A panel comprised of representatives from those companies developing transmission in Wyoming has been convened. Each panel member will deliver a 10-15 minute presentation containing updates on the development progress; development issues faced in 2011; and the hurdles to be overcome to reach project viability. Colin McKee, Energy Policy Analyst for Governor Mead’s Office will moderate. The projects being addressed will include:

Presentations:
1)Energy Gateway Project-Darrell Gerrard, Vice President, Transmission Planning, Rocky Mountain Power/PacifiCorp
2) TransWest Express Project—Bill Boyd, Ex. Vice President & COO, TransWest Express, LLC
3) Zephyr Project-Chris Jones, Managing Director, Duke American Transmission Company (DATC)
4) Wyoming Colorado Intertie Project—Adam Gassaway, Project Manager, LS Power

Wyoming Renewable Energy Coordination Committee (RECC):
This Committee was formed in 2011 with the purpose of expediting generation projects in Wyoming. Membership includes Governor Mead’s Policy Office; Office of State Lands and Investment; Office Dept. of Environmental Quality, Industrial Siting Division; Wyoming Infrastructure Authority; Wyoming Game and Fish; Bureau of Land Management Renewable Energy Coordination Office; and Wyoming County Commissioner’s Association. Todd Parfitt, Deputy Director, Wyoming’s Department of Environmental Quality will present an update on the activities in 2011 and next steps.

Presentation:
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Energy Permitting and Siting Issues for Federal Lands:
Peter J. Schaumberg, Principal, Beveridge & Diamond, P.C. (Washington, DC) will address permitting and siting issues facing the Oil & Gas and renewable energy industries as well as developers of pipelines and transmission facilities crossing federally-managed lands. Peter is a former long-time attorney with the Department of the Interior. Peter has handled numerous matters involving NEPA and other environmental review processes for energy production and transmission projects, and has provided significant input in several contexts to improve those processes.

Presentation:
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An update on the work of the Rapid Response Team (RRT) and the BLM 2012 Renewable Energy Priority Projects:
A panel has been convened to discuss the progress of these two (2) federal initiatives with a discussion as to next steps. Steve Black, Counselor to Interior Secretary, Ken Salazar; Laura Morton, Sr. Advisor for Renewable Energy and to Lauren Azar, Office of the Secretary, Department of Energy; Don Simpson, Wyoming State Director for the BLM ; and Linda Davis, Finance Director, Western Governors Association (WGA). The panel moderator will be Shawn Reese, Policy Director for Governor Matt Mead.

Presentations:
-Shawn Reese, Policy Director for Governor Mead
-Laura Morton, Office of the Secretary, Dept of Energy
-Linda Davis, Western Governor’s Association

An update on the DKRW Coal to Motor Fuels Project near Medicine Bow:
Bill Gathman, DKRW Advanced Fuels, LLC will be giving an update on this important proposed facility in the Medicine Bow area. In addition, Mr. Kelly will address the complexities of acquiring financing for a large-scale CTL facility.

Presentation:
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The Feasibility of Siting Coal (CTL) and Natural Gas to Liquids (GTL) Facilities in Wyoming:
Given Wyoming world-class coal and natural gas reserves, converting such to motor fuels and other products present the opportunity to move such resources “up the value chain” to the benefit of our State and to the U.S. by mitigating the need to import energy supplies from foreign sources. A comprehensive study commissioned by the Wyoming Business Council was recently completed by the Idaho National Laboratory (INL) and in addition to addressing the conversion of coal (CTL); the study also addresses natural gas to liquids (GTL) and methanol to gasoline (MTG). Dr. Richard Boardman, Energy Security Initiative Lead, INL will provide a summary of the study.

Presentation:
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Washington DC Update:
Tom Dennis, Executive Vice President, Cassidy & Associates will provide an update on issues impacting energy in Washington including the PTC debate relative to wind.

Presentation:
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An update of the Montana-Alberta Tie-Line (MATL):
Enbridge, Inc recently completed the acquisition of the MATL Project. Robert Stade, Project Manager, Enbridge will give an update on the efforts to complete the construction of the line.

Presentation:
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Obama set to aggressively implement ‘all-in’ strategy for energyBy Kathleen HartPraising the findings of the White House Jobs Council, President Barack Obama said Jan. 17 that he has emphasized to his Cabinet the importance of aggressively implementing the council’s energy recommendations.America’s future prosperity requires a strategy of energy resilience and diversity, with an “all-in” approach from the public and private sectors, the White House Jobs Council said in a new report, “Road Map to Renewal.” The council recommended expanding and expediting the domestic production of fossil fuels, including allowing more access to oil, gas and coal on federal lands, while also making more areas available for renewable energy development and streamlining the permitting process.In his remarks, Obama agreed that the nation “can’t be bogged down by red tape and bureaucracy if we’re actually going to get every bang for the buck. Building on administration efforts to streamline permitting, I issued an executive order to expedite review of job-creating infrastructure projects, and to track their progress on a new public dashboard. All 14 projects are on track. Most importantly, we’re using these projects to learn lessons that we can scale across a whole range of projects throughout the federal government moving forward.”Obama said he plans to establish a “permitting project manager effort,” which will be overseen by the Office of Management and Budget, to establish performance metrics, track progress and adapt best practices across agencies. Pointing to his executive order to independent agencies to cut excessively burdensome regulations, Obama noted that the administration estimates savings of $10 billion over 10 years by implementing just a fraction of the reforms that have been identified.”I feel confident in being able to say that every one of the agencies in this government has been focused on how do they improve, get smarter, get better, get faster, become more focused on delivering good value to the end user. And I believe that we’ve made genuine progress on all these fronts. We would not have made this progress without this Jobs Council,” the president said.Obama established the council, officially known as the Council on Jobs and Competitiveness, by executive order in January 2011 and tasked it to develop a set of recommendations to create jobs in the short term and improve the nation’s competitiveness over the long term.Currently, the United States has a low-cost electricity advantage over many of the nation’s competitors due to diverse sources of energy, including recent breakthroughs in shale gas. “The average industrial electricity price in the United States is 43% lower than its equivalent in China,” the report said. “However, only 17% of the United States’ total energy consumption comes from low-carbon sources even though we currently lead the world in total renewable energy installed capacity at 53.4 gigawatts.”"As a nation, we need to take advantage of all our natural resources in order to spur economic growth, create new jobs, and reduce the country’s dependence on foreign oil. Over the long-term, innovation and technological advancements will greatly reduce America’s reliance on fossil fuels. Until then, however, we need to be ‘all-in,’” the council said in a fact sheet.The council also emphasized the importance of promoting efficiency to reduce overall energy dependence. “The U.S. should continue to promote energy- and fuel-efficiency measures to stretch our existing domestic resources. The council is encouraging the industrial sector to adopt energy management best practices that can greatly reduce the energy intensity of their work,” the fact sheet said.The council warned that U.S. leadership in energy innovation is being challenged by other nations. For example, Japan and South Korea each spends almost a percentage point more of gross domestic product on research and development than the United States. “The threat to American leadership in innovation extends beyond lagging R&D investment. Private-sector innovation is threatened when critical manufacturing activities move offshore,” the report said. “In the tradable sectors, in which businesses can locate employment anywhere, U.S. performance has lagged. If the United States is to retain its innovative edge, we must attract manufacturing investment, which helps fuel the next generation of ideas.”The council said its recommendations for the nation’s energy strategy reflect current policy discussions in both Congress and the Obama administration aimed at achieving energy resilience and diversity. “America needs to: optimize use of all of its natural resources while protecting public health and the environment; support efficiency measures in both electricity generation and transportation; and drive energy innovation and investment from basic invention to industry scale-up,” the report concluded.

FERC denies calls to convene federal-state board on EPA rules; Moeller blasts EPABy Glen BoshartWith Chairman Jon Wellinghoff suggesting that the request may being fulfilled in other ways, FERC on Jan. 19 rejected calls to convene a joint board with state regulators to study the potential reliability ramifications of new emissions rules being promulgated by the U.S. Environmental Protection Agency.FERC explained that the request (EL11-62) by South Carolina officials was made pursuant to Section 209(a) of the Federal Power Act, but that section only allows joint boards to be formed to address matters arising under Part II of the FPA, which does not include the reliability concerns at issue here.In their September 2010 joint petition, the South Carolina Public Service Commission and the South Carolina Office of Regulatory Staff asked FERC to work with them to assess how EPA rules will impact power prices and reliability in their state and to consider inviting regulators throughout the Southeast and beyond to assess potential regional impacts. The officials also urged FERC to ask EPA to coordinate the promulgation of its regulations affecting the power sector with the joint board’s work. Of particular concern, according to the officials, are the “unrealistic compliance timelines” of many of the EPA rules. Several state commissions subsequently told FERC that they supported the South Carolina officials’ petition. Separately, the South Carolina PSC asked that all materials relating to the commission’s informal analysis of the reliability impact of the EPA rules and to the commission staff’s discussions with EPA be made available to it and to the joint board.Wellinghoff had been refusing to have his agency undertake a comprehensive study of the potential reliability implications of EPA’s rules, insisting that doing so should be the job of ISOs, RTOs and other planning authorities, who can then plan accordingly. However, after his stance came under heavy criticism from certain federal lawmakers and Commissioner Philip Moeller said that either FERC or EPA should assess the reliability implications of the EPA rules, FERC held a technical conference (AD12-1) in late November 2011 to consider the reliability impacts of EPA regulations on the electric power industry.In addition, FERC and the National Association of Regulatory Utility Commissioners recently announced formal plans to engage in ongoing discussions to explore reliability issues stemming from new and pending environmental rules for the power sector. And unlike during the FERC technical conference, at which an EPA official made a presentation and then left, EPA is expected to be engaged throughout the initial forum, which is to take place Feb. 7 during NARUC’s winter meetings in Washington, D.C.FERC’s order rejecting the South Carolina officials’ request noted that FPA Section 209(a) is a procedural option for adjudicating rate cases, mergers or other matters arising under Part II of the FPA. Here, however, the officials failed to identify any matter presently before the commission “that is cognizable under Part II of the FPA that could be referred to a joint board,” the order stated. “Moreover, the petition does not seek the institution of a proceeding cognizable under Part II of the FPA.”FERC also rejected the South Carolina PSC’s information request as moot, noting that it made the information publicly available when it responded on Aug. 1, 2011, to a letter from U.S. Sen. Lisa Murkowski, R-Alaska.After voting to reject the South Carolina officials’ request during FERC’s Jan. 19 regular agenda meeting, Wellinghoff told reporters that the state officials “were asking for something that didn’t fit in the box, per se, and we have lots of other ways to address that.”Wellinghoff also suggested that the request may have been superseded by subsequent developments, including the FERC technical conference and plans to hold the joint FERC/NARUC forums. “They may be satisfied with the way things worked out anyway,” he stated. In a concurrence to the order, Moeller said that while FERC is not legally obligated to form a joint board with the state of South Carolina, it should have directed its staff “to work with South Carolina (and any other state that requests such assistance) in an open and transparent manner to address the issue of reliability.”"Any joint effort between the states and the federal government requires the enthusiastic support of the participants,” Moeller wrote. “Despite the evidence that was submitted as part of our recent conference on reliability issues, and despite the urgent need of this nation to maintain a reliable electric grid that is the envy of the world, this commission has not yet demonstrated a commitment to overcoming the obstacles that have now been imposed on the reliable operation of the power grid.”Moeller also blasted EPA’s limited participation in the recent FERC technical conference. “Perhaps the upcoming FERC and NARUC forum will be the start of a meaningful collaboration and open exchange of data, and not just another opportunity to hear talking points of the federal government,” Moeller wrote.

