear the building down except by using the same rulemaking methods and procedures that it took to build the building up. So what’s begun here last week is a long slog of rulemaking process that may or may not produce the scrapping of the Clean Power Plan … and if he does that, it may or may not withstand judicial scrutiny.”
Doniger said CPP opponents may fail because they use unrealistic data in support of their case, noting the study contracted by CPP opponents that estimated the cost of compliance at $39 billion, about five times EPA’s estimate. He also noted the president’s executive order requiring changes to the calculation of the social cost of carbon.
“So they’re going to walk into court with an arbitrarily high-cost estimate and an arbitrarily low-benefits estimate. And they’re going to lose. So the CPP ain’t dead yet.
“So if you’re an executive or an adviser to an executive and think, ‘Well I really do think climate change is a real problem’ … and you’re making investment decisions that have a 20-year life or more, do we bet that over those 20 years that the Trumpocene will continue? No. I don’t think that’s a good bet.
“We hear … from companies and state regulators … that they are continuing to plan on the trend of decarbonization — at least that much of it which is supported by market forces. This is based on the anticipation [that] either the repeal plans won’t actually succeed — like say, for example, the immigration plan or the health care plan — or that they will be a mere blip because the next president will return to a path that’s more reality-based.”
Doniger said industry trends favoring low-carbon resources need to be buttressed by government policies.
“I think the markets are running in the right direction. Obviously technology is running in the right direction. But you really can’t foresee that they would make the deep decarbonization in the time frame we need,” he said. “So we need some form of policy. … To paraphrase Donald Rumsfeld: ‘You fight climate change with the Clean Air Act you have, not the one you wish you had.’”
Baker Botts attorney William M. Bumpers, who has represented utilities including Southwestern Public Service, Reliant Energy and Entergy, said although he is a strong advocate of reducing carbon emissions, he is not a fan of the CPP.
“I really didn’t like the Clean Power Plan for a host of reasons. One is that I think it was going to be largely ineffective,” he said. “Fifty percent of the reductions they were claiming credit for had already been achieved by the industry with no particular help from the federal government.”
Bumpers also said EPA’s regulatory approach “was sort of a square peg, round hole problem.”
“When they overlay basically three different types of emissions trading — most of which wreak havoc with each other — my own view is it was going to create one of the largest bureaucratic messes with regulatory overreach that was going to create more ossified limitations on the development in the industry than it was going to help.”
Bumpers said he would like to see a ruling by the D.C. Circuit Court, which heard arguments on state challenges alleging EPA overstepped its authority in September. The Supreme Court stayed the rule pending resolution of the challenges. (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)
“In some ways, I think the industry would benefit from having the D.C. Circuit rule because [there are] elements of that plan that the D.C. Circuit would probably strike down — maybe whole large portions of it.”
Bumpers said he represented utilities before EPA in an effort to improve the plan before the final rule was released in August 2015. “We … succeeded to some extent, but [the plan] ended up in bad shape and I ended up representing five companies as part of a challenge,” he said. “I represented probably 20 other companies who were equally as involved who in the end said, ‘We don’t care because it doesn’t affect us. It really doesn’t change our business plan one iota.’
“What it would have done is really substantially affected a handful of states and had no effect on most of the rest. It just didn’t make sense to me.”
Bumpers said his clients would like “a very state-oriented, federalist approach in which states have the opportunity to deploy the resources at their hand based on their resource mix to try to address climate change, and make it less of a nationwide, one-size-fits-all trading program but allow states to tailor their own programs.”
He criticized moves by Trump and congressional Republicans to roll back Obama administration efforts to limit methane emissions from natural gas production. “The path forward is going to result in a whole lot of new natural gas [generation]. … That’s what’s driving coal plants out of business, [and] it’s helping to reduce our carbon footprint within the industry. But if [at] the same time we don’t have rigorous oversight of the drilling and production facilities to reduce methane, we will have shot ourselves in the foot.
“At best, [the CPP] was going to accelerate where the CPP wants us to go by a couple of years. And at this point — given the stay — if it were reinstated, I don’t think it would do anything, assuming there’s a delayed implementation schedule.”
J.P. Morgan: Industry to Decarbonize with or Without CPP
Ian C. Connor, global co-head of J.P. Morgan’s Power & Utility Group, largely agreed with Bumpers’ position on the CPP.
