Vistra Energy announced Friday it will close two additional coal-fired plants, taking another 2,300 MW of capacity offline and slashing its coal portfolio by more than half.
The retirements of Big Brown, north of Houston, and Sandow, northeast of Austin, will leave Vistra’s Luminant generating subsidiary with just two operational coal plants rated at a combined 3,850 MW. Vistra announced Oct. 6 it would be retiring its three-unit, 1,800-MW Monticello plant in East Texas. (See First Shoe to Drop? Vistra to Retire 3 Texas Coal Units.)
Big Brown | Vistra Energy
CEO Curt Morgan again blamed the “economically challenged” environment the plants face in the ERCOT market. The company said sustained low wholesale power prices, an oversupply of renewable generation and low natural gas prices contributed to the decision.
“Though the long-term economic viability of these plants has been in question for some time, our yearlong analysis indicates this announcement is now necessary,” Morgan said.
ERCOT’s most recent Capacity, Demand and Reserves report indicated the ISO had an 18.9% reserve margin for next summer, with margins remaining above 18% the following three years. A revised CDR report will be released in December.
“The market will tighten from a reserve margin perspective, but it remains to be seen if on-peak forwards will rise in response,” Kevin Vo, a research analyst with Tudor, Pickering, Holt, & Co., told RTO Insider. “We don’t believe off-peak pricing would be affected due to the large amount of wind generation.”
The Vistra retirements include the 600-MW Sandow Unit 5, which went online in 2009 and has a 75% capacity factor. Only Luminant’s twin-unit Oak Grove plant, which began operations in 2010, is newer.
Sandow | Vistra Energy
Sandow was built to serve a nearby Alcoa smelter, which was closed in 2008. Shortly before making its announcement, Vistra agreed to an early settlement that terminates a long-standing power and mining agreement with the aluminum company.
A Luminant spokesperson said once the contract was terminated, it became clear the Sandow units were not economical in the ERCOT market.
“The contract has helped shield Sandow from significant exposure to the downturn in the wholesale power market,” the company said in a press release.
“Sandow’s retirement was a surprise but highlights that it is hard for any coal plant to make money in Texas right now,” Ko said. “If you are a coal plant generator, you’re waiting to see if prices will respond. If prices don’t rise meaningfully or any price increase isn’t sustained, we would not be surprised if there are further coal plant retirement announcements.”
The Three Oaks mine, which supports the plant, will also be closed.
Luminant has filed a 90-day notice of suspension of operations with ERCOT. The plant will cease operating Jan. 11 if the ISO’s reliability review shows the units are not needed.
Big Brown is the oldest coal plant in Luminant’s fleet, with its two units having begun operations in 1971 and 1972. The units are together capable of generating 1,150 MW and have a combined capacity factor of 59%. Both units burn lignite supplemented by Powder River Basin coal. The nearby Turlington mine that supplies the plant was already scheduled to wind down operations by the end of this year.
Vistra said it would explore a sales process for the site during ERCOT’s notification period. The company filed a 120-day suspension noticed with the ISO to allow for a “more complete sales process.” With ERCOT’s approval, the plant will cease operations on Feb. 12 if it has not been sold.
Luminant said about 650 employees will be affected by the plant and mine closures.
The company’s 2,250-MW Martin Lake plant in East Texas is now the fleet’s oldest, its three units having gone into service in 1977, 1978 and 1979. Luminant also has 7,500 MW of natural gas capacity and 2,300 MW of nuclear capacity.
WASHINGTON — FERC Chairman Neil Chatterjee praised Energy Secretary Rick Perry’s “bold leadership” in calling for price supports for coal and nuclear plants but promised the commission’s response will be “fuel-neutral” and will not undermine wholesale markets.
“I think the bold directive [Perry] took has initiated this conversation, and it’s something that we are going to look at very seriously, and I’m confident we’ll find a positive resolution to,” Chatterjee said in a nearly hour-long press conference at FERC headquarters Friday. “I’m sympathetic to some of the things that Secretary Perry has raised. This idea that there are perhaps attributes that certain generating sources have that have value [and] that are not appropriately being captured by our existing market structure, we need to look at that carefully…
“I also believe strongly in markets. We’ve invested nearly two decades and billions upon billions of dollars into our existing market structure, and I don’t want to do anything to disrupt that market structure,” he continued. “Accurately valuing resilience is not a zero-sum game. Compensating baseload generation does not equate to destruction of the markets. On the contrary, I think it’s a step toward accurately pricing contributions of all market participants.”
Chatterjee said the commission must act within 60 days in response to the Department of Energy’s Notice of Proposed Rulemaking, which was published in the Federal Register on Tuesday.
FERC’s Options
The NOPR would require FERC-jurisdictional RTOs and ISOs with capacity markets and day-ahead and real-time energy markets to ensure full cost recovery for any generation that can provide “essential energy and ancillary services” and has a 90-day fuel supply on site. Units subject to cost-of-service rate regulation would be excluded. Just and reasonable rates for such generators would cover “its fully allocated costs and a fair return on equity,” including operating and fuel expenses and the costs of capital and debt, the NOPR said.
Chatterjee outlined FERC’s options for responding: “We could do an Advance Notice of Proposed Rulemaking; we could do a Notice of Proposed Rulemaking superseding the DOE NOPR; we could issue a final rule; we could do an extension of the comment period and solicitation of further comments; we can convene technical conferences; we can do a notice of inquiry; we could initiate Federal Power Act Section 206 review proceedings.”
Asked whether the commission could take an up-or-down vote on the proposal within 60 days, Chatterjee responded, “It could be. We’re going to carefully look at it.”
Chatterjee said that while he would prefer to delay major actions until the commission is fully staffed with the addition of nominees Kevin McIntyre and Richard Glick, he wouldn’t hold up action pending their arrival. The two are awaiting a Senate floor vote after clearing the Senate Energy and Natural Resources Committee on Sept. 19.
“These challenges are too important to wait,” Chatterjee said, noting that the commission is planning a “big announcement” on hydropower licensing policy at its next open meeting Oct. 19.
He also defended the commission’s refusal to extend the comment period on the NOPR (RM18-1). The commission set an Oct. 23 deadline on comments, with reply comments due Nov. 7. “It’s not a new issue,” he said. “We have ample time to receive comments.”
Kentucky Native on Coal’s Role
Chatterjee defended comments he made in a podcast in August, which some FERC watchers interpreted as signaling a break from the commission’s traditional “fuel-neutral” policies.