Timing of EPA rules could force utilities to move other CapEx to back burnerBy Abby GruenA main concern of regulated utility investors in 2012 is the timing of U.S. Environmental Protection Agency rules for carbon and other pollutants, according to a Standard & Poor’s Ratings Services investor report. Depending on when they are implemented, the new rules could force power companies to delay other capital expenditures to prevent jumps in customers’ bills, the rating agency said.The new EPA rules will have the most significant impact on utilities and their generation plants since the acid rain programs of the 1990s, according to a Jan. 6 report, “The Top 10 Investor Questions for U.S. Regulated Electric Utilities in 2012.”The ability of regulated power companies to pass compliance costs through to ratepayers underpins S&P’s stable outlook of the industry, but if environmental costs come too fast, public service commissions may balk at causing rate shock to their citizens. A possible delay in implementing the EPA rules, combined with slow growth in electricity demand, are among the industry’s primary credit themes.”It is not certain how much of the [environmental compliance] spending will come in 2012, especially since some of the rule making is being litigated in terms of how quickly it will come into play. Those are all of the questions investors are asking about,” S&P analyst John Whitlock said on S&P CreditMatters TV on Jan. 9.In calculating the credit impact of the rules, S&P focuses on the pace of compliance, S&P analyst Todd Shipman said.”On the regulatory side, I am not aware of any significant, or insignificant, instance of regulators not allowing a utility to fully recover environmental compliance costs,” Shipman said. “It is the timing. This is what we look to the utility and their management to do. We refer to the whole idea of a ‘crowding out’ theory. There is only so much higher cost that you can pass through at any given time, in a politically palatable way.”Utility managements balancing investments in smart grid, new generation, storm preparedness and transmission and distribution upgrades are not trying to “elude the consequences” of the EPA rulemaking, they are just asking for more time and flexibility so they can comply at the lowest cost and at a pace that doesn’t cause rate shock, Shipman said.”If you are trying to do all that, and all of a sudden much more onerous and expensive environmental costs come along, then it could lead to a point where something has got to give. And we all know on the regulatory side when something has to give, it is usually the utilities that are doing the giving,” Shipman said.While S&P has not “detected any whiff of backlash or resistance from regulators,” the timing of when utilities can recover their costs could be put under pressure by the EPA rules.”When the industry gets back on a growth path there is going to be a lot of spending going on and we think it is going to be difficult to keep customer bills tamped down. It is going to be a difficult environment with customer bills rising and median incomes flat to falling — it is not a recipe for contentment for consumers. We are concerned about regulatory fatigue, and we will continue to watch for signs that regulators are having pause to pass along some of these costs. These are top themes that we looked at,” Whitlock said.Fully regulated utilities owned by Southern Co., Wisconsin Energy Corp. and Xcel Energy Inc. are expected to ultimately recover compliance costs from ratepayers through rate cases.Southern’s Alabama Power Co., Progress Energy Inc.’s Florida Power Corp. d/b/a Progress Energy Florida and AES Corp.’s Indianapolis Power & Light Co. will recover their environmental investments through riders, instead of full rate cases, the S&P report said.Ameren Corp., Dominion Resources Inc., FirstEnergy Corp. and PPL Corp., with both regulated and merchant businesses, are expected to have some weakening of their consolidated financial measures, which possibly could translate to a lower credit rating, S&P said.Despite low demand growth, S&P expects 2012 capital spending of about $85 billion in the sector, up slightly from 2011. Environmental spending in 2012 and 2013 is projected to top $10 billion. American Electric Power Co. Inc., Dominion, PPL and Southern are all expected to spend more than $1 billion in CapEx in the next two years, Whitlock said in the report.Companies such as Alliant Energy Corp., which has a high proportion of environmental spending relative to its net property plant and equipment, a ratio of greater than 9%, could face lower ratings if recovering costs proves to be difficult, according to the report, but S&P has not seen anyone run into trouble with the regulators yet, Shipman said.”It is really on the utilities to match their spending, and there are some very large capital expenditure programs out there with some utilities,” Shipman said. “If they don’t slow down on that a little bit, to make sure they can manage the expectations of everybody, and to manage what rate increases are going to be palatable, that’s when they can run into trouble on the regulatory side. But we don’t see any of that.”

Low gas prices could lead to Wyo. budget problemsBy Mark PasswatersThe governor of Wyoming is concerned that the continued low price of natural gas could lead to a budget crisis for his state in the near future.In a statement released by his office Jan. 13, Gov. Matt Mead said the newly released revenue forecast by the state’s Consensus Revenue Estimating Group, or CREG, was “concerning,” showing a drop in revenue to the state from natural-gas-related activity. The drop in revenue, which had been expected to hit further into the future according to CREG’s report in October 2011, is now anticipated to lead to a cash crunch for the next two years.”Because natural gas prices continue to fall, all of us are going to have to take a hard look at the budget,” Mead said. “Our revenue is tied to mineral development and natural gas is a strong contributor. New projected prices for natural gas could mean a decrease in over $100 million … in revenue over two years.”In December, Mead’s office proposed cutting ongoing spending from $2.76 billion to $2.74 billion, but more work may need to be done after reviewing CREG’s estimates.”If we have to make additional cuts, and we very well may, my request to the [Joint Appropriations Committee] is to give me the time to try and make those cuts with precision, understanding that we have already reduced the standard budget and it is not going to be easy business,” he said. Questar Gas requests rate reduction of $13 million
2:37 p.m. MST, January 17, 2012SALT LAKE CITY— Questar Gas asked the Public Service Commission of Utah (PSC) to reduce natural gas rates by $13 million. If approved, the rate cut will lower the typical homeowner’s annual bill by about $10 per year, or 1.5 percent, beginning Feb. 1, 2012.

“Plentiful supplies of natural gas nationwide and warmer weather have resulted in a glut of natural gas. The good news for consumers is that the price we pay to buy gas for our customers is about as low as it’s been in a decade,” said Craig Wagstaff, Senior Vice President of Questar Gas. “As a result, once again we’ve asked to cut our rates, which are already among the lowest in the U.S.” He cautioned, however, that natural gas prices can fluctuate with changes in supply and demand.This latest request comes on the heels of another request, made in December, to reduce rates by $770,000, or about a tenth of a percent. That request adjusted rates to account for Questar Gas’s system-enhancement and conservation-program costs. That change is also requested to go into effect Feb. 1.

Groups urge EPA to ignore industry criticism of Wyo. fracking studyBy Bryan SchuttEnvironmental organizations and a citizen group representing those affected by the water contamination in Pavillion, Wyo., have asked EPA to continue full-speed ahead with the public comment period and peer-review process on a highly controversial study that linked hydraulic fracturing to groundwater contamination.Pavillion Area Concerned Citizens, Powder River Basin Resource Council and Earthworks’ Oil and Gas Accountability Project said EPA’s Pavillion investigation has been completed in a scientifically sound manner, and they urged the agency to continue with its “rigorous investigation.” In December 2011, EPA released draft analysis of information gathered over three years in Pavillion that said groundwater in the local aquifer contains compounds likely associated with natural gas production practices, including fracking. The agency said it is concerned about the movement of contaminants within the aquifer and the safety of drinking water over time.The study has been widely criticized by industry proponents who say the findings need to be verified by an independent, third party. EPA has listened. According to the agency’s website, a 45-day public comment period on the draft report began Dec. 14, and a 30-day peer-review process will follow.Still, Encana Oil & Gas USA Inc., the operator under investigation in Pavillion, has asked EPA to suspend and postpone the public comment period. “The EPA is moving too quickly with its pre-dissemination public comment and peer review process on the Pavillion Report,” the company wrote in a Jan. 6 letter to EPA. “For the reasons set forth below, [Office of Research and Development] should suspend the public comment period until the agency’s plans are better explained and additional critical data can be disseminated by the EPA.”The Encana Corp. subsidiary said the notice of public comment was not sufficiently clear on what topics the public comment should cover, and the comment period should not proceed without all information on the table. The company requested, via Freedom of Information Act requests, all data related to the report, and Encana said it has not received everything.But the environmental organizations said no delay is needed and the industry is simply executing a campaign to cover-up the problem. The groups said if EPA’s draft is finalized with the same conclusion, it would “definitively refute” claims that fracking has never contaminated drinking water wells.”These accusations are a political ploy to cover-up the results and bring a halt to the study,” said Gwen Lachelt, director of Earthworks’ Oil and Gas Accountability Project. “We’ve seen this time and again with industry shirking responsibility and the government turning its back on the people who bear the impact of energy development in our country.”In a letter to EPA, John Fenton, chair of Pavillion Area Concerned Citizens, said the findings are of great importance to everyone who lives in the region. He asked the results not be skewed because of any special interests and that the public comment period proceed as planned.”Since the report’s release, industry and their advocates have voiced their opinions through what appears to be a carefully constructed media campaign,” the letter said. “It appears they are now trying to stop the public from commenting. Please ensure that all voices from the public are heard by accepting public comments through January 27, 2012.”

Oil, gas may be on collision course, says former energy undersecretaryBy Mark PasswatersThe massive amount of natural gas supplies in the United States could lead to an “invasion” of traditional oil markets, former Department of Energy Undersecretary John Deutch said Jan. 18.Speaking via a video conference at Rice University’s North American Energy Resources Summit, Deutch said he anticipates the combination of high prices of oil and the existing supply glut of gas to lead to direct competition between the two energy sources.”The completely unusual, historic difference in cost between oil and gas of almost four-to-one will advance through the future, or … market adaptation will create greater competition between oil and natural gas and an invasion of natural gas into traditional oil markets,” the former director of the CIA during the Clinton administration said. “This disparity over time will increase the price of gas and decrease the price of oil as they compete for common use.”Deutch said the rapidly expanding supply of gas globally was changing the playing field in the energy marketplace.”We’re going to see a tremendous realignment between those who are using energy and those who are producing energy around the world,” he said. “I expect a global price for natural gas will emerge in the next couple of decades, that we will go with a result of expanded LNG trade and expanded pipeline capacity … from three separate markets to a single market around the globe.”Deutch said the Energy Information Administration’s estimate that the United States imports 52% of its liquids demand will be significantly altered in the next few years in large part due to unconventional plays.”There are many reasons to believe that, with the explosion of shale gas and oil and North America, that we will have a much more favorable liquids balance,” he said. “That percentage could fall to the high 20s from 2025. That’s a small distance from what most experts say would mean energy independence. We are going to be better able to meet our energy goals going into the future and natural gas has a great opportunity to substitute for oil in the future economy.” One country Deutch said the U.S. should not hesitate to import from was Canada, which he said was a reliable and friendly energy source.”I personally find Canadians more reliable than Californians when it comes to energy production,” he said.Deutch said the possible positives from domestic oil and gas may not be realized if the industry does not do a better job of informing the public of its activities and criticized it for “getting off on the wrong foot” by not being open with disclosure of ingredients used in hydraulic fracturing fluids. He advocated not only greater openness, but keeping the public informed of improvements in efficiency and environmental protection.”The industry should measure certain key indicators of environmental production; disclose those to the public and commit to improving those indicators over time,” he said. “Follow best practices accompanied by measurements from the field that supports a chain that the impacts are going down over time. It’s a difficult road forward, but it’s the best possible way to see this tremendous benefit, this fortune for North America and the United States, to be realized.”
Wednesday, January 18, 2012 3:16 PM MT
FERC OKs MidAmerican purchase of 49% stake in NRG solar plantBy Zia Ullah KhanFERC on Jan. 17 issued an order authorizing MidAmerican Energy Holdings Co. to acquire a 49% interest in NRG Solar LLC’s Agua Caliente solar project.The companies in December 2011 had filed the application seeking approval for the disposition of jurisdictional facilities through the transfer of indirect ownership interests in Agua Caliente, FERC said in its order. The jurisdictional facilities involved with the proposed transaction consist of Agua Caliente’s market-based rate tariffs, related books and records and a power purchase and sale agreement.Agua Caliente is a 290-MW photovoltaic electric generation facility under construction in Yuma County, Ariz. The project is expected to enter commercial operation by the first quarter of 2014.The project has been awarded a $967 million loan guarantee by the U.S. Department of Energy and has a long-term power purchase agreement with PG&E Corp. subsidiary Pacific Gas and Electric Co.