“I think that the CPP — whatever its noble objectives — it’s relatively irrelevant whether or not it’s enforced … I have little doubt, consistent with what Bill said, that the industry will materially decarbonize and outstrip what the CPP is trying to do.”
Connor said the CPP could actually limit options for controlling carbon emissions in the future.
“At a time of rapid change, I think you want to make sure that you keep absolute optionality,” he said. He noted that although the U.S. did not sign the 1997 Kyoto protocol, it has still reduced carbon emissions since then — in part because of improvements in gas drilling practices and increased energy efficiency.
The U.S. has “actually outperformed most of the signatories of Kyoto. It’s also outstripped the Waxman-Markey objectives as well,” he said, referring to the cap-and-trade bill that faltered in Congress in 2009. “That’s largely driven by technology. Going back to 1997 … no one had any idea the shale revolution was coming.”
The drop in the costs of natural gas has eroded coal’s share of the generation mix. And now, renewables’ dramatic cost reductions are providing competition to gas.
“Today, renewables on a levelized cost basis — wind and solar — are cheaper than an efficient [combined cycle] natural gas plant. And all of these are materially cheaper than coal,” he said.
“To give you an idea of how [quickly] things are moving … six months ago we were talking about a [power purchase agreement] being signed for wind at $20/MWh. … That’s shockingly low. Today it’s $15 to $17/MWh. So in six months the cost of wind has declined 15 to 25%.”
Nuclear not Coming Back
Bumpers and Connors also agreed in their gloomy view of nuclear power’s role in a low-carbon future.
“Nuclear is not coming back,” Bumpers said. “Nobody can afford the balance sheet risk associated with a nuclear plant. So unless we get some super cheap, modular technology, I don’t see that happening.”
Connor noted the cost overruns at plants being built for Southern Co. and SCANA and the bankruptcy filing by Westinghouse, the main builder of the plants.
“It’s really hard to go in to your regulators or anyone else and say ‘I need to build this thing if the levelized cost is way up here and wind and solar are way down here and gas is down here.’ You can’t make the argument anymore.”
WASHINGTON — More than 400 FERC officials, energy lawyers and stakeholders attended the Energy Bar Association’s annual meeting last week. Here’s some of what we heard.
Energy Efficiency ‘Most Expensive’ Form of Energy?
David Nemtzow, director of building technologies for the Department of Energy’s Office of Energy Efficiency and Renewable Energy (EERE), described energy efficiency as “a Swiss Army knife.”
“The benefits are multiple. … For some people and some users and some policymakers, the environmental benefits are central to energy efficiency. For others, it’s the economic savings. For others, it’s the jobs. It’s all the above.”
Bill Campbell, general counsel and head of sustainability and structuring for Equilibrium Capital, doesn’t agree with those who say that energy efficiency is the cheapest form of energy.
“We say that because we focus on the amount that’s paid in incentives. In fact, it’s probably the most expensive form of energy on the planet, but that’s OK. The reason it’s the most expensive form of energy on the planet is that every time you subtract a unit that’s saved with energy efficiency, the utility would lose the retail price of that unit. … Recognize that that just establishes the competitive marketplace for efficiency.”
Minnesota attorney Jeff Paulson, who represents community solar developers, is bullish on distributed energy. But he has heard the naysayers.
“There is a commissioner in the Midwest, who shall go unnamed, who has referred to community solar gardens as ‘the new kale,’ because of the rapid growth in popularity, and [because] we’re attributing so many … benefits that are supposed to be derived from introducing them on your system,” he said. “Maybe some of the talk about community solar gardens is a little hyperbolic. But that doesn’t mean — like kale — that there aren’t some benefits to still be derived.
“It’s a tough market out there right now [for developers] trying to do avoided-cost deals or trying to do utility-scale [projects] in states that are not favorably inclined toward that. This is a huge market opportunity.”
Paulson said he’s been frustrated with the pace of Minnesota regulators’ actions on community solar.
“There’s a lot of good things being done [in Minnesota]. There were [also] a lot of disputes. There was a lot of process,” he said. “I will say that 18 months into that regulatory process I was sitting at the table in front of the commission just screaming for them to shut the heck up and stop trying to make this program perfect. Get it defined. Let us get out in the field and start building projects and getting the financing.”
