PJM and nine interstate pipelines have signed an information-sharing agreement to improve the reliability and flexibility of natural gas supplies for the RTO’s generators.
The pipelines said they are willing to sign contracts to “firm up” services for generators that do not have primary firm service. The MOU notes that the pipelines may require additional facilities to provide firm service.
Each of the pipelines will provide PJM a description of services they are offering to generators that could satisfy the RTO’s Capacity Performance requirements. They also agreed to provide PJM a summary of services that have been requested by generators and the status of those requests. PJM may share any information obtained under the MOU with the Independent Market Monitor.
In return, PJM will provide the pipelines with performance requirements for gas-fired generators serving as capacity resources, including a demonstration of access to firm gas during the peak hours of the electric day and evidence of hourly flexibility — ensuring that generators will not seek compensation due to an inability to procure gas outside the normal scheduling window.
“This agreement sets the stage for greater coordination between electric generators and the natural gas pipeline industry,” said PJM Chief Operations Officer Mike Kormos in a statement. “As electricity-generating facilities increasingly turn to natural gas, it is important that we all communicate clearly to assure reliable service.”
“Continued dialogue will result in more informed decisions by the PJM market participants that operate and rely upon gas-fired electric generators,” said Don Santa, CEO of the Interstate Natural Gas Association of America.
According to data from the U.S. Department of Energy, natural gas surpassed coal as the country’s top source of electric power generation for the first time in April.
The pipelines signing the MOU are Dominion Cove Point LNG; Dominion Transmission; Columbia Gas Transmission; National Fuel Gas Supply; Natural Gas Pipeline Co. of America; Tennessee Gas Pipeline; Texas Eastern Transmission; Texas Gas Transmission; and Transcontinental Gas Pipe Line.
The agreement will run through June 2016, after which it will continue on a month-to-month basis unless terminated by the parties.
CARMEL, Ind. — News that MISO is reconsidering a market congestion project in Southern Indiana sparked renewed complaints from developers over the RTO’s transmission planning processes.
MISO officials told the Planning Advisory Committee on Wednesday that they were considering swapping one Southern Indiana project for a second one on which PJM has offered to assume more than one-third of the cost.
Despite a potential $29 million in savings for MISO, transmission developers accused the RTO of disregarding its transmission planning process and not giving stakeholders enough time for review.
The new development came as some stakeholders were still simmering over the way in which MISO approved Entergy’s $187 million out-of-cycle upgrade near Lake Charles, La. Only a few hours before MISO’s presentation to the committee, PAC participants were discussing ways to restructure the out-of-cycle review and approval process to address their concerns. (See Ideas to Reform MISO Out-of-Cycle Process Emerge.)
But it seemed that any goodwill created by potential out-of-cycle reforms had evaporated by the afternoon, when MISO proposed replacing the Southern Indiana project that was judged as having the highest benefit-cost ratio among proposed market congestion projects in the North-Central region: the 345-kV Duff-Coleman project, estimated to cost $67.2 million.
MISO planners are considering replacing the 345-kV Duff-Coleman transmission project (red dotted line) with the 345-kV Rockport-Coleman project (blue dotted line). The Rockport-Coleman project’s benefit-cost ratio to MISO jumps from 14.4 to 23.4 when PJM assumes the cost of the transformer. (Click to zoom.)
MISO staff said they are considering replacing Duff-Coleman with the project with the second-highest cost-benefit ratio, the $76 million 345-kV Rockport-Coleman line.
PJM recently proposed picking up the cost of a 765/345-kV transformer connecting the Rockport substation. “This would potentially reduce the total MISO cost by $29 million and make Rockport-Coleman 345-kV … the project with the highest B/C ratio,” according to the presentation.
Stakeholder Feedback Loop
George Dawe, vice president at Duke American Transmission Co., was incredulous.
“What you’re saying is that this needs to be done quickly. And we’ve already heard about the cost estimation process [this morning] and how there’s supposed to be a stakeholder feedback loop and [yet] there’s a whole bunch of things that tend to need to happen at the last minute [without stakeholder review or process], just before the System Planning Committee needs to get a recommendation. And we scurry around to try to find answers,” he said.
‘Rigidity of Process’
Jeff Webb, MISO’s director of planning, denied that the RTO was “flipping gears” or that it was suddenly committing to Rockport-Coleman. Webb said MISO is only exploring the idea because PJM came to the table with an idea that provided potential cost savings.
“The only thing we don’t want to happen is the rigidity of the process, George, to interfere with progress in doing the right thing. And I don’t think [the Federal Energy Regulatory Commission] would want that either, unless in doing so that we are somehow egregiously creating an inequity for someone.”
