EPA challenges Utah plan to address PacifiCorp’s haze-forming emissionsBy Jonathan CrawfordThe U.S. EPA in an April 26 order proposed to reject part of a plan by Utah state environmental regulators to address haze-forming emissions from PacifiCorp’s coal-fired Hunter and Huntington power plants.At issue for the EPA was failure by Utah to conduct a required analysis as part of its determinations and emissions limits for visibility-degrading nitrogen oxide and particulate matter from Hunter Units 1 and 2, and Huntington Units 1 and 2.The state, according to the EPA, did not conduct a “five-factor” best available retrofit technology analysis for its determinations, as required. In setting the determinations, a state must consider the costs of compliance; the energy and non-air quality environmental impacts of compliance; any existing pollution control technology in use at the source; the remaining useful life of the source; and the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology.The state has committed to complete the required analysis and submit it to the EPA for review this summer, the agency reported.PacifiCorp spokesman David Eskelsen said the company has been taking steps to limit emissions at its plants.”We have been working with the state of Utah and EPA for a number of years on regional haze issues,” he said May 3. “Our position is that our facilities have always complied with the current applicable air quality standards.”He added that Huntington Units 1 and 2 and Hunter Unit 2 recently installed or upgraded controls to “significantly” reduce NOx and sulfur dioxide emissions. Hunter Unit 1 is scheduled to complete similar emissions controls upgrades in 2014.”With these controls, the plants are lower emitting units for NOx and SO2 — and were lower than the regional haze rule’s presumptive limits,” he stated.The Hunter and Huntington power plants are in Emery County, Utah. Each of the units has a nameplate capacity of roughly 500 MW, according to SNL data.Eskelsen added that the EPA recognized in its proposal that PacifiCorp has made significant reductions in SO2 emissions and, based on those emission reductions, the EPA approved Utah’s state implementation plan. Also, he said that the EPA did not disapprove of the NOx emission reductions made by PacifiCorp; rather, it concluded that the five factors had not been assessed.In 1999 the EPA issued its Regional Haze Rule to tackle visibility impairment at national parks and wilderness areas, known as Class I areas. The rule requires states, or the EPA when it issues a federal implementation plan, to develop strategies to ensure reasonable progress toward improving visibility in those areas. The rule requires some major stationary sources built between 1962 and 1977 to operate the best available retrofit technology. The Huntington units were built within that timeframe; Hunter 1 began operating in 1978 and Hunter 2 began operating in 1980.

Friday, May 04, 2012 12:32 PM MT
Idaho PUC dismisses PURPA complaint, saying solar developer may have been ‘foolhardy’By Jeff StanfieldThe Idaho Public Utilities Commission has dismissed a complaint that Interconnect Solar Development filed against Idaho Power Co. concerning the developer’s proposed 20-MW Murphy Flats Solar Power Project near Murphy, Idaho. The commission said the solar company was repeatedly warned about choosing a commercial operation date that preceded the utility’s estimated time for completion of the project’s interconnection to its transmission system.In the dismissal, the PUC quoted from its Sept. 20, 2011, order approving a new power purchase agreement between Idaho Power and Interconnect Solar for the developer’s project as a qualified facility under the Public Utility Regulatory Policies Act. Interconnect Solar selected Sept. 1, 2012, as its commercial operation date, though Idaho Power said it warned the date was earlier than the interconnection transmission facilities were scheduled to be completed and the PUC noted in its order that the developer’s decision to proceed may be foolhardy.The IDACORP Inc. subsidiary said it specifically told Interconnect Solar that Bureau of Land Management permitting issues were beyond the utility’s control and could delay the project’s commercial operation date. An original path proposed for the line met with objections from the BLM because it crossed along the Oregon Trail with protected raptor nesting areas.However, Interconnect Solar had to have the project in service by July 1 in order to qualify for federal tax incentives, so it agreed to accept the risk and proceed with the project, the PUC said in a press release. The in-service date for a project is the date that both the acceptance test and control system acceptance test for all generating units are deemed by the company to have been successfully completed, while a commercial operation date is the date on which the facility first achieves commercial operations.In its April 24 order (Order No. 32531, Case No. IPC-E-12-10) dismissing the complaint, the PUC quoted from its earlier contract approval order in which the commissioners said, “We share the concerns of commission staff and Idaho Power regarding Interconnect Solar’s choice of a scheduled operation date that precedes Idaho Power’s estimated date for completion of the project’s interconnection. The project’s optimism may prove to be foolhardy. Interconnect Solar maintains its position that interconnection will occur ahead of Idaho Power’s estimated schedule at its own peril.”Interconnect Solar said in its Feb. 15 complaint that since it no longer has a valid interconnection agreement and the in-service date has not been moved, the developer was unable to complete a new loan based on the investment tax credit and accelerated depreciation and post a security deposit required in the power purchase agreement because lenders were unwilling to provide the deposit money, exposing the developer to $900,000 in a liquidated damages bond.”Interconnect Solar’s lenders are not willing to post a security deposit that is a set-up for failure,” the developer said in its complaint.Interconnect Solar claimed force majeure based on a clause in the agreement that the developer contends allowed it to delay posting security due to a cause beyond its control. As a result of failing to post the security as called for in the power purchase agreement, Idaho Power said it canceled the agreement on Feb. 23.Interconnect Solar alleged Idaho Power improperly canceled its firm energy sales agreement and mishandled its generator interconnection agreement and a facility study that was to determine where the project would interconnect with Idaho Power’s transmission system. The developer asked the PUC to make Idaho Power provide a future in-service date so as to accommodate BLM permitting issues.The PUC rebuffed the developer, saying, “Interconnect Solar was repeatedly warned about choosing a commercial operation date that preceded Idaho Power’s estimated time for completion of the project’s interconnection.” The commission ruled that Idaho Power terminated its firm energy sales agreement with Interconnect Solar consistent with the terms of the agreement.PUC weighs agreement for another projectConcerning another solar project (Case No. IPC-E-10-19), the PUC said it will take comments through May 31 on an amended power purchase agreement with Idaho Power that would give developer Grand View Solar PV One LLC more time to complete its project. The facility, located 16 miles west of Mountain Home, Idaho, would have 10 MW of average generation capacity. In this case the developer appears to have negotiated more favorable terms.The scheduled online date was Jan. 30, 2011, according to Idaho Power, but Grand View Solar One said it has a “rolling” scheduled operation date for which its deadline has not expired.Idaho Power and the developer have negotiated an amended sales agreement that would set an operating date of Jan. 12, 2013. Under terms of this new agreement, Grand View Solar One posted an $810,000 security for Idaho Power in case the project is not operating by that date, the PUC’s press release said.The developer also paid $475,000 in a construction deposit. The agreement states that if Idaho Power is the cause of any delays, then the operation date can be extended to accommodate those delays without penalty to the developer.The manager of the Grand View Solar PV One project is Robert Paul of Deseret Hot Springs, Calif., the press release said.

MidAmerican and First Solar start major construction on world’s largest solar project MidAmerican Solar of Phoenix, AZ (a subsidiary of MidAmerican Renewables LLC, itself part of global energy services provider MidAmerican Energy Holdings Company of Des Moines, Iowa) and cadmium telluride (CdTe) thin-film photovoltaic module maker First Solar Inc of Tempe, AZ have marked the start of major construction at Topaz Solar Farms in San Luis Obispo County, CA. The firms’ representatives held a groundbreaking ceremony at which they discussed the project’s construction schedule, environmental values and community-centered plans with local and state community leaders and landowners. The event was followed by a community celebration at nearby Santa Margarita Ranch attended by more than 400 people. The 550MWAC photovoltaic project will employ about 400 workers during its three-year construction period; will generate nearly $417m in local economic impact (most of which will be generated during construction); and will provide California with renewable electricity. When complete, it will be the world’s largest solar electric power plant, providing enough energy to power about 160,000 average California homes. Pacific Gas and Electric Company will purchase the electricity from the Topaz project under a 25-year power purchase agreement, helping California meet its mandate to generate 33% of its power from renewable sources by 2020. Electricity generated by Topaz will displace about 377,000 metric tons of carbon dioxide per year (equivalent to taking about 73,000 cars off the road). “As Topaz is phased-in over time, it will help us meet that commitment while moving the state one step closer toward achieving its long-term environmental objectives,” says John Conway, PG&E’s senior VP for energy supply. “In addition to providing clean energy and jobs, we’re committed to working hand-in-hand with stakeholders to demonstrate how large-scale solar projects and geographies, such as the Carrizo Plain, can co-exist and benefit native biological species,” says MidAmerican Solar’s president Paul Caudill. “Utility-scale PV projects like Topaz are the quickest and most cost-effective way to bring significant solar power to the grid,” says Jim Lamon, First Solar’s senior VP of engineering, procurement and construction, and operations and maintenance. The Topaz project is owned by MidAmerican Solar and will be constructed, operated and maintained by First Solar. Construction began in November and is expected to be completed by early 2015.
Study: Smaller-than-expected number of gas plants would meet EPA’s CO2 emissions ruleBy Jonathan CrawfordThe U.S. EPA’s proposed carbon dioxide emissions standards for new power plants may affect more recently constructed natural gas-fired plants than estimated by the agency, according to a new study by the University of California Center for Energy and Environmental Economics.While the EPA reported that 95% of combined-cycle gas turbine units that began operations between 2006 and 2010 would meet the 1,000 pounds of CO2 per megawatt-hour standard that the agency proposed, an analysis of actual emissions and self-reported generation shows that 84% of such power plants would meet the standard, the study’s authors explained in their report, “How Stringent is the EPA’s Proposed Carbon Pollution Standard for New Power Plants?”The study examined three years of CO2 emissions of combined-cycle gas turbine units that began operations between 2006 and 2010 to understand how the standards could affect generating units that are modified and become subject to the standard under the Clean Air Act’s New Source Review provisions.”If you want to know how stringent the rules are based on how power plants are constructed in the next few years, the best way is to look at the ones most recently constructed,” said Matthew Kotchen, co-author of the study and an associate professor of environmental economics and policy at Yale University.The report revealed that 71% of combined-cycle gas turbine units slated for construction through 2017 would meet the emissions target because of a trend toward smaller capacity. The authors predicted that such units with a generating capacity of 226 MW or less would fail to meet the standard. Power plants that fail to meet the standard would potentially need to employ carbon capture and storage, which has not been demonstrated on a large scale and is deemed prohibitively expensive.The EPA’s impact analysis, however, does not appear to reflect such a level of noncompliance. The agency contends that its rule will impose few costs on the power sector as the standard generally reflects the emissions profile of an efficient combined-cycle gas turbine. Combined-cycle gas turbines, which are used for baseload generation, are generally more efficient than other types of plants as they produce additional electricity through driving a steam turbine from exhaust heat.Kotchen noted his study’s analysis does not account for the possibility that operators will adjust their power plant operations to meet the standard. As natural gas becomes cheaper, it will be more economical to run gas-fired power plants at higher utilization rates, which in turn will make it easier to comply with the proposed standards, he said.”That 71% level is the worst case scenario. As power plants adjust their operations, I would expect that number to get quite a bit higher,” he said.While the proposed rule exempts such facilities that are used for meeting peak demand, only 10% of simple-cycle gas turbine units that began operations between 2006 and 2010 would be able to comply without additional measures.Consistent with projections by the EPA and industry, the report found that no coal units would comply with the annual target without use of carbon capture and storage. The report analyzed CO2 emissions data for 2008, 2009 and 2010. Data was collected from the EPA’s Continuous Emissions Monitoring System program as well as data on power plants from the U.S. Energy Information Administration.The University of California Center for Energy and Environmental Economics is a joint venture of the University of California Energy Institute and the University of California Santa Barbara Bren School of Environmental Science and Management.