Robert Weishaar was elected as the EBA’s new president, succeeding Emma Hand. In lunchtime comments after the transition, Weishaar praised Hand for making “diversity and inclusion a focal point” of her term as president. He pledged to continue the work of Hand and President-elect Matthew Rudolphi, who led a task force that developed what he called the “strong diversity and inclusion initiatives” adopted by the EBA.
“EBA remains dedicated to the value of diverse perspectives,” said Weishaar, an attorney with McNees Wallace & Nurick who represents industrial consumers and owners of cogeneration facilities. “While not losing sight of that core value, we need to focus on another. The current dynamics of our profession and the challenges currently facing our country also demand a recommitment by all EBA members to collegiality and civility in our profession and in our day-to-day [actions].”
NYISO’s summer 2017 capacity auction results surprised analysts last week with higher-than-expected prices for New York City — up 72 cents year over year to $11.71/kW-month.
Prices for the Lower Hudson Valley rose even more, jumping $2.25 to $10.50/kW-month, while the Rest of State dropped 62 cents to $3. Long Island was up $1.50 to $5.79.
In an April 5 market analysis, UBS Securities analyst Julien Dumoulin-Smith said the results were higher than “we had initially expected as a new, more bearish demand curve was put into effect alongside weak demand forecasts.”
Retirements and New Entry
The results indicated that the 312-MW Cayuga coal-fired plant — which is operating under a reliability support services agreement with New York State Electric and Gas that ends in June — cleared the auction. Without higher prices, however, Cayuga Unit 2 could face retirement next year because of environmental upgrades needed to operate past mid-2018, UBS said.
Riesling Power, a company affiliated with The Blackstone Group, purchased Cayuga and the Somerset coal plant outside Buffalo — the only two operating coal-fired plants in the state — last year from a group of bondholders that had purchased them from the bankrupt AES Energy East in 2012. The sale came after New York regulators rejected a request to have ratepayers fund a $102 million conversion of the plant to natural gas. (See Cayuga Coal Plant in Jeopardy.)
The higher New York City prices suggested that 79 MW of uprates did not clear, but UBS said it expects prices to drop by $1/kW-month next year because of the uprates and exports from the Bayonne Energy Center, which is adding two new turbines that will boost its capacity from 512 MW to 644 MW. The New Jersey plant is connected to a substation in Brooklyn via a 345-kV transmission line under New York Harbor.
Additional downward pressure on New York capacity prices may come in the future from two new combined cycle gas turbine generators under construction, including the 1,100-MW Cricket Valley plant in Dover, expected to be operational by the first quarter of 2020.
The 650-MW CPV Valley plant has targeted a February 2018 opening, but construction has not yet begun on a 7.8-mile lateral to supply the plant. Millennium Pipeline sued the state Department of Environmental Conservation in December over the department’s refusal to issue a required water quality permit and expects a decision from the D.C. Circuit Court of Appeals in April or May. (See Pipeline Sues to Force NY to Issue Permit for CPV Plant.)
| NYISO
One wild card is the 1,242-MW Roseton power plant in the Lower Hudson Valley, which has approval to export 500 MW to New England for the 2018/19 period. Roseton’s decision to export or not may depend on “whether a half year capacity obligation for the winter can be established to maximize its position in both markets,” UBS said. (See FERC Sides with ISO-NE in Capacity Dispute with NYISO.)
UBS said prices are unlikely to rise for the next three years. “With more renewables coming, it is hard to point to much of a bullish prospect on either energy or capacity until Indian Point retirements hit in 2020 and 2021,” it said in a March 23 report. (See NYISO, PSC: No Worries on Replacing Indian Point Capacity.)
The mothballed 435-MW Dunkirk coal-fired plant near Buffalo has “little chance” of converting to natural gas and returning to the grid, UBS said — a prediction that was strongly denied by NRG spokesman David Gaier.
“UBS doesn’t speak for NRG. Our plans are to move the gas addition project forward, as I’ve said several times since November,” Gaier said.
Impact on IPPs
The results were good news for NRG, for which NYISO represents 10% of its fossil-fueled generation. Two other independent power producers, Dynegy (4%) and Calpine (1%) have much lower exposures to the state.