Dawe complained that, while he had seen a lot of cost information about the Duff-Coleman project, “I haven’t seen anything on Rockport.”
Digaunto Chatterjee, MISO senior manager of economic studies, countered that the RTO has been evaluating both Southern Indiana projects since at least the beginning of the year, and thus it is not comparable to an out-of-cycle project request. “This isn’t a brand-new project. We’ve been studying it.”
‘Smells Like’ Cross-Border
Dawe and other stakeholders questioned whether PJM’s financial assistance made Rockport-Coleman an interregional project subject to review by the Interregional Planning Stakeholder Advisory Committee (IPSAC).
“My issue is that it looks and smells like a cross-border project. And it’s not following that cross-border project process,” Dawe said.
Flora Flygt, strategic planning and policy advisor at American Transmission Co., echoed Dawes’ concern. “We’re now taking what is part of an [market efficiency project] process and now we’re turning it into [a multi-value project], an interregional MVP, basically.”
Chatterjee disagreed, saying it is not an interregional project as defined in the RTOs’ joint operating agreement.
“We’ve been through the IPSAC and it has resulted in no projects,” Webb added. “We’re looking for a way to get something to result in projects.”
During its annual meeting in June, MISO said it will reevaluate metrics used in evaluating market efficiency transmission projects (MEPs) because of concerns they are unduly conservative and prevent viable solutions to congestion. (See MISO to Reevaluate Metrics on Market Efficiency Tx Projects.)
Delays Feared
Chatterjee said MISO will soon discuss the matter further with PJM and make a recommendation — likely at the next PAC meeting.
Flygt said she feared the review could result in delays, with the next PAC not until Aug. 19 and the MISO Transmission Expansion Plan (MTEP) is scheduled to go to the board Dec. 10. “We’re sitting here at the end of July,” she said.
Webb insisted the review would not cause delays, and PJM’s Chuck Liebold assured the committee that his RTO could quickly analyze an interconnection request.
“The first thing I said [to PJM] was if this keeps us from taking an MEP to the MISO board in MTEP 15, it’s a show stopper,” Webb said. “If there’s a delay we’re doing Duff-to-Coleman, OK? If we can get this done and we can show ourselves and stakeholders that this is a better deal for MISO, we certainly want to let MISO know that.”
11th Hour Concerns
Flygt said that FERC Order 1000 requires transparency at every point in the process. “When you’re in a competitive market and you’ve got these processes to follow, I think it’s more important to follow the process than the implication that we’re getting here.”
PAC Chairman Bob McKee said he was concerned that, after all the analysis, the proposed alternative was only coming up now. “Why are we getting all this shuttle diplomacy and all of this right at the 11th hour, right before we’re to go to the board?”
Webb replied that PJM became aware of the potential for a win-win solution, albeit “late in the game.”
“I think it’s unfortunate that the awareness came late and I think that’s a process issue. That’s the point I’m raising,” McKee said.
No Violation of MISO Process
Kip Fox, director of transmission strategy and grid development at American Electric Power, said MISO identified three projects with similar benefit–cost ratios. “In my mind, this is the way the process is supposed to work. I don’t see a lot of process change. These projects have been talked about ever since we went through the [market congestion planning study] process.”
McKee wasn’t buying it. “I would say I respectfully disagree that this is how the process should work. The reason why I say this is that, look at all the confrontation that we’ve had,” he said.
Webb said if a plan is presented to MISO stakeholders that produces more benefits to the RTO at a lower cost, but the stakeholders rejected it because it didn’t follow a certain process that they were comfortable with, “I think we will want to make that clear so that FERC at the end of day can react to that too.”
If MISO stakeholders demonstrate that the project doesn’t follow the process and can’t be done, “then that’s probably the way it will end up,” he added.
Webb said that it was “a little murky” to him about what part of the process MISO is violating.
“We had the [Rockport-Coleman] project here already. The only thing new is that the entity that we already had studied, that we were going to connect to [PJM], said, ‘Yeah, that’s a great idea. … That’s the only change so I’m not sure that’s a big process change.”
KANSAS CITY — The Integrated Marketplace’s first 12 months of operations provided the highlights for SPP’s 2014 State of the Market report, which notes a maturing market, changing congestion patterns due to completed transmission projects and lower energy prices.
Alan McQueen, director of SPP’s Market Monitoring Unit (MMU), briefed the Board of Directors/Members Committee last week on the draft report.