FERC’s Wellinghoff: Gas-power coordination issues not urgent; coal no longer low-costBy Glen BoshartFERC Chairman Jon Wellinghoff told reporters April 26 that he “has not heard a lot of high-level concern” that natural gas pipelines and other facilities are struggling to reliably meet the growing needs of electric generators and other gas consumers at the same time. “I don’t see it as a serious concern right now,” Wellinghoff said during a rare no-holds-barred Q&A session with reporters, reasoning that most gas-power coordination difficulties appear to be incremental and localized. The chairman nevertheless said his agency will continue to explore the issue.Commissioner Philip Moeller initiated FERC’s efforts in this regard in February when he asked for feedback on how the natural gas and electricity markets could become more coordinated for the sake of maintaining reliability. The full commission then got involved when the agency issued a notice (AD12-12) assigning a docket number to Moeller’s request, and Commissioner Cheryl LaFleur posed a series of her own questions on the topic.During a subsequent conference hosted jointly by state regulators and FERC, however, power and natural gas officials appeared skeptical of assertions that existing practices and mechanisms are inadequate to ensure system reliability. Many electric utility industry stakeholders went slightly further in their responses to Moeller’s inquiry, acknowledging that the electric utility and natural gas industries should become better coordinated. However, they also insisted that the problems are not widespread but region-specific and therefore should be addressed on the regional level, with FERC’s role being to issue policy guidance and oversee the implementation of any remedies.Wellinghoff appeared to agree with that suggested approach, citing the various regional efforts under way to address the issue and pledging to have staff members attend regional meetings. He also suggested that FERC may hold more joint meetings with the National Association of Utility Regulatory Commissioners on the issue. “People are moving ahead and we want to work with them,” the chairman said.Gas prices, EPA rules not a concernIn response to a separate question, Wellinghoff said the current low prices for natural gas do not concern him. “I’m a believer in the market,” he said, and if the market price for gas is low because of abundant supplies, so be it.The chairman predicted that, as with oil, the market for gas inevitably will become a global market “given the very substantial price differentials between the price in this country and the price in Europe and Asia.” However, that transformation will not happen for at least another five years, and probably much later, given the time needed to construct gas export facilities in the U.S., Wellinghoff added. He also dismissed concerns that exporting gas will dramatically boost the cost of domestic supplies, citing studies predicting that those increases would be limited to 50 cents per MMBtu.As for coal, Wellinghoff said that fuel no longer will be seen as the low-cost alternative for generating electricity given both the costs that coal-fired generators will have to incur to keep running while complying with new emissions regulations and the expense of building new coal-fired plants. He also predicted that domestic coal increasingly will be sold overseas due to its relatively low cost, which in turn could raise the price of domestic coal.Wellinghoff also downplayed concerns that the U.S. EPA’s new emissions regulations and the predicted retirement of many coal plants will threaten electric grid reliability. He therefore questioned various federal legislative efforts to block the new regulations or force the EPA to modify them to address potential reliability issues.”People need to look at processes already in place in regard to reliability,” including the planning requirements of Order 1000 and the mandatory reliability standards being developed and enforced by the North American Electric Reliability Corp., he said. He also insisted that EPA’s rules and regional planning requirements offer plenty of safeguards to prevent the retirement of coal-fired plants that are crucial to maintaining system reliability. “Thus, people should carefully review what already exists, and in my view, those things are adequate,” Wellinghoff said.Enforcement actions continueAddressing a different topic, Wellinghoff acknowledged that FERC’s efforts to comply with a statutory requirement to negotiate agreements with the U.S. Commodity Futures Trading Commission to ward off jurisdictional tussles and conflicting or duplicative regulations are at a standstill. “We stand ready to sign,” Wellinghoff said, but he suggested that no progress has been made on the issue for some time given certain fundamental differences between the two agencies on where the jurisdictional lines should be drawn. The two agencies were supposed to have presented signed agreements to Congress in January 2011.That said, Wellinghoff insisted that no animosity exists between the two agencies and that they are willing to cooperate with each other in overseeing markets. He also said the lack of signed agreements has not hampered FERC’s market enforcement efforts. For instance, the chairman noted that it recently approved a consent and stipulation agreement requiring a Constellation Energy Group Inc. energy trading unit to pay a $135 million fine and disgorge an additional $110 million in unjust profits tied to various physical and virtual (purely financial) trades the company engaged in from September 2007 through December 2008. While Wellinghoff acknowledged that the CFTC was not involved in the effort, he said the Constellation agreement sends a very clear message about actions that FERC views as market manipulation. Energy traders “cannot deliberately lose a bunch of money in one market in order to make even more money in a different market,” the chairman stressed, adding that anyone who reads the order approving the agreement “should be pretty clear about this.”The chairman nevertheless lamented the length of time it took his agency to investigate and resolve the Constellation case, blaming the delays on the lack of the proper analytical tools. That is going to change, he added, noting that the commission has established a new division within its Office of Enforcement charged with analyzing market data and looking for any suspect behavioral patterns. The Constellation agreement also provides money to RTOs and ISOs to boost their surveillance and analytic capabilities, he noted.Looking aheadWellinghoff said FERC soon will hold a joint meeting with the U.S. Nuclear Regulatory Commission to explore possible reliability impacts related to nuclear power plants. For instance, the chairman noted that nuclear power plants can cause transmission congestion because they are required to run all the time at a fairly constant output. He said the meeting also will consider whether the operational inflexibility of nuclear plants could cause other reliability issues or costs that are not being properly allocated.Also on FERC’s calendar is “some type of proceeding,” such as a notice of inquiry or technical conference, to investigate whether distributed resources are being adequately compensated by existing market structures, Wellinghoff said. The chairman had reported in March that he was having his agency’s lawyers and policy experts look at whether the avoided-cost rates utilities pay under the Public Utility Regulatory Policies Act should include extra compensation for the additional efficiency benefits offered by distributed generation.FERC further will be looking at concerns that solar storms could threaten grid reliability. “It is appropriate for us to look at how real the threat is,” Wellinghoff said, noting that NERC has said the threat is real and potential consequences dramatic, while others have downplayed the risks associated with geomagnetic disturbances. FERC will hold a technical conference April 30 as an initial step in that effort. Meanwhile, NERC in March announced that it will address geomagnetic disturbance effects through a multiyear collaboration with industry and governmental agencies, and Wellinghoff said FERC will cooperate in that effort.Finally, Wellinghoff refused to speculate as to whether he will pursue another five-year term at FERC once his current term expires on June 30, 2013. “I love this commission and working with its staff,” the most qualified and professional that he has ever worked with, he said. However, he said he does not yet have “a strong feeling” about whether to seek a new term.

Questar will raise a new chairman of the board
By Abhishek JhaRonald Jibson will succeed Keith Rattie as the chairman of the board of directors of Questar Corp. effective July 1.According to a May 10 announcement, Jibson will continue to serve as president and CEO of the Salt Lake City-based integrated energy company.Rattie will retire as Questar’s chairman after serving since May 2003, but he will continue as a Questar director. He joined Questar in January 2001 as its president and COO.”Keith’s leadership transformed us from a respected regional energy company into two top-tier energy companies nationally recognized for financial performance and operational excellence,” said Jibson, who has served as president and CEO of Questar since July 2010