NRG’s share price rose from $18.86 to $19.05 following the announcement of the results April 4, but the boost was short-lived and shares closed the week at $18.49.
CARMEL, Ind. — MISO is beginning a study to assess its frequency response performance and identify needed improvements.
In the first half of 2017, MISO will compile system data from major generation loss events for evaluation. The RTO’s initial sample of generation loss events are spread evenly across the footprint, although it said data may not be available for some locations.
| MISO
MISO’s frequency response continues to “decline year after year” and while not a pressing problem yet, it is “concerning,” Durgesh Manjure, MISO resource adequacy manager, said at an April 6 Reliability Subcommittee (RSC) meeting.
In January, the RTO’s staff asked for stakeholder input on how to address the declining frequency response capability, presenting preliminary simulations showing the system recovering too quickly when compared with real events — an indication of the need to fix governor parameters, officials said. (See MISO Aims for Improved Frequency Response Modeling.)
In the latter half of 2017, MISO will run simulations based on collected data and compare results to the actual events. By early 2018, the RTO will use stakeholder input to refine the study models.
Although MISO originally planned to use data from its SCADA system, it now says those measurements “seem inadequate for model validation” because the data are not detailed enough and not synchronized across locations, creating a potential time lag.
Data collected from phasor measurement units (PMUs) might be the better option, because their measurements are detailed and synchronized in real time across the grid, the RTO said.
However, Manjure said PMU data may not be available for all of the large generating units. In addition, PMU data is deleted after one year. It “remains to be seen how useful” the PMU data will be, Manjure said.
“Just being able to leverage the PMU data is a work stream in itself,” Manjure said. “We’re not quite sure which things are going to work … as we start peeling the onion.”
RSC Chair Tony Jankowski said he preferred MISO get the most detailed data to begin improving modeling.
Manjure said MISO would present more information on the study at the June RSC meeting.
MISO’s Independent Market Monitor last week filed a complaint over PJM’s pseudo-tie procedure, the latest volley in an increasingly complex debate over the future of the pseudo-tie concept.
Spurred by a recent PJM bid to tighten its pseudo-tie rules, Monitor David Patton filed a Section 206 complaint April 6, claiming that the increasing use of pseudo-ties degrades reliability, hinders efficient dispatch and raises costs. He asked FERC to eliminate PJM’s existing pseudo-tie definition (EL17-62).
“PJM has asserted that it has a very broad right to impose requirements on external generators to ensure that their capacity can be delivered reliably and efficiently, but the PJM pseudo-tie practices exceed all reasonable bounds,” wrote Patton, whose Potomac Economics firm provides monitoring for MISO and NYISO.
NYISO also took issue with PJM’s March 9 FERC filing seeking approval to apply more stringent requirements on external capacity resources serving the RTO’s load. PJM wants the new rules to be effective in time for its May 10 Base Residual Auction (ER17-1138). (See PJM to Tighten Pseudo-Tie Rules Despite Stakeholder Pushback.)
In a March 31 protest, the ISO said PJM’s proposal — which would allow PJM to commit and dispatch generators directly interconnected to the New York Control Area — “could threaten the reliable operation of the NYCA and disrupt the NYISO-administered markets.”
Patton said PJM provides only “scant support” for its new, “arbitrary parameters,” and that the filing makes it “impossible for any supplier in MISO that does not currently have a unit pseudo-tied to PJM to meet these requirements to offer capacity in the [Reliability Pricing Model] forward auctions.”
If the new rules are implemented, PJM’s customers could experience annual capacity cost increases of $500 million to $4 billion, Patton said. The complaint suggested that FERC consider replacing pseudo-ties with a firm capacity delivery procedure, a collaborative approach that Patton and MISO presented last year. (See PJM Filing Renews MISO Monitor’s Call for Pseudo-Tie Elimination.)
PJM Cries Foul over MISO Pro Forma
Meanwhile, PJM and MISO are attempting to settle a disagreement over the Midwestern RTO’s stricter pseudo-tie pro forma agreement.
The two RTOs are considering adding coordinated pseudo-tie policies to their joint operating agreement “in lieu of MISO being a signatory to PJM’s agreement,” MISO Senior Director of Regional Operations David Zwergel said during an April 6 Reliability Subcommittee meeting.