After praising “baseload” coal and nuclear generation for their value to “resilience and reliability,” Chatterjee noted that coal provided more than 80% of the electricity in his home state of Kentucky last year. “As a nation, we need to ensure that coal, along with gas and renewables, continue to be part of our diverse fuel mix,” he said then.
“I wasn’t saying that FERC was not fuel-neutral,” he said Friday. “To be clear, whatever solution that we pursue here will be fuel-neutral as well. I agree with Commissioner [Cheryl] LaFleur’s assessment that we don’t start with a resource and work backwards. We come up with policies that will be applied in a fuel-neutral way.”
But he said he agreed with lawmakers who want to preserve “fuel diversity,” suggesting coal could act as a hedge against “unintended consequences” from technological changes on the grid.
He cited the switch of the Big Sandy generator in Kentucky from coal to natural gas. Much of the plant’s load was from the energy-intensive coal mines in the region.
“So, when the power plant shut down, the coal mines that fed that plant shut down with it. … Now the operators of the gas plant find themselves in a situation where they’ve got to come to the state for a massive rate increase to account for … lost load,” he said. “So that’s a perfect example of an unintended consequence that occurs when you have these technological shifts. And I just think we need to be very thoughtful and careful in assessing what the long-term future of our grid looks like when these types of unintended consequences can occur.”
Chatterjee declined to offer an opinion on whether a 90-day fuel supply is a valid way to measure reliability. The NOPR said such supplies enable a plant “to operate during an emergency, extreme weather conditions, or a natural or man-made disaster.”
“I just think we have to go through our process, take in people’s comments. Look at the rationale to see how it would impact them,” Chatterjee said. “I’m not prepared at this stage of our process — not having all that complete information submitted — [to say] how we will address that.”
The commission also will consider data cited by members of the House Energy Subcommittee during a Thursday hearing with Perry indicating that most outages result from problems on the distribution system rather than from insufficient generation, the chairman said. (See Perry Defends Call for Coal, Nuclear Supports.)
“Staff put out an … extensive list of questions to facilitate this kind of dialogue and commenting. I fully expect comments in line with what you’re laying out will come in.”
Mum on White House Input on Staff
Chatterjee declined to answer concerns among some FERC watchers that his appointments of General Counsel James Danly and Chief of Staff Anthony Pugliese were directed by the Trump administration.
The commission has traditionally been independent and rarely decides issues on party lines. But some observers said the appointments suggested that could change because the two key positions were filled before the arrival of McIntyre, who was tapped by President Trump to lead the agency. New chairmen typically select their own general counsel and staff chiefs.
Danly, an Iraq War veteran, joined the commission from Skadden, Arps, Slate, Meagher & Flom.
Pugliese, who formerly lobbied on solar, oil and natural gas issues in Pennsylvania, came to FERC after serving as the White House’s eyes and ears at the Department of Transportation. Politico described Pugliese in May as one of Trump’s “White House-installed chaperones,” saying he clashed with Secretary Elaine Chao.
“Day to day, Pugliese and his counterparts inform Cabinet officials of priorities the White House wants them to keep on their radar,” The Washington Post reported in March. “They oversee the arrival of new political appointees and coordinate with the West Wing on the agency’s direction.”
At his press conference — which Pugliese and Danly attended — Chatterjee praised the two as “very talented people.” The two sat in the rear of the room, behind reporters and facing Chatterjee — Pugliese frequently shaking his head no or yes in response to the questions and answers.
“Mr. Pugliese has extensive experience in infrastructure and public policy, and I’ve been thoroughly impressed in the manner in which he has comported himself in his time here at the agency,” Chatterjee said.
He also praised Danly’s “astonishing resume,” calling him “one of the most talented brightest, capable energy lawyers in the country.”
Were they suggested to Chatterjee by White House officials?
“They were suggested to me by a number of people,” Chatterjee responded. “They have sterling reputations, and people who I respect and trust recommended them to me.”
Including the White House?
“I’m not going to speak [about] who recommended them,” Chatterjee said.
HOUSTON — When Missouri regulators recently rejected Clean Line Energy Partners’ application to build a high-voltage transmission line through the state, it seemed to sound the project’s death knell.
After all, it marked the company’s third unsuccessful attempt to gain Public Service Commission approval for its 780-mile Grain Belt Express, a $2.3 billion initiative that would deliver 4,000 MW of wind power from western Kansas through Missouri and Illinois to the Indiana border.
The company’s first attempt in 2015 was shot down after the PSC determined the project did not provide enough benefits to Missouri consumers. A second attempt last year failed on a technicality. The project has already been approved by Kansas and Illinois.
But Michael Skelly, Clean Line’s founder and president, was undeterred. Moments after the PSC determined that Grain Belt had not obtained approvals from all the counties it would cross, Skelly turned to his staff and said, “We’re not giving up.”
The commission rejected that request Sept. 19. This time Clean Line responded by hiring former Missouri Gov. Jay Nixon and his law firm as Grain Belt’s legal counsel.
Nixon’s first bit of advice? Take the case to the Missouri Court of Appeals’ Eastern District, because the Western District had greased the skids for the PSC’s previous rejection when it ruled that an infrastructure project must secure approvals from each county it crosses. (See Clean Line Ponders Options After Grain Belt Rejection.)
Clean Line did just that on Sept. 19.
Staying Power
Skelly does not easily take “no” for an answer. Developing long-term projects requires vision and staying power, something Skelly learned as a founding partner of the Rain Forest Aerial Tram in Costa Rica’s rainforest. Skelly had come to the country as a Peace Corps volunteer after earning a bachelor’s in economics from the University of Notre Dame and an MBA from Harvard Business School.
Tenacity also was essential in his role developing wind farms as employee No. 3 for Zilkha Renewable Energy in the 1990s. Skelly was the firm’s chief development officer when it became Horizon Wind Energy after Goldman Sachs bought it in 2005. The banking giant sold Horizon (now EDP Renewables North America) for $2.2 billion in 2007.
Skelly then took a brief stab at politics, but after an unsuccessful run for Congress as a Democrat in Texas’ 7th District (he lost by 13 points), he turned his attention back to the power industry and wind energy.
Sensing an opening, he founded Clean Line in 2009. Skelly had financial backing from Houston’s Zilkha family, which had also bankrolled the wind company, and ZBI Ventures, owned by the Ziff family of New York.