The report says the market, which went live in March 2014, “provided wholesale electricity at modest prices that compare favorably to those in regions with well-established markets,” with LMPs generally tracking the steadily decreasing price of natural gas.
“We saw significant maturing and growth in the market, maturing in the market participants and in how they participated in the market,” McQueen said. He pointed to “robust participation” in the day-ahead market, with 99% of the reported load clearing, efficient management of wind resources and reductions in uplift.
“We saw fewer make-whole payments in this market, and that’s a good thing,” McQueen said. The report said make-whole payments made up less than 1% of electricity’s “all-inclusive price,” with 70% of make-whole payments related to reliability unit commitments.
Golden Spread Electric Cooperative’s Mike Wise, however, challenged McQueen’s assertion. He said the market’s make-whole payments are low because of its over-reliance on simple-cycle combustion turbines as quick-start resources in the RUC market.
“The market wants to use them all the time, but it’s not paying the startup costs,” Wise said. “We’re having more maintenance costs because they’re being run so much.”
In response, McQueen said the Monitor doesn’t believe startup charges should be included as costs recovered through make-whole payments.
“It’s an area of concern, but we have a difference of opinion,” McQueen said.
McQueen said the Market Working Group will study the issue further.
McQueen said there also needs to be further discussion with the MWG related to the transmission congestion rights (TCR) market. He said TCRs have been underfunded each month (85% of full funding), while the opposite is true of auction revenue rights positions (112% of full funding). “The concern is that if all the ARRs and TCR rights are allocated early in the process, they can’t be supported by the market later in the year.”
The report recommends reducing the amount of transmission capacity made available in the TCR and ARR process, earlier reporting of planned transmission outages and improvements to modelling of the conversion of ARRs to TCRs.
(Click to zoom.)
The report also said SPP successfully integrated 9 GW of wind turbines in 2014. Wind produced as much of 33% of the RTO’s energy needs during the year. The market also navigated a winter-weather event with a natural gas supply shortage in March and coal delivery delays through the summer and fall.
Board Chairman Jim Eckelberger said his reading of the report indicated “we have done a good job starting the market, but it seems we’re missing a lot of equipment members have to offer.” He asked MOPC chair Noman Williams of South Central MCN to brief the MOPC and MWG on the report to ensure “good ideas are being pursued” and gather additional feedback on market improvements.
“I disagree with how the MWG has approached this thing. I think rapid-cycle CTs need to be handled differently,” Eckelberger said. “I want to ensure Noman makes sure all sides are addressed.”
NEW YORK — While the New York Public Service Commission may seem to be driving the Reforming the Energy Vision initiative, it is public demand for more control over their energy choices that is the true driver, speakers said at the Infocast New York REV Summit last week.
The challenge, said Jigar Shah, president of Generate Capital, is harnessing the public interest and providing the regulatory structure to enable markets to provide services and technologies that support distributed energy resources (DER).
“Customers do want access to innovative technology, that’s absolutely true, but whether it’s 50% of customers, or 10% of customers, it doesn’t matter. That 10% can create a grassroots movement that’s the type that bowls over politicians. You don’t need 50%,” said Shah, the founder of renewable generator SunEdison.
Shah said the relationship of the utility with the public radically changed as a result of Hurricane Irene and Superstorm Sandy in 2011-12, “with people saying, ‘Wow, I can be out of power for two weeks, and what can I do to solve that problem?’”
That also changed the role of regulators, said Anthony Belsito, a PSC policy advisor. “The former model was regulating from the top down, and it was easy to hang out in the ivory tower,” he said. “… We’ve seen public involvement in the two REV proceedings that so far has been unprecedented.”
O’Brien
David O’Brien, vice president of BRIDGE Energy Group, said New York’s initiative is a start. “Are regulators fully prepared to tackle these issues or to look at the complexity of all this? My feeling is not necessarily,” he said. “But what I really like about REV is its comprehensiveness.”
DeCotis
Paul DeCotis, a director at West Monroe Partners, also expressed doubts. “I have a real concern that there’s a lack of real hard evidence on how to determine the impact [of DER] on cost,” he said.
“There’s a real reason there’s a tension in this room,” said Chris Hickman, CEO of Innovari. “At its core, everybody here knows we better not screw this up.”
Federal regulators’ approval last week of SPP’s request to terminate an interconnection agreement with the proposed Tres Amigas “superstation” won’t hurt plans to unite the three major U.S. grids, developers said (ER15-1797).
“In our minds, it’s not that significant,” Tres Amigas CFO Russ Stidolph said in an interview Monday. “While the ruling canceled the agreement, it also said as soon as the participants are ready to work together again, they can. It’s not the end of the world for us.”