Gas transmission asset growth expands in 2011; storage growth wanesBy Neil PowellGas interstate transmission assets among pipeline companies submitting Form 2 filings to FERC rose 12% year over year in 2011, climbing to $120.34 billion. Gas storage spending saw a much lower level of growth, up only 3.6% year over year.The growth was driven not only by larger expansion projects, but also by new pipeline companies filing with FERC. Seven companies filed the FERC Form 2 for the first time in 2011, accounting for more than $7.3 billion in transmission assets. Of the new 2011 filers, Ruby Pipeline LLC was the most significant, with transmission assets of $3.7 billion. Completed in July 2011, the 680-mile long-haul pipeline brings Rocky Mountain natural gas to California, Nevada and the Pacific Northwest.Of the 117 companies filing total transmission assets on Form 2, 81 reported a positive growth rate, while 36 had negative or no growth versus 2010 values. Florida Gas Transmission Co. LLC reported $6.05 billion in transmission plant assets, representing 77% growth over 2010’s assets of $3.42 billion. Much of the growth can be attributed to the phase eight expansion project operating in Mississippi, Alabama and Florida. Consisting of approximately 483 miles of multi-diameter pipe, the phase will provide 861,733 Dth of capacity. The pipeline cost roughly $2.48 billion and will help to meet the Gulf Coast’s and Florida’s rising demand for electric generation. The company with the second-highest growth rate was Kern River Gas Transmission Co., reporting a 14% increase over 2010 levels. The approximately 28-mile Apex Expansion, completed in October 2011, accounted for more than $373 million of the company’s transmission assets. The expansion will increase summer capacity by 266,000 Dth/d, to 2,142,126 Dth/d from 1,876,126 Dth/d.With shale gas production still booming, interstate pipeline and storage companies are quickly approaching maximum storage levels. SNL’s recent white paper on coal-to-gas switching comments on gas storage, stating: “The EIA storage report for the week of ended April 13 shows total working gas in storage standing at 2,512 Bcf, with working inventories 871 Bcf higher than the year-ago volume and 919 Bcf above the five-year average. At the current rate of building, many expect natural gas inventories to reach levels that will exceed available storage capacity.”Of the 42 companies reporting storage assets in 2011, 34 reported growth over 2010 levels, while eight reported decreases or no change. Although the bulk of the companies reported growth, only three companies posted double-digit growth rates. Gulf South Pipeline Co. LP recorded the biggest increase, at 29%, up almost $24 million over 2010 levels. Gulf South made upgrades to existing storage, installing a new 8,180-horsepower natural gas compressor in the Bistineau Storage Field.Southern Star Central Gas Pipeline Inc. had the second-largest growth in 2011 storage assets, reporting $151.6 million, up from $125.9 million in 2010. The 21% growth rate can be attributed to an expansion of the Elk City Storage Field in Kansas. The expansion brings an additional 4 million Dth of storage capacity and increases Southern Star’s daily deliverability by 40,000 Dth/d.
FERC, EPA clash over House bill to resolve reliability conflicts for utilitiesBy Kathleen HartTop officials from the U.S. EPA and FERC disagree about the need for legislation to amend the Federal Power Act to clarify that when an electric utility complies with an order to generate electricity to prevent a reliability emergency, the company will not be considered in violation of conflicting environmental laws.The opposing viewpoints of FERC and the EPA came to light at a May 9 House Energy and Commerce Committee Energy and Power Subcommittee hearing on H.R. 4273, the Resolving Environmental and Grid Reliability Conflicts Act of 2012.EPA Assistant Administrator of Air and Radiation Gina McCarthy told the subcommittee that while the Obama administration does not yet have a position on the bill, the EPA believes that the federal government “already has sufficient tools to address issues that may arise.”Arguing that orders under Section 202(c) have been very rare, McCarthy said the EPA “is aware of no instance in which compliance with such an order required any necessary conflict with environmental laws or regulations.” The EPA does not believe that its recently promulgated power sector regulations, including the Mercury and Air Toxics Standards, change the situation, she said.McCarthy said the bill could have the unintended consequence of “creating problems that would not otherwise exist.” The bill “could actually increase the likelihood of conflict between electric reliability and compliance with environmental laws, by removing important incentives to take timely actions necessary to avoid or minimize such conflicts,” she said. “Finally, the bill also could unnecessarily endanger public health.”However, FERC Commissioner Philip Moeller told the subcommittee that he, along with Chairman Jon Wellinghoff and Commissioners John Norris and Cheryl LaFleur, all support “the concept” behind H.R. 4273. “That is, we all agree that generators of electricity should not be put in a position of having to choose whether to violate Section 202(c) of the Federal Power Act or whether to violate the Clean Air Act when certain generating facilities are needed for crucial electric reliability needs,” he said.The U.S. has always faced “unique challenges to electric reliability,” which could accelerate as older power plants gradually retire or run less frequently as environmental mandates change, Moeller said.FERC is working to formulate a role in advising the EPA on the reliability impacts of retiring or retrofitting various power plants in compliance with the agency’s regulations, Moeller told the subcommittee.”Regardless of how well FERC and EPA can coordinate their reliability efforts, a bill like H.R. 4273 is essential to address potential reliability challenges. Like Section 202(c) more broadly, we hope that the provisions in a bill like H.R. 4273 would never need to be invoked, but erring on the side of reliability is the responsible approach,” Moeller added.Experience indicates that orders under Section 202(c) “are sometimes necessary,” Moeller said. “Yet the very operation of a power plant in compliance with a Section 202(c) order can result in violation of the Clean Air Act,” he said. “In this sense, federal law can sometimes require the owners and operators of a power plant to violate either the Clean Air Act or the Federal Power Act. The law should not require citizens to violate the law.”But McCarthy said the EPA is concerned that, if enacted, H.R. 4273 would create problems that would not otherwise exist. “It could actually increase the likelihood of conflicts between reliability and compliance with environmental laws and regulations,” she argued. “The bill would shield a generation owner from any liability for violations of environmental laws or regulations resulting from operation to comply with a Section 202(c) order, without any regard to whether the owner could have taken or did take any actions to timely comply” with the environmental requirements or mitigate the reliability concern, she added.That, in turn, would eliminate “important incentives for owners to take expeditious actions to comply with environmental requirements and avoid conflicts of this nature,” McCarthy told the subcommittee. “In addition, if a plant were subject to a 202(c) order, the bill would do little to ensure that the generation owner would have appropriate incentives to take expeditious action to eliminate the need for the order to continue — again, either by bringing the source into compliance with environmental regulations or by taking other actions necessary to mitigate the reliability issue.”Added McCarthy: “Advance planning and timely action are key to the successful implementation of EPA’s power sector rules, and this bill could undercut power plants’ incentives to plan and act in a timely fashion.”Waxman: Bill creates ‘loophole’”It is no secret that the EPA’s new power sector rules are going to force a significant portion of our coal-fired generation fleet to retire and these retirements will have negative impacts on the reliability of our electric grid. These reliability-related impacts may force DOE to use its authority in order to avoid potential reliability emergencies,” Rep. Ed Whitfield, R-Ky., chairman of the subcommittee, said. “It is essential that we amend the Federal Power Act so that generators aren’t forced to choose between compliance with an emergency order and compliance with EPA regulations. Otherwise utilities are unacceptably forced between a rock and hard place of federal authority.”Rep. Fred Upton, R-Mich., chairman of the full committee, also described H.R. 4273 as a “critical” piece of legislation. The bipartisan bill was introduced in the House by Reps. Pete Olson, R-Texas; Mike Doyle, D-Pa.; Gene Green, D-Texas; Lee Terry, R-Neb.; Adam Kinzinger, R-Ill.; and Charlie Gonzalez, D-Texas.”The government cannot have it both ways. It cannot direct a generator to operate for emergency purposes and then turn around and fine them for doing so. It’s like having one police officer telling you to speed up, while another sits at the end of the street to give you a ticket,” Upton said. “It’s simply not fair, which is why I am pleased that our colleagues have developed bipartisan legislation to resolve this conflict.”However, Rep. Henry Waxman, D-Calif., ranking Democrat on the full committee, argued that the bill is too broad in scope. The legislation would shield utilities complying with a DOE emergency order from “any liability for noncompliance with any federal, state, or local environmental law or regulation resulting from actions taken to comply with the DOE order,” he said.Waxman said the EPA plays an important role in minimizing environmental impacts when a unit must run for reliability reasons. Under this bill, a utility “has no incentive to reach an agreement with EPA to minimize the environmental impacts of operating under a DOE order,” he said. “That’s because all potential liability for environmental violations would be waived by the issuance of the DOE order. EPA’s role is eliminated. And the public is left with no assurance that unnecessary pollution will be avoided. This bill is drafted in a way that creates the potential for a big loophole in environmental protections.”In addition, Waxman noted that there is no time limit on the liability waiver. “This approach creates an incentive for electric utilities to delay installation of required pollution controls, betting that at the end of the day DOE will have to issue an order to keep the lights on and shield the power plant from liability for its illegal pollution,” he said. “This poses a serious threat to the recently finalized mercury air toxics rules as well as other important rules.”

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1) Questar seeks OK to refund ‘typical’ Utah customer $34.50
2) Questar launches natural gas line upgrade in Riverton, Herriman area
3) EIA hacks natural gas price forecast, but projects market will bottom out in 2012
4) DOE study: Treasury grants for renewables supported up to 75,000 jobs per year
5) Duke CEO warns against ‘all gas, all the time’ for electric generation
6) Yergin: No carbon rules? US still has an energy policy

On March 16, 2012, FERC Chairman Jon Wellinghoff spoke at the GreenBiz Energy Group Verge conference. During a post-speech interview he stated “[t]he traditional utility is either going to have to change or die.” Wellinghoff noted during the interview that this statement is an attempt to clarify an earlier comment where Wellinghoff categorized utilities as “dinosaurs.” Wellinghoff explained that vertically integrated utilities no longer make sense in part due to the “convergence of new technology.” Wellinghoff said that if traditional utilities do not adapt, they will be relegated to become distribution companies.

Wellinghoff went on to endorse demand response technologies, as he has many times in the past. He advocated for consumers to lobby their lawmakers and state commissions to provide demand response data in order to control retail consumption and costs. Wellinghoff concluded also stated that demand response markets should be extended at wholesale. He urged retail consumers located in regions that do not allow participation in RTOs (such as the West and the Southeast) to lobby state commissions to be allowed to participate in electricity markets through demand response activities.

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Federal energy regulators on Friday tamped down another barrier raised by a group opposed to the development of a wind energy project proposed for south of Glenrock.
The U.S. Federal Energy Regulatory Commission on Thursday denied a petition by the Northern Laramie Range Alliance that would have effectively killed a pair of adjacent wind farms on ridges in the Mormon Canyon area, proposed by Wasatch Wind of Park City, Utah.
The alliance is a group of area residents against what they call “industrialization” in the northern arc of the Laramie Range. They have fought the Wasatch Wind project
before county commissioners, a state industrial permit board and a state district judge, but so far have failed to stop the project.
In its petition to the regulatory commission, the alliance claimed Wasatch had improperly split its proposal into two smaller projects to take advantage of a federal law requiring that utilities must give priority to small energy projects when signing agreements to purchase power from producers, such as Wasatch Wind.
The company had talked up its proposal as a single project, with plans to connect to transmission lines at a single point, and got a single-project permit from both county and state officials, the alliance said.
The alliance claimed Wasatch gamed the system by dividing the project into two parts to push it to the head of the line of power sellers to Rocky Mountain Power, the utility in the area.
While the 100-megawatt, 62-turbine Wasatch Pioneer Park wind project wouldn’t qualify if considered a single project, the project consists of two different turbine clusters spaced at least a mile away — the distance required by the commission.
By forcing the utility to buy power produced from the wind energy project, Wasatch would zap Rocky Mountain Power customers with higher electricity rates, the alliance said.
Power utility Xcel Energy filed an opinion in the case, saying it didn’t have any interest in the matter. But the utility wanted the commission to be aware Xcel had seen similar, “not isolated” examples of a large project split into smaller parts to take advantage of federal rules.
On Thursday, the commission disagreed with the alliance’s claims, saying its one-mile rule applied in this situation. The commission said it wouldn’t examine whether Wasatch was indeed gaming the system.
“As with the positive decisions we’ve received for other NLRA challenges, we’re pleased but not surprised,” Wasatch Wind spokeswoman Michelle Stevens said. “The law governing our status with FERC is clear and we’ve followed the law. The claims by the NLRA that we are somehow gaming the system are false and now this is proven.”
On Monday, the group’s steering committee said it was disappointed by the commision’s decision.
“The alliance is considering the options open to it to appeal this decision on behalf of its members and other Rocky Mountain Power customers,” the Northern Laramie Range Alliance said in a media release.
On Friday, the alliance appealed lawsuits against county and state permits for the project to the Wyoming Supreme Court. A state district court judge in January affirmed both the state and county permits for the Wasatch project, which the company says it will begin construction on this spring.
The alliance also has appealed to a state court a Wyoming Public Service Commission decision that gave Wasatch more time — beyond the end of 2011 — to start delivering power from its project.

2) Klamath Agreement Parties Stall Restoration

3) Bingaman introduces clean energy standard bill in Senate

4) Manhattan Institute: Suspend RPS mandates until states conduct cost-benefit analysis

5) Analysts increase gas price outlook as rig cuts seen impacting production

6) Observers cast doubt on success of legal challenge to EPA greenhouse rules

7) Record investments raise concern over new-transmission needs

Environmental groups challenge EPA’s proposed exemptions for meeting haze rule

PacifiCorp files for 3 requests to increase rates by 4.3 percent to cover power, coal plant upgrades and transmission lines
Published: Thursday, March 01, 2012, 9:18 PM Updated: Friday, March 02, 2012, 9:37 AM
By Ted Sickinger, The OregonianThe Oregonian

Portland-based PacifiCorp filed three requests with Oregon regulators this week to increase rates by a total of 4.3 percent to cover power costs, coal plant upgrades, a solar project and a transmission expansion.

The increase comes on top of the 4.4 percent increase Oregon customers saw in January and rate hikes last year totaling nearly 15 percent. The bulk of the latest request would cover capital costs such as emission controls at coal plants and would take effect Jan. 1, 2013 if approved.

The rate request was less than expected as PacifiCorp shifted some capital costs to ratepayers in other states. But advocates still point out the company has raised rates in Oregon by about 50 percent since 2006, the year it was acquired by MidAmerican Energy Holdings, a subsidiary of Warren Buffett’s Berkshire Hathaway conglomerate.

And there appears to be no end in sight.

Though PacifiCorp says it does everything possible to manage costs, its representatives are telling Utah customers to expect rate increases nearly every year for the next decade as it makes capital investments to clean up coal plant emissions and build wind farms, transmission lines and natural gas plants.

Utility managers say rate increases will differ among the states where it operates, and Oregon may not see the same impact as states where demand is growing.

Nevertheless, the utility is in a “build cycle.” Customers, it appears, will be in a “bill cycle.”