Zwergel said the discussions are the result of PJM’s March 21 protest of MISO’s pro forma filing (ER17-1061).
“MISO made this filing without the opportunity for PJM to review, leaving PJM no choice but to file this protest and seek revisions to this agreement through the commission,” PJM wrote. It asked FERC to require MISO to “revise any provision of the proposed agreement to the extent it gives MISO unilateral authority to control the implementation, operation, suspension and/or termination of the impacted pseudo-tie, or is inconsistent with the coordinated implementation and operation of pseudo-ties as between MISO and PJM.”
PJM said it sought MISO input on the development of its own pro forma pseudo-tie agreement but was not granted the same courtesy.
Work Continues on Double-Counting Congestion
In a related matter, the two RTOs last week presented an update to their proposal for eliminating overlapping measurements of congestion related to pseudo-ties.
| PJM
During an April 7 Joint and Common Market Initiative meeting, the RTOs proposed a revised solution that involves exchanging more congestion information in the day-ahead market and refunding or charging pseudo-tie owners for deviations between day-ahead predictions and real-time numbers.
“The RTOs will coordinate pseudo-tie firm flow entitlement impacts before the day-ahead run so that the congestion and the day-ahead LMPs for the pseudo-tie resources will better reflect actual congestion,” the RTOs said.
“We’d be aligning our firm flow entitlement impacts in the day-ahead to reflect what we think the settlement will be in real time,” said Kevin Vannoy, MISO director of forward operations planning.
PJM Interregional Coordination Manager Tim Horger said the solution solves the double-counting issue “as best we can” with prices more reflective of the real-time market. “It’s not going completely solve congestion, but we’re measuring that pseudo-tie impact on every coordinated market-to-market flowgate,” he said.
Horger said that the impacts will be brought “in front” of LMPs and pare down “excess congestion” that is usually folded into the pricing, reducing the need for refunds.
PJM and MISO staff have not yet determined which Tariff or JOA changes might be necessary, but Horger said pseudo-tied resources will not have to make any changes. Vannoy said MISO and PJM hope to adjust the market-to-market settlement process in time for a June 1 implementation.
A future phase of MISO and PJM’s solution will allow for optional scheduling and settlement of pseudo-tie transactions in the native balancing authority’s day-ahead market. In February, MISO and PJM said they would provide congestion rebates in the near term while developing a way to incorporate pseudo-ties in the day-ahead scheduling process by 2018. (See MISO, PJM Propose Solution to Pseudo-Tie Congestion Problem.)
WASHINGTON — More than three years and thousands of pages of analysis later, there is no consensus on how the electric industry should respond to the January 2014 cold snap that revealed weaknesses in the Eastern Interconnection.
The differences of opinion were on display during a panel discussion on gas-electric coordination at the Energy Bar Association’s annual conference on Monday.
Macdara Nash of National Grid and Todd Piczak of Kinder Morgan advocated for additional pipelines in the Northeast U.S., saying they would ensure sufficient gas supplies for generators on high-demand days. David Ismay of the Conservation Law Foundation called for peak shaving and increased gas storage, saying additional pipeline capacity would reduce utilization of existing infrastructure most of the time.
One thing all the panelists agreed on is that natural gas has a place in the region’s energy future and that action needs to be taken to better gird the grid against unforeseen events like the polar vortex.
“The region should be thinking about what are solutions, what can we do,” Nash said. “We think that natural gas is key.”
He cautioned that pipelines require an extensive lead time, “so if you believe in the problem [of potential pipeline capacity shortages], the time to act is sooner than later.”
Piczak said FERC has made progress on one half of the problem — ordering increased coordination between gas pipelines and gas-fired generators — but hasn’t done much to facilitate the other half, which is adding capacity. A major issue, he said, is the need for the commission to develop criteria other than long-term contracts to support a finding of public convenience and necessity.
Piczak’s company operates the Tennessee Gas Pipeline, one of the nation’s most critical natural gas conduits because it runs from Houston to Boston and crosses two prolific shale gas plays, the Utica and Marcellus in the region of Ohio, Pennsylvania and West Virginia.
Not a Capacity Problem
“This is fundamentally a regulatory problem,” he said. “There’s not enough gas for the generators when they need it. … It’s an important problem, and it’s a growing problem.”