The Federal Energy Regulatory Commission’s ruling ending the agreement with Xcel Energy’s Southwestern Public Service noted that Xcel and SPP are “willing to work with Tres Amigas” on a new interconnection agreement once the developers can meet contractual milestones.
‘No Appreciable Progress’
SPP filed the termination request in May after the company told FERC that Tres Amigas had failed to make an initial $1.4 million payment. SPS said it had already agreed to cut the payment from $7.5 million and that it extended compliance deadlines four times, delaying the agreement’s commercial-operation date by two years.
Xcel said that Tres Amigas made “no appreciable progress toward placing its transmission line project in service or interconnecting with the SPS transmission system,” creating uncertainty for SPS as it plans its transmission system.
Stidolph said making that payment would have committed Tres Amigas to spending $500 million immediately. “That was not a good use of capital for us,” he said.
Tres Amigas would connect the Eastern Interconnection, Western Interconnection and Texas Interconnection through HVDC lines. Developers say the project would use the latest power grid technology to “facilitate the smooth, reliable and efficient transfer of green power from region to region.”
SPS would provide Tres Amigas with its link to the Eastern Interconnection. The project would be built on 14,400 acres in Curry County, N.M., near the city of Clovis and the Texas border.
Fundraising Slow
Project developers have been slow to raise funds for the $1.6 billion project and have yet to set a groundbreaking date after initially saying construction would begin in 2014. In January, Curry County commissioners voted unanimously to ask the state to reallocate $350,000 intended for Tres Amigas, so the county could use the money elsewhere.
Asked about groundbreaking, Stidolph said Monday, “I think you will see activity out there by year’s end.”
Stidolph said Tres Amigas is finalizing agreements with wind developers that would ship power from eastern New Mexico to the west.
“We’ve had no issue giving [Public Service Co. of New Mexico] notice to proceed on the western side,” he said. “We’ve posted significant capital there.”
Tres Amigas protested the termination because, “given the complexities of its project, it has not been able to secure funding.”
“Transmission development is not easy,” Stidolph said. “It takes longer than you think, and it always ends up costing more.”
The interconnection agreement, originally filed in 2013, would have linked a 73-mile, 345-kV Tres Amigas-owned transmission line providing a 750-MW, two-node intertie between the SPS transmission system in the Eastern Interconnection and the PNM transmission system in the Western Interconnection.
Texas Roadblock?
The project may also be facing further roadblocks in Texas, which has long prided itself on having its own electric grid, exempt from FERC regulation. In June, Texas Gov. Greg Abbott signed into law a bill that gives the Public Utility Commission of Texas the ability to sign off on major power lines connecting ERCOT to multi-state grids elsewhere.
State Sen. Troy Fraser, the bill’s author and a long-time proponent for the Texas electric industry, believes the state should make those kinds of decisions.
“These interconnections can create tremendous risk for our electric system, including having Texas lose control over its own electric system,” Fraser said during hearings in March.
The bill says electric utilities or municipally owned utilities “may not interconnect a facility to the ERCOT transmission grid that enables additional power to be imported into or exported out of the ERCOT power grid,” unless a certificate of convenience and necessity (CCN) is obtained from the PUCT. The bill requires the application for a CCN be made at least 180 days before the developer seeks a FERC order related to the interconnection.
Tres Amigas is one of several projects managed by Connecticut-based AltEnergy, an investment fund focused on alternative energy and agriculture.
Tests conducted by the Department of Energy and the University of Hawaii have shown it is possible to generate energy using ocean waves and then transmit it to the state’s power grid. In tests that started this summer, a 20-kW wave energy generator was installed off the coast of Oahu and started trickling energy into the grid. The wave energy converter, called Azura, is made by Northwest Energy Innovations, of Portland, Ore., and is one of the first attempts to demonstrate the practicality of a technology scientists have long envisioned.
The floating platform captures the up-and-down and side-to-side motion of waves, converting it to electricity. It is anchored in water about 100 feet deep at a U.S. Navy testing facility. The small generator doesn’t even produce enough energy to serve a single household, but researchers say the data collected will be used to plan for a larger project in the future.
“Utilities and power project developers won’t even consider buying wave power technology unless they can see what an independent third party says it can really do,” said Steven Kopf, Northwest Energy Innovations CEO. “So we’re consciously running this test in all sorts of conditions, even when wave conditions are suboptimal for power production, just to get a complete picture of performance.”