Clean Line’s business model is building long-distance transmission lines to deliver wind energy to urban population centers. “We thought transmission was going to be the linchpin of expanding wind energy,” Skelly said. “If you look at the right technical solution to move lots of wind a long distance, you pretty quickly come to the conclusion that DC lines are the right answer. For anything over 100 miles [long], DC makes more sense. Then, thinking about it further, it was clear that the incumbents weren’t going to do this. It’s not their job to move energy to the Southeast or PJM. Their job is to focus on native load” and meeting demand.
“That felt like an opportunity for an individual to come in and tackle this job. No one else is going to do it.”
HVDC can cost as much as $2 million a mile, according to Clean Line. The high capital costs and the regulatory obstacles that have delayed construction led the company to seek additional financial backers. The company, which has almost 40 employees, has no current source of revenue.
In 2012, National Grid USA announced it was investing $40 million for about a 40% stake in Clean Line. In 2015, Bluescape Resources, an energy investment and operating company headed by former TXU Chairman and CEO C. John Wilder, agreed to spend up to $50 million for equity in Clean Line, with the potential to invest more in the company’s transmission projects.
Clean Line spokeswoman Sarah Bray said Bluescape is now the company’s “principal investor,” although National Grid, ZBI and the Zilkha family have retained equity stakes.
Project development for Grain Belt began in 2010, and in late 2012, the company was hoping to begin construction as early as 2015. Clean Line now says construction could begin in 2019, with the project operational as soon as 2021.
Besides Grain Belt, Clean Line is developing four other projects. Below is a description of the projects and their current status, contrasted with the company’s projections from 2012, where applicable:
The Rock Island Clean Line, a 500-mile project from northwest Iowa to Illinois, delivering 3,500 MW of wind energy. The project was originally expected to be operational in 2017. But on Sept. 21, the Illinois Supreme Court rejected the Rock Island application because Clean Line held only an option agreement on a parcel for a converter station — rather than a completed purchase agreement — when it applied to the Illinois Commerce Commission. The company said the ruling will cause “great delay” for the project. “Although we are disappointed with the Supreme Court ruling on the Rock Island Clean Line, on the positive side, the decision did not impact the authority of the ICC, and the court made clear that we have an opportunity to refile with the ICC at a later date,” the company said in a news release. The company hasn’t decided on its next steps.
The Plains & Eastern Clean Line, an approximately 700-mile project from the Oklahoma Panhandle through Arkansas to Memphis, Tenn., delivering 3,500 MW of power to the Tennessee Valley Authority and 500 MW to Arkansas. The company is involved in commercial negotiations with potential customers, both wind generators and loads seeking power. It will begin construction once it has contracts for 2,000 MW of capacity.
The Centennial West Clean Line, a 900-mile project delivering 3,500 MW of renewable energy from New Mexico and Arizona to California. The company had expected construction to begin in 2017 and be operational in 2019. Development has slowed down while the company works on its other projects.
The Western Spirit Clean Line, a 140-mile project complementing the Centennial West project, delivering 1,000 MW of renewable power from east-central New Mexico to markets in the western U.S. Clean Line acquired the project, originally named Power Network New Mexico, in 2013. Construction, which will take about one year, could begin by the end of 2018.
Like jugglers, Skelly and his staff must keep their eyes on many balls at the same time. The project teams are regionally based, but they enjoy legal, financial, communications, environmental and other support from Clean Line headquarters in downtown Houston, where black-and-white photographs of rock stars and the New York punk scene hang on the walls.
“You would think in eight years, you would have sort of a lull, but it’s a sort of a mad dash every day to move these projects forward,” Skelly said. “It’s more like an Ironman [Triathlon], not a marathon. It’s more like a decathlon, but it goes on for eight years.”
Projects that take so many years to put together will inevitably face changes at the federal, state and utility commission levels, Skelly said.
“One of the things you want to think about is putting together projects that can last through administrations,” he said.
One example: In March, the Arkansas congressional delegation — all Republicans — asked Energy Secretary Rick Perry to “preserve states’ rights” and reverse the Department of Energy’s decision to partner on the Plains & Eastern project over the objections of Arkansas officials. (See DOE Agrees to Join Clean Line’s Plains & Eastern Project.) The department had invoked Section 1222 of the Energy Policy Act of 2005, which, the legislators said, “risks codifying into law the practice of federal eminent domain seizures.”
The lawmakers also are sponsoring a bill that that would prevent the department from using eminent domain for Section 1222 transmission projects without the approval of both the governor and utility commission of affected states.
The project also has drawn the ire of Sen. Lamar Alexander (R-Tenn.), a member of the Energy and Natural Resources Committee, who said it could burden TVA with expensive wind power it does not need.
TVA has signed a memorandum of understanding with Clean Line, which has begun buying rights of way for the project. But neither TVA nor any other utility has signed a contract to buy the power the project would transmit.
Bray said she’s confident that Perry, the former Texas governor, will see the value of the project. “He’s seen the benefits of wind power first hand,” she said, citing the economic growth the state’s Competitive Renewable Energy Zone projects brought to rural Texas.
Skelly has said seeking DOE authority for the Grain Belt and Rock Island lines is an option but not his first choice because it is slow and costly.
Nothing to Show
Skelly doesn’t have to be reminded that Clean Line has yet to see a project come to completion, but that’s through no fault of the staff, he says.
“We haven’t done anything yet. We haven’t built anything yet,” he said. “You have to have a very motivated team. You have to be tremendously tenacious, you have to be creative. You’ve got to think long, long term. You have to have a team that works.”
Skelly said that while landowners’ opposition to transmission projects is “understandable,” the pushback from within the industry is more frustrating.
“We need to do a better job in embracing new ideas and innovation,” Skelly said. “If you separate [transmission and generation], you generally get more innovation. You don’t have the same level of common interests.”
Pointing to Commonwealth Edison’s opposition to the Rock Island project in Illinois, he said, “Why are they doing that? They’re doing that to protect their generation. If you look at what other countries are doing to build up their grid, they are embracing new ideas and innovation. They’re coming up with cost-effective solutions and they’re getting big projects done.”
ComEd did not respond to a request for comment.
In May, ComEd asked the Illinois Supreme Court to dismiss Clean Line’s appeal seeking to overturn an appellate ruling that reversed the ICC’s approval of the project. ComEd said the project had changed since the ICC’s approval in 2012.