“They may be able to defend each of their individual investments as reasonable,” said Bob Jenks, executive director of the Citizens’ Utility Board of Oregon. “My question is whether they can defend pancaking all these things on top of each other as reasonable. They’re not managing it well.”
RECORD PROFITS
Ratepayers say PacifiCorp has become a great investment vehicle for Berkshire, which has injected billions into PacifiCorp capital projects. In his annual letter to shareholders, Buffett described MidAmerican as one of Berkshire’s “fabulous five” operating companies because of record profits — profits he expects to continue this year.

But advocates say it is exhausting ratepayers

“Oregon is still in an economic recession,” said Melinda Davison, a lawyer for industrial customers of Northwest Utilities, a trade group. “At a time when you have customers barely hanging on, you should be delaying capital expenditures unless they are absolutely necessary. The question is at what point the public utility commission will say enough is enough.”

Rate increases are particularly tough to swallow, Davison said, when power prices have plummeted.

Utility managers say they have little choice. Customers have enjoyed relatively lower rates for years thanks to the company’s fleet of coal-fired power plants — 26 boilers spread over 11 location in five states. But stricter pollution regulations are forcing costly environmental upgrades. The cost of coal, both from its own captive mines and contracts, has been increasing.

“We’re not investing in any new coal plants, but we’re trying to get value out of plants that are producing low-cost power,” said Paul Vogel, a spokesman for PacifiCorp. “In order to operate these plants, we need to comply.”

Meanwhile, lawmakers in Oregon, California and Washington are requiring utilities to build renewables, generally meaning wind farms. Oregon’s renewable energy standard requires utilities to meet 25 percent of demand with renewable energy by 2025.

And PacifiCorp is pursuing transmission upgrades to move power around its six-state operating territory. Vogel said the company scrutinizes transmission needs on an annual basis and scales down where possible.

“We hear that concern loud and clear,” he said.
ASK FOR THE MOON

Disagreement over individual items in a utility rate case is standard fare. Conventional wisdom among ratepayers is that utilities ask for the moon, then see their request trimmed as regulators, ratepayer groups and other stakeholders wade through their voluminous filings and reject certain costs.

Yet the volume, at least, is louder these days. PacifiCorp executives were dressed down by Oregon’s public utility commissioners at a recent meeting where the company was reviewing its long-term resource plans. Commissioners insisted on a more detailed analysis of coal plant upgrades. They wanted more energy efficiency.

And they said they wanted corporate chieftains in Des Moines, Iowa, to get the message that business as usual wasn’t working.

Regulators are set to issue an order on PacifiCorp’s resource plan in coming weeks. The company reportedly has agreed to more energy efficiency to stave off investment in a new natural gas plant. Coal plant upgrades will be held aside and considered separately.

That may be a long debate. To meet stricter federal pollution rules and keep the coal-fires burning, PacifiCorp foresees spending more than $4 billion on equipment and additional operating costs by 2023. The company’s analysis suggests that’s the least-cost, least-risk way to meet customer needs.

The pollution controls would do nothing to reduce the plants’ vast output of carbon dioxide, however. If Congress ultimately institutes a carbon tax to combat global warming, many plants could become uneconomical to run.

The danger, critics contend, is the company will sink so much capital into the plants to meet clean air standards it will be harder to justify their retirement, or result in vast unrecovered costs. Moreover, PacifiCorp has already heavily invested in pollution upgrades at some plants without a full-blown analysis as to whether those plants will survive.

To Jenks, of the Citizens’ Utility Board, PacifiCorp appears to be deliberately breaking up investments and working them into rates piecemeal.

“You study and analyze a cost before you incur it, not afterward,” he said. “We’re going to have a big fight over a lot of coal.”
CONSERVATION-MINDED
Rate shock isn’t limited to Oregon, though the composition and size of the increases, as well as the underlying politics, differ by state. Regulators in Wyoming, for instance, are unlikely to oppose PacifiCorp’s coal investments, which provide jobs there. Oregon regulators have pushed harder on energy efficiency and renewables, with ratepayers footing the bill. And while growing demand drives new investments in power plants in Utah, it is flat in Oregon.

Utah’s residential and small commercial customer advocate, Michele Beck, said contentious issues there include PacifiCorp’s hedging strategies for natural gas, its renewable energy credits to customers and transmission expansion needs.

Repeated rate hikes in Wyoming are drawing fire from customers.

And in Idaho, the company has fought with Monsanto Co. over transmission investments.

In the rate filing Thursday, PacifiCorp responded to the Oregon Public Utility Commission’s earlier concerns about cost allocation among different states by lowering Oregon ratepayers’ share of those costs.

“Oregon’s share of system costs is $9.5 million lower in this filing than if the allocation factors from the last case had been used,” Vogel said. “It’s what we have to have and no more.”
Klamath Agreement Parties Stall Restoration
Hayley Hutt/For the Times-Standard
Eureka Times Standard
Posted:03/01/2012 02:35:11 AM PST

Today the Interior Department announced that it would fail to meet the March 31, 2012 deadline for a decision on whether to remove the four obsolete Klamath Hydroelectric dams. Was anyone surprised? The principal goal of the Klamath Agreements was, and is, to delay dam removal. March 31, 2012 was never a realistic date. The Agreements block the relevant federal agency, FERC, from acting in a way that forces PacifiCorp to remove the old dams. The delays enrich PacifiCorp; that was always the plan.
The Interior Department’s press release makes clear that many obstacles stand in the way of dam removal under the Klamath Agreements. They note that their Final Environmental Impact Statement is not finished. A draft EIS/EIR was published last year. Comments have come in. The Interior Department is still working on responding to the serious flaws in their draft. Yet without a Final Environmental Impact Statement, no decision could be made, and none will be made.
The press release notes that California “must identify a source for financing their share of the dam removal costs.” Again, there’s no surprise here — California’s bloated water bond was taken off the ballot and has not been put before the people yet. Of course, under the Federal Energy Regulatory Commission (FERC) process, there would be no need for California to pick up dam removal costs — that’s PacifiCorp’s responsibility. Yet under the Klamath Agreements, California is supposed to pick up some costs and dams won’t be removed until they come up with a new share.
The press release also explains that a “single draft overview report” is being prepared for the Secretary of Interior. Is it done? No.
The Interior Department and Klamath Agreement parties blame Congress for not enacting the unfair, expensive legislation that they seek. Congress is a favorite whipping boy, of course, but in this case, Congress’s inaction is praise-worthy. There is no need for new legislation to authorize dam removal. Existing laws and regulations will achieve dam removal if the Klamath Agreements weren’t in the way. There is no need to take away the federal government’s trust responsibility to protect the water and fishing rights of the tribes who didn’t buy the Klamath Agreements. There is no need to authorize $800 million in federal expenditures that will go to the benefit of just a few (and not a penny of it toward to costs of dam removal).
So, the Interior Department missed another deadline. No one should be surprised. Instead, people should look for the better alternative, and that starts with the State Water Resources Control Board doing its job and issuing a certificate of conditions for the proposed action. With a SWRCB certificate, the Federal Energy Regulatory Commission can bring this matter to closure.
PacifiCorp’s Condit dam project, located on a major salmon tributary of the Columbia River, is a good example of how the relicensing process leads to dam removal. Condit dam was breached in October 2011, and the remaining concrete will be removed this year. The FERC process for Klamath has not been placed “on hold.” Instead, it is blocked by the Klamath Agreements.
Hayley Hutt is a member of the Hoopa Valley Tribal Council.

Thursday, March 01, 2012 3:14 PM MT
Bingaman introduces clean energy standard bill in Senate
By Kathleen Hart
Senate Energy and Natural Resources Committee Chairman Jeff Bingaman, D-N.M., introduced legislation March 1 to establish a clean energy standard that would use a market-based approach to encourage electricity generators to use “clean” sources of energy.
The Clean Energy Standard Act of 2012, or CES, sets a national goal of doubling the amount of electricity generated by clean energy sources by 2035. To be considered “clean,” a generator must either be a zero-carbon source of energy, a category including renewables and nuclear power, or have a lower “carbon intensity” than a modern, efficient coal plant. Carbon intensity refers to the amount of carbon dioxide emitted per megawatt-hour of electricity generated.
The CES is intended to make sure that the U.S. leverages “the clean resources we have available today” and provide “a continuing incentive to develop the cheaper, cleaner technologies that we’ll need in the future,” Bingaman said in a March 1 news release. “We want to make sure that we drive continued diversity in our energy sources, and allow every region to deploy clean energy using its own resources. And we want to make sure that we do all of this in a way that supports home-grown innovation and manufacturing and keeps us competitive in the global clean energy economy.”
Solar Energy Industries Association President and CEO Rhone Resch was quick to praise the legislation. “Removing market barriers and providing a competitive structure that allows the nation to recognize solar energy’s full potential is a top priority for America’s solar industry. We’ve already seen what well-structured clean energy standards have meant in states,” he said in a March 1 statement.
Resch argued that state renewable portfolio standards have opened electricity markets to allow for more competition from renewable sources and ultimately drive down the cost of electricity for consumers. “This success can be replicated at the national level. We applaud Senator Bingaman for taking a leadership role and introducing legislation to establish a national clean energy standard. A national standard that successfully deploys solar energy would diversity our energy portfolio, reduce electricity costs for consumers and create jobs,” he said.
Bingaman acknowledged that the goal of doubling clean energy by 2035 is ambitious. “But analysis has shown that the goal is also achievable and affordable. Meeting the CES will yield substantial benefits to our health, our economy, our global competitiveness and our economy,” he said.
The CES only applies to utilities that sell electricity to retail consumers and exempts small utilities, according to a summary of the bill produced by the Senate Energy and Natural Resources Committee. In 2015, 8% of all utilities would need to meet the standard; in 2025, 13% of all utilities would need to meet it. The vast majority of municipal and cooperative utilities will never need to meet the minimum standard.
The CES draws on the Energy Information Administration modeling, which was performed at Bingaman’s request in 2011. Bingaman said the EIA’s modeling showed that a properly designed CES would have almost no impact on gross domestic product growth and little to no impact on national electricity rates for the first decade of the program.
Under the plan, all generators of clean energy are given credits based upon their carbon emissions, with greater numbers of credits going to generators with lower emissions per unit of electricity. Sponsors of the bill said this framework allows a wide variety of sources, including solar, wind, nuclear, natural gas and coal with carbon capture and storage, to be used to meet the standard and allows market forces to determine what the optimal mix of technologies and fuels should be.
The CES legislation was co-sponsored by Sens. Ron Wyden, D-Ore.; Bernard Sanders, I-Vt.; Mark Udall, D-Colo.; Al Franken, D-Minn.; Christopher Coons, D-Del.; John Kerry, D-Mass.; Sheldon Whitehouse , D-R.I.; and Tom Udall, D-N.M.
In addition to driving cleaner electricity generation in the power sector, the CES also rewards industrial efficiency. Combined heat and power units, which generate electricity while capturing and using the heat for other purposes, are treated as clean generators under the CES.
The CES does not put a limit on overall emissions, nor does it limit the growth of electricity generation, Bingaman said. The CES is not expected to cost the federal government anything and does not raise money for the U.S. Treasury. “If any money does happen to come into the Treasury as a result of the program, it goes straight back to the particular state from which it came, to fund energy efficiency programs,” Bingaman’s news release said.
NextEra CEO says bill provides ‘right incentives’
Bingaman’s bill provides “the right incentives for the nation’s electric utilities and equipment manufacturers to create good, high-paying jobs for American workers and for private capital to accelerate investment in innovative energy technologies,” NextEra Energy Inc. Chairman and CEO Lewis Hay III said in a March 1 statement. “The bill’s market-oriented standard would allow many different types of fuel sources to be competitive, while rewarding innovation, early action, efficiency and project execution.”
Added Hay: “America’s economic vitality and future energy security depend upon an ‘all of the above’ energy strategy, in which we rely on a diverse array of generation technologies and fuels that are cleaner, more efficient, and produced in the United States. A diverse array of generation technologies and fuels will ensure that Americans will benefit as new technologies become more efficient and new sources of fuel are discovered. Over the long term, an ‘all of the above’ approach will produce electric bills that are as low as possible, while ensuring high reliability and fewer harmful emissions.”
Center for American Progress Vice President for Energy Policy Kate Gordon also voiced support for the legislation. “By prioritizing low-carbon energy sources, a clean energy standard would drive investments in renewable energy and other low-carbon energy infrastructure that will put Americans back to work while also improving our air quality and reducing the likelihood of catastrophic climate change,” she said in a March 1 statement. “This bill will also create stable demand that’s critical for growing our domestic clean energy manufacturing base, and will help spur new innovations in the low-carbon energy technologies of the future.”