House Speaker John Boehner said he favors lifting the ban on U.S. crude oil exports, a move that he said would create about a million jobs and strengthen the domestic oil industry. “If the administration wants to lift the ban for Iran,” Boehner said last week, “certainly the United States should not be the only country left in the world with such a ban in place.”
The ban was implemented after the Arab oil embargo of the 1970s, at a time when reduced imports drove up gasoline prices and even resulted in rationing. But since then, and particularly in the last 10 years, U.S. oil production has surged, partly because of the adoption of fracking.
Boehner joined Sen. Lisa Murkowski (R-Alaska), chairwoman of the Senate Energy and Natural Resources Committee, who is also pushing for lifting the ban.
DOE Expands Renewable Assistance to 5 American Indian Tribes
The Department of Energy is lending technical assistance to five American Indian tribes working on renewable energy projects.
The Blue Lake Rancheria Tribe of Blue Lake, Calif., is getting help producing a community microgrid with solar generation and battery storage. The Grand Portage Band of the Chippewa Indians in Minnesota will be getting help to determine the best way to transmit energy from a 2.5-MW wind project to tribal homes and facilities. The Oneida Tribe in Wisconsin is getting technical assistance on a 700-kW solar project. The Picuris Pueblo of Peñasco, N.M., is getting assistance developing a 1-MW solar project. And the Ute Mountain Tribe in Towaoc, Colo., will get help investigating the feasibility of community-scale solar as well as small-scale and closed-loop hydro projects.
These five tribes now join five Alaska Native villages getting federal technical assistance on a variety of energy efficiency and renewable energy projects.
Alberta Energy Minister Marg McCuaig-Boyd says that the decision on the Keystone XL Pipeline is out of the provincial government’s hands and that it will not devote any more energy lobbying for the controversial project.
“It’s in their hands,” the minister said, referring to the Obama administration. Her comments came in the wake of published reports that quoted Sen. John Hoeven (R-N.D.) saying that President Obama would reject the pipeline, probably this month.
A White House press official said that a decision would come during Obama’s time in office but wouldn’t elaborate. The pipeline would be a major link in getting Alberta’s oil sands to market, but there are competing pipelines in the planning stage. McCuaig-Boyd said Alberta would concentrate on those instead.
“We’re going with the ones that are probably going to have the most success soonest,” she said. “Energy East has some promise, and so does Kinder Morgan’s Trans Mountain. Those are the two right now to put our energies into.”
Kinder Morgan Hearing Draws Hundreds in Massachusetts
A Federal Energy Regulatory Commission hearing on a proposed Kinder Morgan pipeline drew hundreds of people last week, including nearly 100 who testified. Most were critical of the plan for the 412-mile pipeline, although some construction union representatives said they were in favor of it. The scoping session in Greenfield, Mass., was held to take public comment and help determine which issues FERC should address in its Environmental Impact Statement.
The Northeast Energy Direct pipeline would deliver Marcellus shale gas from Pennsylvania to markets in the Northeast. Existing pipelines serving the region are overburdened, as evidenced by the natural gas shortages during winter storms in the last two years.
A joint letter from six Massachusetts legislators asked FERC to stop the permitting work that has been conducted so far and to start over. The lawmakers and other opponents noted that Kinder Morgan only recently released thousands of pages of environmental and technical information and contended that the current permitting timeline doesn’t allow enough time to examine it all.
The Federal Energy Regulatory Commission on Wednesday said it needed more time to consider rehearing requests of its June 9 order largely approving PJM’s Capacity Performance plan after receiving a flurry of feedback from state regulators, consumer advocates, generators and the Independent Market Monitor.
The order is only a procedural motion; without commission action within 30 days of a rehearing request, the request is automatically denied.
“In order to afford additional time for consideration of the matters raised or to be raised, rehearing of the commission’s order is hereby granted for the limited purpose of further consideration,” it said. “Rehearing requests of the above-cited order filed in this proceeding will be addressed in a future order.” No answers to the rehearing requests will be entertained, it said.
PJM’s new Capacity Performance product, a response to poor generator performance during the polar vortex of January 2014, aims to increase reliability by rewarding over-performing participants and penalizing non-performers. (See FERC OKs PJM Capacity Performance: What You Need to Know.)
In seeking a rehearing of FERC’s approval, generators sought to relax the penalty provisions.
The PJM Industrial Customer Coalition, environmentalists, regulators and consumer advocates asked that demand response be allowed to participate in the transition auctions. On July 23, FERC issued a ruling ordering PJM to include DR and energy efficiency, thus delaying the auctions. (See FERC Orders PJM to Include DR, EE in Transition Auctions.)