Interregional Planning
Skelly is among those who have been frustrated that FERC Order 1000 hasn’t resulted in interregional transmission projects. WIRES, an industry organization supporting transmission investment, says the order has failed to produce true interregional planning because of inconsistencies in how neighboring regions evaluate projects.
“It is common for projects that are shown to provide benefits in interregional evaluations to fail regional evaluations for inclusion in regional plans,” the group said in comments following a FERC technical conference last year (AD16-18). (See Five Years Later, FERC Takes Another Look at Order 1000.)
WIRES also says transmission planning should model “a broader range of plausible market conditions, system contingencies and public policy environments” to consider the “flexibility benefits and insurance value that a more robust interregional transmission infrastructure can offer.”
In its grid study released in August, DOE called for a review of “regulatory burdens for siting and permitting” of transmission and actions to “accelerate the process and reduce costs.” (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)
Building Relationships
Clean Line has worked hard in Missouri to gain community support for Grain Belt. The company signed up more than three dozen cities to purchase about 100 MW of power from the project; many of the cities also offered statements of support. That $525 million project, the company says, will save the state’s consumers $10 million annually and create more than 500 permanent jobs to maintain and operate the wind farms and the transmission line.
“You have to build alliances,” Skelly said. “We’ve got support from labor groups, environmental groups, business groups, from political leaders … doing these projects without building those types of alliances would be really, really difficult.”
That relationship-building extends to RTOs. While SPP, MISO and other grid operators don’t manage long-distance DC lines, their responsibility for grid reliability comes into play when interconnections are discussed.
Clean Line also must “fit within the context of how they do their market operations,” Skelly says.
The RTOs’ “paradigm is around the cost allocation of projects built by incumbents, which comes out of their planning process. Their planning process doesn’t plan around significant transmission exports. We have to make sure and work with them, so our projects fit within the context of those plans.”
Skelly said Clean Line recently spoke with an SPP member concerned about congestion caused by wind farms in the RTO’s western footprint. “They said, ‘We used to think you were too early. Now, we can’t get you to build your project soon enough,’” he recalled.
‘Preservation and Adaption’
While his business is focused on energy sources of the future, Skelly is also a history buff and preservationist. He and his wife, Anne Whitlock, live in a renovated firehouse in East Houston, which was recently recognized by Preservation Houston as a “shining example of preservation and adaption.” Nearby sit six Victorian homes that Skelly had moved and refurbished.
Firestation No. 2 and the other buildings served as a refuge for residents forced from their homes during the flooding during Hurricane Harvey, an act that drew attention from The Washington Post.
Skelly writes occasional op-eds in the Houston Chronicle, in which he has advocated for making the car-centric city more pedestrian- and cyclist-friendly.
Optimistic About the Future
Meanwhile, an optimistic Skelly continues to look to the future. Although federal production tax credits for wind projects will expire at the end of 2019, he thinks continued technological advances in wind turbines will compensate for that loss.
“We thought that the combo of open-access, low-cost wind [that is] relatively easy to permit … would result in an overbuild of wind,” requiring transmission to move the excess energy to load centers, he said. “We didn’t think that would happen until 2030, but it’s upon us now. Over time, we are moving to a leaner energy mix, there’s no question. Economics favor that. That’s just reality.
“There’s a lot of people pulling for us. I don’t think [demand for renewable energy] is going away any time soon. There are very large consumers of power in this country that care about carbon [emissions], and they’re putting their money where their mouth is in how they source electricity.”
RENSSELAER, N.Y. — NYISO year-to-date monthly energy prices averaged $35.34/MWh in September, a 3% increase from a year earlier, Michael DeSocio, senior manager for market design, said Wednesday in presenting the ISO’s market operations report to the Business Issues Committee.
Locational-based marginal prices (LBMPs) averaged $29.57/MWh for the month, down 3.3% from August and 4.3% from September 2016.
The ISO’s average daily sendout was 437 GWh/day in September, down from 477 GWh/day in August and 458 GWh/day a year earlier.
New York natural gas prices gained 5% in September, averaging $2.27/MMBtu at the Transco Z6 hub. Prices were up 72.2% from a year ago. Distillate prices gained 32.3% year-on-year, with Jet Kerosene Gulf Coast averaging $13.40/MMBtu, up from $11.53/MMBtu in August. Ultra-Low Sulfur No. 2 Diesel NY Harbor averaged $12.80/MMBtu, compared with $11.65/MMBtu in August.
The ISO’s local reliability share was 16 cents/MWh, one-third higher than the previous month, while the statewide share “is trending lower at -50 cents/MWh,” compared with -31 cents/MWh in August, DeSocio said. Total uplift costs were lower than in August.
In speaking about the Broader Regional Markets report, DeSocio only highlighted that FERC last month accepted NYISO’s proposed Tariff revisions regarding cost recovery for the Ramapo PARs, as filed by the ISO in June. NYISO foresees negotiating with PJM by year-end the cost sharing for the replacement of PAR 3500.
Proposed Tariff Changes for Energy Storage
Solar inverter battery
The committee approved proposed Tariff and Ancillary Services Manual changes to define the role of inverter-based energy storage in providing synchronized reserves.
Daniel F. Noriega, NYISO associate market design specialist, presented the BIC-proposed Tariff changes that would allow generators and demand-side resources that use inverter-based energy storage technology to provide spinning reserves.
The ISO last year asked the Northeast Power Coordinating Council (NPCC) to clarify whether such resources can provide synchronized reserves. The NPCC responded that “a storage resource with inverter technology complies with the original intent of the synchronized reserve requirement and therefore shall qualify towards a [balancing authority’s] complement of synchronized reserves.”
NYISO in January presented its Market Issues Working Group with proposed Ancillary Services Manual revisions to reflect that clarification. Stakeholders provided feedback on the wording, which NYISO incorporated in the updated proposal presented Wednesday. NYISO intends to bring the proposed Tariff and manual changes to the Operating and Management committees for action this month.
Fuel Cost Adjustment Calculation to be Refined
The BIC also approved a proposal that would more closely align the real-time and day-ahead impact tests and penalty calculations used to identify generator misuse of fuel cost adjustments (FCAs). The current day-ahead process is considered more precise because it tests the impact on real-time LBMPs based on market reruns.
