FERC members testify on issues like Clean Power Plan, LNG project permitting

The House Energy and Power Subcommittee, chaired by Rep. Ed Whitfield, R-Ky., a frequent critic of any Obama Administration policy harming coal-fired power, on Dec. 1 held a hearing examining the Federal Energy Regulatory Commission’s current role in regulating electricity markets, and its timeliness as it relates to licensing liquefied natural gas (LNG) export facilities, interstate gas pipelines, and non-federal hydropower projects.

Members of the panel, which is part of the House Energy and Commerce Committee, expressed their concern with the U.S. Environmental Protection Agency’s (EPA) recent moves to supplant FERC’s authority over electricity well beyond anything in the Federal Power Act, especially as it relates to the EPA’s Clean Power Plan.

During the hearing, Whitfield stated: “There are valid concerns that FERC is allowing itself to become a helpless bystander as EPA seeks to dominate the electricity sector in ways that exacerbate the very problems FERC is supposed to protect consumers from. America’s energy situation is better than it has been in decades, but nonetheless there are challenges in the years ahead and a critical role for FERC is dealing with them.”

Energy and Commerce Committee Chairman Fred Upton, R-Mich., discussed the need for FERC to be timelier in its approvals and demonstrated that many of the current issues at the agency could be fixed by provisions within the pending H.R. 8, the North American Energy Security and Infrastructure Act. “There are problems with the timeliness of FERC approvals. If left unaddressed, these delays may cost jobs, raise energy prices, and compromise reliability. H.R. 8, which will be considered by the full House later this week, contains provisions to help expedite job-creating energy infrastructure projects. H.R. 8 also includes provisions that seek to strengthen our ability to prevent these risks and minimize the impact when they do occur,” Upton commented.

Here are some highlights from the prepared testimony from the four current FERC members: 

Norman C. Bay, Chairman

“My testimony will outline my priorities. Commissioner Cheryl A. LaFleur will address reliability and the competitive markets. Commissioner Tony Clark will focus on infrastructure. And Commissioner Colette D. Honorable will discuss a number of issues, including FERC’s role with respect to the EPA’s Clean Power Plan.

“There are at least several major trends or developments driving change in the energy space. First, the shale revolution has resulted in an abundant and historically low priced gas supply. Second, organized markets are expanding, and the Nation is seeing a period of low load growth and increased energy efficiency, which impact the markets the Commission oversees. Third, more renewables and distributed generation are being integrated into the energy system. Fourth, state and federal public policies are affecting the energy industry. Finally, the energy industry is seeing a period of increased technological innovation.

“My testimony will discuss my priorities given the change that is happening. Underpinning each of the priorities is a belief that, in approaching matters that come before the Commission, it is essential to be fair, balanced, and pragmatic; to decide cases on the merits, based on the facts and the law; and to be consensus-oriented.

“My first priority is to focus on the fundamentals in the competitive markets. It will be important to continue to look for ways to improve the efficiency of the markets and to deliver greater value to consumers. Second, the reliability of the grid is a primary responsibility for the Commission. This encompasses not only the everyday responsibility over Reliability Standards, including physical security and cybersecurity, but it also includes gas-electric coordination issues. Third, I believe that infrastructure continues to be an important issue at the Commission. Right now, there is a need for more infrastructure, in terms of both gas facilities and electric transmission, and FERC plays a critical role in permitting and incenting the development of that infrastructure. Finally, to accomplish my priorities, I will need to focus on human capital at the Commission. The work of the Commission cannot be done without its dedicated staff, and it is critical to recruit and retain our staff so that the Commission maintains its status as one of the very best places to work in the government.”

Commissioner Cheryl LaFleur

“In my testimony today, I am going to briefly touch on two core aspects of the Commission’s reliability work: (1) our efforts to protect the grid from emerging systemic reliability challenges through the adoption of mandatory reliability standards, and (2) our oversight of wholesale electric markets. My colleague, Commissioner Clark, will address another key component of the Commission’s reliability work, our responsibility for authorizing the construction of energy infrastructure.

“The Commission’s direct jurisdiction over electric reliability comes from section 215 of the Federal Power Act, which Congress enacted as part of the Energy Policy Act of 2005. Section 215 directs the Commission to certify and work with an independent Electric Reliability Organization (ERO) to develop reliability standards for the Bulk-Power System. In 2006, the Commission certified the North American Electric Reliability Corporation (NERC) as the ERO.