Essential Power, Competitive Power Ventures, NextEra Energy and Invenergy Thermal Development contested FERC’s decision to eliminate monthly stop-loss limitations and said the commission erred in deciding that generator non-performance would not be excused, even in circumstances beyond their control.
The PJM Board of Managers today approved staff’s recommendation for the stability fix at New Jersey’s Artificial Island, despite numerous objections from spurned bidders and representatives of the Delmarva Peninsula, which will be allocated nearly the full cost of the project.
Winner LS Power’s proposal involves laying a 230-kV line under the Delaware River as well as expanding interconnection facilities at the nuclear complex, the latter task being assigned to Public Service Electric & Gas and Pepco Holdings Inc.
“These projects will resolve the operational performance issues around the Artificial Island area and provide important transmission support for the sub region,” said outgoing CEO Terry Boston in a letter to members following the private board meeting.
“The board also recognizes the valid concerns raised by [Delaware Gov. Jack] Markell, the Delaware Public Service Commission, the Maryland Public Service Commission and others regarding the allocation of costs associated with this project. PJM must follow its Tariff,” he said.
“With regard to the cost allocation provisions applicable to this project, PJM also must respect legal precedent in the Atlantic City case allocating specific rate filing responsibilities between PJM and its transmission owners. Nonetheless, we recognize that several parties have appropriately questioned the specific allocation in this case,” Boston continued. (See Officials Urge PJM to Reject Artificial Island Proposal.)
“Accordingly, PJM will continue to provide technical analysis and information to affected stakeholders in order to help [the Federal Energy Regulatory Commission] with its ruling on this particular cost allocation and its cost allocation rules in general.”
PJM planners outlined their rationale in a 44-page white paper, noting that $246.42 million of the $275.45 million total cost estimate will be assigned to the Delmarva transmission zone, with the remaining $29.03 million allocated to other transmission zones based on load ratio shares.
“This pilot case implementing Order 1000 principles and a competitive solicitation process will continue to be examined for a number of ‘lessons learned,’” Boston wrote. “The board thanks the Planning Committee for its thorough review, and we urge the adoption of changes that will improve the planning process.”
According to the Delaware Public Service Commission, the project could translate to a 25% increase in transmission costs in Delaware. Some of the state’s heaviest users could see their monthly bills surge by hundreds of thousands of dollars, Markell said.
In a statement Wednesday, Markell said, “I continue to have serious concerns about the cost distribution associated with the proposal approved by PJM, which would force Delawareans to bear a high cost for a project that provides little benefit to the state. I am working with the PSC and others concerned about this result to explore our options moving forward.”
A number of those dissatisfied with the cost allocation recalled the board’s rejection last summer of a Public Service Electric & Gas proposal to upgrade Artificial Island following outcry from losing bidders, environmentalists and New Jersey officials. (See PJM Board Puts the Brakes on Artificial Island Selection.) They urged the board to again halt the project.
PJM staff announced at a special April 28 meeting of the Transmission Expansion Advisory Committee that they would recommend LS Power’s plan to use horizontal directional drilling under the Delaware River to build a new 230-kV circuit from Salem, N.J., to a new substation near the 230-kV corridor in Delaware, tapping the existing Red Lion-Cartanza and Red Lion-Cedar Creek 230-kV lines. (See PJM Staff Picks LS Power for Artificial Island Stability Fix; Dominion Loses Out.) LS Power’s proposal also includes the option of an overhead crossing.
Home to the Salem and Hope Creek nuclear reactors, Artificial Island is the second largest nuclear complex in the country.
PJM’s competitive solicitation process sought “transmission improvements to provide the ability to generate maximum power from all three Artificial Island nuclear units while maintaining transmission system voltage within limits during various contingencies and line outages.”
SPP’s latest analysis of the Environmental Protection Agency’s draft Clean Power Plan indicates state-by-state compliance with the plan would result in nearly 40% higher costs than a regional approach.
According to SPP’s state-by-state compliance assessment released Monday, meeting the goals outlined in EPA’s draft rule would cost an estimated $3.3 billion annually in new generation capital investment and energy production costs. That is $900 million more than the $2.4 billion per year under a regional approach, on which SPP released a report in March. (See SPP: $45/ton Adder, Wind, Gas Meets EPA Carbon Rule.)
The assessment analyzed the rule’s impact on existing generation and resource-expansion plans. It did not include the cost of new transmission needed to maintain reliability, gas-infrastructure expansion, market-design changes or transmission congestion.