NYISO Mitigation Reference Analyst Nicholas Shelton explained that FCAs allow generators to submit a fuel type or fuel price — or a combination of both — along with their energy offers. Once the ISO validates the FCA is within posted thresholds, a generator can update its incremental energy and minimum generation reference levels to reflect the new information. The ISO’s Market Mitigation & Analysis unit reviews all FCAs, and those that fail the conduct and impact tests may be subject to penalty.
The ISO has found that reviewing FCAs from only the prior seven days does not ensure enough data are available to draw conclusions about tendencies toward an upward bias in prices. The proposed changes would combine the day-ahead and real-time market penalties into one section and lengthen the FCA review period to 90 days from the previous seven days.
According to the proposal, the 10% threshold used in screening for bias has become increasingly restrictive with the decline in natural gas prices, so that a $2/MMBtu price translates into a very tight threshold. Rather than using a 10% threshold to identify bias, the proposal would rely on the greater of 10% or 50 cents/MMBtu.
The proposed changes will go to the Management Committee in October and, if approved, be submitted to the Board of Directors in November prior to filing with FERC.
Editor’s note: An earlier version of this story incorrectly used data from the ERCOT North zone, and not the Houston Hub.
By Tom Kleckner
ERCOT’s Houston Hub saw real-time prices spike as high as $1,251/MWh on Monday during an early fall heat wave.
Hub prices first cracked $1,000/MWh during the 15-minute interval ending at 1:45 p.m. on Oct. 9, and then again during each of the 11 intervals between 2:30 and 5 p.m. The systemwide hub average peaked at $520.59/MWh during the 3:15 p.m. interval.
According to ERCOT data, the Houston Hub has now produced 47 intervals of $1,000/MWh this year. That’s the most since 2011, the first full year of the nodal market, when the hub recorded 163 high-priced events. It only had 87 occurrences in 2012-2016.
| ICF
Congestion has long been an issue in the Houston zone, but the high temperatures caught the market with several plants on maintenance outages.
Speaking during a Tuesday webinar, Dinesh Madan, an ICF technical director, said scarcity pricing has been “almost missing from this market.” Madan pointed to a volatile market, thanks to an overabundance of wind energy and short load forecasts.
“ERCOT is a weather-and-wind story now,” Madan said. “In 2016, the story was wind. In 2017, the story was weather.”
In 2016, wind resources generated 2,024 MW more than their forecasted output coinciding with the summer peak. In 2017, the market’s peak load was 3,428 MW below forecast, thanks to a milder summer. With ample reserves (and lower loads), ERCOT was able to withstand 2016 and 2017 peak loads despite generation outages exceeding forecasts by 1,780 MW and 2,713 MW, respectively, during each summer’s peak.
Monday’s spike came as Texas temperatures soared into the mid 90s. The ISO set a new record for October peak demand at 62,263 MW — just above projections — during the hour ending at 5 p.m., breaking the previous mark set the year before by more than 2.3 GW.
Houston Hub prices peaked at $34.11/MWh on Tuesday, when temperatures and ERCOT load both dropped.
Reservoir of Retirements
During the same webinar Tuesday, ICF Senior Vice President Judah Rose also addressed Vistra Energy’s recent decision to retire three aging coal-burning units in East Texas. (See First Shoe to Drop? Vistra to Retire 3 Texas Coal Units.)
He referred to a “reservoir” of potential retirements among ERCOT’s coal fleet, driven by fat reserve margins, low gas prices and cheaper renewable resources. Rose also pointed out that many of the coal plants, once reliant on cheap, local lignite — including Vistra’s Monticello plant — now depend on Powder River Basin coal brought in on rails from the Rocky Mountains.
| ICF
“Almost ironically, these plants are facing the least environmental pressure in a long time,” Rose said, referring to the Trump administration’s efforts to roll back the Clean Power Plan. (See EPA to Announce Clean Power Plan Repeal.)
He said the Energy Department’s recent Notice of Proposed Rulemaking to FERC to support out-of-market baseload plants would likely have little effect on Texas coal units, as the agency has no jurisdictional authority over ERCOT.
Any FERC policy “will not provide additional revenue,” Rose said. “The exit of these plants will be related to low power prices.”
Rose said ICF will be watching ERCOT’s reserve margins, which the ISO forecasts will be 16.3% next year. The firm expects that margin to dip below the planning reserve margin of 15.6% in 2019.
“That’s significant, because generally, when you start getting below 15% in markets, you have the potential for all hell breaking loose,” he said. “You get a lot of potential for price spikes.”
The Monticello retirement may provide $1 to $2/MWh of upside in scarcity equilibrium in 2019, Rose said.
WASHINGTON — Energy Secretary Rick Perry on Thursday defended his call for price supports for struggling coal and nuclear plants, telling the House Energy Subcommittee “these resources must be revived, not reviled.”
Perry also pushed back on criticism that his Notice of Proposed Rulemaking, which called for “full recovery” of the plants’ costs, would undermine competitive markets.
Republicans largely expressed support for the rule. But Perry did little to counter allegations that his action was motivated by President Trump’s campaign promises to help the coal industry — repeatedly sidestepping Democrats’ questions about the costs of his proposal and the evidence supporting the need for 90 days of on-site fuel.
“The base reason that we asked for this … is that, for years, this has been kicked down the road,” Perry said.
The NOPR, published in the Federal Register Tuesday, would require FERC-jurisdictional RTOs and ISOs with capacity markets and day-ahead and a real-time energy markets to ensure full cost recovery for any generation not subject to cost of service rate regulation that is capable of providing “essential energy and ancillary services” and has a 90-day fuel supply on site “enabling it to operate during an emergency, extreme weather conditions, or a natural or man-made disaster.”
Essential services include voltage support, frequency services, operating reserves, and reactive power. Just and reasonable rates for such generators would cover “its fully allocated costs and a fair return on equity,” including operating and fuel expenses and the costs of capital and debt, the NOPR said.
Countering Subsidies
Perry said he was attempting to counter subsidies that have benefited renewables at the expense of coal and nuclear. “There is no such thing as a free market for in the energy industry,” he said. “Government’s picking winners and losers everyday through regulations… and I’m at least honest enough to say it.”
Perry said the grid is normally resilient during “blue sky” days and said his support for an “all of the above” generation mix was proven during his time overseeing wind growth as governor of Texas. “But the wind does not always blow. The sun doesn’t always shine. The gas pipelines — they can’t guarantee every day that supply is going to be there.”