“Under the unique statutory relationship established by Congress, reliability standards are typically first developed by NERC pursuant to an open and inclusive stakeholder process, and then submitted to the Commission for review and approval. However, section 215 also vests the Commission with authority to direct NERC to develop or modify reliability standards if the Commission determines that a new or modified standard is necessary to address a reliability concern. The Commission has frequently exercised that authority to help ensure the reliability of the grid.

“The reliability standards for the bulk electric system range from day-to-day, nuts and bolts requirements to keep the lights on, to forward-looking standards to address emerging issues, like cybersecurity, physical security, and geomagnetic disturbances. The Commission, NERC, and industry have made significant progress in the past several years on the nuts and bolts issues, including promulgation of standards addressing tree trimming, frequency response, under-frequency load shedding, reliability planning criteria, and protection system maintenance and testing, among other areas. The Commission has also been actively engaged in efforts to address emerging threats to the grid.

“These issues present different challenges that the day-to-day activities I mentioned, because in many cases we do not have the benefit of decades of experience to draw upon. Instead, because these threats are either constantly evolving or not fully understood, the Commission must work to develop meaningful, cost-effective protections in an environment of rapid change and imperfect knowledge. Despite this difficulty, the Commission has been proactive to identify and address emerging threats.

“The nation is experiencing significant change in the resource mix used to generate electricity. There are three primary drivers of this change. First, we are experiencing a significant increase in the reliance on natural gas for electric generation, due primarily to the increased availability and affordability of domestic natural gas, but also to its relative environmental advantages and its role in balancing the growing fleet of variable resources. Second, we are seeing considerable growth in renewable and demand-side resources, fostered by developments in technology and by policy initiatives at both the state and Federal level. Finally, new environmental regulations, particularly the Environmental Protection Agency’s Mercury and Air Toxics Standards and Clean Power Plan, which Commissioner Honorable will address in her remarks, are driving changes in power supply.

“These changes are stress-testing the competitive markets. The growth of natural gas resources as well as new environmental requirements are leading to the retirement of baseload capacity, particularly coal, and driving the need for new investment. During the initial transition to competitive market structures, most regions had excess capacity, and regional markets produced efficiencies that led to lower wholesale prices. As resources have retired, some areas are transitioning from generation surpluses to scarcity. That scarcity is leading to higher forward capacity prices and more focus on market outcomes. At the same time, affordable and abundant domestic natural gas is creating challenges for other resources, while the deployment of new renewable technologies is leading to integration challenges. In many places, we see lower energy prices during most hours due to the low variable cost of renewables and gas, yet we also see spikes in the cost of electricity during times of system stress.

“These changes are also causing the competitive market operators across the country to examine their rules to ensure that reliability is properly valued and sustained. At a time of resource change and the need for new investment, it is particularly important that markets send accurate price signals to both existing and new resources. The Commission’s recent efforts have focused on all aspects of our competitive markets, including the energy, capacity, and ancillary services markets. As I mentioned when I previously testified before this committee, starting in 2013, the Commission has worked to help adjust capacity markets to these new challenges and attract needed investment in new and existing resources. In the last year and a half, the Commission approved market changes in eastern RTOs that redefine the capacity product to procure generation resources that can perform when needed most, to ensure that we can keep the lights on during extreme weather events and other times of system stress.

“Separately, the Commission has also focused on gas-electric interdependence issues, an effort that grew out of the increased reliance on gas-fired generation, particularly in regions that also rely on natural gas for heating during the winter. After engagement with stakeholders, the Commission determined there was a need to better align the gas markets and the electricity markets to optimize the use of our pipelines to ensure the reliable operation of gas-fired generation. On that front, FERC established new rules to better harmonize scheduling in the gas and electric markets to provide the most efficient scheduling rules for both industries. The Commission also modified its rules to promote increased communication between transmission operators and gas pipelines. These market rules changes should help maintain reliability at times when gas pipeline capacity is stressed.

“The Commission also adopted a number of other markets rules to help accommodate the integration of renewables and other new technologies into the energy markets. In recent years, FERC has issued rules to integrate variable energy resources, compensate resources for providing frequency regulation in a way that recognizes greater contributions from faster ramping resources, compensate demand response resources, and reform transmission planning and cost allocation requirements so that they consider, among other things, transmission needs driven by state and federal public policy requirements.” 