State regulators accept Idaho Power’s IRP, while keeping eye on environmental issuesBy JP FinlayRegulators in Idaho accepted a long-range plan from Idaho Power Co. documenting the utility’s plans to meet customer demand through 2030. Idaho Power submitted its integrated resource plan, or IRP, for acceptance last summer.”Based on our review, we find it reasonable to accept for filing and to acknowledge Idaho Power’s 2011 Electric Integrated Resource Plan,” the Idaho Public Utilities Commission said in its Dec. 30, 2011, order. “As the discussion in the comments demonstrates, however, many of the issues are not resolved and will need continued review in the company’s next IRP as more information becomes available.”Issues raised in Idaho Power’s IRP centered on the Gateway West transmission line project, the possible early retirement of coal plants, progress on solar projects, and federal relicensing of the Hells Canyon hydro projects.In their review of the plan, county commissioners from Power and Cassia counties, Idaho, expressed concern over proposed changes to the Gateway West project, the PUC said.”The county commissioners acknowledge that the 2011 IRP addresses the Gateway West project only as a long-term plan to be considered in 2021 to 2030, specifically noting that the near term 10-year action plan, 2011-2020, does not consider the Gateway West project,” the Idaho PUC said. “The commissioners believe Gateway West ‘is a much more remote possibility than what was asserted by Idaho Power in its purpose and need [for the project] to the BLM.’ Noting the total cost for the project may be in excess of $2 billion, and given the ‘uncertainty of many of the assumptions that lead to this proposal,’ the commissioners state that caution should be exercised before proceeding with the project. The commissioners ask the commission to review and re-analyze Idaho Power’s participation in the Gateway West project.”Idaho Power spokesman Brad Bowlin explained that his company is waiting to hear back from the Bureau of Land Management on the Gateway West project. “We’re in a holding pattern at this point,” he said Jan. 9. The BLM is gathering comments on a draft environmental impact statement, and Bowlin said a final EIS could come next summer.”We think it’s important that we keep a stake in that project because the opportunities for siting transmission lines are pretty limited. We don’t want to miss the opportunity to do that. It’s going to be important down the line,” Bowlin said of the Gateway West line to be jointly developed with Rocky Mountain Power Inc. President Barack Obama fast-tracked the Gateway West transmission project in October 2011.Another Idaho Power project, the Boardman to Hemingway line, also was named to the fast-track list. The 300-mile, 500-kV line should improve access to markets and increase reliability for Idaho Power customers, the PUC said in a Jan. 6 news release. But the Renewable Northwest Project, a renewable energy advocacy group, expressed concern about when the line will be completed.”RNP generally supports the company’s development of the Boardman to Hemingway line and recognizes the benefits it will provide. Specifically, the transmission line will help the company improve access to markets, meet summertime peak capacity needs with market purchases, and bring strong reliability benefits to Idaho Power’s system,” the PUC said in its order. “Recognizing that the Boardman to Hemingway transmission line could be delayed, RNP encourages Idaho Power to consider alternatives to its alternate resource portfolio, which is comprised solely of simple-cycle combustion turbine plants. RNP suggests the company give demand-side management alternatives and solar photovoltaic resources consideration because pursuing those alternatives to lower peak needs could provide greater long term benefits to the utility and its customers.”Idaho Power expects its customer base to grow from 492,000 in 2010 to more than 650,000 by the end of 2030. Over that same time frame, the utility expects to reduce its coal generation, the PUC said. In 2010, coal accounted for almost 44% of Idaho Power’s generation. By 2030, the utility expects coal generation to drop to 26%, the PUC said.One project included in Idaho Power’s 2009 IRP, the 300-MW Langley Gulch natural gas-fired plant, should be completed this year. Bowlin said projects such as Langley Gulch and other upgrades will allow the utility to reduce coal generation.Idaho regulators require the state’s electric and gas utilities to file an IRP every two years to provide details on how to meet demand in 10-year and 20-year windows. The Idaho PUC then accepts or rejects the plan. The company also submits an IRP to the Oregon Public Utility Commission, though Bowlin said the utility does not expect to hear back on that filing until February or later.

Idaho PUC authorizes electric rate increase for PacifiCorpBy Lisa FontanellaOn Jan. 10, the Idaho Public Utilities Commission (PUC) authorized PacifiCorp a two-step $34 million (15.6%) electric rate increase following adoption of an Oct. 17, 2011 settlement (Case No. PAC-E-11-12). The settlement and PUC order call for the aggregate increase to be implemented as follows: a $17 million (7.8%) increase effective Jan. 10, 2012; and, an incremental $17 million (7.2%) increase effective Jan. 1, 2013. Each $17 million increase is comprised of $6 million of non-net power costs (capital, operations and maintenance, and other), and $11 million of net power costs. The approved settlement is silent with respect to traditional rate case parameters, including rate of return. As part of the settlement, PacifiCorp agrees to refrain from seeking a base rate increase that would become effective prior to Jan. 1, 2014.

The approved settlement also resolves an issue on appeal before the Idaho Supreme Court regarding PacifiCorp’s last Idaho-jurisdictional rate decision (Case No. PAC-E-10-07), in which a final order on reconsideration was issued in April 2011 (see below). In that decision, the PUC determined that because PacifiCorp was able to utilize only a portion of the total capacity of the 345-KV Populus-to-Terminal transmission line, the full cost of the line should not be included in rates until the entire capacity is available to customers. Thus, the PUC ordered the company to classify 27% of the transmission investment as plant-held-for-future-use and exclude it from rate base. In accordance with the newly adopted settlement, the PUC found that the entire Populus-to-Terminal line is now used and useful. However, the portion classified as plant-held-for-future-will not be reflected in rates until PacifiCorp’s next base rate case. This action occurred in a proceeding initiated on May 27, 2011, when PacifiCorp filed for a single-step rate increase of $32.7 million (15%) premised upon a 10.5% return on equity (52.3% of capital) and an 8.25% return on an average rate base valued at $745.7 million for a test period ended Dec. 31, 2010, adjusted for known-and-measurable changes. The company cited several reasons for the rate request, including increased net power costs, incremental capital investments, and higher operating and maintenance costs.

In PacifiCorp’s previous Idaho-jurisdictional rate decision in April 2011, the company was authorized a $14.4 million rate increase, on reconsideration (initial decision was issued in December 2010), premised upon a 9.9% return on equity (52.1% of capital) and a 7.98% return on a rate base valued at $677.6 million (Final Report 3/31/11). PacifiCorp is a subsidiary of MidAmerican Energy Holdings Co., which is privately owned by a consortium of investors, including Berkshire Hathaway. PacifiCorp does business in Idaho as Rocky Mountain Power.

Sources expect tepid trade in CSAPR SO2, NOx allowance marketsBy Amanda LuhavaljaAlthough the U.S. Environmental Protection Agency has reportedly reinstated the electronic transfer of NOx and SO2 allowances under the Cross-State Air Pollution Rule, according to market sources, allowance prices under the rule remain under pressure.As of Jan. 12, CSAPR seasonal NOx 2012 allowances were quoted in a bid-and-offer spread of $50 to $200. This compares to a range of $150 to $300 a few days earlier. CSAPR annual NOx 2012 allowances were quoted last at $75 to $150, down from a range of $100 to $200 earlier in the week. As of Jan. 12, CSAPR Group 1 SO2 allowances saw bids at $50 and offers at $150, with CSAPR Group 2 SO2 allowances seeing bids at $75 and offers as high as $200.Following a Dec. 30, 2011, court decision to stay the implementation of CSAPR, EPA, in early January, suspended the transfer of CSAPR allowances in the Clean Air Markets Division, or CAMD, electronic business system, essentially grinding physical allowance trading to a halt. The CAMD system provides a final confirmation to entities that allowances have been transferred from one account to another.Despite the recent turnaround by the EPA, market sources still expect trading of CSAPR allowances will be scant in light of the ongoing legal uncertainty. “Mostly only hedge funds and pure speculators will likely participate at this time. Naturals (utilities) are much too conservative, and many, subject to after the fact regulatory oversight, will be reluctant to trade,” Gary Hart, emissions market analyst at ICAP Energy Inc., said. CSAPR was slated to go into effect Jan. 1, replacing the Clean Air Interstate Rule, which was overturned by the U.S. Court of Appeals for the District of Columbia Circuit in July 2008. In the CAIR markets, seasonal NOx 2012 was pegged in a bid-and-offer spread of $10 to $40. Annual NOx 2011 was bid at $60 and offered as high as $80, while annual NOx 2012 was seen bid at $60 to offered at $70.While CAIR is back in place, due to an oversupply situation, prices are not expected to trade at much higher levels than they already are, Steve Fine, vice president at consulting firm ICF International’s Environmental Markets Group, said during a Jan. 12 webinar.”CAIR is oversupplied, and there just won’t be a lot of action there,” Fine said.Sources continue to agree that the recent court action preventing the implementation of CSAPR leaves the rule on ice at least until the beginning of 2013. Either way, liquidity is going to be truncated, Fine said.”Once the CSAPR stay was announced, basically the bottom fell out of the market. And in fact, it is unclear, in some instances why the prices just didn’t completely fall to zero. The only reason that we can figure is that some people are putting some weight in the possibility that CSAPR will actually be reinstated in 2012. Because if it’s not, as we understand it those 2012 allowances that can’t be banked forward into 2013 become a worthless currency,” Fine said.

NJ energy year 2012 solar RECs slide after S. 2371 falls to wayside (see attached REC index)Legislation in New Jersey that would have increased the state’s renewable portfolio standard in an effort to sop up existing solar supply fell by the wayside Jan. 9, the final voting session of the legislative year.The much-anticipated legislation, S. 2371, sponsored by state Sen. Bob Smith, would have accelerated the state’s solar renewable portfolio standard. The bill would have increased the SREC requirement in 2013 to 772 MW and would move forward the SREC requirements by one year in each year after 2012.”The main intention of this legislation was to increase the amount of SRECs that the power companies in New Jersey have to purchase. This is needed to soak up the excess amount of SRECs because developers installed 3 times more than the amount of solar required in the present year due to dropping installed costs of solar and large solar installations,” Michael Flett, president and CEO of Flett Exchange wrote Jan. 10.While New Jersey Gov. Chris Christie signaled his overall agreement with the majority of the bill in his energy master plan released in December 2011, several last-minute changes were made to the bill in the final two days of the session. The bill reportedly never came up for a vote due to disagreements among solar advocates, who were not in lockstep over issues such as the mix between distributed net-metered and larger utility scale projects.Christie’s office submitted changes Jan. 8 for the legislature to consider. While supporting an increase in the RPS to stabilize the SREC market, the Christie administration suggested having all non-net metered projects seek New Jersey Board of Public Utilities approval. These projects would not be approved if it is determined they would have a detrimental impact on the SREC market. Smith’s bill would have required facilities with a capacity of 10 MW or higher to get NJBPU approval.”The complexity of these changes was apparently too great to digest given the limited time available. The view of the new legislature on this issue should not change appreciably with the start of the next session and the governor’s support is clear,” a Jan. 11 blog post from SRECTrade said.In response to the news that the bill was not passed in the Garden State, SREC prices for 2012 dropped like a rock, from a bid-and-ask level of $230/MWh to $260/MWh during the week ended Jan. 6 to about $200/MWh, sources said. Most recently, the 2012 SREC market in New Jersey was quoted bid at $220 per MWh and offered at $240/MWh. Bids and offers for energy year 2013 solar RECs in New Jersey were assessed at $220/MWh to $235/MWh.New Jersey energy year SREC prices saw a tumultuous year in 2011, starting in the $600s/MWh before indications that solar installations were being built at such a rapid clip in the state that supply would soon outpace demand sent prices spiraling lower in the $400s/MWh. Following a brief stabilization, energy-year 2012 SREC prices resumed their downtrend over the summer, reaching a bottom by the middle of August 2011, when values tumbled to below $200/MWh. However, expectations for the passage of a bill that would increase the RPS in New Jersey goosed New Jersey SREC prices slightly higher near year’s end to sit near $300/MWh by the end of December 2011.Unless demand is ratcheted higher, the oversupply situation is expected to continue to grow as the state has averaged 32.0 MW installed per month since the beginning of the compliance period, adding downside pressure to prices. “If the legislation is not passed it is expected that the SREC market will continue its crash and the amount of installations will have to virtually cease for the next few years before the State mandates catch up. Investors in solar will suffer from low SREC prices and solar business in New Jersey may have to close down,” Flett said.Evolution Markets to hold auction Jan. 25 for University of New HampshireIn other news, Evolution Markets Inc. will conduct a REC auction for the University of New Hampshire on Jan. 25. The sale will include 15,000 RECs produced in calendar year 2011 that will be sold in two lots, one of 10,000 and another of 5,000. The auction will also offer for sale 10,000 RECs to be produced during the 2012 calendar year that will be sold in two lots of 5,000 each, as well as 5,000 RECs to be produced during the calendar year of 2013 that will be sold in one lot. The credits meet renewable portfolio standards in Massachusetts, Connecticut, New Hampshire and Maine.”There has been a surge in New England REC prices of late, reflecting a general need for more supply,” Andrew Kolchins, managing director, renewable energy markets at Evolution Markets Inc., said. “The University of New Hampshire REC auction therefore comes at an interesting time. We anticipate the supply offered by the University’s auction will be met with considerable bid interest.” As of Jan. 12, Massachusetts class I 2011 RECs were quoted in a bid and offer range of $39.00/MWh to $41.00/MWh, while the Massachusetts class I 2012 market was pegged between $34.50/MWh and $36.50/MWh. Class I 2013 RECs in Massachusetts were assessed at $33.00/MWh to $36.00/MWh.Connecticut class I 2011 RECs were quoted last in a bid and offer range of $38.00/MWh to $39.50/MWh, with the Connecticut class I 2012 market running from $32.50/MWh to $33.50/MWh. Connecticut class I 2013 was bid at $31.50/MWh and offered at $33.00/per MWh.Most recently, the New Hampshire class I 2011 market was bid at $35/MWh and offered at $42/MWh, while the class I 2012 market was pegged at $33/MWh to $39/MWh.

