The Federal Energy Regulatory Commission last week denied a request to reinstate a generator interconnection agreement terminated by MISO last year after a wind developer failed to make milestone payments.
The commission denied Shetek Wind’s request to rehear an order it issued last October accepting MISO’s termination of the GIA (ER14-2681).
That agreement, which included transmission owner Northern States Power, provided up to 146.6 MW of interconnection service to Northern States’ Garvin, Minn., substation.
In October, FERC found that Shetek failed to meet milestone payments under the GIA and that extending the milestones without assurance that the developer would meet its obligations would present “harm to lower-queued interconnection customers in the form of uncertainty, cascading restudies and shifted costs necessitated if the project were to be removed from the queue at a later date.”
Northern States parent Xcel Energy said that since signing the agreement in 2007, Shetek had made no progress toward development.
Shetek’s plan was to install up to 60 turbines near Tracy, Minn. In 2006, the developer reported that it had raised $470,000 in equity from almost 40 landowner-investors in the project’s targeted area.
The company was seeking an extension of time to make progress payments and argued that Northern States breached its obligations to act in good faith.
Shetek said FERC’s decision last year was not in the public interest because termination would frustrate Minnesota’s interest in supporting community-based projects.
But FERC noted that both the state’s Public Utilities Commission and its Court of Appeals found that Xcel was not required to give special consideration to the project.
Ameren reported last week that earnings were flat in the second quarter, largely on milder temperatures that reduced demand for electricity.
The St. Louis-based company earned $150 million ($0.61/share) compared with $149 million ($0.61/share) in the same period last year. Operating revenues were $1.40 billion versus $1.42 billion last year.
Ameren said its results were buoyed by earnings from investment in electric transmission and delivery infrastructure, along with a lower tax rate.
The company raised its full-year earnings-per-share guidance slightly, to $2.48 to $2.68 from $2.45 to $2.65.
— Chris O’Malley
Lower Revenues Dim CMS Energy Profits in Q2
Second-quarter net income for CMS Energy fell 19% on a 8% decline in revenue, the company reported last week.
The Jackson, Mich.-based parent of Consumers Energy earned $67 million ($0.25/share) compared with $83 million ($0.30/share) during the second quarter of last year. Revenue was down to $1.35 billion, from $1.47 billion a year earlier.
Nevertheless, CMS reaffirmed its 2015 earnings-per-share guidance of $1.86 to $1.89, consistent with its goal of 5 to 7% annual adjusted EPS growth.
President and CEO John Russell said CMS is still on track to retire its seven oldest coal plants — amounting to one-third of its coal fleet — by next April. The units being shuttered are an average of 60 years old and will be replaced by gas-fired units.
Russell also said CMS will proceed with its first-ever utility-scale solar generating station. The 10-MW demonstration project will be evaluated for the potential of additional utility-scale units in Michigan.
— Chris O’Malley
Unfavorable Weather Cited in DTE Earnings Drop
DTE Energy’s second-quarter profits fell 12% on increased costs and unfavorable weather.
The Detroit-based company posted net income of $109 million ($0.61/share) compared with $124 million ($0.70/share) in the same quarter last year.
Operating earnings in DTE’s electric segment were down by $18 million, while the gas utility segment recorded a $3 million decline. Operating revenue for the company fell 15%, to $2.27 billion.
During a conference call, executives cited strong growth in the gas storage and pipeline business and in energy trading. As a result, DTE raised its 2015 operating EPS guidance to $4.54 to $4.90, from $4.48 to $4.72.
— Chris O’Malley
Eversource Q2 Earnings Jump 63%
Eversource Energy said last week that the company’s second-quarter profits this year increased by nearly 63%, from $127.4 million ($0.40/share) in 2014 to $207.5 million ($0.65/share).
“We had an excellent first half of 2015, with financial performance consistent with our targeted 6 to 8% long-term earnings growth rate and our 2015 projected earnings of $2.75 to $2.90 per share,” Eversource CEO Thomas May said in a statement.
“We don’t believe it poses any unanticipated challenges to the construction of the project,” said Lee Olivier, executive vice president of enterprise strategy and business development. He added that plans for site approval will be filed with state officials in “early to mid-fall,” with review taking about one year.
— William Opalka
Exelon: Quad Cities Decision as Soon as September; Awaiting Pepco Decision from DC
Exelon CEO Chris Crane told analysts during the company’s quarterly earnings conference call that if Illinois legislators fail to pass a law that would essentially guarantee profits for its nuclear plants, the company may be forced to close its Quad Cities generator, with a decision coming as soon as September.
Crane and other company officials have long said that three of its six nuclear stations in Illinois are losing money on the wholesale market, primarily because low natural gas prices are pushing wholesale power prices down.
Even anticipated revenue boosts from PJM’s Capacity Performance program “will not be enough to keep all the units economically viable,” Crane said. The decision on whether to keep its Clinton nuclear station open — which bids into MISO and therefore is governed by different rules — won’t be made until the first months of next year.
“We don’t take the decision lightly,” Crane said. “We understand the effect that we have on the communities and potential effect on employees, but this has been a long-term issue that we’ve been evaluating and trying to come to a resolution [on], and we’re staying within the timeline.”
Exelon reported second-quarter earnings of $508 million ($0.59/share) compared with $440 million ($0.51/share) this time last year.