Ismay said the issue isn’t the availability of gas — he said gas was never unavailable, even during the polar vortex — but that constraints and high demand make it prohibitively expensive. A new pipeline would, on average, be about half full half of the year and wouldn’t justify the installation costs, he said.
“Instead of a capacity problem … it’s a temporal, location-based problem of getting a certain amount of gas to a certain location … on the pipeline system at time of year,” he said. “We [will] always have days above the peak, even if we build a new pipeline.”
LNG storage has been and should be the solution, he said, along with demand response and energy efficiency to shave peak demand. He pointed out that while Massachusetts’ electricity rates are the fifth highest in the country, customers’ bills are the 31st lowest on average.
A study of future energy needs in the Bay State, conducted by Analysis Group for the state attorney general, found that, in a business-as-usual scenario, there will be no reliability concerns out to 2030, he said. Moving forward, energy storage, increased pipeline compression, additional pipeline loops and developing targeted markets will address remaining issues.
“If we understand the problem of temporal availability, let’s create a market for it,” Ismay said. “There is a role for natural gas in 2050, but it’s not very big. … It doesn’t run very much in the future.”
With natural gas already occupying 40% of installed generation and providing 50% of the electrons in New England, “our bridge is built” to a low-carbon future, Ismay said.
Discussion attendees pushed back on some of Ismay’s arguments, noting the Massachusetts study assumed best-case, “blue skies” scenarios and that adding localized LNG storage to gas-fired units raises their bid prices to levels comparable with coal-fired units.
“Another important thing to recognize about LNG solutions is you still have to get the gas from the LNG facility to where it’s needed,” Piczak said. “It’s not as easy as just to say, ‘Let’s put some LNG in a tank,’ and it’s going to be available.”
NRDC, J.P. Morgan Skeptical of Pipeline Need
At the EBA’s general session on Tuesday, J.P. Morgan’s Ian C. Connor, and David Doniger of the Natural Resources Defense Council, also expressed skepticism over the need for additional pipelines.
Connor, global co-head of J.P. Morgan’s power & utility group, noted that renewables are supplanting a lot of retired coal capacity.
“I think you’re going to see significantly less gas [generation] build than people believe,” he said. “These [combined cycle gas turbines]: Yes there are a few being built between now and 2020. After 2020, right now no one really thinks any more CCGTs are getting built. So how many more pipelines are you really going to need to build? I think it’s a lot less.”
Doniger, director of NRDC’s Climate & Clean Air program, said the rise of renewables and flat electric demand should prompt FERC to look more skeptically at the need for new pipelines.
“Are we building gas pipelines in order to stimulate the development of new gas power plants or is there really a need?” Doniger asked. “If you look at the system more systematically … efficiency, renewables and some of the other options can [replace] extensions of the gas pipelines and the natural gas infrastructure. The FERC process for evaluating new pipeline applications doesn’t ask all those questions and [it] should.”
CAISO management is proposing to amend the Western Energy Imbalance Market (EIM) charter to explicitly provide the market’s Governing Body with a voice in any future governance changes.
Other charter changes currently under review would give the Governing Body the first — and, in most cases, the last — word on its relationship with two increasingly important stakeholder groups.
The proposed changes were drafted at the request of Governing Body Chair Kristine Schmidt, who wanted more clarity on the body’s role in modifying the charter.
Originally approved by CAISO’s Board of Governors, the EIM’s charter sets out the mission of the Governing Body and details the authority delegated to it by the board over EIM market rules and administration.
The charter currently stipulates that any “substantive changes” to the charter must be approved by the board, as required under the CAISO Tariff. “The role of the EIM Governing Body in considering proposed changes, however, is not specifically addressed,” Roger Collanton, the ISO’s general counsel, noted in a memo addressed to the Governing Body.
Under the proposed revisions, any substantive modifications to the charter would first be presented to the Governing Body for its “advisory” input — similar to the role body members play with respect to ISO market rule changes that also affect the EIM. (See EIM Leaders OK Governance ‘Guidance’ Proposal.)
CAISO management also seeks to extend the authority of the Governing Body over sections of the charter dealing with the EIM’s Body of State Regulators (BOSR) and Regional Issues Forum (RIF), two West-wide groups established by the ISO to monitor and provide feedback on the EIM’s activities.