Manhattan Institute: Suspend RPS mandates until states conduct cost-benefit analysis
By Laura D’Alessandro
Renewable portfolio standards, created to change the power supply landscape in the U.S. while lowering carbon emissions, are not demonstrating the benefits that were touted when states adopted them, according to a new study released by the Manhattan Institute’s Center for Energy Policy and the Environment.
In the study, its author, Manhattan Institute Senior Fellow Robert Bryce, recommends that RPS mandates be suspended or eliminated while federal and state policymakers assess renewable energy policies.
Electricity rates in states with RPS requirements are “starkly higher” than in states without them, according to the study, “The High Cost of Renewable-Electricity Mandates.” And the mandates could not have been rolled out at a worse time, Bryce said. The timing of RPS implementation during a recession could exacerbate the nation’s economic problems, he argued.
“Because utility rate increases have a disproportionate impact on the pocketbooks of residential users, with the heaviest burden falling on the least well-off, the higher costs imposed by the mandates are being felt the most in the ranks of the unemployed and among the record number of some 46 million Americans receiving food stamps,” the study said.
According to the study’s analysis of energy cost data from the U.S. Energy Information Administration, seven coal-dependent states with RPS mandates saw their rates increase by more than 54% on average between 2001 and 2010, more than twice the average increase experienced by seven other coal-dependent states without mandates.
Only two states with RPS requirements made it on to the study’s list of the top 10 states with the least-expensive electricity per kilowatt-hour. Washington had the second-lowest electricity cost in the U.S. at 8.04 cents per kWh, and Oregon came in ninth at 8.87 cents per kWh.
Washington’s RPS is 15% by 2020, and Oregon’s RPS is 25% by 2025 for large utilities, 10% for small utilities and 5% for the smallest utilities. Leading the list for most expensive electricity cost is Hawaii at 28.1 cents per kWh, followed by Connecticut at 19.25 cents per kWh and New York at 18.74 cents per kWh. Hawaii’s RPS is 40% by 2030, while Connecticut’s is 27% by 2020 and New York’s is 29% by 2015. The state with the least expensive energy is Idaho at 7.99 cents per kWh; it does not have an RPS.
“Given that the RPS mandates have not received enough study and that they appear to be posing risks to a fragile economy, the prudent course of action is to put the state programs on hold,” Bryce said. “Existing mandates should be suspended and new ones blocked pending a thorough cost-benefit analysis to determine responsible levels of renewable electricity.”
Natural gas should be the fuel of choice to fill gaps in energy supply while federal and state officials study the impact of RPS mandates and provide a per-ton cost of carbon dioxide reduction, he said.

Analysts increase gas price outlook as rig cuts seen impacting production
By Jodi Shafto
Demand growth from a shift from coal to gas power generation, and an increase in industrial demand, along with the ongoing shift by producers from gas-directed drilling to oil and liquids drilling, will gradually result in a move toward a better supply/demand balance, analysts with Stephen Smith Energy Associates said.
A sustained natural gas supply surplus in the last two years has been the result of a shale-driven horizontal drilling boom and a weather-normalized demand growth rate at best only one third the rate of gas production averaging 4.3 Bcf/d higher than year-earlier levels, indicating a “severe and chronic surplus conditions” that until October 2011 had been offset by two near-record hot summers and two colder-than-normal winters, the analysts said in the latest “Monthly Energy Outlook.”
In the Feb. 29 report, however, the analysts noted the latest EIA 914 showed gross gas production for the Lower 48 for December 2011 declined sequentially by 0.20 Bcf/d, the first sequential decline in the last nine months and the first sequential decline in the last 18 months that was not related significantly to well freeze-offs.
The decline shows early signs of shale-driven gas production flattening out, as drillers over the past five months, shifted from gas to oil in response to the move from $3.50/MMBtu gas to $2.50/MMBtu gas, the analysts said.
Between October 2011 and February 2012 the average monthly horizontal gas rig count declined from roughly 650 rigs to near 480 rigs, a near 27% decline. Horizontal oil drilling showed a corresponding increase.
“For horizontal gas wells, the average time between the drilling mid-point and flowing to sales is arguably about 4-6 months,” the analysts said. “This suggests the Lower 48 onshore gas production should begin to show a noticeable ‘lagged-drilling-driven’ production-capacity-related slow-down in monthly sequential gas production growth at some time during 2Q12,” the analysts said.
“Even sooner, and in addition to lagged rig-driven effects, several voluntary producer price-driven shut-ins were announced in Jan/Feb and the effect of these cutbacks could show up as early as the late March or the late April EIA 914 reports.”
On the demand-side, the analysts see the main driver of gas demand growth from the continuing shift from coal to gas power generation along with some increase in industrial production.
Demand is dampened however, by the assumption of more conservative summer cooling degree days following two record-hot summers, with CDDs for 2012 and 2013 expected to be 106% of the 1997-2009 averages, as compared with an actual 112% to 113% for the past two years, the analysts said.
The gas rig count drop over the past five months is expected to continue for at least several months and result in strong monthly production rates to slow at first, and reach zero growth by year-end 2012.
The analysts revised higher their 2012 estimated price forecast from $2.80/MMBtu to $2.95/MMBtu.
Additionally, subject to normal HDD/CDD uncertainty, 2012 horizontal gas rig reductions will have had much more time to work, and as a result, the year 2013 appears to be moving towards a better supply/demand balance, the analysts said.
Projections for 2013 futures were revised from $3.50/MMBtu to $3.60/MMBtu

Observers cast doubt on success of legal challenge to EPA greenhouse rules
By Jonathan Crawford
In a federal court hearing Feb. 28-29 examining the EPA’s authority to regulate greenhouse gases, many of the legal challenges made by industry appeared to be coolly received, if not outright rejected, by the presiding judges, dimming the prospects for any major action on the rules, legal observers said at a March 1 briefing in Washington, D.C.
At the hearing, the U.S. Court of Appeals for the District of Columbia Circuit heard arguments on the EPA’s interpretation of its obligations under the Clean Air Act to regulate greenhouse gases. The court’s ruling has the potential to halt, modify or even greatly increase the scope of the greenhouse gas regulations.
Industry interests have called the rules the “most burdensome and far-reaching set of regulations ever,” imposing billions of dollars in compliance costs, permitting requirements and enforcement actions. Proponents say the EPA’s proposed move is a critical and necessary step in fighting climate change that also will create jobs and help move the nation toward energy independence. The hearing addressed arguments raised in 94 cases that have been consolidated into four (Coalition for Responsible Regulation Inc. et al. v. EPA, 09-1322, 10-1092, 10-1073; and American Chemistry Council et al. v. EPA, 10-1167).
At a March 1 forum at the office of the law firm Jones Day, panelist Bill Cobb, a partner at Jackson Walker LLP, said Texas Solicitor General Jonathan Mitchell made the argument that the EPA had overstepped its authority and violated the Constitution’s separation of powers when it tweaked the threshold at which greenhouse gas regulations would kick in for stationary sources. The EPA had adjusted them from 250 tons emitted annually to 100,000 tons per year of carbon dioxide equivalent.
“The court was — I don’t want to say hostile to this issue — but they didn’t take to it immediately,” Cobb said. The court pointed out that administrative agencies take statutes all the time and interpret them. One of the judges asked, “How is this any different?”
Petitioners also asked the court to consider the extent to which the EPA, in making its “endangerment finding” — which formed the basis for setting the regulations — should consider non-science factors. Petitioners argued that the U.S. Supreme Court decision in Massachusetts v. EPA (05-1120) did not require that only science factors should be considered. One such non-science factor that petitioners brought up was whether in its endangerment finding the EPA should have considered the ability for society to adapt to, or mitigate in the future, the impacts from climate change.
“My impression was that, overall, the court wasn’t particularly receptive to the argument about things the court would consider non-science factors,” Tracy Triplett, an assistant attorney general for Massachusetts, said at the forum.
D.C. Circuit Judge David Tatel appeared to reject outright this line of reasoning. Triplett said Tatel responded: “What if you’re dealing with carcinogenic air pollution? Should EPA assume that someday we will have a cure for cancer, and should it be taking that into account in thinking about the impacts?”
As for the “tailpipe rule,” which triggers the greenhouse gas regulations for stationary sources, Tim Webster, a partner at Sidley Austin LLP, said the judges appeared unmoved by arguments that the EPA fell short when it constructed the rules. He said Peter Glaser, a partner with Troutman Sanders LLP who was among the counsel representing the petitioners, argued that the rule was unlawful because the EPA did not properly investigate its consequences.
“He didn’t get very many words in before the questions started flying. In fact, I would venture to say that the panel used most of its fire on petitioners’ counsel and a lot fewer questions for government counsel,” he said.
Webster listed several questions asked by Tatel, including, “Wouldn’t the Supreme court have reversed if EPA used stationary source impacts as an excuse not to regulate?” and “What explicit language is there in the statute that would give EPA the authority to look at impacts of stationary source impacts when deciding what to do with mobile source emissions of greenhouse gasses?”
Another central argument, surrounding the “absurdity doctrine,” by which petitioners argued that the rules were invalid because of the “absurd” results that would fall on small and non-industrial sources, appeared to find little support from the judges. In particular, petitioners argued that the ramifications of the rule should have informed the EPA’s “endangerment finding.”
“I think there is a level of discomfort, to some extent, all around on that doctrine,” Triplett said. “I think particularly because there are other doctrines available here. Certainly, [D.C. Circuit Judge David Sentelle] from day one said at one point: ‘I don’t do absurdity. I’ll think about the other doctrines, maybe.’”
Triplett said Tatel asked, “Where’s the authority for EPA to fix that absurdity in the endangerment finding as opposed to later on?”
Legal observers also indicated that any court decision on the prevention of significant deterioration permitting is likely to have no effect on new source performance standards for greenhouse gases emitted by new and existing power plants, as well as a rule on reporting requirements.
Panelist Dina Kruger, a former director of the Climate Change Division at the EPA and founder of Kruger Environmental Strategies LLC, said that if the EPA is called on to make any changes, they will probably be limited in scope.
“My own sense is that if it does come back to EPA, I would not expect that this would be accompanied by a stay of the entire endangerment finding and of the vehicle rule and everything that followed it. I think it would be sent back and EPA would be told to take another look and potentially redefine the pollutants in a different way,” she said. “So the consequences of it might not be so adverse.”
Still, legal observers said there were some signs of hope for the petitioners during the hearing. Webster said Tatel ended his questioning with a couple of observations.
“One that was most interesting, he did mention that the last sentence of the Massachusetts v. EPA decision does in fact suggest there is some room for EPA to take policy considerations into account in setting standards under the motor vehicle provisions,” he said. “In other words, while Massachusetts didn’t give EPA any flexibility in using policy considerations in determining whether greenhouse gases were air pollutants, perhaps it does have the ability to look to policy justifications for rulemaking.”
Cobb also expressed some optimism. “As a general proposition, I think most people will agree day one went better for EPA, and day two went better for the petitioners. It seems like that if there is a chink in EPA’s armor, it is this tailoring rule,” he said.

