EPSA: the ‘shale gale’ not the last game changer in power business

The Electric Power Supply Association sees three main challenges to grid reliability; electric/gas coordination; declining demand and increasing demand response; and the economic integrity of power market rules.

That is according to May 9 prepared testimony from John Shelk, President and CEO of the Electric Power Supply Association (EPSA), to be delivered to the House Energy and Commerce Committee’s Subcommittee on Energy and Power. The subcommittee hearing is on the subject, “American Energy Security and Innovation: Grid Reliability Challenges in a Shifting Energy Resource Landscape.”

EPSA is the national trade association for competitive wholesale electricity suppliers, with the competitive sector accounting for 40% of U.S. generating capacity.

“Today policymakers and market participants understandably focus on the so-called ‘shale gale’ stemming from prolific new supplies of natural gas,” Shelk wrote in his prepared testimony. “This Committee can take credit for having the foresight in the 1980’s to repeal the price controls on natural gas that skewed the market toward higher priced sources of natural gas while also repealing the provisions of the Fuel Use Act of 1978 that essentially prohibited the use of natural gas in power generation. Had this Committee not taken those actions decades ago, the shale natural gas revolution would not be occurring. Yet before it blossomed in the past several years, experts were convinced that the United States would become a net importer of natural gas, not a potential exporter.”

Shelk added: “The nation ignores this lesson of the inherent weakness of energy forecasts at its peril. Just in the past eight years I have been at EPSA, we have witnessed the headlines that ‘King Coal is Back’ then the ‘Nuclear Renaissance’ followed by the ‘Renewables Revolution’ and now the debate is whether natural gas-fired power generation is a bridge to the future or the future destination itself. What we do know is that the ‘shale gale’ will not be the last game changer. What’s next in cleaner coal, solar, smart grid, storage, modular nuclear reactors, natural gas technologies, electric vehicles, efficiency, distributed generation and demand side management? The variables are numerous and the possibilities are nearly endless.”

Against this backdrop, Shelk focused on three specific challenges: electric/gas coordination; declining demand and increasing demand response; and the economic integrity of power market rules.

Electric/gas coordination

On electric/gas coordination, EPSA viewed with interest a subcommittee hearing on March 19 that focused on this topic. EPSA members, as large consumers of natural gas, have a major stake in robust gas supplies and a reliable gas delivery network, Shelk noted.

There are many ways by which gas-fired power plants procure fuel to reliably generate electricity day in and day out, he wrote. One way is to purchase firm transmission on an interstate pipeline. But, some plants are not served by interstate pipelines and instead get fuel from local natural gas distribution companies. Thus, firm transportation on interstate pipelines should remain a business option for power plants, not something to be mandated, Shelk said.

The electric/gas coordination challenge varies by region and therefore a regional, stakeholder-driven approach with fair and transparent collaboration and communication is preferable to a “one-size-fits-all” top-down federal solution, Shelk added. A regional approach can take into account multiple factors that vary widely across regions including: the level of gas storage and shale gas development; the fuel-resource mix; wholesale and retail power market design; and the level of development of interstate natural gas pipelines, among other factors.

“The regional approach is working and FERC is to be commended for its attention to these issues in a thoughtful manner,” Shelk said. “As you learned in the earlier hearing, FERC held a series of regional conferences on electric/gas issues last year with follow-up technical conferences on specific issues this year. Various electric and natural gas trade associations have been working on these issues even longer and we continue to do so.”

He added: “In New England, ISO New England is engaged in a formal effort with stakeholders to examine and address these issues. EPSA’s regional partner, the New England Power Generators Association (NEPGA), cochairs the regional ‘focus group’ on this subject. FERC recently approved new scheduling times for ISO New England that will better align when in the prior day power plants are notified to operate to provide more time to arrange for natural gas. ISO New England would benefit from allowing generators to update their power bids as natural gas costs change during the day, particularly during winter months. In addition, New England states are encouraging a conversion from home heating oil to natural gas for economic and environmental reasons. This means that local natural gas distribution companies may have a larger role to play in contracting for the build out of the regional natural gas delivery infrastructure.”