A final version of the rule is expected to be released in August. The draft version proposes reducing U.S. carbon dioxide emissions 30% from 2005 levels by 2030.
More Disruptive
Lanny Nickell, SPP’s vice president of engineering, told the RTO’s Regional State Committee on Monday that a state-by-state compliance approach would be more expensive to administer than a regional approach. He said a state-by-state solution “would be more disruptive … to the significant reliability and economic value that SPP provides to its members as a regional transmission organization.”
Nickell offered the example of one state taking a physical approach to carbon-reduction and limiting the amount of coal generation in November and December, only to have a neighboring state take a different approach and add renewable generation. That might force the first state to resort to additional coal generation to maintain grid reliability.
“All we look at in our market systems is price,” Nickell said. “The price offered into the market in [one state] could force the dispatch of more energy than planned elsewhere.”
A previous analysis predicted that SPP’s Integrated Marketplace, which went online in March 2014, would yield its participants $131 million in annual net savings in its first year. According to the latest report, SPP expects a reduction in the Integrated Marketplace’s savings to comply with the rule under any implementation strategy, but a state-by-state approach “would have a much more negative impact.”
SPP’s analysis was based on EPA’s proposed individual state-reduction goals in its draft rulemaking. SPP said its study does not take a position on the appropriateness of those goals or EPA’s supporting assumptions.
Apples-to-Apples
SPP’s state-by-state approach used the same analysis format as it did with March’s regional approach, using a $45/ton carbon-cost adder for an “apples-to-apples” comparison between the two plans. As before, the carbon adder was used as a mechanism to simulate the dispatch of lower carbon-emitting resources.
Click to zoom.
Coupled with modifications to current resource plans, the report said, that would “indicate the implications of meeting SPP’s regional and states’ emissions goals by 2030.”
The assessment says up to 15.1 GW of generation expected to continue running under current planning assumptions could be at risk of retirement under a state-by-state compliance approach. The study also added 5.5 GW of wind energy and 4 GW of gas-fueled resources above currently planned capacity, which already includes approximately 4 GW of new wind and 22 GW of new gas resources.
However, the assessment did not take into account renewable tax credits, currently being debated in Congress. The Senate Finance Committee last week voted 23-3 to approve extending tax credits for wind energy, along with subsidies for biodiesel and cellulosic ethanol.
“We did not assume renewable credits would be an option, because we interpreted the draft plan as they wouldn’t be allowed,” Lanny Nickell said. “Now the final plan may very well allow those credit exchanges over state boundaries.”
SPP did use wind as a reasonable abatement measure in both the regional and state-by-state compliance assessments, because of the high wind potential in most SPP states and the desire to maintain a consistent approach for comparisons.
The state-by-state compliance scenario’s analysis assumed approximately 4,700 MW of coal retirements incremental to those retirements already planned. SPP said this assumption could be conservative, as its analysis indicates nearly all the region’s existing coal-fired generation would operate above an 80% capacity factor in the business-as-usual model, but approximately 13,400 MW of coal-fired generation would operate below an 80% capacity factor after applying the $45/ton carbon-cost adder.
Three Models
The state-by-state assessment used three different models: a business-as-usual (BAU) case, a BAU model with the $45/ton carbon-cost adder, and a third model with a variable cost adder.
Incremental coal retirements were assumed using a tiered approach. The first tier came from additional information gathered in preparation for a 2017 transmission-planning study. Updated projections found an additional 300 MW of coal units expected to be retired by 2030. The next three tiers took an age-based approach, targeting units’ ages in 2030: over 60 years, 55-60 years and 50-55 years.
The state-by-state compliance plan is the third study SPP has conducted of the proposed Clean Power Plan. The RTO’s first study in October 2014 found that the rule did not allow enough time to build the generation and transmission infrastructure needed to maintain system reliability and avoid severe system overloads that could lead to cascading outages.
Consumers in states that focus on carbon-free generation and energy efficiency to comply with the Clean Power Plan could see significant cost savings, according to a study by Synapse Energy Economics. The consultant estimated that residential consumers could see bills averaging $35 a month lower by 2030, according to the study.
The study shows savings greater than the Environmental Protection Agency estimates and counters those that predict the carbon-emissions mandates will increase energy costs. The U.S. Chamber of Commerce, for instance, said some states could see energy costs increase about $200 a year per family after the Clean Power Plan is adopted.
The report also predicted that compliance with the rule would reduce carbon emissions by 58% by 2030, nearly twice the reductions mandated.