BPA seeks rehearing of FERC wind curtailment order

The Bonneville Power Administration (BPA) is appealing last month’s Federal Energy Regulatory Commission (FERC) ruling that its policy of curtailing wind turbines during periods of over-generation violates the Federal Power Act.

The ruling was in response to a petition by several US Northwest wind turbine operators, including Iberdrola Renewables and NextEra Energy Resources. They faced mandatory curtailment last spring when high winds coincided with high springtime river flows, driving generation on the BPA system to exceed electricity demand. The curtailment was part of a policy called Environmental Redispatch. The BPA, a federal agency that operates most of the Northwest transmission grid and markets power from dams on the Columbia River, says its preference is to reach a settlement with regional energy players to address the issue. But as expected, it also filed a request for a rehearing and clarification of the FERC ruling. “We support the continuation and acceleration of ongoing informal settlement discussions with affected parties,” says BPA administrator Steve Wright. The BPA has not historically been under the jurisdiction of FERC, so the ruling was almost certain to be appealed if only to avoid setting a precedent. The FERC ordered the BPA to make the terms of its transmission tariffs for wind generators “comparable to those under which Bonneville provides transmission services to itself”. The BPA notes that a new solution to the over-generation problem is needed soon, as the Environmental Redispatch policy was meant to serve on an interim basis and expires at the end of March. “Absent a settlement, any new policy seems likely to lead to even more litigation that may stretch for many years,” the agency says. As wind development has surged faster than expected in the Northwest over the last five years, the BPA has struggled to integrate the variable resource. Its preference customers – mostly public and municipal utilities around the region – balk at paying more for power to cover the cost of integrating wind that they don’t view as benefiting them. Much of the wind power on BPA’s system is shipped to renewables-hungry California.

EIA: Carbon dioxide emissions decline in US, but results vary widely by stateBy JP FinlayFrom 2000 to 2009, carbon dioxide emissions declined in the U.S., according to a new report from the U.S. Energy Information Administration.Most individual states saw a decrease in carbon dioxide emissions, though 13 states reported an increase. Nebraska led the country in greatest percentage increase in carbon dioxide emissions with a 13% jump, followed by Colorado at 10.5% and Arizona at 9.5%, the EIA said in the report, released Jan. 9. Colorado led the nation in greatest absolute increase, with almost 9 million metric tons, compared to 5.5 million metric tons for Nebraska.Delaware experienced the largest percentage decline in carbon dioxide emissions at almost 30% and an absolute decline of 5 million metric tons. The greatest absolute decline came from Texas at more than 52 million metric tons. New York’s absolute decline came in at more than 42 million metric tons, and both Indiana and Michigan saw reductions of more than 32 million metric tons.Comparing various state data is a challenge, the EIA said. “The overall size of a state, of course, determines much of the absolute level of a state’s emissions,” the agency said. “Available fuels, types of businesses, climate, and population density also play a role in overall and per capita emissions. It should be noted that each state’s energy system reflects circumstances specific to that state. For example, some states are located near abundant hydroelectric supplies, while others contain abundant coal resources.”Perry Lindstrom, an industry economist and analyst at the EIA, said shifts in the national economy contributed to changes in carbon emissions and the need for multiple metrics to determine a state’s carbon emissions.”Obviously, there are different factors that affect different states, but the same general factors are in place,” Lindstrom said in a Jan. 10 interview. As the country shifts from the “old smoke-stack industries” and moves toward a service-based economy, less energy use is required, he said. Less energy use means less fuel is used, regardless of the type of fuel.Lindstrom also said the shift to renewable energy and natural gas has affected carbon dioxide emissions in addition to the economic downturn that started in 2008 and took hold in 2009.Comparing Wyoming to New YorkThe report, “State-Level Energy-Related Carbon Dioxide Emissions, 2000-2009,” contains numerous metrics, including emissions by sector, per-capita carbon dioxide emissions and emissions by fuel, energy intensity and carbon intensity of the energy supply.”It is difficult to compare total carbon dioxide emissions across states because of variation in their sizes,” the EIA said. “One way to normalize emissions across states is to divide them by state population and examine them on a per-capita basis. Many factors contribute to the amount of emissions per capita, including: climate, the structure of the state economy, population density, energy sources, building standards and explicit state policies to reduce emissions. In 2009, the U.S. average was 17.6 metric tons of carbon dioxide per capita — down about 15 percent from 2000.”Wyoming led the U.S. with the highest per-capita carbon dioxide emissions at 117 metric tons. But the explanation beyond the numbers paints a more complete picture. “In 2009, Wyoming was the second largest energy producer in the United States. Unlike the largest energy producer, Texas, that has a population of 25 million, Wyoming has less than 600 thousand people,” the EIA said. “Its winters are cold (the average low temperatures in January are in the 5 to 10 degree Fahrenheit range) and its population density is the lowest of the lower-48 States. These factors act to raise Wyoming’s per capita emissions compared to other states.”Other states with high per-capita emissions rates are fossil-energy-producing states such as North Dakota, Alaska, West Virginia and Louisiana. “The activity of producing energy is itself energy intensive,” the EIA said.New York found itself on the opposite side of the ledger from Wyoming, with the nation’s lowest per-capita carbon dioxide emissions at 9 metric tons per capita. Again, the explanation provided details on the numbers. According to the report, a large portion of New York’s 19.5 million people live in the New York City metropolitan area with easy access to mass transit and densely packed residences. That creates efficiencies of scale for heating and cooling.”The New York economy is oriented towards high-value, low-energy-consuming activities such as financial markets,” the agency said. “For example, New York contains 6.4 percent of the U.S. population, but consumes only 1.3 percent of the country’s industrial energy. New York’s energy prices are relatively high (average retail electricity prices of 15.5 cents per kilowatt hour were third highest in the country in 2009), which in turn encourages energy savings.”Where power is generatedThe report clarifies that emissions are determined by the states that generate the electricity, not where that generated power goes. Electricity trade is not accounted for in the report.”Because this analysis does not account for electricity trade, it is important to understand how much this can influence a state’s carbon dioxide emissions profile,” the report said. “If the emissions associated with the generation of electricity were allocated to the states where that electricity is consumed, in many cases, the emissions profiles of both the producing and consuming states would change.”Idaho, California, Massachusetts and Florida consistently import electricity from other states. Those four states also rank among the 10 states with the lowest per-capita carbon dioxide emissions. Three states among the highest per-capita carbon dioxide emissions — Wyoming, North Dakota and West Virginia — are “large electricity exporters of power produced predominantly with coal,” the EIA said.

EPA: Power plants are main global warming culpritsBy Dina Cappiello, Associated PressUpdated 2h 23m ago WASHINGTON – The most detailed data yet on emissions of heat-trapping gases show that U.S. power plants are responsible for the bulk of the pollution blamed for global warming.Power plants released 72% of the greenhouse gases reported to the Environmental Protection Agency for 2010, according to information released Wednesday that was the first catalog of global warming pollution by facility. The data include more than 6,700 of the largest industrial sources of greenhouse gases, or about 80 percent of total U.S. emissions.According to an Associated Press analysis of the data, 20 mostly coal-fired power plants in 15 states account for the top-releasing facilities.Gina McCarthy, the top air official at the EPA, said the database marked “a major milestone” in the agency’s work to address climate change. She said it would help industry, states and the federal government identify ways to reduce greenhouse gases.The Obama administration plans to regulate emissions of heat-trapping gases under existing law. A proposed regulation to address pollution from new power plants could be released as early as this month. Eventually, the EPA will have to tackle facilities already in operation. The largest emitters will be the first in line.The largest greenhouse gas polluter in the nation in 2010, according to the EPA’s data, was the Scherer power plant in Juliette, Ga., owned by Southern Company. That coal-fired power plant reported releasing nearly 23 million metric tons of carbon dioxide, the chief greenhouse gas, in 2010.Two other power plants owned by Southern were the second- and third-largest polluters nationally: the Bowen plant in Bowen, Ga., and the James H. Miller, Jr. power plant in Quinton, Ala.American Electric Power, another large coal-fired power producer, has three power plants in the top 20. They are in Rockport, Ind., Cheshire, Ohio, and St. Albans, W. Va.”This is just another way to identify the largest coal-fired power plants in the country,” said AEP spokesman Pat Hemlepp. “We always assumed we would be No. 1 in greenhouse gas emissions or No. 2 behind Southern Co. Us and Southern are the two largest consumers of coal.”The other states with high-polluting power plants are Texas, Michigan, Missouri, Montana, Pennsylvania, Arizona, Wyoming, North Carolina, Kansas and Kentucky.Refineries were the second-largest source of greenhouse gas emissions, with 5.7% of the reported total. The top states in greenhouse gas emissions from power plants and from refineries were Texas, Pennsylvania, Florida, Ohio, and Indiana.Congress required industries to report their emissions as part of a 2008 spending bill. Until now, the agency has estimated greenhouse gas emissions by industry sector.

Friday, December 30, 2011 4:26 PM MT
Power generators score a reprieve with court’s stay of cross-state ruleBy Jonathan CrawfordIn an eleventh-hour move, the U.S. Court of Appeals for the District of Columbia Circuit on Dec. 30 stayed the controversial Cross-State Air Pollution Rule, effectively postponing a cap-and-trade program for much of the eastern half of the United States aimed at aggressively slashing sulfur dioxide and nitrogen oxide emissions from power plants.”We are pleased with the court’s ruling because it recognizes the irreparable harm that would have resulted from the short six-month timeline for compliance outlined in the original rule,” Luminant Generation Co. LLC CEO David Campbell said in a Dec. 30 statement.Luminant said it intends to continue evaluating business and operational decisions, given that the court’s stay does not invalidate the rule but only delays a decision on its implementation until a final court ruling is issued.The D.C. Circuit, in its order in the case, EME Homer City Generation LP v. EPA (11-1302, et al.), stated that the petitioners “satisfied the standards required for a stay pending court review.” The court order specifies a Jan. 17, 2012, deadline for the parties to submit proposed schedules for the “briefing of these cases” to accommodate a hearing by April 2012. The EPA, the court noted, is expected to continue administering the less-stringent Clean Air Interstate Rule, which preceded CSAPR. Emissions reductions of SO2 and annual NOx were originally set to begin on Jan. 1, with sources required to demonstrate compliance by March 1, 2013, according to the EPA.In a Dec. 30 interview, Robert W. Baird & Co. analyst Christine Tezak said: “If you’re a coal power plant owner, the specter of having to run your units less or pay a lot for emissions credits, which would erode margins, has passed” based on the court’s stay. Tezak, who in October said a stay of the rule was likely, confirmed that the court’s order is an “across-the-board” stay.The next order of business will be to find out how problematic the issues raised in the petition for review really are, she said, adding that the issues could be fundamental and drive the EPA to “start from scratch” on the rule. Changes to the rule could ultimately extend the starting date for a new version beyond the recently finalized Mercury and Air Toxics Standards rule — which is set to take effect in 2015 — if states have the option of crafting their own implementation plans.Dozens of states and power companies have urged the D.C. Circuit to effect a stay of CSAPR in order to buy more time to comply with the rule and allow the EPA more time to fix what they see as fatal flaws in the rule’s modeling. Opponents have argued that the compliance window was far too short, and that the rule threatens to compromise the integrity of the electric grid as a result of unit retirements and the rule’s stringency.The rule’s critics warned that a Jan. 1 implementation date for CSAPR could cause major disruptions. Luminant indicated it was going to idle generating units and may lay off workers beginning in 2012 should the rule go into effect. Westar Energy Inc. cautioned that it may not be able to “keep all the lights on” for all of its customers. It described as “impossible” the task of coming into compliance by Jan. 1, while also maintaining the reliability of its electric power system. Westar also claimed there was a shortage of allowances to cover the emissions.Entergy Corp., on the other hand, cited faulty modeling in its legal challenge to CSAPR. The company alleged that the model employed by the EPA “significantly underestimated” generation needs, and the final state budgets are “drastically reduced from recent actual emissions data.”The rule was expected to saddle the power sector with $1.4 billion in compliance costs in 2012 and $800 million in 2014, according to the EPA. These costs represent the total costs to the power generation industry of reducing NOx and SO2 emissions to meet the emissions caps set out in the rule. The costs do not include the $1.6 billion per year in expenditures the sector has incurred under the Clean Air Interstate Rule.The EPA appeared to embolden critics of the rule when on Oct. 6 it released proposed changes to CSAPR, which it claimed were “technical adjustments” that would increase emissions budgets in 10 states and ease limits on market-based compliance options. And as recently as Dec. 12, utility companies claimed that a number of comments on the EPA’s revisions to the rule cited material errors, casting further doubt on the rule’s integrity.Industry observers argued the EPA made “serious” procedural missteps with regard to Texas by failing to provide the state with adequate notice of several critical rule changes that went into effect when the rule was finalized, triggering a lawsuit from Texas Attorney General Greg Abbott.By many estimates, the industry overcame long odds in staying the CSAPR, as a result of the high threshold plaintiffs must meet in convincing courts to suspend a rule.Luminant is owned by Luminant Holding Co. LLC, which in turn is owned by Texas Energy Future Holdings. EME Homer City Generation is owned by Edison International.