He said the NOPR was intended to “kick start a national discussion about resiliency and about the reliability of the grid.” Noting the vociferous opposition his proposal provoked, he chuckled, “And best I can tell we were pretty successful in doing that. …We’re having this conversation now that we really haven’t had in this country.” (See Consumer Advocates Slam Perry NOPR, RTOs, FERC.)
Indeed, about 50 companies, regulatory agencies and trade groups have intervened or made comments in the docket FERC opened to respond to the NOPR (RM18-1).
Not Supported by DOE Study
Rep. Frank Pallone (D-N.J.) said the NOPR was not supported by the grid study DOE released in August, asking Perry what analyses DOE or its national labs had done to support the proposal.
Pallone
Perry did not respond to the question, instead challenging Pallone’s premise. The DOE study, he said, didn’t address “with specificity the events I’m concerned about,” he said, citing the 2014 polar vortex.
Perry also sparred with Rep. Michael Doyle (R-Pa.), who said said the committee had held eight hearings on markets and reliability. “We’ve actually been having the conversation you claimed to be starting,” he said.
“This has been discussed for a long time, as you rightfully said,” Perry conceded. But he said it was now time for action.
Doyle
“Our RTO made that adjustment” after the polar vortex, Doyle said, referring to PJM’s Capacity Performance rules, which increased the penalties and bonuses for capacity resources during grid emergencies. “We feel pretty confident of our capacity in Pennsylvania.”
“’Pretty confident’ is not going to get it [done]” Perry shot back.
Doyle also pressed Perry on discrepancies between the NOPR, which repeatedly says FERC “must” act and the secretary’s reference to a conversation. (See FERC’s Independence to be Tested by DOE NOPR.)
“Is it a directive to FERC to do this or a conversation?” Doyle asked.
“Both,” Perry said.
“So, it’s a directive then?” Doyle asked.
“My words are what my words are. I don’t back off from them,” Perry said.
“It can’t be both,” Doyle protested. “So, which one is it?”
“Well actually it is both. I can be both. We can have a conversation and I think [FERC] must move. I think they must act. We’ve kicked this can down the road as long as we need to.”
Rep. Kathy Castor (D-Fla.) also said the NOPR conflicted with the findings of the grid study and said it would cost consumers and businesses billions. “There is just no rational basis for this new FERC rule that you’re trying to move through as quickly as possible,” she said.
“If the request … the NOPR to FERC is what you say it is, [FERC] won’t go forward with it,” Perry responded.
VALLEY FORGE, Pa. — Only a few PJM stakeholders attended Monday’s special Planning Commission session on cost-containment provisions in bids on transmission projects, but they came prepared to defend their opposing positions.
PJM’s Sue Glatz reviewed proposed changes to Manual 14F to incorporate cost-containment principles that were identified by stakeholders in previous meetings of the group, including submission requirements, what submission information will be kept private and evaluation guidelines.
Much of the debate at the Oct. 9 meeting occurred over what should or should not be specifically stated in the manual.
Sharon Segner, with merchant transmission developer LS Power, disputed PJM’s plan to require bidders to explain the rationale behind requested exclusions from the proposal’s cost cap. The decision could be for competitive reasons that don’t aid PJM’s analysis but might harm the bidder, she said.
Jodi Moskowitz of Public Service Electric and Gas supported PJM’s plan to require the supporting rationale for exclusions. She questioned why the requirement was a concern given that supporting information should be treated on a confidential basis.
“Isn’t a lot of this information redacted?” she asked.
Segner requested that the manual language guarantee the confidentiality of bidders’ explanations for any exceptions to their proposed cost cap, such as if the prices for certain materials change drastically or the anticipated siting route fails to receive approval.
“If you’re asking for supporting rationale [to be included within proposals], it should be made clear in the business practice language that that rationale will not be made public,” she said.
Glatz said she would investigate what changes might better protect “commercially sensitive language.”
Creating Clarity
Stakeholders disagreed on whether to enunciate that PJM will not consider any cost-cap guarantees beyond those related to construction costs, although they “may be included in the project proposals,” and that winning bidders are free to “propose, through the FERC ratemaking process, other cost-cap mechanisms associated with the project.”
Segner and Greg Poulos, the executive director of the Consumer Advocates of the PJM States, agreed that the language improves clarity, even if they didn’t agree with the policy itself. However, PSEG’s Vilna Gaston and Delaware Public Service Commission staffer John Farber opposed it because they felt it suggests powers that go beyond PJM’s actual authority.
“I think the FERC ratemaking process speaks for itself,” Farber said. “The PJM approval process should not be involved with those ratemaking issues.”
“You have no authority to say what someone can file or not file at FERC [or] what FERC can consider,” Moskowitz said.
Poulos and Segner agreed that their preference would be for “more opportunity for cost caps in other areas,” but that the language demarcates exactly what is PJM’s policy.
“I think this is a very helpful sentence because it creates clarity,” Poulos said. “It’s very clear what PJM is considering and not considering.”
“Part of the reason that this whole stakeholder process is going on is because varying types of cost containment proposals are being proposed,” Segner said. “I don’t think it’s obvious that other forms of cost containment won’t be considered unless it’s spelled out.”
“I think what I’m hearing is that people do like the clarity but don’t want something that creates the illusion” that PJM has authority to control what can be filed at FERC, Glatz said, attempting to summarize the proceeding.
‘Over the Top’
Gaston and Segner again clashed on whether to include requirements that any confidential information that is inadvertently disclosed could not be used in the future by any third parties for any purposes.
“I think that’s over the top,” Segner said in opposing the requirement, suggesting its intended purpose was to muzzle state regulators and consumer advocates.
“It’s not really about protecting the bidders against each other,” she said. “The issue is how it could be used against you later in a litigation proceeding, and you’re trying to put language in that would exclude that type of information in a litigated proceeding.”
“That’s not the intent,” Gaston said. “There’s confidential information that may be competitive information.”
Glatz said she’d ask PJM’s attorneys “how complicated that is” to include.
PJM hopes to receive endorsement for the rule changes in time for the upcoming planning year, which would mean bringing it to the Planning Committee for a vote in December at the earliest. Stakeholders asked for another meeting or video conference before then to finalize their requests. Glatz said she would search for an available date prior to the November committee meeting.
Now that EPA has reversed its position on the legality of the Clean Power Plan, some supporters of the program say the appellate court that heard oral arguments a year ago should rule on the issue.