The company said profit rose due to higher sales and a hedging-related gain. Crane also credited strong financial performance by Exelon Generation.
Crane also said the company is prepared to quickly finalize its $6.8 million acquisition of Pepco Holdings Inc., pending approval by regulators in D.C. As the company awaits the ruling, expected late this month, it extended the deal’s termination date from July 29 to Oct. 29.
Pepco’s second-quarter earnings were flat compared with the same period in 2014, with net income of $53 million ($0.21/share).
“Increased operation and maintenance costs, primarily driven by the implementation of a new customer information system, impacted second-quarter results,” CEO Joseph Rigby said.
— Suzanne Herel
FirstEnergy Beats Expectations
FirstEnergy beat its own expectations, reporting second-quarter net income of $187 million ($0.44/share) compared with $64 million ($0.16/share) for the same period last year, despite the fact that the company’s revenues stayed flat at $3.5 billion, the company said.
“We remain focused on implementing our regulated growth initiatives and our Cash Flow Improvement Project, which was launched in April,” CEO Charles Jones said in a statement. “I’m pleased that the opportunities we have identified as part of that project are expected to result in cash savings of $240 million by 2017, exceeding our original targets.”
Operating earnings for the Akron, Ohio, company’s regulated distribution business were flat compared with the same period last year, as the benefit of higher distribution revenues and approved rate cases was offset by higher operating expenses and a higher effective income tax rate.
The regulated transmission business saw higher transmission revenues, in part related to the company’s Energizing the Future plan to upgrade its grid.
The company’s competitive energy services benefited from lower operating expenses and a slightly higher commodity margin compared with last year.
The company said the loss reflected a $1 billion hit from discontinued operations of the competitive supply business.
For the same period last year, PPL had reported net income of $229 million ($0.34/share).
Not taking into consideration the spinoff and some other accounting items, the utility reported second-quarter earnings of $329 million ($0.49/share), an 11% increase from adjusted earnings of $296 million ($0.44/share) for the same period in 2014.
The company also narrowed its 2015 forecast range from ongoing operations to $2.15 to $2.25 per share and increased its quarterly common stock dividend to $0.3775/share.
“Based on the strong performance of PPL’s seven regulated utility businesses in both the U.S. and the U.K., the continued rate base growth from our significant infrastructure investment and our solid business plan to grow earnings per share, we are increasing the midpoint of our 2015 earnings forecast,” CEO William H. Spence said in a statement.
“The new PPL Corp. — with its strong growth profile, a solid dividend and diverse mix of holdings — is a unique and very compelling investment option in the U.S. utility sector,” he said.
— Suzanne Herel
PSEG Q2 Earnings Up 62%
Public Service Enterprise Group on Friday reported second-quarter net income of $345 million ($0.68/share) compared with $212 million ($0.42/share) for the same period in 2014.
“Our businesses performed well. [Public Service Electric & Gas’] expanded investment program is successfully translating into improvements in customer satisfaction at the same time operational improvements at PSEG Power supported increased output,” CEO Ralph Izzo said in a statement.
Operating earnings for PSE&G rose to $167 million ($0.33/share) from $151 million ($0.30/share) this time last year. The company attributed the boost to an expansion of its capital program, warmer-than-normal temperatures and a recovering economy.
Meanwhile, PSEG Power reported operating earnings of $110 million ($0.22/share) compared with $87 million ($0.17/share) this time last year.
The company said the results reflect improvement in operations of its nuclear and fossil fuel generating facilities, higher prices on its hedged energy output and a drop in the cost of its gas supply.
— Suzanne Herel
WEC Energy Group Erases $0.24/Share on Integrys costs
Costs related to its June acquisition of Integrys Energy put the squeeze on WEC Energy Group’s second-quarter profits.
Milwaukee-based WEC earned $80.9 million ($0.35/share), a 39% decline from $133 million ($1.04/share) in the second quarter of 2014. Excluding the acquisition costs, which cut EPS by $0.24, WEC would have reported EPS of $0.59.
Like many northern utilities, a cooler-than-normal June crimped electricity revenues. Operating revenues declined to $991.2 million from $1.04 billion last year.
WEC’s results do not yet include the financial performance of Integrys or its subsidiaries.
— Chris O’Malley
Xcel Reports Flat Earnings for Q2
Xcel Energy reported flat profits for the second-quarter, with earnings of $197 million ($0.39/share), compared with $195 million ($0.39/share) for the same period last year.
Minneapolis-based Xcel said the results were generally in line with expectations. Though the company missed analysts’ estimates by $0.01/share, it reaffirmed its full-year earnings-per-share guidance of $2 to $2.15.
Xcel blamed unfavorable weather conditions that affected customers’ heating and cooling costs and adjustments to a rate request in Minnesota.
Second-quarter electric margins increased due to new rates and riders in various jurisdictions and a lower Public Service Company of Colorado earnings test refund. Xcel said that increase was offset by higher depreciation, a lower allowance for construction funds and higher property taxes, operating and maintenance expenses and interest charges.
Xcel’s Monticello nuclear plant is operating at full capacity, having received final Nuclear Regulatory Commission approval. The facility was uprated to 671 MW from 600 MW in 2013, at a cost of $748 million (a $0.16/share hit to profits). Xcel said its Cherokee combined-cycle plant in Colorado completed its first-fire during the quarter and is on budget and on time.
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.”