US BLM to consider gas pipeline route through historic canyon in Utah

Houston (Platts)–3Jan2012/459 pm EST/2159 GMT

The US Bureau of Land Management is considering a Rockies natural gas producer’s proposal to build a gas pipeline in a Utah canyon that is famous for its Indian rock carvings.

The public will be able to comment, through January 15, on an environmental assessment for the proposed Peter’s Point Loop Line, a seven-mile, 20-inch-diameter, low-pressure pipeline that Denver-based Bill Barrett plans to build in Nine Mile Canyon to serve its drilling operations on the West Tavaputs Plateau in Carbon County. Nine Mile Canyon is the nationally recognized site of hundreds of historic Native American pictographs.

Last month, the BLM Price field office released the EA for the project, which considers whether the agency should grant a right-of-way for the proposed pipeline. The EA describes the potential impact of the producer’s proposal to build, operate and maintain the pipeline and suggests several alternative actions, including taking no action on the proposal.

“All activities associated with construction, operation and maintenance of the pipeline would be within the authorized limits of the ROW. Any future realignment, reconstruction, or maintenance outside the authorized area would require additional analysis,” BLM said in a statement.

In January 2010, after a year of negotiations, BLM and Bill Barrett signed a historic agreement that paved the way for the producer to drill up to 807 gas wells atop the Tavaputs Plateau in exchange for adopting a broad range of mitigation measures to ensure the preservation of the canyon’s environmental and cultural resources.

Jennifer Martin, Bill Barrett’s vice president of investor relations, said Tuesday in an interview that the proposed pipeline is part of the infrastructure that the producer plans to build in the first quarter of this year to service drilling operations it plans to conduct under its permit.

Pam Miller, president of the Nine Mile Coalition, said the coalition has not yet commented on the proposed project, but plans to do so before the deadline. “I haven’t read the proposal yet,” she said. The coalition, a citizens group dedicated to protecting the canyon’s historic artwork, is “comparing the proposal to the West Tavaputs [environmental impact statement] and other documents to make sure the same values and conditions are being met,” Miller said.

In an action alert, the coalition’s board called on the group’s members to examine the EA and formulate comments to submit to the BLM. The alert notes that the proposed pipeline easement across federal and state lands “will affect the historic Lower Ranch and the prehistoric Cottonwood Village Complex.”

In its EA, BLM said the proposed pipeline was needed “to transport low-pressure natural gas to the existing Dry Canyon Compressor Station.” The agency said it had previously analyzed proposed locations for pipelines, including loop lines, in the West Tavaputs Plateau Natural Gas Full Field Development Plan’s environmental impact statement.

Under the EIS the infrastructure for the project would comprise six- to eight-inch-diameter gathering lines to individual wells, which would tie into a 10- to 16-inch-diameter trunk line that “would eventually transport the gas to the Questar gas sales pipeline.” Questar Gas asks PSC for tiny trim of natural gas rates
By Steven OberbeckThe Salt Lake Tribune
Questar Gas is asking state utility regulators for permission to lower the amount it collects from its customers for the natural gas it supplies by $770,000.If the Public Service Commission approves the rate cut, the typical Utah homeowner’s annual bill will go down by 61 cents a year.“We actually had some system-enhancement cost increases this year but, when we combined them with decreases in our conservation program costs, the end result is a decrease in our overall rates,” Craig Wagstaff, senior vice president of Questar Gas, said in a statement announcing the rate reduction request.Questar Gas doesn’t make any money off the natural gas it supplies its customers. Still, the company must periodically adjust rates to ensure it is collecting just enough money to cover the cost of the natural gas it purchases. The company makes its money by charging customers to deliver natural gas over its pipeline network.The utility, whose rates for natural gas in Utah are among the lowest in the nation, typically asks the PSC twice a year for permission to adjust the rate it charges its customers for the fuel.The last time Questar Gas request a rate adjustment was in early September. At that time, Questar asked the PSC for permission to lower the amount it charged customers by $18.9 million beginning Oct. 1. That decrease resulted in the typical Utah homeowner’s annual bill going down by $11.65, or 1.7 percent.MidAmerican Energy Holdings buys into NRG’s Agua Caliente PV farm Chris MeehanJan 04, 2012In less than two weeks, MidAmerican Energy Holdings Co. has gone from zero to 840—at least in terms of solar megawatts. This time it purchased a 49 percent stake in NRG Energy’s (NYSE: NRG) 290-megawatt Agua Caliente solar project in Yuma County, Ariz., slated for completion in 2014.MidAmerican Energy is controlled by billionaire investor Warren Buffett’s Berkshire Hathaway. It is the nation’s largest purveyor of wind among rate-regulated utilities. And by the end of 2011, 28 percent of all its generation will come from renewable and non-carbon sources, according to a press release.But this is only the second instance where the Iowa-based company has invested in a solar project. On Dec. 7, it purchased the 550-megawatt Topaz Solar Farm in California that’s being developed by First Solar, Inc. (NASDAQ: FSLR).Agua Caliente also will use First Solar modules and is being built by the company. While MidAmerican purchased a large stake in the project, it will not control the project.“NRG will remain the majority owner,” said NRG spokesperson Lori Neuman.This $1.8 billion Agua Caliente project is supported by a $967 million loan guarantee from the U.S. Department of Energy. It’s under a 25-year, power-purchase agreement with Pacific Gas and Electric.The company will use the proceeds from MidAmerican’s purchase for general corporate purchases.“Such as further reinvestment in our business, further solar developments, capital allocation in the form of share repurchases or debt pay-down,” Neuman said.NRG is looking to sell other solar projects in its portfolio.“As mentioned over the past few months, and more recently during our quarterly earnings, we’re continuing to pursue other opportunities to sell-down additional solar projects. But we haven’t talked about any specific companies,” Neuman said.

This is the first project NRG has worked on with MidAmerican.NRG has a history of both wind and solar project development. It has 485 megawatts of wind power in the U.S. It also has more than 1,900 megawatts of solar generation in various stages of development, with 900 megawatts of solar generation operating or under construction.
FERC, NARUC Launch Forum On Reliability, Environment

Renew Grid, Thursday 05 January 2012 - 10:03:24 Federal and state energy regulators plan to launch a forum to explore reliability issues stemming from new and pending environmental rules for the power sector.

The forum, which consists of members from the Federal Energy Regulatory Commission (FERC) and the National Association of Regulatory Utility Commissioners (NARUC), will coincide with NARUC’s three yearly meetings.

The first meeting of the FERC-NARUC Forum on Reliability and the Environment will take place Feb. 7 during the NARUC Winter Committee Meetings in Washington, D.C. FERC Commissioners Cheryl LaFleur and Philip Moeller will be the federal co-chairs of the workshops, and NARUC First Vice President Philip Jones and Treasurer David Ziegner will be the state co-chairs.

FERC and NARUC initiated the forum as part of an effort to determine how prepared the electric utility industry will be to meet upcoming rules and requirements on emissions reductions. With significant investment in utility infrastructure predicted over the next several years, the forum will let federal and state regulators discuss these issues in an open and transparent venue, according to the organizations.

The Utah Association of Energy Users wishes you, your staff and families a wonderful and safe Christmas.New mercury rule seen putting added pressure on US power marketsBy Peter MarrinFalling natural gas prices and weak power demand continue to weigh down power prices, with further losses possible after the EPA’s mercury rule released Dec. 21 came in “slightly softer than expected,” according to analysts with Macquarie (USA) Research.”We estimate that PJM East/ERCOT power prices include less than US$1/MWh from EPA but we continue to see roughly US$3/MWh in the Midwest,” the firm said in a Dec. 22 note to clients. “The mercury and air toxics rule finalized yesterday came even softer than we expected and further delays are possible.”The advisers said weather-normalized power demand remains weak, especially in California and New England, where demand is down about 2% year on year. And while Ohio, Texas and New York have recorded strong power demand, “[t]he strength in OH/NY could be temporary … and associated with a catch-up in the auto industry from 1H2011.”The weak demand, coupled with a 9% drop in natural gas prices since the firm’s last update in late November, has sent power prices 5% to 8% lower in the past month. The analysts noted that continued growth in gas output and moderate weather, especially in the Midwest and the Northeast, continue to weigh on natural gas prices.”Macquarie Energy continues to see some downside to natural gas prices but believes that 2013+ gas prices have fallen to such low levels that by 2013 we could see some supply curtailment,” the firm said. “Coal-to-gas switching has accelerated (up 3 Bcf/day) but when we analyze the location of most vulnerable coal plants we see an upside to switching of only 2 Bcf/day — not enough to provide much support to natural gas prices, we believe.”The falling natural gas prices have encouraged a response from coal prices, and from CAPP prices in particular, but dark spreads remain very weak. In addition, quark spreads, which account for nuclear generation costs, “are particularly pressured by falling natural gas and coal prices.”The firm said 2012-2013 spark spreads have expanded strongly across the U.S., especially in the Midwest and ERCOT, where coal-fired plants predominantly set power prices.But “somewhat surprisingly,” 2014-2015 spark spreads have compressed everywhere but in the Midwest.”We are puzzled by the compression in 2014/2015 heat rates, which we see as driven by market liquidity issues, unwinding of some trades and (to a lesser extent) a lack of willingness to pay for a long-term heat rate expansion due to weak near-term load growth fundamentals, especially in PJM,” the analysts said.ERCOT’s tightening marketAccording to Macquarie, given growing power demand and a lack of new power capacity additions, ERCOT will be short on power capacity as soon as 2013. “Our power price assumptions for ERCOT for 2013-2015 already assume a 3-4% inflation above the current forward curve but a further pick up in power prices is needed to justify new build,” the firm said.On Dec. 1, ERCOT said it was slashing its projected reserve margins through 2015 due to delayed and canceled power projects, as well as increased load growth forecasts. In a report released in May, ERCOT said it expects summer reserve margins to reach 17.5% in 2012, 14.2% in 2013, 11.1% in 2014 and 11.3% in 2015. However, ERCOT now expects its summer reserve margins to reach 12.1% in 2012 and 2013 before plunging to 7.6% in 2014 and to 3.6% in 2015. ERCOT’s target reserve margin is 13.75%. “Forward power prices in TX do not reflect the market tightness, especially beyond 2013,” the analysts said, pointing to a lack of liquidity in the forward markets since almost 80% of ERCOT load is served by competitive retailers who tend to hedge 12 to 18 months forward.Pointing to a recently hosted luncheon with Public Utility Commission of Texas Chairman Donna Nelson, Macquarie said Nelson admitted the Texas power market is tightening and that strong pricing signals need to be sent to encourage new build for merchant power plants. She said higher pricing floors to dispatch non-spin reserves together with higher caps on power prices could provide an initial boost, though she felt the currently proposed levels could be insufficient.”Chairman Nelson did not seem supportive of capacity markets in TX,” the analysts wrote. “Instead she seemed more open to requiring load-serving entities in TX to procure electricity under at least medium-term contracts to support new build.”EPA regs lend pressure, but CSAPR could still spook prices Macquarie estimated that PJM East and ERCOT power prices are carrying less than $1/MWh in EPA-driven inflation but that power prices in the Midwest could be carrying a premium of roughly $3/MWh.On Dec. 21, the EPA finalized its mercury and air toxics standards, providing for an additional one year of compliance to assure reliability of electric services, postponing the compliance to December 2016 on a plant-by-plant basis.”The rule came even softer than we expected but so far we have seen no reaction to the rule in forward power prices,” Macquarie said. “Compared to the proposed [standards] from March, the final rule reduced the levels of emission reductions for Hg/HCl/SO2 to 75%/88%/41% from 79%/91%/53%, respectively.”The report said the final rule will cover 1,100 coal-fired units, instead of 1,200 previously estimated, and should lead to retirements of 4.7 GW as opposed to 10 GW previously thought, “though both numbers seem low to us.”The softer final version of rule together with weak load growth also could weigh on the next PJM capacity auction, the analysts said, “though for now we assume flat capacity prices YoY.”"Given that the final rule is less stringent than the proposal, we would have expected forward power prices to have fallen today, especially in the PJM. However our understanding is that we are yet to see any meaningful reaction. We attribute this simply to low trading volumes ahead of the holiday weekend.”However, prices could still find support as the industry awaits a court ruling on stay motions for EPA’s SO2/NOx rule, known as the Cross-State Air Pollution Rule, or CSAPR. The court decision could be released as soon as Dec. 23. “If the implementation of the rule is not delayed and/or TX is not exempt, we could see a sharp rise in forward power prices,” Macquarie said.