Commissioner Tony Clark

“With regard to hydropower licensing, the Commission continues to advance Congress’ initiatives in the Hydropower Regulatory Efficiency Act of 2013 by processing conduit exemptions and preliminary permit extensions. Since issuance of the Act through November 24, 2015, staff has received notices of intent to construct 67 qualifying conduit facilities, 39 applications for extensions of permit terms, and no small hydropower exemption applications for projects between 5 and 10 MW. Of the 67 conduit facilities, 55 have been qualified, 8 were rejected because they did not meet the criteria set forth in the Act, and the remaining 4 are pending. Of the 39 applications for permit extensions, 20 were granted and 19 were denied due to lack of diligence.

“On a separate hydropower topic, I feel it important to highlight for the Committee that the number of projects that will begin the relicensing process will substantially increase beginning in FY 2016 and continue well into the 2030s. Between FY 2016 and FY 2030, over 500 projects, which represent about 50 percent of our licensed projects and about 30 percent of the generating capacity under Commission jurisdiction, will begin the pre-filing consultation stages of the relicensing process. For those of you that have licensed projects in your districts, I am sure you will want to be up-to-speed on these matters because hydropower relicensing is the sort of issue that can generate considerable constituent interest.

“Once new licenses are issued, the license implementation phase will begin. Currently, the Commission’s license compliance and administration division is processing over 3,500 license-related filings per year. This workload is certain to increase given the number of projects to be relicensed.

“Many of these projects now on the eve of relicensing were first licensed in the early to mid-1980s. This was prior to enactment of modern environmental standards, including those of the Electric Consumers Protection Act of 1986, which first directed the Commission, when issuing licenses, to give equal consideration to energy conservation, fish and wildlife protection, recreational opportunities, and environmental quality, and required that licenses be granted upon the condition that the project adopted shall, in the judgment of the Commission, be the one best adapted to a comprehensive plan encompassing fish and wildlife protection, irrigation, flood control, and water supply. As we work through this period of substantial relicensing, I hope you and your staff members will see FERC as a resource to help provide background on the various projects and the Commission’s regulatory process.

“Moving to natural gas; within the natural gas sphere of our responsibilities, since I last appeared before you, the Commission has continued its work related to the siting of interstate pipelines and LNG export facilities.

“In addition, the Commission continues to carry out its responsibilities related to the siting of LNG facilities. As of November 2015, the Commission has authorized 7 LNG export projects, totaling 10.62 Bcf/d in capacity. Another 10 projects have pending formal applications in various stages of review totaling 12.53 Bcf/d in capacity. Not included in these totals are the 12 other projects that are in the “prefiling” stage.

“The ongoing demand for natural gas infrastructure is not surprising given the changes occurring in the energy world. A combination of affordable natural gas and certain state and federal environmental policies have sharply increased electricity generation from natural gas and renewables, often at the expense of coal. Working within the statutes passed by Congress, FERC has the responsibility to ensure that this infrastructure is sited the right way, which is accomplished through a siting process that allows various parties and stakeholders to be heard via a record that is compiled with both written submissions and public testimony. While the Commission is generally able to handle most energy projects in a timely matter – in the last 10 years, 92% of all applications have been processed and completed within 12 months, I believe it is fair to observe that infrastructure development and siting is becoming more challenging.

“Infrastructure, be it related to natural gas, large hydropower projects, electric transmission or generation (the last two being sited at the state level) engenders a level of opposition that was rarely seen in the past. In years gone by, intervention in regulatory proceedings tended to be driven by those most directly affected by the energy project – for example a landowner who would prefer an energy project be located on “Site A” rather than “Site B.” The regulatory process is well equipped to consider and weigh these sorts of comments, and we still do receive a fair amount of this type of intervention in our cases. In fact, as a Commissioner, I have always viewed this type of intervention as particularly critical to our work because it helps develop a complete record regarding where infrastructure is both well and poorly suited. But today there is an increasing trend towards “Just Say No” intervention. This intervention is designed to block entire classes of infrastructure projects – either through outright denial or through a strategy of defeat through delay. It is not opposition based on a particular project or its location; it is an opposition to all infrastructure as a matter of ideology. Often this opposition is from those expressing concern about climate change and carbon emissions. The irony is that much of this infrastructure is being necessitated by the very regulations that are being promulgated in the name of reducing carbon intensity in the electric generating sector.