The proposal would allow the Governing Body to initiate any modifications to those areas of the charter. Approved changes would then be placed on the consent agenda of the board, translating into “a decisional process similar to the one that is used for proposed tariff amendments that fall within the primary authority of the EIM Governing Body,” Collanton’s memo said.
The board would reserve the right to consider — and reject — any proposed changes outside its consent agenda, but “this full consideration will occur only if the board affirmatively decides to take up the issue,” according to the memo.
Other proposed amendments to the charter detail how ISO staff will support the work of the BOSR and RIF, including coordination of meetings, assistance with stakeholder communication and reimbursing state regulators’ staff for travel to attend meetings. RIF members expressed a need for staff support during a Feb. 28 joint meeting with the Governing Body. (See Western Stakeholders Support Continuing Regional EIM Forum.)
CAISO will seek Governing Body endorsement for the charter amendments at a future meeting of the body.
PJM’s Board of Managers on Thursday ordered a resumption of the Artificial Island transmission upgrades but directed the development of alternative cost allocations to address Delmarva peninsula stakeholders who argue they’re unfairly on the hook for the vast majority of the $280 million project.
The board suspended work on the controversial project last August following years of stakeholder complaints about how the project was scoped, awarded and had its costs allocated, ordering staff to perform a comprehensive analysis. At a special session of the Transmission Expansion Advisory Committee in March, staff announced some modifications to the scope of the project, but remained supportive of the proposal the board had approved in 2015. (See PJM Sticks with LS Power on Artificial Island Project.)
PJM says the DFAX cost-allocation methodology can produce “”anomalous”” results in some projects, such as Artificial Island, in which it assigned 93% of the cost to Delmarva Power & Light ratepayers. All other transmission zones would pay less than 1% each. | PJM Transmission Expansion Advisory Committee, 3/3/17
Last April, FERC approved the cost allocation for the project, but in June it said it would consider rehearing requests over whether PJM’s use of the solution-based distribution factor (DFAX) cost allocation method is appropriate (EL15-95, ER15-2563). Under the DFAX method, 93% of the costs would be borne by Delmarva Power & Light ratepayers, with all other transmission zones paying less than 1% each.
PJM’s signal last month that it would move forward with the project prompted renewed complaints to the board from 12 stakeholders — including the governors of Maryland and Delaware — upset over the cost allocation.
In a letter to stakeholders on Thursday, PJM CEO Andy Ott acknowledged the dispute and called on PJM’s transmission owners to come up with a compromise.
“PJM has stated in past Federal Energy Regulatory Commission proceedings and at a Jan. 12, 2016, FERC technical conference that a solution-based power flow formula (the ‘DFAX methodology’) works fairly and reasonably to identify project beneficiaries for cost allocation purposes in the overwhelming majority of lower-voltage transmission projects considered by the board,” Ott wrote. “But we also noted that application of the DFAX methodology can result in cost allocations that seem anomalous in cases where the engineering rationale or need for the particular project is not one driven by power flows. Indeed, PJM has suggested that the Artificial Island project is unique in nature and that application of the DFAX methodology to a stability or short-circuit problem may not yield clear beneficiaries.”
TOs, not PJM, Responsible for Cost Allocation
Ott said the Federal Power Act makes the PJM TOs responsible for proposing cost allocation methods and prevents the RTO from imposing alternatives. But he also acknowledged that the cost allocation dispute “is so polarized [that] it threatens to impede PJM in discharging its reliability responsibilities.”
As a result, he said, PJM staff “will analyze project beneficiaries from alternate perspectives, including identifying load and the extent of service interruption that could be expected in the case of an uncontrolled stability event at Artificial Island.”
“Importantly, we anticipate this information will still demonstrate the logic supporting an allocation of project costs to beneficiaries located in the Delmarva region, along with beneficiaries in one or more neighboring states,” he added.
He said the analyses will be available “shortly” and will be referenced in its FERC filing on the project.
The board also used in its decision a whitepaper produced by PJM, which stakeholders have complained was not made available for comment and response prior to the board’s decision. Ott said in his letter that the “whitepaper is anticipated for public release in the near future and will offer additional transparency to stakeholders.”