BPA’s Wind Curtailment Violates Open Access TariffIn a major victory for wind developers, FERC ruled Dec. 7 that Bonneville Power Administration’s interim Environmental Redispatch (ER) and Negative Pricing policy “results in transmission service that is not comparable to the service it provides itself.” The 38-page order did not rule on BPA’s past actions, but gave the agency 90 days to file tariff revisions that are comparable and “not unduly discriminatory or preferential.” It also invited BPA to include any deviations it can justify. More than 50 parties filed comments in the closely-watched case [EL11-44].BPA adopted the ER policy May 13, 2011, saying that during periods of high runoff and low electricity demand, it must reduce generation in its balancing area. Under the policy, when it cannot back off hydropower generation without risking reliability violations or statutory violations triggered by increased dissolved oxygen levels, it turns off other non-federal generation. Although BPA provided curtailed generators free hydropower as compensation, wind owners lost production-tax and renewable-energy credits. Estimates of the value of those losses in 2011 vary from $2 million to $50 million. FERC said it “recognize[s] the dilemma that BPA faces in having to navigate many competing obligations” and that it “must reconcile the obligations set forth in its organic statutes with numerous rules and regulations,” including the Clean Water Act and ESA. But, it said, BPA “also must reconcile the provision of comparable service” and that its effort to do so through the ER policy “significantly diminishes open access.” The ruling came as BPA administrator Steve Wright continues facilitating settlement meetings with a small group of developers who filed for review of the ER record of decision in the 9th U.S. Circuit Court of Appeals. Briefing in the case, previously in abeyance during settlement talks, is set to begin Feb. 15 — six weeks before the interim ER policy expires. Even so, the settlement group met last Monday and is set to meet again before Christmas. It is unclear how the ruling will affect the talks.In a motion opposed by wind developers, most of BPA’s major public agency customer trade groups and some individual preference customers asked FERC to hold off issuing its order until the Ninth Circuit rules. FERC refused, saying it has “exclusive authority” under Section 211A of the Federal Power Act to order compliance. But it did offer to designate non-decisional staff to help in the discussions to craft the tariff revisions.”We are surprised and very disappointed that FERC would choose at this moment to render a decision when it is aware that we have been urged by many members of the Northwest Congressional delegation to settle this issue, and when settlement discussions are proceeding in good faith,” Wright said in a brief statement. “The temporary oversupply of energy is a Northwest challenge. We believe it is the region’s responsibility to find the most appropriate way to address this challenge.”His comment was echoed by Sen. Ron Wyden (D-Ore.), one of 11 delegation members who signed an Aug. 8 letter urging BPA to settle. “I would have preferred that this issue had been resolved in the region and not at FERC,” Wyden told Energy Prospects West by email. “I have urged BPA and the wind developers to work together to solve this and I think that is still the best course. BPA has now been told by FERC to come up with a new approach to handling wind generation on its transmission system and all parties need to roll up their sleeves and get to work.”BPA’s public-agency customers were disappointed. BPA’s ER policy “is warranted in that it treats all generators equally” while ensuring system stability and protections for endangered fish, said Scott Corwin, executive director of PPC. He criticized the ruling for its dearth of analysis: “It focuses narrowly on FERC’s jurisdiction under the Federal Power Act but ignores all the other federal laws that BPA is subject to.” PPC is concerned the ruling “will lead to an unfair increase” for customers served by federal power, and that “we don’t know the scope or size of the exposure, especially if we have some really large water years,” Corwin added. He said it is statutorily improper to “burden” public utilities who do not benefit from wind power with the costs of lost renewable resource credits.Wind developers and their allies were delighted. “I think the order was about as good as the wind power developers could have expected,” said John Cameron, attorney for Caithness Shepherds Flat. “It is reasoned. It is not extreme. It acknowledges Bonneville’s various statutory obligations but says one of them, co-equal with the rest, is to provide comparable transmission service.” He dismissed the need to await the Ninth Circuit’s ruling because the statutes at issue in that case are different. Don Furman, senior VP for external affairs at Iberdrola — one of the original five complainants in the FERC proceeding — said he was pleased with the order because “we presented them with the facts and they, in a fairly workmanlike way,” applied the facts to the law. “They did not range far afield but also did not equivocate and were clear and direct. Hopefully that clarity and simplicity will allow us to go back to the table, where we have been all along with Bonneville.” Furman, who fully expects some party will file for rehearing, said Iberdrola does not intend to dwell on the past. “Obviously we didn’t like” what happened when BPA implemented the ER policy last spring, “but it was not the end of the world. The reason for the filing was for going forward. We need to know what the rules are and why Bonneville shouldn’t follow the same rules as other transmission providers.”"We won’t complain if they curtail us,” he added, “but not for economic reasons.” BPA said in its ER ROD they didn’t want to pay prices below zero, “but as it turns out their intertie lines were open,” so there were places it could have sold the surplus. “They didn’t like the prices and curtailed us instead.”"BPA easily could have avoided this outcome but chose to pursue a flawed and a blatantly discriminatory Environmental Redispatch policy that exemplified BPA’s arrogance,” said Robert Kahn, executive director of the Northwest & Intermountain Power Producers Coalition. “FERC’s action will ultimately lead to optimization of the West’s transmission grid by, to cite a single example, breaking down SEAMS between balancing area authorities. Today’s action will also, in due course, restore the confidence of renewable energy developers and Independent Power Producers generally that BPA will treat them equitably as transmission customers.”Rachel Shimshak, executive director of the Renewable Northwest Project, said FERC’s ruling “will precipitate new levels of collaboration and clean energy advancement.” She said RNP is “eager to continue working with BPA” and others on solutions to overgeneration that are “economical, equitable and good for the environment.” Shimshak recommended a “suite of strategies” to choose from, including displacing fossil fuel beyond BPA’s balancing area, improved forecasting and storage techniques. Other alternatives mentioned in the record include entering storage agreements with British Columbia, signing displacement agreements with regional IOUs for generation outside the BPA BA, and paying “negative prices” to get generators to back off output.The ruling also left parties wondering how it will affect BPA’s long effort to restore its reciprocity status at FERC. Entities such as BPA are not required to file OATTs, but under its safe harbor process, FERC allows such entities to voluntarily file an OATT in exchange for being entitled to reciprocal treatment from other transmission owners. BPA filed a voluntary OATT, but FERC ruled that it did not conform to the pro forma OATT. In its ongoing Bonneville OATT proceeding, BPA has been working with customers to resolve 19 pro forma OATT deviations with an eye to filing a revised OATT tariff as early as this month. The next meeting was scheduled Dec. 19.Most issues have been resolved, but Iberdrola’s Furman said one major outstanding question is whether there is “preference” to transmission access. Furman said he has no problem with public preference to federal generation, but does not agree preference exists for transmission.Public power says “transmission preference” is the wrong phraseology. PPC’s Nancy Baker said the question is over Priority Access, that is, the conditions under which BPA makes excess transmission capacity available, whether it can step in front of other parties to take that capacity, and whether this can be accommodated under the OATT. “The fundamental, philosophical difference of opinion is whether the pro forma OATT is the primary driver behind what Bonneville does” or, when it has conflicting statutes, whether it can act under its own authority.Pending further review, Baker declined to opine on the effect of the FERC ruling, or what its nexus may have with the Priority Access question [Ben Tansey].

Zephyr Line Sold to Duke-American Transmission Co.Wyoming wind developers may have a taken giant leap forward in reaching markets in California and the Southwest.Duke-American Transmission Co. (DATC) announced on Dec. 19 that it has acquired the proposed $3.5-billion Zephyr Power Transmission Project from from Pathfinder Renewable Wind Energy LLC., which bought the project from TransCanada in July.The proposed 950-mile DC line would originate in Chugwater, Wyo., and terminate in the Eldorado Valley just south of Las Vegas, Nev. The project has been in limbo since TransCanada backed out of it earlier this year.”Transmission development in the West over public lands is not for the impatient or the faint of wallet,” Loyd Drain, executive director of the Wyoming Infrastructure Authority, told Energy Prospects West. “It would have taken a quality developer like Duke-ATC to definitely step in and continue the development that has occurred. Duke-ATC is a welcome addition to the other great developers at work in this state,” Drain said.Pathfinder will retain 2,100 MW of the 3,000 MW of capacity on the line for its portfolio of wind projects planned for 100,000 acres near Chugwater. In May 2010, the project was fully subscribed, with Horizon Wind Energy and BP Wind Energy NA claiming a combined 900 MW of the line. In June 2011, TransCanada “terminated the precedent agreements with our potential shippers as the parties were unable to resolve key commercial issues,” Terry Cunha, spokesperson for TransCanada, told Prospects, via email. In July 2011, Pathfinder exercised its contractual rights to acquire the Zephyr project from TransCanada.TransCanada has suspended development of the 3,000-MW Chinook Transmission Line, which would have started in Harlowton, Mont., and run parallel with the Zephyr line through southeastern Idaho to the Eldorado Valley, terminating south of Las Vegas.Phil Grigsby, Duke Energy Commercial Businesses senior vice president, said in a prepared statement that California may be the largest market for renewable power in the country with a renewable energy portfolio standard of 33 percent.DATC’s Zephyr project creates a highly efficient and strategic connection between the wind-rich areas of Wyoming and electricity load centers in California and the southwestern U.S., Grigsby said.In October, the Western Electricity Coordinating Council’s 10-year Regional Transmission Plan labeled the Zephyr Line and the 600-KV HVDC TransWest Express Transmission Project as “providing the most cost-effective remote renewable energy resource alternatives to satisfy a portion of California’s needs.”"Zephyr is an ambitious energy infrastructure project that is laser-focused on providing an integrated solution to a recurring problem facing America: How do we get clean, renewable energy to the population centers?” Grigsby said.While wind generation and transmission development are being pursued separately, Pathfinder and DATC have agreed to work together to increase the viability of the integrated projects.”The success of this transmission project is dependent upon on the success of Pathfinder’s generation project, and vice versa,” said John Flynn, vice president, Strategic Planning and Business Development for American Transmission Co. “By working together on a parallel development path, we avoid ‘the chicken and the egg’ dilemma that has often challenged major projects like this.”In April, Duke Energy and American Transmission Co. announced they were forming a joint venture to build, own and operate new electric transmission infrastructure in North America.DATC hopes to begin environmental analysis, design routing and work on siting the project next year. If approved, the transmission line would be in service in 2020 [Steve Ernst].

Canada Pulls Out of Kyoto ProtocolCanada announced on Dec. 12 that it is withdrawing from the Kyoto Protocol, the 1997 treaty to reduce greenhouse gas emissions, citing huge potential fines the country may face for not meeting the emissions standard.The decision by Prime Minister Stephen Harper’s conservative government was not unexpected, since Conservative Party officials have made no secret of their disdain for the treaty, which was negotiated and signed on behalf of Canada by a Liberal Party government in 1997.Under terms of the treaty, Canada had to give notice of its intention to withdraw by the end of 2011. The country faced billions in fines for not reaching its emissions targets. In his announcement of Canada’s withdrawal from the agreement, Environment Minister Peter Kent said, “We are invoking Canada’s legal right to formally withdraw from Kyoto.”The day before Canada’s announcement, at a United Nations conference in Durban, South Africa, nearly 200 nations voted to renew the treaty — which will expire at the end of 2012 — but did not come to agreement on whether its emissions targets will apply equally to all countries. The original agreement required industrialized nations to meet targets for reducing greenhouse gas emissions but did not impose those targets on developing nations, and the United States never ratified the treaty.In his announcement, Environment Minister Kent said the current agreement does not cover the world’s two largest emitters — the United States and China — and “therefore, cannot work.”Kent added that Canada would work toward an agreement that would include targets for all countries, including developing nations, such as China and India [Penelope Kern].