“In the case of gas pipelines, it is in large part to fuel generators that are either replacing higher carbon emitting baseload coal plants or being paired with variable energy resources like intermittent wind and solar. In the case of electric transmission lines, it is often to facilitate geographically distant renewables, and to optimize their use to compensate for their inherent intermittency. I believe a major challenge for energy regulators over the next several years – both at the federal and state levels – will be to grapple with this tension of dealing with policies that necessitate large infrastructure projects in an era of heightened infrastructure opposition.

“Dealing with these issues will be even more important should the Environmental Protection Agency’s new 111(d) carbon regulations [the Clean Power Plan] come to pass. For if infrastructure development is largely delayed or blocked, I have difficulty envisioning affordable or reliable ways for utilities to meet the EPA mandates. These 111(d) rules put regulatory commissions at the state and federal level in a very precarious position. The rules are not ours; they are the product of the EPA. Yet nearly all of the potential negative outcomes fall squarely on our shoulders, whether related to affordability or reliability. While I continue to have concerns related to potential market impacts and jurisdictional issues, for the purposes of this testimony, I will highlight the potential tension between 111(d) and infrastructure. In this regard, I note the timelines contained in the EPA’s rules.

“While the final rule, as compared with the draft rule, extended state compliance timelines by up to 2 years, it is worth remembering how long it takes infrastructure projects to be developed. Final state implementation plans would not be due, in many cases, until 2018. Compliance targets begin in 2022. Yet major pipeline and transmission projects can take anywhere from 3-12 years, or longer, to accomplish from concept to in-service completion. I would emphasize that if a generation resource shift is compelled prior to necessary infrastructure completion, electric reliability could be a challenge, but regardless, affordability will almost certainly suffer. Substantially higher energy costs have been the result everywhere this has occurred, and it will not be any different in this case if expanded infrastructure is not built in time to meet the generation mix changes required by the regulation.

“This problem, at least from an affordability standpoint, will be compounded in certain parts of the country, where there is a significant risk of infrastructure assets being stranded years before the end of their useful lives. This means consumers will be paying not just for the new infrastructure, but also for the previous investments in assets that are being retired to comply with the EPA regulation. The impact of this rule will not be evenly felt because of the nature of the EPA targets themselves. To be perfectly honest, some states don’t have all that difficult a road to compliance. This is often related not so much to any particular policy choice the state made, but rather to the vagaries of the math behind the state-by-state targets set by EPA in relation to the nature and vintage of a state’s legacy electric generation fleet.

“For example, some states have older conventional plants that were just recently retired or are soon to be retired for reasons other than environmental regulations. These states may find targets that are relatively easy to meet because they will get full carbon reduction credit for the retirement of assets that were due to be retired anyway. It can be argued this has more to do with luck than planning. At the other end of the spectrum are states like my home state of North Dakota. Between the draft and final rules, the state’s emissions reduction target skyrocketed from 11% to 45%. In North Dakota, actual emissions were down 11% between 2005 and 2014, despite a rapidly growing economy. Utilities during that timeframe built a significant amount of wind power, in part as a hedge against carbon regulatory risk. Unfortunately, it turned out to be a hedge for which they will receive no credit. Additionally, the state’s coal fleet is still relatively young, and has thus incurred recent investments for environmental compliance. In fact, North Dakota is proud to be one of only a few of states in full attainment of EPA’s National Ambient Air Quality Standards. Nonetheless, the state was given an emissions reduction target so punitive that I struggle to conceive of a way it can meet it in an affordable manner.

“Indeed, the North Dakota Health Department has estimated the annual cost of compliance if the state adopted an emissions credit trading program could top $400 million per year; a staggering figure for a state of less than 750,000 people. I hope Committee members understand how problematic this is for states like North Dakota that did not fare so well under the EPA’s state-by-state emissions target math. Such states stand to see a huge transfer of wealth out of them, and will receive little in quantifiable environmental benefits in return given the worldwide nature of carbon emissions.”

Commissioner Colette Honorable

“Our focus on reliability has continued through our engagement with stakeholders in the energy sector and the Environmental Protection Agency (EPA) during implementation of the Clean Power Plan. In early 2015, FERC hosted a series of technical conferences on the implications of compliance efforts with regard to the Clean Power Plan. These conferences, held in Washington, D.C., Denver, and St. Louis, aided the Commission in assessing whether and how the Plan may impact the reliability of the grid.