Record investments raise concern over new-transmission needs
By blundin FIERCEENERGY
Created Mar 5 2012 - 7:59am
According to the Edison Electric Institute (EEI), utilities and others are expected to invest $54 billion on transmission between 2011 and 2014, a 43 percent increase over transmission investment during the previous four-year period.
Shareholder-owned electric utilities and stand-alone transmission companies surpassed the $10 billion mark for a yearly investment in transmission infrastructure for the first time in 2010 with transmission spending increasing nine percent from 2009 to 2010, according to EEI.
However, the Coalition for Fair Transmission Policy (CFTP) has raised concerns about the consumer costs that go along with increased transmission spending and the role that FERC Order 1000 plays.
The U.S. Department of Energy (DOE) and FERC Order 1000 are devising policies to encourage a national transmission build out, but according to CFTP Executive Director Bruce Edelston, it is important to recognize that unprecedented investments in transmission are already underway with billions in utility spending to interconnect new generation such as wind and solar onto the grid, replace aging power lines, ensure reliability and alleviate congestion.
“Perhaps what we should be asking is not whether new transmission is needed, but where it is needed — and why,” Edelston proposed while speaking at the 2012 Infocast Transmission Executive Forum. “Simply building more power lines without considering how transmission affects energy policy and markets can be extremely wasteful and inefficient.”
Appropriate price signals will ensure needed generation is located in the right places so load-serving utilities and other retail suppliers will make the most efficient resource decisions, based on the generation and delivery costs of electricity, Edelston concluded.

Environmental groups challenge EPA’s proposed exemptions for meeting haze rule
By Jonathan Crawford
Environmental groups are challenging a proposal by the EPA to let states rely on power sector emissions limits under the Cross-State Air Pollution Rule as an alternative to best available retrofit technology, or BART, requirements to meet regulations for reducing haze at national parks and wilderness areas.
In Feb. 28 comments, environmental group Earthjustice, on behalf of groups including the National Parks Conservation Association and the Sierra Club argued that CSAPR — a regional cap-and-trade program limiting power sector emissions of sulfur dioxide and nitrogen oxide in Eastern states — is not sufficiently stringent to address regional haze issues. The groups said the EPA has failed to demonstrate that the limits set by the newly finalized CSAPR will do a better job of improving visibility than the BART requirements under the Clean Air Act.
“To protect America’s scenic natural areas the EPA must change its proposed revisions to guarantee that coal-fired power plants are fully cleaned up for the benefit of our parks, our health, and the economic vitality of gateway communities that depend on tourism and recreation,” Earthjustice Coal Program Director Abigail Dillen said in a March 1 statement. “Haze pollution contributes to heart attacks, asthma attacks, chronic bronchitis, respiratory illness and even premature death.”
The EPA in 1999 initiated an effort to improve air quality in national parks and wilderness areas, known as Class I areas, through a regional haze rule that requires some major stationary sources built between 1962 and 1977 to operate the best available retrofit technology as determined by the state, or employ an alternative measure that is deemed more effective.
The environmental groups took issue with the EPA’s reliance on CSAPR in lieu of BART requirements because the U.S. Court of Appeals for the District of Columbia Circuit has stayed the rule. A court hearing is scheduled for April 13 for oral arguments in response to the stay of CSAPR.
Also at issue is a loosening of CSAPR standards that could compromise the ability of the rule to reduce haze. The EPA indicated Feb. 7 that it will increase emissions allocation budgets in 17 states — by about 2% in total — and ease compliance options.
While the EPA cast the changes as “minor technical adjustments,” industry officials have argued that some of the tweaks were significant. For example, Texas’ state budget for SO2 emissions was increased by about 50,000 tons in the final rule. The revisions were made after the EPA and others had identified errors in the agency’s modeling assumptions that affect the calculation of budgets, assurance levels and new unit set-asides for several states.
Much of the opposition to the proposed exemption to the BART requirements follows what the groups perceive as an inability by the EPA to demonstrate that CSAPR achieves greater reasonable progress than the BART requirements. The environmental groups pointed out that the EPA has not evaluated or determined each state’s reasonable progress goals or conducted any technical analysis to determine whether the CSAPR would achieve results superior to those attained from BART requirements.
Earthjustice cited EPA rules requiring that visibility must not decline in Class I areas and that the alternative to the BART requirements would lead to an overall improvement in visibility in those areas.
“EPA has yet to provide a satisfactory demonstration that substituting participation in CSAPR for source-specific BART controls will satisfy either condition,” Earthjustice said in its comments. “Fundamentally, flaws in EPA’s methodology preclude the agency from reaching a credible conclusion that CSAPR is better than BART.”
The groups also argued that the EPA cannot approve partial federal implementation plans for Alabama, Florida, Georgia, Indiana, Iowa, Louisiana, Michigan, Mississippi, Missouri, North Carolina, Ohio, Pennsylvania, South Carolina and Texas by relying on CSAPR. “EPA has not demonstrated that any of these states can meet reasonable progress goals without imposing BART requirements on power plants,” the groups said.
Earthjustice maintained that little progress has been made under the regional haze rule. It cited National Park Service estimates that visibility conditions at about 90% of 241 studied national parks are showing no significant improvement or degradation on the haziest days, while about 70% are showing no significant improvement or degradation in visibility on the clearest days.

IDACORP: Partners in major transmission projects have ‘complementary needs’
By Kerry Bleskan

Analysts on IDACORP Inc.’s fourth-quarter earnings call Feb. 22 were keenly interested in the company’s upcoming large transmission projects.
The company expects that load will grow for its subsidiary utility, Idaho Power Co., once the recession eases. It plans to meet much of that expected need by building two 500-kV transmission projects to access existing generation in the region: the Boardman-Hemingway line from Boardman, Ore., to the Hemingway substation near Melba, Idaho; and Gateway West, between the Hemingway station and the Windstar substation near Glenrock, Wyo.
IDACORP has partners in both projects and additional arrangements are under discussion. Under a recent agreement to share the costs of permitting the Boardman-Hemingway line, MidAmerican Energy Holdings Co. subsidiary PacifiCorp and federal power marketing agency Bonneville Power Administration committed to fund larger shares than Idaho Power.
Daniel Minor, IDACORP executive vice president of operations, said Idaho Power’s 21% stake in the initial agreement is just about perfect. “The 21% that we’ve landed on actually matches very closely to what our operational needs are from the project,” he said. “The good news is the other partners that we brought in have very complementary needs to the company and have need both in Oregon and in Idaho to get across the systems.”
Though Bonneville promised to fund a share of permitting activities, that agreement is not a commitment to participate in further development of the Boardman-Hemingway line. The agency will decide later in 2012 whether to fully participate in the project.
Permitting Boardman-Hemingway will likely take at least until 2014, Minor and other executives said, and construction of the 300-mile line will take about two years. The company is unlikely to be affected, even if the project faces delays typical in recent transmission development, said Darrel Anderson, IDACORP CFO and executive vice president of administrative services. “That line is really being built to access resources in the Northwest, which is already there available today, that we can’t bring home because at certain times of the year, those pipes are full,” he said. “That particular project … goes to the top of the heap for us because the resources are really already there.”
Bonneville is also considering a role in the 1,150-mile Gateway West project, currently a joint effort of Idaho Power and PacifiCorp, doing business as Rocky Mountain Power. Gateway West is expected to be online in 2017 or so, said Vern Porter, Idaho Power vice president of delivery engineering and operations.

Companies charge BPA with trying to circumvent FERC order mandating open access transmission
By Marcy Crane

The five companies whose complaint prompted FERC in December to order the Bonneville Power Administration to immediately revise its curtailment practices recently told Energy Secretary Steven Chu that BPA’s proposed solutions to the region’s oversupply problem “do not reflect the … goals of nondiscriminatory transmission access, consumer protection and promoting the development of renewable energy.”
In particular, the companies — Iberdrola Renewables Inc., PacifiCorp’s Pacific Power division, NextEra Energy Resources LLC, Invenergy Wind North America LLC and EDP Renewables North America LLC (aka Horizon Energy LLC) — faulted BPA for unilaterally releasing for comment a draft oversupply plan to replace its controversial redispatch program and for indicating that it will file a “reciprocity” tariff with FERC.
BPA has maintained that when spring runoffs produce high water conditions on the Columbia River, its only choices are to run the excess water through its hydro facilities or release it through the dam spillways, which can endanger salmon in potential violation of its Clean Water Act and Endangered Species Act obligations by boosting dissolved gas levels in the water. Deciding the former was the better choice, BPA instituted an environmental dispatch program, under which it would temporarily substitute federal hydropower for other generation in its balancing authority area when faced with excess water supply, to ensure that the reliability of its system is not threatened by over-generation.
Crying foul, the companies in June 2011 collectively asked (EL11-44) FERC to order BPA to stop the new practice, accusing the federal power marketer of using its transmission market power to curtail competing generators in order to protect its preferred power customer base from costs it does not consider “socially optimal.”
FERC in December 2011 found that BPA’s environmental redispatch program is discriminatory and mandated that the federal power marketer submit a revised open-access transmission tariff, or OATT, “that addresses the comparability concerns raised in this proceeding in a manner that provides comparable transmission service that is not unduly discriminatory or preferential.” However, the agency recognized the difficult position that BPA is in, and urged stakeholders to work together to find a solution to the oversupply problem.
BPA recently released for comment a draft plan under which it would still replace wind and other generation with hydropower during times of oversupply, but it would compensate displaced generators with the associated cost to be allocated approximately equally to the users of the Federal Base System and wind generation customers in BPA’s balancing authority area. BPA, which explained that it “has been engaged in discussions with a number of key stakeholders since last spring to find an equitable solution to oversupply,” said the proposal “is based on concepts developed in these discussions.”
However, the five companies reported to Chu in a Feb. 13 letter that several of them “are engaged directly with BPA” in attempting to resolve their differences and insisted that the federal power marketer’s unilateral publication of its draft plan is “contrary to these settlement efforts.”
The companies also complained that BPA has said it will file a “reciprocity” tariff rather than the OATT mandated by FERC. The problem with such an approach, according to the companies, is that while an OATT is binding, a reciprocity tariff “is voluntary and can be amended or rescinded by BPA at any time without FERC approval.”
“Not only would such a voluntary reciprocity filing contravene the FERC order, and prejudge a crucial issue in the regional settlement discussions, it also would fail to address a root cause of the issues that led to the litigation — a lack of adequate oversight over BPA’s transmission system operations,” the companies said.
Asserting that BPA’s self-regulation of its transmission system “has harmed consumers,” the companies told Chu it is vital that BPA comply with FERC’s order by filing an OATT that can be modified in the future only with FERC’s approval. While they acknowledged that BPA’s OATT can vary from the commission’s pro forma OATT in order to address unique regional situations, they said “an independent regulator — not Bonneville itself — needs to be the final arbiter of such BPA variance proposals.”
The companies also addressed assertions made by a bipartisan group of Northwestern lawmakers in a letter sent to Chu in January. Those lawmakers had argued that a literal reading of the commission’s December 2011 order “indicates that FERC may believe Section 211A of the Federal Power Act trumps BPA’s organic statute and all related enabling statutes, as well as the Endangered Species Act and the Clean Water Act.”
Recounting that the order at issue “repeatedly references the need for BPA to balance” all of its responsibilities, however, the companies said they “agree this is essential.”
Iberdrola Renewables is a subsidiary of Iberdrola SA, PacifiCorp is a subsidiary of MidAmerican Energy Holdings Co., NextEra is a subsidiary of NextEra Energy Inc., and Invenergy Wind is a subsidiary of Invenergy LLC.