Bernstein: Major shift in US power generation coming in next 5 yearsBy Michael NivenThe next five years will see a significant shift in the composition of U.S. power generation as strict environmental regulations will combine with other factors to shrink coal-fired capacity and spark strong growth in natural gas-fired power and renewable energy, Sanford C. Bernstein & Co. LLC concluded in a new research report.Bernstein said it expects 66 GW of existing U.S. coal-fired capacity to be retired by 2015, consisting of 54 GW of cumulative retirements from the U.S. EPA’s Cross-State Air Pollution Rule and Mercury and Air Toxics Standards, and an additional 12 GW from closures of old coal plants near the end of their lives. The firm said the anticipated coal retirements will be partly offset by the addition of 17 GW of new coal-fired capacity by 2015, resulting in an overall net reduction of U.S. coal-fired generating capacity of 49 GW.On the flip side, Bernstein anticipates that the EPA clean air rules combined with state renewable generation mandates and the relatively cheap and quick process for building new gas-fired generation will drive sharp growth in renewable and gas capacity additions. Bernstein analyzed the potential shift U.S. power generation resource mix under two different scenarios: a low-load-growth scenario using the U.S. Energy Information Administration load growth forecast of 0.2% per year from 2010 to 2016, and a high-growth scenario using the North American Electric Reliability Corp.’s load growth forecast of 2.5% per year over the same period.Under both scenarios, Bernstein said it anticipates approximately 60 GW of new U.S. renewable capacity to be added by 2015 to comply with state renewable generation mandates. On the gas side, Bernstein estimates that 75 GW of new gas-fired capacity would be added in the U.S. by 2015 under the low-growth scenario and 90 GW built under the high-growth scenario.Bernstein estimated that under the low-growth model, the U.S. fuel mix for power generation would be 39% coal, 25% gas, 20% nuclear, 10% renewable and 6% hydro. Under the high-growth model, the mix would be 36% coal, 30% gas, 20% nuclear, 11% renewable and 5% hydro, according to the report. In 2009, the breakdown was 45% coal, 24% gas, 20% nuclear, 6% hydro and 5% renewable, Bernstein said.The anticipated shift in the U.S. generating mix will take a major toll on domestic coal consumption, according to Bernstein, which estimates that utility coal demand will fall by more than 100 million tons by 2015, equivalent to 10% of total U.S. coal production. Appalachia will be the coal-producing region hardest hit by the shift, with Bernstein estimating that demand will fall by an estimated 76 million tons, or 16%, by 2015.Utility demand for natural gas, meanwhile, should grow by an annual rate of 2% to 7% through 2015, depending on the load growth forecast, Bernstein said.

Warren Buffett To Buy Another Solar PlantDec. 19, 2011
MidAmerican Energy Holdings Company, which is owned by billionaire Warren Buffett, announced on Friday it agreed to buy a
$1.8 billion solar farm in Arizona, betting on promising development of the solar industry.
MidAmerican Energy said it would acquire a 49 percent stake in the Agua Caliente solar project, a 290-megawatt photovoltaic power plant, from NRG Energy, but it did not disclose the price of the
deal.
The solar plant, which is being constructed by First Solar in Yuma County, Arizona, is supported by a $967 million guarantee
from the U.S. Department of Energy. The project is expected to be complete by 2014 and will generate enough electricity to offset about 5.5 million metric tons of carbon dioxide over 25 years.
This is the second solar project Buffett announced to buy this month. On Dec. 7, MidAmerican said it had purchased from First Solar the 550-megawatt Topaz project, being built in South California.
Buffett told investors earlier this year he would pursue bigger acquisitions by using his over $38 billion pile of cash. EPA sets new NOx emissions limits for 5 statesBy Jonathan CrawfordThe EPA on Dec. 15 announced that it finalized a rule placing more stringent summertime limits on nitrogen oxide emissions for five states — Iowa, Michigan, Missouri, Oklahoma and Wisconsin.The EPA added the states to the ozone season NOx program under the Cross-State Air Pollution Rule on the basis that the states were found to “significantly contribute” to, or interfere with, pollution levels in other states, according to an agency fact sheet. The emissions reductions apply to the months of May-September.”With today’s action, the CSAPR requires 28 states to significantly improve air quality by reducing power plant emissions that contribute to ozone and/or fine particle pollution in other states,” the EPA stated in its fact sheet.The EPA is finalizing ozone season NOx emissions budgets for covered units, associated variability limits and new unit set-asides, as well as allowance allocations for covered units in each state.The EPA’s supplemental rule sets a 2012 and 2013 NOx ozone season trading budget, which includes new unit set-asides, of 16,532 tons for Iowa, 28,041 tons for Michigan, 22,762 tons for Missouri, 36,567 tons (2012) and 21,835 tons (2013) for Oklahoma, and 14,784 tons for Wisconsin. The EPA also noted that it is increasing Oklahoma’s ozone season NOx budget for 2012 from the level proposed in July 2010 in response to concerns brought up in public comments.”EPA recognizes that the timing of this final action would not allow Oklahoma sources to install new combustion control equipment ahead of the 2012 ozone season. In addition, EPA acknowledges that Oklahoma sources would not have enough time to shift the distribution of electricity to cleaner generators to meet local electricity demand that is currently being met by oil/gas units,” the agency said.The EPA determined that Kansas also contributes to nonattainment of ozone standards in other states, but it is not finalizing a federal implementation plan for the state “due to the unique status of Kansas’ state implementation for ozone.” The EPA said that, instead, in a separate action, it will issue a state implementation plan call, for Kansas to reduce its emissions and will give the state 12 months to resubmit an ozone state implementation plan that “adequately reduces its contribution to downwind ozone air quality problems. PacifiCorp files for rate increase in WyomingBy Jim DavisOn Dec. 9, PacifiCorp filed with the Wyoming Public Service Commission (PSC) for a $62.8 million (10.4%) electric rate increase premised upon a 10.2% return on equity (52.1% of capital) and a 7.934% return on an average rate base valued at $1.839 billion for a test period ending March 31, 2013 (Docket No. 20000-405-ER-11). The company cites as reasons for the request increased investments “necessary to maintain safe and reliable electric service in compliance with all environmental regulations, to obtain resources to meet growing electricity use in Wyoming and to sustain quality of life, economic development and long-term competitive prices.” PacifiCorp does business in Wyoming as Rocky Mountain Power and is a subsidiary of MidAmerican Energy Holdings, which is privately owned by a consortium of investors, including Berkshire Hathaway.PacifiCorp’s most recent Wyoming-jurisdictional rate proceeding was decided on Sept. 22, 2011, when the PSC authorized the company a $61.3 million base rate increase premised upon a 10% equity return, following a settlement (see the Final Report dated 10/18/11). A final PSC decision in the instant case is expected in October 2012.

Other highlights of The C Three North American Electric Transmission Project Database show that Texas still comfortably leads all states with more than 9,175 miles of new lines planned through 2020. The C Three Group also found that the U.S. and Canada has nearly 4,000 substation projects planned over the next eight years with American Electric Power topping all utilities with 268 new projects.

The C Three Group continuously tracks the status of early stage, advanced development, and under-construction electric transmission projects in its North American Electric Transmission Project Database. C Three’s electric power industry experts developed the database for long-range forecasting, strategic planning and business development.
Since December 1, 2011, The C Three Group has added more than $2.7 billion and 1,408 miles of new and upgrade transmission line and substation projects to the database. “Our team exhaustively combs through more than 300 data sources annually to provide our users with the most up-to-date, comprehensive electric transmission project information source available. More than 150 companies and organizations depend on our analysis and timely updates as input into their strategic planning and business development functions,” said Jean Reaves Rollins, founder of The C Three Group.

The ruling will impact various aspects of three dozen or more coal-fired power plants, including some now already under construction.

Major coal-fired power plants impacted by the ruling include: LS Power White Pine (1500 MW - permit pending in Nevada); Sierra Ely (1500 MW - permit pending in Nevada); Toquop (850 MW - permit pending in Nevada) Desert Rock (Sithe Global’s 1500 MW in New Mexico); Longleaf ( LS Power’s 1200 MW Plant in Georgia); Cliffside (Duke Energy’s 800 MW Plant in North Carolina); Alliant Marshalltown (600 MW – permit pending in Iowa); LS Power Waterloo (750 MW – permit pending in Iowa); AMP (1000 MW – permit challenged in Ohio); LS Power/Dynegy (750 MW in Michigan). For a complete list of all 32 plants, go to http://www.nrdc.org.

Without Bluewater Wind, this Atlantic Wind Connection power underwater transmission cable,
funded in part by Google, faces increasingly tall hurdles.

“Financially untenable” is how NRG Energy updates its outlook for what was a planned array of wind turbines offshore Delaware. And with that prognosis, the future of wind energy off the U.S. East Coast is very much in doubt.

While the project’s fate may have been cast when the U.S. Department of Energy rejected its application for a federal loan guarantee earlier this year, the failure to find a project partner in the increasingly challenging financial and policy environments for renewable energy in the U.S. apparently has sealed its defeat.

More than just a few renewable energy developers and financiers are asking: what’s the next ‘shoe’ to drop on clean energy in the U.S.? Questions abound while China forges ahead strengthening its manufacturing prowess and further driving down its wind and solar energy cost advantages

Is Google going to pull back from its vision for an underwater transmission line linking wind energy systems between coastal New Jersey and Virginia? Will the Maryland legislature continue to reject financing offshore wind to meet its renewable electricity requirements by 2022? Will Gamesa and Northrup Grumman Shipbuilding hit the pause button on its planned offshore wind technology center in Chesapeake, VA?

The Bluewater Wind project announcement is especially unsettling to clean energy advocates because of the foundation for what appeared to be a financially viable system leading the charge on the U.S. East Coast. Even so, darkening prospects for the wind production tax credit which expires at year-end 2012 further raised an increasingly high ‘bar.’

Bluewater Wind had a 25-year contract with utility Delmarva Power to supply up to 200 megawatts of power from the project. That deal was approved by the Delaware Public Service Commission in 2008, and provided a base energy price of 9.9 cents per kilowatt-hour. When combined with a statutory bonus for offshore wind renewable energy credits, the effective price per kilowatt hour in 2012 might have been closer to 14 cents.