Pruitt | EPA
In proposing to repeal the CPP, EPA Administrator Scott Pruitt said Tuesday that the Obama administration overreached its legal authority under Section 111(d) of the Clean Air Act by ordering generators to take actions “outside the fence line” of individual generators. (See EPA to Announce Clean Power Plan Repeal.)
That was one of the central issues in the appeal that Pruitt, as Oklahoma attorney general, filed along with more than two dozen other states after the CPP was issued in August 2015. In September 2016, the D.C. Circuit Court of Appeals heard oral arguments on that and other legal challenges to the plan.
In August, however, the D.C. Circuit agreed to hold the case in abeyance after President Trump’s executive order calling on EPA to reconsider the rule.
Judicial Economy
Profeta | Duke University
Attorney Tim Profeta, director of Duke University’s Nicholas Institute for Environmental Policy Solutions, said Tuesday that the D.C. Circuit should now rule on the case because of “the logic and judicial economy of the situation.”
“You’ve got the court of jurisdiction having heard en banc the precise legal arguments that are being made in this rule,” he said in an interview. “It’s fully briefed. It’s fully argued.”
If the court doesn’t act on the case before it, he said, “they will probably have the same case before them in new litigation that would have to be briefed and argued all over again. … There’s no reason for the court to waste its time and taxpayers’ money to relitigate the case,” he said.
David Doniger, director of the Natural Resources Defense Council’s Climate & Clean Air program, agreed. The court “could rule before [Pruitt] gets to the finish line on the repeal,” he said during a press conference Tuesday. “At least some of the judges there are looking at their wristwatches.”
Doniger was referring to the concurrence filed by Judges David S. Tatel and Patricia A. Millett on Aug. 8, when the court held the case in abeyance and ordered EPA to file reports monthly detailing the status of its review. The D.C. Circuit’s action followed the Supreme Court’s February 2016 stay preventing EPA from implementing the rule pending the legal challenges.
“As this court has held the case in abeyance, the Supreme Court’s stay now operates to postpone application of the Clean Power Plan indefinitely while the agency reconsiders and perhaps repeals the rule,” the two judges wrote. “That in and of itself might not be a problem but for the fact that, in 2009, EPA promulgated an endangerment finding, which we have sustained. … That finding triggered an affirmative statutory obligation to regulate greenhouse gases. Combined with this court’s abeyance, the stay has the effect of relieving EPA of its obligation to comply with that statutory duty for the indefinite future.”
Three judges nominated by President Obama to the D.C. Circuit Court of Appeals in 2013 are among 10 that could rule on the EPA Clean Power Plan. From left are Robert Leon Wilkins, Cornelia “Nina” Pillard and Patricia Ann Millett. The White House
During the oral arguments, Millett and Tatel had indicated sympathy for the Obama administration’s position that the CPP complied with Section 111(d). The term “best system of emission reduction” is “an awful broad grant” from Congress, Tatel said. “It says best system of emissions reduction,” he repeated twice, emphasizing “system.” (See Analysis: No Knock Out Blow for Clean Power Plan Foes in Court Arguments.)
Status Report
EPA filed a status report late Tuesday informing the court of the proposed repeal and asking it to continue holding the case in abeyance. “EPA will be signing in the near future an Advance Notice of Proposed Rulemaking that will solicit information on systems of emission reduction that are in accord with the legal interpretation that has been proposed by EPA,” said the report, which was signed by Deputy Assistant Attorney General Eric Grant.
Doniger said NRDC, which intervened in the case on behalf of the Obama EPA, has the right to defend the CPP now even if the agency no longer does. “Depending on what [EPA does regarding the delayed ruling], we’ll respond,” he said. “If they don’t do anything, we may do something [to request a ruling.] … We deserve a resolution of the legality of the Obama rule.”
If it chooses not to rule now, the court could set a deadline for final EPA action or grant additional short-term delays “to keep the pressure on,” Doniger said.
An EPA spokeswoman declined to comment on the status of the D.C. Circuit case, referring questions to the Department of Justice, which also declined to comment.
During oral arguments, Justice Department attorney Eric Hostetler told the court it should back the CPP under the Supreme Court’s Chevron decision, which held that courts should defer to agencies’ interpretations of the laws they are charged with enforcing unless the court finds their actions unreasonable. “This is far from the first time EPA has relied on generation-shifting,” Hostetler said. EPA’s rule, he added, is a “proper and sensible” response for the “most urgent threat that our country has ever faced.”
Returning to Prior Interpretation
CPP critic Jeff Holmstead, a partner with Bracewell and former EPA assistant administrator for air and radiation, had a very different view.
“In today’s proposal, EPA is not breaking any new legal ground. It is simply returning to the position that EPA had taken, under all prior administrations except the Obama administration, regarding the way in which industrial facilities can be regulated under a particular provision of the Clean Air Act,” he said in a statement.
“Under the CPP, the Obama EPA claimed that this 45-year-old provision actually gave it the extraordinary power to restructure the entire U.S. power sector — requiring that coal-fired power plants be shut down and replaced by wind and solar facilities favored by the Obama administration. Virtually every major business group joined 27 states in challenging this claim, arguing that the CPP was an example of historic regulatory overreach.”
Single Source
According to a draft of the proposed rulemaking that was leaked last week, EPA said it will interpret the CAA’s “best system of emission reduction” as referring to measures “that can be applied to or at an individual stationary source. That is, such measures must be based on a physical or operational change to a building, structure, facility or installation at that source, rather than measures that the source’s owner or operator can implement on behalf of the source at another location.”
The draft indicated EPA will not seek to reverse the agency’s 2009 finding that GHGs endanger public health.
EPA’s Obligation to Act
Doniger said EPA’s “legal obligation is to have an effective standard and one that reflects how the power system actually works.”
“Pruitt is operating under a fictional view — a 125-year-old view — that each power plant is operating by itself and serving the surrounding community alone. … Pruitt is constructing a legal argument based on a factual fiction — it basically assumes that there is no grid and there is no interconnection. And that’s among the reasons why his legal view will not prevail.”
MISO and PJM will submit new filings with FERC in response to a second deficiency letter regarding their pseudo-tie coordination efforts.