S&P: Likelihood of nuclear renaissance ‘faint at this time’
By Matthew Bandyk

The NRC’s recent approval of a construction license for the nation’s first new nuclear reactors in about 30 years will not usher in a new “nuclear renaissance,” at least not yet, according to a Feb. 15 report from Standard & Poor’s Ratings Services.
Instead, the S&P report predicts no additional reactor construction before the end of the decade beyond the proposed Vogtle units 3 and 4 in Georgia and the proposed V.C. Summer units 2 and 3 in South Carolina. The two projects are estimated to be completed before 2020.
“Electric utility industry observers have been watching these developments with interest to see whether other utilities will follow suit — leading to a ‘nuclear renaissance’ in the U.S.,” S&P said in the report. “However, market conditions indicate that the likelihood of such a rebirth is faint at this time. The economic slowdown that started in 2008 significantly reduced demand for electricity, and there are no signs that the economy will surge back anytime soon.”
Southern Co. subsidiary Georgia Power Co., along with project partners Oglethorpe Power Corp.; Municipal Electric Authority of Georgia; and the city of Dalton, Ga., have scheduled Vogtle unit 3 for completion in 2016 and unit 4 in 2017.
Adhering to this schedule, such as finishing the first of the two units in April 2016, is not as important for the project’s success as is the new units meeting their $14 billion estimated cost, S&P credit analyst Dimitri Nikas, one of the authors of the report, said Feb. 15. If unit 3 can be finished without going significantly over budget and without major technical problems during construction, “that’s more important because that will demonstrate that the company planned well,” he said.
Georgia Power appears to be well-positioned to mitigate cost overruns, he argued, based on details about the project’s engineering, procurement and construction agreement in Southern’s 2010 Form 10-K, filed Feb. 25, 2011.
“The owners and the consortium have agreed to certain liquidated damages upon the consortium’s failure to comply with the schedule and performance guarantees,” Southern said in the Form 10-K. “The consortium’s liability to the owners for schedule and performance liquidated damages and warranty claims is subject to a cap.” The consortium refers to Westinghouse Electric Co. LLC and Stone & Webster Inc., with whom the project developers struck the deal.
While the Vogtle units received a combined construction and operating license from the NRC on Feb. 9, the Summer units are not far behind and are likely to receive their own license in about a month, Nikas said. “It’s basically the same project times two. They are trailing Georgia Power by a step,” he said.
South Carolina Electric & Gas Co., a SCANA Corp. subsidiary, is developing the Summer units with the South Carolina Public Service Authority, more commonly known as Santee Cooper.
After this initial wave of construction, represented by the Vogtle and Summer projects, other utilities will wait to see whether these projects can be built on budget and will try to determine any lessons learned before pushing ahead with their own new nuclear reactors, S&P said in the report, “The U.S. Nuclear Power Industry Takes a Giant Leap Forward.”
“In our opinion, the current market conditions combined with nuclear projects’ long planning and construction timelines will prevent the construction of additional new units until at least the end of this decade,” S&P said.
One reason why projects in Georgia and South Carolina, as opposed to other states, are moving ahead, according to the report, is that the states, along with Florida, have put in place regulatory frameworks that provide for preapproval of a project’s budget and schedule by state regulators, periodic review of the project’s development, recovery of financing costs during construction, and recovery of any abandoned investment.
“If integrated utilities in other states want to pursue new nuclear construction, these states will need to develop comparable frameworks to enable the utilities to preserve their credit quality,” S&P said.

Friday, February 17, 2012 3:32 PM MT
Governors report states making clean energy investments to spur economy
By Jonathan Crawford

A majority of states are looking to advance clean energy initiatives as part of their strategy to boost economic growth, according to a new analysis by the National Governors Association.
In its “Clean State Energy Actions: 2011 Update,” the NGA said that from June 2010 to August 2011, 28 states developed policies or made investments to spur economic development tied to the clean energy sector. Such initiatives include providing business incubation support, creating incentives for expanding the use or manufacturing of clean technologies, establishing workforce development programs, and expanding education opportunities for emerging professionals and retraining displaced workers.
“Efforts to advance the clean energy economic sector drew particular interest this past year,” the NGA said in the Feb. 1 report. “Governors saw economic development as their top priority, and many looked to the clean energy sector as an opportunity to stimulate growth, often as part of broader recovery efforts.”
The report, which was compiled by the National Governors Association Center for Best Practices, was commissioned to better gauge state efforts, identify policy models that can be replicated, and pinpoint emerging policy tools. The report summarizes and highlights state actions from June 2010 to August 2011.
Despite facing economic headwinds, many states took actions to develop and expand the use of clean energy in 2010 and 2011. The report showed that the environmental benefits from such initiatives, such as through reducing harmful emissions, were not the only motivation.
Efforts to drive economic development in the clean energy sector are widespread, with 46 states and territories involved on this front. The report highlighted the creation of the Colorado Center for Renewable Energy Economic Development, a joint venture between Colorado and the U.S. Department of Energy’s National Renewable Energy Laboratory, to support startup clean technology companies.
The Clean Energy Initiative in Mississippi was created to provide state income and sales-and-use tax exemptions to support manufacturers in the renewable industry, including biomass, solar, wind and hydropower. Virginia established the Clean Energy Manufacturing Incentive Grant to provide financial incentives to manufacturers of products for renewable and nuclear energy generation, as well as energy conservation, storage and efficiency.
The prospects of economic growth and job creation from the global clean energy market — estimated by some to be worth $243 billion — has been a rallying call for proponents of such initiatives. Groups, such as the American Sustainable Business Council, have said that more action is needed to foster the clean energy industry to create jobs, boost innovation and draw investments into the sector.
In another trend highlighted in the report, from June 2010 to August 2011, 48 states took action to boost energy efficiency, such as through setting appliance and equipment efficiency standards, adopting building energy codes, implementing demand-side management initiatives, and setting energy savings goals.
The report also noted that three states implemented new efficiency levels for products sold or installed in the state; 27 states updated existing building codes in the past year; 16 states modified utility demand-side management programs; three states set or revised energy efficiency targets; and 40 states and territories created new financial and nonfinancial incentives to promote energy-efficiency measures.

In Arizona, a Showdown over Regulatory Power and a Bonjour to Nuclear Waste
February 21, 2012

Another fight has broken out over whether the Arizona Legislature should be able to second-guess the Arizona Corporation Commission’s energy policy decisions.
After a lengthy hearing, the House Government Committee on Feb. 14 passed House Bill 2789, which would require the commission to submit to the Legislature and the governor for approval all energy policy rules or amendments adopted after Dec.31, 2012, including rules mandating the use of specific sources of energy or that increase energy efficiency or renewable energy standards.
Rep. Debbie Lesko (R-Glendale) sponsored the bill. Two years ago, she floated a proposal to give the Legislature “exclusive authority” to determine renewable energy policy for the state, but withdrew it after strong opposition from environmentalists and the business community.
At the hearing, Lesko called HB 2789, which would go into effect Jan. 1, 2013 “prospective,” in that “it does nothing to change current renewable energy or efficiency standards.” She said its intent is to keep utility bills “as low as possible.” Plus, the Legislature has the authority to set energy policy just as it has the authority to set other policies, Lesko said.
People who testified against the bill warned it would hurt the state’s growing solar industry and some said it is unconstitutional, noting that a court case brought by the Goldwater Institute challenging the ACC’s ability to adopt renewable energy standards was decided in the commission’s favor by the state court of appeals in 2011.
“We’ve invested millions in Arizona because it is a relatively stable regulatory environment,” said Lon Huber of Suntech, which built a solar panel manufacturing plant in Goodyear. This bill “adds another layer of government regulation — that isn’t the way to attract businesses to Arizona,” said Michael Neary of the Arizona Solar Energy Industries Association.
Corporation Commissioner Paul Newman predicted the legislation could provoke “a huge constitutional crisis.” He called the bill an end-run to the Legislature “because the Goldwater Institute lost in the courts.” Newman noted that each year utilities come to the commission to have their Renewable Energy Standard implementation plans approved.
“What happens if we have to give that power up to the Legislature — we’d have 1,000 stakeholders and maybe some bridges to nowhere if it’s not tightly held,” he said.
Clint Bolick of the Goldwater Institute, a conservative think tank in Phoenix, told the committee the court of appeals “greatly enlarged the powers of the ACC over energy policy for the first time by judicial fiat” and that HB 2789 would “restore the checks and balances intended by the state constitution.”
“The solar lobby is out in force against this bill” because “it wants to be able to advance its agenda by convincing three members of an obscure commission, rather than 47 members of the Legislature,” Bolick said. “This is exactly what the framers of the constitution intended to prevent: the capture of the commission by a particular special interest group.”
ACC chair Gary Pierce, representing himself, said he thinks the ACC has “permissive authority,” which means “authority that can be trumped by the Legislature,” but also has exclusive ratemaking authority. Pierce called the bill “a reasonable vehicle to get the Legislature and the ACC working together.” He also urged the lawmakers to adopt energy policies that would apply statewide and include Salt River Project.
The committee voted 6-3 on party lines to approve the bill. Passage by the Republican-dominated House is expected, with a trickier, but ultimately successful, route through the Republican-run Senate. Some insiders suggest the governor might veto the bill; otherwise, look for another trip through the courts.
Lesko is also sponsoring HB 2790, which would scrap the energy efficiency standard the ACC adopted in 2010 that requires utilities, by 2020, to achieve savings equal to 22 percent of their previous year’s retail electric sales. The bill says the ACC can’t require a utility to carry out any energy efficiency standard without showing it is “cost-effective.” Cost-effective is defined to mean the total incremental benefits from an efficiency measure or program exceed total incremental costs over a five-year period.
The Arizona Senate on Feb. 16 passed a memorial indicating the state’s interest in becoming the country’s nuclear waste storage and recycling capital. SCM 1004 “will send a message to Washington D.C.,” Sen. Al Melvin (R-Tucson), the bill’s sponsor, said at a Senate Commerce and Energy hearing Feb. 1. “We want to be the most nuclear-friendly state in the nation because of the wealth, prosperity and jobs it will bring,” he added.
“We are looking at doing what the French have done successfully for 30 years,” Melvin said. “If we were to recycle all the spent nuclear fuel in the United States, we would have enough power for the 104 reactors in the country for the next eight to 10 years, and we wouldn’t have to mine for additional uranium.”
Arizona would look for large power companies in and out of the state to sponsor its efforts, Melvin added. He wants to charge $50,000 per metric ton of nuclear waste sent to the state, with the money to be used to fund education to the tune of $100 million a year.
Mark Lewis of the Arizona chapter of the American Nuclear Society said at the hearing that “instead of dumping fuel in Yucca Mountain or a new repository,” 95 percent of the nation’s spent fuel could be recycled.
“The French tell me one reactor bundle, once recycled, can be reduced down to an unrecyclable amount that will fit in a French wine bottle, and that the entire waste stream of the United States would fit in a building the size of a high-school gymnasium,” he said. “We’ve paid over $500 million into Yucca Mountain and we are still paying that today, and we need a new solution.”
Sandy Bahr of the Grand Canyon chapter of the Sierra Club testified against the bill, citing issues with nuclear waste transportation, storage and national security.
“In France, the central government owns the nuclear power industry and what they do, they do through command and control,” Bahr said. “It’s somewhat ironic to hear a desire to be like France coming from a conservative legislature such as this.”
The Arizona Senate on Feb. 9 passed SB 1215, which would repeal new energy-efficiency standards for electric spas and residential pool pumps that went into effect Jan. 1. Testifying at a House Energy Committee hearing against a similar House bill, Russell Smoldon of SRP noted there are “hundreds of thousands” of residential pools in SRP’s service territory, that pool pumps “are a big energy user” and that the new standards would save the utility about $6 million.
The House Energy Committee also approved HB 2743, which would make it easier to lease school district lands for solar projects, and HB 2724, which would create an energy policy study committee to write a new energy policy for Arizona. HB 2724’s sponsor, Daniel Patterson (D-Tucson), said the 21-member committee would be “a forum for all the best brains in the state to talk about conventional and renewable sources of energy” and provide recommendations to the Legislature or the ACC.