In a news release, the board said it directed staff to publish the alternative allocations because it believes “this data could offer insight to, and a basis for, those states, transmission owners and customers that derive benefit from this project to devise a different cost allocation proposal for stability projects such as Artificial Island.”
At the special TEAC meeting last month, PJM officials said their review confirmed that LS Power’s proposal for a 230-kV line from Artificial Island to a new Silver Run substation in Delaware was the best solution but that the interconnection point should be changed from the Salem nuclear plant to the Hope Creek plant. The analysis also eliminated as unnecessary a static VAR compensator and optical groundwire upgrades.
Salem Nuclear Generating Station on Artificial Island
The revised project assigned $146 million of the project work to LS Power, $132 million to Public Service Electric and Gas, and $2 million to Delmarva Power & Light.
PacifiCorp has released a 20-year plan that commits the utility to increased investment in renewable resources and energy efficiency while sharply reducing reliance on the coal-fired generation that currently produces more than half the company’s electricity output.
The 2017 Integrated Resource Plan — filed this week with utility commissions in PacifiCorp’s six-state territory — spells out $3.5 billion in capital spending focused on new renewables, upgrades to the company’s existing wind fleet and the construction of a 140-mile segment of the Gateway West transmission project in Wyoming.
The 500-kV line, slated to be in service by the end of 2020, would advance the company’s strategy for tapping new wind development in Wyoming. While the first segment is intended to serve PacifiCorp ratepayers, other portions of Gateway West are designed to facilitate the flow of wind energy into California, where utilities are required to serve 50% of their load with renewables by 2030.
Under the IRP, PacifiCorp would complete construction of 1,100 MW of new wind generation, mostly in Wyoming, by 2020 to take advantage of federal production tax credits. The company would also squeeze out an additional 905 MW of renewable capacity by upgrading its existing wind fleet with larger blades and new technology.
PacifiCorp currently owns or contracts for more than 2,300 MW of wind resources.
Between 2028 and 2036, the company plans to add another 859 MW of wind and build 1,040 MW of new solar capacity.
“These investments will significantly increase the amount of clean renewable energy serving customers and reduce costs at the same time,” Stefan Bird, president and CEO of Pacific Power, the PacifiCorp subsidiary that serves Oregon, Washington and California, said in a statement.
The plan calls for retiring 3,650 MW in coal-fired capacity by 2036 to avoid spending on equipment to comply with EPA’s Regional Haze rules. An Oregon law passed last year that will prohibit the state’s utilities from importing coal-fired power by 2030 also was a factor in the early retirements of the Craig, Jim Bridger, Hayden, Huntington and Naughton coal units located in the inland West. A rollback of EPA’s Clean Power Plan is unlikely to affect the company’s plans, it said.
“This early closure assumption was considered in PacifiCorp’s Regional Haze compliance analysis to account for changes in market conditions, characterized by reduced loads and wholesale power prices,” the IRP said.
By the end of the planning horizon, coal would represent 31% of the company’s resource portfolio, compared with almost 60% today.
The plan foresees the company building 1,313 MW of new natural gas-fired capacity, down 1,540 MW from the 2015 IRP estimate.
“Reduced loads, ongoing investment in energy efficiency programs and increased renewables reduce the need for new natural gas resources in the 2017 IRP,” the company said.
PacifiCorp expects energy efficiency to offset 88% of forecasted load growth over the next 10 years.
Stagnant loads and energy efficiency programs also caused the company to reduce its projections for wholesale power purchases through 2027 relative to a 2015 IRP update released last year, despite relatively low forward prices. Wholesale market purchases are expected to increase in 2028 in concert with the company’s coal retirements.
PacifiCorp said it developed the 2017 IRP through a process that included input from “an active and diverse group of stakeholders, including advocacy groups, regulatory staff and other interested parties.” The company completed the plan after meeting with stakeholders in five states and hosting seven public meetings.
The company delivers power to about 1.8 million customers in California, Idaho, Oregon, Utah, Washington and Wyoming through its Pacific Power and Rocky Mountain Power subsidiaries. The company was the first utility in the West to join CAISO’s Energy Imbalance Market and in 2015 signed a memorandum of understanding to explore becoming a full member of the ISO.