The commission’s deficiency letter seeks clarification on a proposed joint operating agreement revision that would allow the RTOs to terminate or suspend pseudo-ties that don’t acquire transmission service or follow modeling rules (ER17-2220). The language gives a native balancing authority the ability to redirect pseudo-tie output to avoid exceeding NERC operating limits. (See MISO, PJM Float Pseudo-Tie Coordination Plan.) PJM’s matching proposal triggered an identical deficiency letter (ER17-2218).
| MISO, PJM
FERC’s lingering questions include how and under what circumstances a native reliability coordinator would commit, de-commit or redispatch pseudo-tied generation to avoid exceeding system operating limits or interconnection reliability operating limits, features both RTOs say would be beneficial for maintaining reliability. The commission also asked the RTOs to clarify what constitutes a pseudo-tie suspension and delineate the grounds for such suspensions. It also seeks clarity on the rationale behind the 42-month notice to terminate a PJM pseudo-tie, all the possible grounds for termination and what process will be in place to handle contested terminations. The RTOs have until Oct. 28 to respond.
MISO will be working internally and with PJM to draft a response to the deficiency letter, MISO Director of Market Engineering Kim Sperry said at an Oct. 5 Reliability Subcommittee meeting. She provided no other details. MISO and PJM introduced the coordination efforts in early July.
The most recent letter comes five months after the RTOs received a deficiency notice on their pseudo-tie pro forma agreement. The pro forma has since been approved by FERC staff, but the commission ― which has since gained a quorum ― could overturn that approval. (See FERC Conditionally OKs MISO’s Pseudo-tie Pro Forma.)
MISO’s Independent Market Monitor has protested the new JOA language, saying “nothing in the filing ameliorates the myriad significant problems caused by the pseudo ties.” For more than a year, Monitor David Patton has called for the complete elimination of pseudo-ties, arguing that the process produces dispatch and reliability risks along with expensive congestion that is difficult to manage.
FERC on Thursday rejected a request by PJM to allow Linden VFT to convert the 330 MW of firm transmission on its lines between PJM and NYISO to non-firm, but the commission acknowledged it is moving forward with an investigation of the rules that required it to deny the request (ER17-2267).
The ruling mirrors one the commission made Sept. 8 in response to a similar request by Hudson Transmission Partners, which owns lines that carry 673 MW across the PJM-NYISO border (ER17-2073).
Those lines were part of a decades-old service agreement between Public Service Electric and Gas and Consolidated Edison that the latter company terminated in April. The service “wheeled” 1,000 MW from Upstate New York through PSE&G’s facilities in northern New Jersey and into New York City on the lines owned by Linden and Hudson.
A joint engineering analysis by PJM and NYISO found that continuing to wheel a 400-MW operational base flow (OBF) was the best option for maintaining system reliability. The OBF was implemented despite strong opposition from PJM stakeholders but is expected to be reduced to zero by 2021. (See NYISO Members OK End to Con Ed-PSEG Wheel.)
| PJM
In a separate order Friday, the commission approved changes to the PJM-NYISO joint operating agreement reflecting the new operational plan for the ABC and JK interfaces between New York and New Jersey, effective May 1, 2017 (ER17-905).
Linden and Hudson attempted to convert their firm transmission withdrawal rights to non-firm rights, but FERC denied both companies after PSE&G refused to accept the changes. Under the current rules, PSE&G has the right, as a party to the original interconnection service agreements (ISAs), to refuse them.
‘Preferential’ Rate
The New Jersey Board of Public Utilities, which supported PSE&G’s refusal, argued the requests are “an attempt to obtain a preferential rate for New York customers to the detriment of New Jersey ratepayers … because New York customers will continue to receive the same benefits … without any cost responsibility.” It also said the filings constitute “a collateral attack on PJM’s pending [Regional Transmission Expansion Plan] cost allocation methodology and its results in pending cost allocation proceedings” because the firm withdrawal rights are used in determining cost allocations. The changes would establish an alternative cost-allocation methodology “that would yield arbitrary results” compared to PJM’s current solution-based distribution factor (DFAX) method, the BPU said.
Following termination of the “wheel,” PJM asked FERC to reassign $533 million in costs related to the Bergen-Linden Corridor (BLC) project to Hudson, which the commission approved on April 25. The project upgrades facilities needed for the wheel. The New York Power Authority, which is contracted to use Hudson’s lines until 2033 and has taken control of the lines’ firm withdrawal rights, said the reassignment increased its allocation for the project to $645.42 million. It is seeking rehearing on the reassignment order (ER17-950).
FERC sided with PSE&G in both cases but acknowledged that the merchant transmission companies’ ISAs “may be unjust and unreasonable and unduly discriminatory” in not allowing the companies to unilaterally convert their firm transmission rights. The fact that the changes may impact PJM’s RTEP cost allocation “is a challenge to the justness and reasonableness of PJM’s RTEP cost allocation, not whether [the companies] should be able to relinquish [their firm transmission rights].”
In the Hudson case, FERC opened a separate docket (EL17-84). Linden, however, has already filed a complaint where FERC said it will address the issue (EL17-90).
Commissioner Cheryl LaFleur noted as part of the order rejecting Hudson’s request to convert its firm rights that she dissented in the order that applied the solution-based DFAX to the BLC. In certain situations, such as the short-circuit violations addressed in the BLC upgrades or the stability violations addressed by the Artificial Island project, “entities that use the lines may grossly overpay, while entities that benefit from resolution of the underlying violation underpay,” she said. (See Board Restarts Artificial Island Tx Project; Seeks Cost Allocation Fix.)
JOA Changes
In its order Friday, the commission approved revisions to interchange scheduling and market-to-market (M2M) coordination for the PJM-NYISO interfaces, finalizing a delegated order by FERC staff on March 31, when the commission lacked a quorum. The commission also rejected requests by PSE&G, the BPU and Linden to rehear the March 31 order.
The revised JOA combines the ABC and JK Interfaces with the 5018 line and the RTO’s Western ties into an aggregate PJM-NY AC proxy bus. The grid operators said the changes would make use of existing interchange scheduling constructs and support the phase angle regulators (PARs) on the interfaces. Pricing will reflect the impacts of imports and exports on the NYISO and PJM transmission systems, weighted by power flow distribution percentages.
In approving the changes, the commission:
Rejected complaints by PSE&G that there is no reliability need for the OBF and that the changes infringe on transmission owners’ rights;
Said Con Ed should not be charged for PJM RTEP projects, including the BLC project; and
Rejected NRG Energy’s protest over establishing a single price for the PJM-NY AC proxy bus and its complaint that the OBF is a barrier to open access under FERC Order 888.
