Wyoming Infrastructure Authority

1) EPA challenges Utah plan to address PacifiCorp’s haze-forming emissions
2) Idaho PUC dismisses PURPA complaint, saying solar developer may have been ‘foolhardy’
3) MidAmerican and First Solar start major construction on world’s largest solar project
4) Study: Smaller-than-expected number of gas plants would meet EPA’s CO2 emissions rule
5) FERC’s Wellinghoff: Gas-power coordination issues not urgent; coal no longer low-cost
6) Questar will raise a new chairman of the board
7) Gas transmission asset growth expands in 2011; storage growth wanes
FERC, EPA clash over House bill to resolve reliability conflicts for utilities

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.”

1) Sage grouse is becoming Utah’s spotted owl
2) Questar gets another year on Utah gas compression upgrade
3) Coal plant developers: EPA rules forcing them into ‘untenable regulatory dilemma’
4) Stage set for significant coal-to-gas switching in remainder of 2012
5) BPA Cuts Wind Generation
6) Sage Grouse Ends Development of Nevada Wind Farm
7) EIA finds Senate clean energy standard bill would significantly reduce coal generation
FERC says wind companies may sue Idaho PUC for alleged PURPA violations
9) Wyoming Consumer Advocate recommends rate increase for PacifiCorp

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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

by Troutman Sanders LLP

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.

1) PacifiCorp considers retiring coal-fired Carbon plant in Utah
2) PacifiCorp exec sees decision on Carbon plant retirement within year
3) EPA’s proposed carbon standard fraught with potential legal vulnerabilities
4) Environmentalists worry as EPA delays emissions rules for gas industry
5) Bonneville files open-access transmission tariff, includes generator imbalance provisions
6) New Wind Builds Could Plunge Without PTC
7) Dramatic 45% slump leaves March spot gas averages near 1990s levels, dragging coal lower
8) Moody’s foresees permanent shifts in energy sector over next decade

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