Friday, December 02, 2011 4:33 PM MT
Calif. PUC approves standard offer utility contracts for combined heat, powerBy Jeff StanfieldThe California Public Utilities Commission on Dec. 1 approved two standard offer power purchase agreements for eligible combined heat and power facilities. The commission hopes its decision will finally get utilities and industrial customers to cooperate in generating more electricity from industrial, commercial and institutional sites instead of letting that energy go to waste.The approval of the contracts is the final stage of a three-year process to develop the contract price, terms and conditions for the CHP feed-in tariff program, which was hammered out in contentious, protracted negotiations between industrial customers and their utilities. The standard offer contracts are meant to provide CHP facilities that generate fewer than 20 MW and are at least 62% efficient with an easy outlet for power that cannot be used by the facilities where they are located, the PUC said in its decision.Following passage of Assembly Bill 1613, the PUC, in collaboration with the California Energy Commission, established the CHP FIT program, which requires investor-owned utilities to purchase excess power from small, efficient CHP facilities at a known fixed price under a standardized contract.The standard FIT contract approval comes just after a December 2010 settlement among the parties became effective Nov. 23. The PUC approved the settlement in December 2010, but some issues, including the standard contracts, remained to be settled.The utilities sought a rehearing on the PUC’s 2010 decision, saying the price to be paid to CHP generators would violate both the Public Utility Regulatory Policies Act of 1978 and FERC regulations because it was higher than the utilities’ avoided costs.The commission on April 19 denied rehearing except on limited issues, saying FERC has recognized that qualifying facilities of 20 MW or below represent a special class of small QFs, which has routinely been subjected to different standards than large QFs.However, the PUC directed the utilities to submit advice letters to amend tariff sheets and contracts. From that process, the just-approved standard contracts were drawn up and approved.”The AB 1613 program has been very controversial because of the utilities’ objections to a standard tariff that establishes a fixed price for purchases, also known as a ‘fixed price feed in tariff’ or ‘FIT,’” the PUC said in its April decision. “Consequently, the utilities have opposed implementation of AB 1613 at the commission and before FERC.”There are more than 9,000 MW of CHP systems, large and small, operating at 776 sites in California, according to the California Air Resources Board’s Climate Change Scoping Plan.However, the state has a goal of adding an additional 4,000 MW of CHP capacity by 2020, with the potential to produce 30,000 GWh and reduce greenhouse gases, the plan said.By allowing CHP system owners to sell excess electricity to investor-owned utilities at a reasonable price, the program helps encourage more efficient sizing of CHP systems and maximize the use of waste heat for distributed generation, the PUC said in a press release.”This combined heat and power technology offers economic benefits for the California energy market,” Commissioner Timothy Simon said in the press release. “These systems produce power locally for users, aid the entire grid by reducing demand during peak times, and minimize congestion of electric power on the network.”The FIT plays a critical role in the state’s larger efforts in creating a viable market for combined heat and power facilities, Commissioner Mark Ferron said in the release. “Converting waste heat to power using a CHP system can be a highly effective way for a facility to increase its energy efficiency and decrease its carbon emissions,” Ferron said.The PUC hopes this will help California become the first state in the nation to move CHP facilities into a competitive market in 2012.Berkshire Buys $2 Billion Power Project in Buffett Solar BetDecember 07, 2011, 10:45 AM EST By Todd White and Marc Roca (Updates with shares in the seventh paragraph.)Dec. 7 (Bloomberg) — Warren Buffett’s MidAmerican Energy Holdings utility agreed to buy the $2 billion Topaz project in southern California, branching into solar power after the industry was battered by stock markets around the world.The Topaz Solar Farm will be one of the world’s largest photovoltaic power plants and is being developed by the seller, First Solar Inc. of Tempe, Arizona, according to a joint statement today. Terms weren’t disclosed. The project’s 550- megawatt capacity is equal to about half a new nuclear reactor.Buffett’s Iowa-based utility, which entered clean energy buying U.S. wind farms and a stake in Chinese electric-car producer BYD Co., struck today’s deal after First Solar failed to get a U.S. government loan guarantee for the project that will use First Solar’s thin-film solar panels.Topaz “demonstrates that solar energy is a commercially viable technology without the support of governmental loan guarantees,” said Greg Abel, chief executive officer of the MidAmerican business at Buffett’s Berkshire Hathaway Inc., in the statement. The utility will seek to add more assets of this type to its unregulated portfolio, he said.Tax benefits may have helped attract the billionaire, according to Jefferies International Ltd.“The reason for the move from wind to solar is very simple,” Gerard Reid, a London-based analyst at Jefferies, said in an interview. “Tax credits for wind in the U.S. expire at the end of next year, while solar ones run till 2015.”Stock PerformanceBerkshire slipped 1.1 percent to $116,190 at 9:36 a.m. in New York, while First Solar advanced 8.6 percent to $50.07. The renewable energy company’s shares had fallen 65 percent this year through yesterday, matching the drop in the 17-company Bloomberg Industry Global Leaders Large Solar Energy index.The declines, triggered by plunging prices for solar panels and their components, have pushed companies around the world to conserve cash, look for partners or consider bankruptcy. Cylindrical thin-film panel maker Solyndra LLC received a $535 million government loan guarantee and then went bust this year.MidAmerican, which had $46 billion in assets on Dec. 31, called the Topaz purchase a “strategic move” that builds on its experience with wind energy. The natural gas and power provider has built up stakes in more than a dozen wind parks that can generate at least 1.5 gigawatts of power, according to Bloomberg New Energy Finance data.Largest SupplierThe power company sells electricity to 2.4 million customers in the U.S., and is the largest supplier in Iowa, Wyoming and Utah, according to Buffett’s most recent annual letter to Berkshire shareholders. Buffett is chairman and CEO of Omaha, Nebraska-based Berkshire.The unit transports 8 percent of the country’s natural gas through its pipelines and is among the largest producers of wind energy. It’s exploring the development of a nuclear plant, according to regulatory filings.First Solar has agreed to build and operate the plant in San Luis Obispo County for MidAmerican. Construction began in November and is set to finish by early 2015, the companies said.“Selling such a project before you build it makes your life so much easier,” Reid said about First Solar. Photovoltaic energy is also a “much safer” bet than wind because there’s less maintenance and weather risk, he said.Buffett, 81, has said that businesses like utilities have earnings power even under adverse economic conditions and can provide fair returns on capital as long as they make investments in infrastructure to meet customer needs. Owning utilities is “not a way to get rich,” he said at a meeting of U.S. state regulators in 2006. “It’s a way to stay rich.”Berkshire’s earnings from the utilities and energy business were $888 million in the nine months ended Sept. 30, an increase of 13 percent from the same period last year. Initiative to Close California Nukes Makes BallotDecember 6, 2011

A proposal that would halt operations at California’s two nuclear power plants officially qualified for the ballot and could be put to a vote next fall. The initiative prohibits nuclear power generation in the state until the CEC finds that the federal government has approved technology for the permanent disposal of nuclear waste. If approved by voters, the initiative would cause reliability issues and service disruptions, potentially lead to billions of dollars in economic losses, and boost electricity costs for ratepayers, according to an analysis by the Legislative Analyst’s Office. California enacted a moratorium in 1976 on the permitting of new nuclear plants until the federal government develops solutions for the permanent disposal of nuclear waste and nuclear fuel-rod reprocessing. The new proposal, if approved, would force the immediate shutdown of Pacific Gas & Electric’s Diablo Canyon power plant and San Diego Gas & Electric’s San Onofre Nuclear Generating Station (SONGS). It would also prohibit the Legislature from overturning the current moratorium. State Attorney General Kamala Harris issued a title and summary for the initiative, Proposition 42, on Nov. 18. It was initially proposed by Santa Cruz resident Ben Davis in March. Diablo Canyon and SONGS account for about 16 percent of the state’s power mix. The Legislative Analyst’s Office earlier this year, and again in a Nov. 3 letter to the attorney general, outlined the serious ramifications for the state power grid, utilities and ratepayers, should Prop. 42 be approved. Even though the effect of a shutdown could be drastic, the LAO noted that federal preemption and other legal issues make the fiscal effects of the measure highly uncertain. Federal energy authorities could preempt the measure by requiring one or both nuclear facilities to continue operating for reliability purposes until replacement infrastructure could be built, for example. A federal or state court could also prohibit Prop. 42 from taking effect by finding the shutdown amounted to an unconstitutional “taking” of private property without just compensation, the analyst stated. FERC gives Northwest wind a win in BPA curtailment case US Northwest wind energy producers have won a major victory in their battle with the Bonneville Power Administration (BPA), the region’s grid operator, over curtailments that totalled about 5.4% of wind generation last spring.

Related Stories· Wind generators open new legal front against BPA curtailments · US wind curtailment ends as the legal battle-lines are drawn · Wind farms face forced shutdowns to balance system The Federal Energy Regulatory Commission (FERC), in an order issued Wednesday [37-page PDF], directed the BPA to revise its transmission tariffs for wind generators to make the terms and conditions “comparable to those under which Bonneville provides transmission services to itself and that are not unduly discriminatory or preferential”. In addition to providing transmission, BPA markets power from the federal dams on the Columbia River. Wind generators, including Iberdrola Renewables, NextEra Energy Resources, Horizon Wind Energy and Invenergy Wind North America, petitioned the FERC after their turbines were forced to shut down during periods in May and June when high river flows and high winds caused generation on the BPA system to exceed electricity demand. The BPA refused to compensate the wind generators for the value of the lost tax and renewable energy credits during these curtailments, estimated at about $2.1m. Power from the federal dams was used to fulfill the wind generators’ energy deliveries. The FERC declined to address whether the BPA should pay generators to voluntarily curtail production as a remedy to over-generation. The BPA must file a revised transmission tariff within 90 days.
Thursday, December 08, 2011 9:41 AM MT
House passes REINS Act requiring congressional review of major rulesBy Kathleen HartBy a vote of 241-184, the House of Representatives on Dec. 7 passed H.R. 10, a bill that would require Congress to approve major regulations that would cost the U.S. economy $100 million or more, including environmental rules affecting the nation’s power plants.Only four Democrats crossed the aisle to vote in favor of the Regulations from the Executive in Need of Scrutiny Act, known as the REINS Act, which was introduced in the House by Rep. Geoff Davis, R-Ky. Sen. Rand Paul, R-Ky., introduced companion legislation, S. 299, in the Senate in February. Paul’s bill has 31 co-sponsors, including Sen. Joe Manchin, D-W.Va.President Barack Obama on Dec. 6 threatened to veto the bill, should it pass the Senate and reach his desk. Senate Majority Leader Harry Reid, D-Nev., is not expected to bring the legislation to the Senate floor for consideration.Republicans contend the REINS Act would improve the accountability and transparency of the federal regulatory process. Supporters of the bill argue that over time, Congress has excessively delegated its constitutional charge to federal agencies and has failed to conduct adequate oversight. Requiring congressional approval for major regulations would make the legislative branch more accountable to the public for the laws it passes, they insist.In a Dec. 6 statement of administration policy, the White House Office of Management and Budget argued that there is “no justification for such an unprecedented requirement. When a federal agency promulgates a major rule, it must already adhere to the particular requirements of the statute that it is implementing and to the constraints imposed by other federal statutes and the Constitution.” When issuing a major rule, a federal agency must perform analyses of benefits and costs that typically are required by laws such as the Regulatory Flexibility Act, the Unfunded Mandates Reform Act and the Paperwork Reduction Act, the White House added.In addition, the Obama administration noted that for the past 15 years, Congress has been afforded the ability under the Congressional Review Act of 1996 to review individual rules issued by executive branch agencies.

NRECA urges Congress to tailor renewable energy incentives for co-opsBy Kathleen HartThe National Rural Electric Cooperative Association urged Senate Finance Committee and House Ways and Means Committee leaders to include incentives for renewable projects by cooperatives in any tax bill that extends energy grant programs.”As the year ends, we are writing to encourage you to include incentives for renewable electricity resources, together with comparable incentives tailored for not-for-profit electric cooperatives, if there is a tax bill addressing energy extenders,” NRECA CEO Glenn English wrote in a Dec. 1 letter to Sens. Max Baucus, D-Mont., chairman, and Orrin Hatch, R-Utah, ranking Republican, of the Senate Finance Committee, and Reps. Dave Camp, R-Mich., chairman, and Sander Levin, D-Mich., ranking Democrat, of the House Ways and Means Committee.English said the U.S. Treasury Department Section 1603 cash grant program, which is set to expire at the end of the year, and the Clean Renewable Energy Bond program, which exhausted its funding in 2010, have helped electric cooperatives to develop renewable energy projects at an affordable cost. In addition, English told the congressional leaders, renewable incentives are key to helping electric utilities “meet mandates and add new generation at a time when meeting the Environmental Protection Agency’s clean air requirements is increasingly challenging and expensive.”"The 1603 Treasury Grant Program has been critical to the success of renewable projects in a challenging economic environment. Ending these programs will almost certainly prevent cooperatives from developing any significant new renewable projects and, in effect, ends a successful federal policy to promote the development of domestic resources,” NRECA said in a Dec. 6 news release.The CREB program provides an incentive similar to the production tax credits that have been available to the for-profit sector, NRECA explained. A CREB offers cooperatives the equivalent of a low-interest loan for financing qualified renewable energy projects for a limited term. Noting that the program unleashed demand among cooperatives that were eager to develop renewable projects, NRECA said the nation’s electric cooperatives have submitted more than $1.4 billion in applications since CREBs were first authorized.”Co-ops have initiated wind, solar, biomass and hydropower projects in 18 states. Twenty-eight projects representing more than 209 MW of capacity are already in service, and co-ops are poised to finance another 17 projects representing at least 235 MW of new capacity with recent awards under the program,” the news release said. NRECA noted that investor-owned utilities and private developers can use the production tax credit to reduce the price of renewable generation from wind, closed loop biomass, open loop biomass, animal waste nutrients, landfill gas, municipal solid waste, geothermal and hydropower.”Without incentives designed for the co-op business model, renewable generation is simply unaffordable for most electric cooperative consumers. The significant capital expense of developing these resources is compounded by the fact that electric cooperatives serve by far the lowest average number of consumers per mile of distribution line among the three utility sectors,” NRECA said. “This translates to the lowest revenue per mile — making co-op consumers particularly sensitive to the cost of new generation resources.”Separately, more than 750 companies, small businesses and organizations sent a letter to leaders in Congress on Nov. 30 calling for a one-year extension of the Department of Treasury’s Section 1603 Program.”The 1603 Treasury Program has been a resounding success. Since its enactment, the program has leveraged over $22.8 billion in private sector investment to support over 22,000 projects utilizing a wide range of energy technologies in all 50 states. This has resulted in thousands of new American jobs,” the companies and organizations said. The letter was sent to House Speaker John Boehner, R-Ohio; House Democratic Leader Nancy Pelosi, D-Calif.; Senate Majority Leader Harry Reid, D-Nev.; and Senate Republican Leader Mitch McConnell, R-Ky.”Extension of this program will create jobs, spur economic growth and promote private sector development of energy technologies,” the letter said.