“We heard from diverse stakeholder groups: regulators, utilities, regional transmission organizations (RTOs) and independent system operators (ISOs), environmental groups and consumer organizations. These conferences raised a host of issues that informed the Commission’s advice and counsel to the EPA.

“In addition, I co-moderated a “deep dive” workshop in May 2015 sponsored by the Bipartisan Policy Center (BPC) on specific reliability measures such as the Reliability Safety Value and Reliability Assurance Mechanism that many believe will help shore up the reliability during compliance with the Clean Power Plan if necessary.

“The feedback the Commission received during our technical conferences, along with information gathered from the BPC event and other types of engagement, including letters and comments from stakeholders, informed our communication to EPA this past May. In a letter signed unanimously by the Commission, we advised EPA to consider reviewing the interim compliance timeline set forth in the proposed Clean Power Plan to ensure flexibility in the early years of compliance. In addition, we encouraged EPA to consider adopting both a “Reliability Safety Valve,” which would allow the Commission to work with the EPA to address temporary, unexpected impacts upon Bulk-Power System reliability, and a proactive process to provide for reliability monitoring and assistance. Under the latter process, existing planning procedures should be used initially to review state plans for potential reliability concerns. The EPA accepted our recommendations in the final rule.

“Going forward, the Commission stands ready to work with EPA, the Department of Energy (DOE), the states, regions, NERC and other stakeholders. The Commission has offered to review analyses or request additional assessments as necessary. We also noted that the Commission could continue holding technical conferences or other public workshops as states and utilities begin implementation of the rule. Pursuant to a joint staff working document that informs our interagency work, we will continue participating in future discussions with EPA and the Department of Energy (DOE). This may include further engagement with NARUC or the BPC, in addition to continuing our work with RTOs, ISOs, NERC and regional entities.

“Since the issuance of the final Clean Power Plan, I have continued engaging with diverse groups. For example, in October I was invited to participate in a workshop hosted by the BPC and the Great Plains Institute which focused on compliance in the Midwest. Although most of these states are challenging the rule in court, many are also working in parallel on compliance plans should the rule be upheld. Indeed, my home state of Arkansas is a fitting example. During my tenure as chairman of the Arkansas Public Service Commission, we worked closely with the Arkansas Department of Environmental Quality and a diverse group of stakeholders to evaluate the issues associated with Arkansas’s compliance with the Clean Power Plan. These discussions have continued, even though the state has joined the litigation against the final rule. According to press reports, thirteen other states have reportedly indicated they will follow a similar path as Arkansas.

“A number of studies indicate that if the rule is upheld, fully contemplated compliance plans will have considerable potential to reduce compliance costs, particularly those undertaken in regional efforts. In the Midwest, for example, both the Southwest Power Pool and the Midcontinent Independent System Operator have released studies concluding that regional compliance with the Clean Power Plan is more efficient, less costly, and therefore better for consumers. It is imperative that all affected stakeholders engage and work collaboratively to maintain reliability while minimizing any potential cost impacts of plan implementation going forward.

“In September 2015, the Commission’s Office of Energy Projects reported that 60% of the new generation-in service this year (January-September 2015) was from renewable sources. Most of this new capacity was wind—2,966 MW of installed capacity—and solar, with 1,137 MW of installed capacity. Gas accounted for 2,884 MW, or 39.6% of installed capacity thus far in 2015. In order to bring this new and diverse generation to market, new infrastructure—pipelines, power lines, and other technologies—will be necessary.

“In the electric industry, RTOs, ISOs, transmission providers, and their respective stakeholders are addressing the need for additional transmission projects and the ability to integrate storage, energy efficiency and demand response in regional and interregional planning processes. We have continued to refine the Order No. 1000 competitive solicitation process, which has helped bring together a number of significant stakeholders around regional planning processes. While the planning processes are almost fully underway, as demonstrated in compliance filings, regional differences and modeling issues are proving to be particularly challenging for interregional planning processes. As these new processes are evolving, we will continue to listen to stakeholders and be open-minded on changes necessary to improve Order No. 1000. I look forward to working with my colleagues to ensure that our efforts pursuant to Order No. 1000 meet their intended goals.”

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.