Idaho Legislature Considers Wind Moratorium
February 21, 2012

The Idaho House of Representatives is considering a bill that would set a two-year moratorium on development of “industrial wind farms,” until a legislative task force can review their pros and cons.
Also before House committees is a proposal that would require more transparency about the impacts of large utility capital expenditures on rates, a measure that extends the income tax deduction for residential energy efficiency upgrades, and a concurrent resolution approving the revised state energy plan.
The House Energy, Environment and Technology Committee voted Feb. 16 to move HCR 34, the state energy plan, to the House floor. It’s expected to be approved and forwarded to the Senate.
The House Revenue and Taxation Committee on Feb. 15 approved House Bill 485, which revises and extends the income tax deduction for energy efficiency upgrades on existing residences. The bill, co-sponsored by Rep. Wendy Jaquet (D-Ketchum) and John Vander Woude (R-Nampa), was then sent back to general orders to incorporate some minor amendments. As now written, it provides a tax deduction for insulation and other efficiency measures to residences built before 2002, when the Idaho’s first state-wide energy code went into effect.
While the bill could cost the state as much as $1 million in forgone revenue, it would have a net positive impact, according to the fiscal note. Participants would save money on their energy bills “and usually more of the dollars spent on energy efficiency remain in the local economy than dollars spent on ‘traditional’ electric generation or fossil fuel purchases.” In addition, weatherization efforts are “more labor-intensive than typical generation, which means more jobs are created than lost by reducing spending on electric generation.”
Rep. Erik Simpson (R-Idaho Falls), who championed a wind moratorium proposal last year, introduced HB 527 on Feb. 10 in the House Local Government Committee. The bill would prohibit municipalities, counties and state agencies from approving or issuing licenses or permits for new wind turbines more than 100 feet tall and with a nameplate capacity of over 100 KW until July 1, 2014. Projects that had been approved as of Feb. 1, 2012 could go forward, as long as no legal proceedings have been filed against them.
In the interim, the bill calls for creating an eight-member legislative task force, with four members each from the House and Senate, to study the effects of wind energy and provide recommendations to the Legislature and the governor. The task force’s analysis “shall address, but not be limited to,” issues related to the effect of wind development on power rates and the ability of Idaho’s utilities to integrate intermittent wind into their systems; the effect of wind turbines on wildlife, private property values and uses; tax issues associated with wind power development; and “any other issues found to be pertinent.”
According to the bill’s statement of purpose, HB 527 “is intended to allow policymakers adequate time and resources to review the impact of wind energy development on Idaho citizens. Because of the massive financial incentives offered to wind developers at the federal, state, and local levels, wind energy development in Idaho has proliferated at an unprecedented rate.”
Although the IPUC last year set a 100-KW cap on wind projects qualifying for the published PURPA rate, “wind development in Idaho continues unabated,” the statement continues. “Simply put, the negative impacts of wind energy on wildlife, residents, property owners, taxpayers, and utilities continue to be of concern. This legislation would provide an opportunity for lawmakers to adequately and thoroughly assess the wind energy sector in Idaho and make recommendations based on that assessment.”
The moratorium would not apply to facilities owned or controlled by the federal government or BPA “for the purpose of providing power to the citizens of Idaho.”
The bill moved to the House Environment, Energy and Technology Committee Feb. 14.
A bill requiring more transparency regarding utility capital expenditures was introduced Feb. 16. According to its statement of purpose, HB 554 is intended “to include disclosure and transparency around large capital expenditures by regulated electric utilities in the course of the existing planning process, when such expenditures are first anticipated to be added to the electric utility rates paid by Idahoans.”
The bill defines a “large capital expenditure” as an investment for which an IOU “intends to seek cost reimbursement and returns on capital in future proceedings” before the Idaho PUC.
“The legislature hereby finds that large capital investments by public utilities often become obligations anticipated to be collected from ratepayers and that disclosure of the proportion and size of any such investment anticipated to be reimbursed by ratepayers is necessary to judge whether said investment is in the ratepayers’ best interest,” the bill reads in part. It directs the IPUC to require the utility to “disclose any impact on rates or tariffs anticipated over the planning period associated with that large capital expenditure.”
The bill is sponsored by Rep. Marc Gibbs (R-Grace) and former Idaho Republican Party Chairman Trent Clark, the lobbyist for Monsanto, which has a large phosphate plant in Soda Springs. According to an AP report, Monsanto “argued utilities are unnecessarily investing in infrastructure because they can reap 10 percent returns, all covered by ratepayers.”
The bill has been sent to printing.
On Friday, Feb. 17, the House was scheduled to hold the third reading on HB 464, the oil and gas regulation bill that limits local restrictions on such activities.

US power dailies mostly lower amid mild weather, easing demand, slumping gas
By Amanda Luhavalja
Spot power prices were generally lower at major market centers across the U.S. on Tuesday, Feb. 21, as traders looked to overall mild weather in most regions, easing demand, weak natural gas prices and improvements in the supply picture. Markets were closed Feb. 20 in observance of Presidents Day.
Supply will come into greater focus as the spring maintenance and refueling season continues to ramp up. Data from IIR Energy shows almost 60,000 MW across the U.S. offline, down close to 5,000 MW on the day, led by improvements in coal- and gas-fired generation. Coal-based outages now stand at about 21,000 MW, down 3,000 MW from Feb. 17, while gas outages stand below 18,000 MW, down more than 3,000 MW from Feb. 17.
On the nuclear front, three outages started this past weekend: Entergy Corp.’s Grand Gulf in Mississippi, Exelon Corp.’s Limerick 1 in Pennsylvania and Constellation Energy Group Inc.’s Nine Mile Point 1. Private sources indicate that Xcel Energy Inc.’s Prairie Island 2 in Minnesota will shut soon for refueling.
In terms of fueling costs, traders also kept a close eye on natural gas market activity Tuesday. After posting an 11.7-cent gain Feb. 17, the front-month March contract reversed course Tuesday, settling at $2.626/MMBtu, down 5.8 cents. Cash natural gas markets, meanwhile, were mostly lower, in line with the session’s losses in futures.
West Coast power markets leak lower with steady demand, softer spot gas
West Coast power prices were on the downswing Tuesday, with a stable load outlook and easing regional cash gas markets working to put a damper on values. Load in California is expected to reach a high of 29,069 MW on Wednesday, little changed from Tuesday’s levels.
With the near-term demand outlook little changed in the Golden State, heavy-load spot power deals at South Path-15 in California were completed in the upper $20s, down about $2 on the day. Light-load South Path-15 parcels were inked in the low $20s.
In the Northwest, heavy-load COB packages traded in the mid-$20s, easing $2 as well on the session, with heavy-load Mid-Columbia parcels running at a slight discount, losing $1.50 on the day. Light-load power at both markets was seen in the high teens to low $20s.
In term trade in the Northwest, March delivery Mid-C was talked at about $23.50 to $24, with second-quarter Mid-C deals eyed near $19.50.
In the Southwest, heavy-load Palo Verde spot power lost about $1.50 to $2, with business reported in the mid-$20s. Heavy-load Mead deals were exchanged in the upper $20s, down about $2.50 on the session. Light-load deals at Palo Verde were reported in the upper teens with light-load Mead packages melded in the low $20s.
State utility staff reaches settlement in Pacific Power’s electric rate increase request
OLYMPIA, Wash. – Staff members of the state’s Utilities and Transportation Commission (UTC) today reached an all-party settlement agreement in Pacific Power’s request to increase electric rates for its customers in Washington.
The three-member UTC, which is not bound by the staff recommendation, will make a final decision on the utility’s proposed rate hike this spring. The agreement calls for a June 1 effective date.
Under the terms of the settlement, Pacific Power’s annual electric revenues would increase by $4.5 million, or an overall 1.5 percent, down considerably from the $12.9 million, or 4.3 percent, the company asked for in its initial request on July 1.
The average residential electric customer using about 1,000 kilowatt hours-a-month will see an increase of $1.24, for an average $77.65 monthly bill. The basic monthly service charge of $6 – paid by all customers regardless of the amount of electricity used - would remain the same.
The settlement also includes an eight-cent-a-month rise in residential customer contributions to the company’s low-income bill assistance program, from 55 to 63 cents a month on June 1. If approved, the settlement would allow an additional 1,800 people to receive energy assistance over the next five years.
An additional provision in the agreement calls for Pacific Power to not file another general rate case with the UTC before Jan. 1, 2013.
On July 1 Pacific Power filed a general rate case with the UTC requesting an annual $12.9 million or 4.3 percent overall rate increase. The company did not request a change in its overall rate of return of 7.74 percent.
The commission has received 89 total public comments on Pacific Power’s rate-increase proposal – five undecided and 84 opposed.
In addition to the UTC staff and the company, three other parties signed the agreement. They are the Attorney General’s Public Counsel Section, Industrial Customers of Northwest Utilities and the Energy Project.
Pacific Power is a division of Portland, Ore.-based PacifiCorp and is owned by MidAmerican Energy Holdings Co. of Des Moines, Iowa. The company provides electric service to about 130,000 customers in five Eastern Washington counties: Kittitas, Columbia, Garfield, Walla Walla and Yakima. Cities in the company’s service territory include Yakima, Toppenish, Sunnyside, Selah, Pomeroy, Walla Walla and Dayton.
The UTC is the state agency in charge of regulating the private, investor-owned electric companies in Washington. It is the commission’s responsibility to ensure regulated companies provide safe and reliable service to customers at reasonable rates, while allowing them the opportunity to earn a fair profit.