Jeb Bush Calls for End to Fed, State Energy Subsidies
Former Florida Gov. Jeb Bush told a crowd in New Hampshire that the United States should discontinue tax credits that have subsidized the growth of the wind and solar industries. And in what many could see as a break from his family’s oil-industry roots, he also advocated cutting oil and gas industry subsidies.
“I don’t think we should pick winners and losers,” said the Republican presidential candidate. “I think tax reform ought to be to lower the rates as far as you can and eliminate as many of these subsidies — all of the things that impede the ability for a more dynamic way to get where we need to get.”
Ben Schreiber, of Friends of the Earth Action, agrees that it is time to cut oil and gas subsidies, but he thinks tax breaks for renewable energy should stay in place. “We cannot suddenly decide that renewables can compete fairly after decades of taxpayer support privileging polluters,” he said.
Mass. Senate President Asks FERC for More Public Review on Pipeline
Rosenberg
Massachusetts Senate President Stan Rosenberg, a Democrat from Amherst, thinks the public needs more time to review the Tennessee Gas Pipeline’s $3.3 billion natural gas pipeline proposal and he has asked the Federal Energy Regulatory Commission to postpone a scoping hearing.
Rosenberg joined other pipeline opponents in trying to postpone the meetings. The meetings are a step in an approval process that would allow the Kinder Morgan subsidiary to build the pipeline across northwestern Massachusetts, New Hampshire and terminating in Dracut, Mass. If the pipeline is approved, it would be allowed to obtain rights of way by eminent domain, bypass some building regulations and cross environmentally protected areas.
Several opposition groups have already tried, and failed, to get FERC to delay the process.
FERC: 128 MW of Biomass Generation Added this Year
The Federal Energy Regulatory Commission’s Office of Energy Projects reported that biomass-fueled projects generating 128 MW have been added to the U.S. portfolio in the first six months of 2015.
Seven projects, including a 95 MW waste-to-energy project in Palm Beach, Florida, were added to the country’s generation fleet. That compares to a total of 137 MW of biomass projects in all of 2014. Biomass projects typically use wood as a fuel.
NRC Closes Inspector’s Office at Vermont Yankee Plant
The Nuclear Regulatory Commission has closed its resident inspector’s office at Entergy’s Vermont Yankee nuclear generating station, which retired in December and is undergoing decommissioning. The NRC has had a resident inspector at the site since the Resident Inspector program was launched.
The regulatory agency will continue to conduct periodic inspections at the plant, however. And when a major decommissioning work is undertaken, such as spent-fuel removal, an on-site inspector will be on hand.
The Nuclear Regulatory Commission says there are no environmental reasons to deny operating license renewals to Exelon Nuclear’s Byron Generating Station. A week ago, the NRC said there were no technical reasons to deny a similar extension for the company’s Braidwood Generating Station.
Exelon is seeking 20-year license extensions for both plants. If approved, Byron Unit 1 would receive a license good through Oct. 31, 2044, and Unit 2 would be good until Nov. 6, 2046.
Judge Orders US Government to Pay $20.6M to Entergy on Waste Issue
A federal claims judge in New York denied a U.S. government motion to appeal an order requiring it to pay $20.6 million to Entergy Nuclear Palisades for failing to meet its responsibility to dispose of the plant’s radioactive waste.
Judge Nancy Firestone of the U.S. Court of Federal Claims granted Entergy’s request for partial judgement of $20.6 million of a total damage claim of $36.4 million. She ruled the government had a duty to pick up and dispose of the plant’s spent fuel under a 1983 contract and never fulfilled it. Government attorneys didn’t dispute the breach of contract, but they argued that the amount should be determined during the upcoming trial in December.
“Because the government has already agreed that it owes plaintiff approximately $20.6 million in damages, the outcome of the remaining portion of the litigation will not have any effect on the government’s obligation to pay that amount,” Firestone wrote. The government has been unable to live up to any agreements to dispose of spent nuclear fuel because it has been unable to build a spent-fuel repository.
BOEM Offering 22 Million Offshore Acres to Energy Exploration
The Bureau of Ocean Energy Management scheduled an auction for Aug. 19 on oil and gas leases on about 21.9 million acres in the Gulf of Mexico off Texas. The auction will include all available unleased areas in the Western Gulf of Mexico Planning Area.
The area is divided into 4,038 blocks, from nine to 250 nautical miles offshore, according to Abigail Ross Hopper, bureau director. She said the water depths of the areas range from 16 feet to more than 10,975 feet.
It will be the eighth sale in BOEM’s current five-year program. The first seven auctions generated nearly $2.9 billion in revenue for the federal government.