Demand side challenges

The second set of challenges is on the demand side, including the extent to which demand response is not being regulated consistent with grid reliability, Shelk said. While policymakers and market participants tend to argue over which supply source of electricity is preferable, the changing landscape on the demand side deserves as much if not more Congressional attention. Recent reports from the Energy Information Administration, regional grid operators, private forecasters, and power sector financial analysts all confirm that the nation is likely facing a relatively flat demand for electricity in coming decades even as the economy recovers, though with some pockets of state and regional load growth, he noted.

“Expectations of lower power demand growth are a marked shift from prior forecasts that until recently projected that demand would pick up,” Shelk wrote. “The reasons are structural and focus on efficiency standards, energy management options, and the changing mix of the nation’s economy to less electricity-intensive sectors. The consequences are profound. For competitive suppliers there will be less demand to serve from which to earn market revenues to recover the costs of long-term investments. For traditional rate-base utilities, flat demand at a time of rising costs for generation, transmission and distribution means more frequent rate cases seeking ever higher rates, which will start making competitive wholesale and retail supply options more attractive to policymakers and consumers in those states.”

The other component of this second challenge is Demand Response, which involves some consumers paying others to use less electricity (so-called “negawatts”), Shelk wrote. When this committee and the Congress acted on this subject in Section 1252 of the Energy Policy Act of 2005 and Section 529 of the Energy Independence and Security Act of 2007, Congress was careful to only direct the Department of Energy and FERC to work with the states. This is because demand side resources are inherently retail matters that the Federal Power Act since its enactment decades ago has reserved to the states, he pointed out. Congress specifically limited the federal role to preparation of a National Action Plan and similar technical measures to pursue how customers could be properly incented to reduce demand below what they would otherwise consume.

Power market rules

The third challenge to grid reliability takes this discussion back to where this testimony started, Shelk said. It is often said that the U.S. has a “hybrid” electricity system, as if there are only two business models for generating electricity (competitive and monopoly) and two corresponding regulatory regimes, he noted. In fact, states and regions exist in a range between cost-based regulation and markets.

Regulation needs to keep up with market changes, he said. For example, the growth of intermittent resources such as wind and solar argues for large regional markets that can more reliably manage resources across a wider footprint. It means that flexible resources, such as gas plants, must be fully compensated for standing by and providing electricity when intermittent resources do not. It also means that while percentages may change among resource types, the “work horses” of coal and nuclear will continue to play important roles, Shelk said.

American Wind Energy Association touts wind need, reliability

Rob Gramlich, Interim CEO of the American Wind Energy Association, is also a hearing witness. His prepared testimony focused more on the importance of wind to the grid.

“Wind energy production has grown dramatically in recent years, lowering energy costs for consumers while keeping the grid reliable,” Gramlich said. “Over the past five years, wind energy has accounted for more than 35 percent of all new electric generating capacity in the U.S. Last year alone, $25 billion in private investment went into building new U.S. wind projects, providing 80,000 American jobs. The wind industry now has 550 manufacturing facilities in 44 states, and wind projects in 39 states and Puerto Rico. Nearly 70% of the content used in U.S. wind turbines is produced here in America, up from 25% just a few years ago.”

Last year, wind energy reliably provided more than 20% of the electricity in Iowa and South Dakota, and more than 10% of the electricity in nine states, Gramlich added. At times, wind energy has reliably provided more than 55% of the electricity on the main utility system in Colorado, and 35% on the main grid in Texas, he noted.

“Compared to wind energy, changes in electricity demand and failures at conventional power plants are far larger contributors to grid variability and the need for the flexible reserves, or backup, that grid operators use to keep supply and demand in balance,” he said. “Grid operators that use efficient practices have found that they can reliably add large amounts of wind energy with virtually zero need for backup power beyond what is already needed. Even if additional backup is needed, it is much cheaper to accommodate the slow and predictable variations in wind output than the instantaneous loss of conventional power plants that can occur at any time.”

Data from the Texas grid operator indicate that the additional cost of backup for obtaining almost 10% of its electricity from wind energy accounts for about six cents out of a typical household’s $140 monthly electric bill, Gramlich said.

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.