Recent technical conferences held by the Federal Energy Regulatory Commission confirmed that parties’ concerns about electric system reliability at a time of increased natural gas use for power generation vary by region due to a variety of factors.
That includes the generation mix within a region and the percentage of generation fueled by natural gas, the amount of coal-fired generation anticipated to retire, the amount of available unsubscribed gas pipeline capacity and the electric market structure within that region.
That was one of the points made by the Interstate Natural Gas Association of America (INGAA), which represents U.S. gas pipeline companies, in Nov. 13 post-conference remarks filed at FERC in a docket where the commission is looking at issues related to gas and electric power system integration at a time when gas is taking an ever-larger share of the power generation fuel market from coal.
Said the Nov. 6 version of the U.S. Energy Information Administration’s Short-Term Energy Outlook about the coal-to-gas mix: “The shares of total U.S. electricity generation fueled by natural gas and coal during 2012 averaged 30.6 percent and 37.2 percent, respectively. EIA expects that prices for natural gas delivered to electric generators during 2013 will average 22 percent higher than during 2012, while the average cost of coal is just over 1 percent higher. The projected higher price of natural gas relative to coal contributes to a decline in the share of total generation fueled by natural gas 27.2 percent next year and an increase in the coal share to 40.1 percent.”
While the gas share is projected by EIA to fall off its highs of recent months, the long-term trend is for much higher gas use for power generation as utilities and independent power producers meet new air emissions standards for aging coal-fired power plants by shutting many of them.
“INGAA appreciates the Commission’s leadership in bringing together stakeholders to discuss the opportunities and challenges associated with the increased use of natural gas for electric power generation,” the association wrote in its Nov. 13 comments. “The Commission’s five roundtable technical conferences provided an opportunity to share ideas and to discuss issues concerning gas-electric scheduling and market structures, communications, coordination and information sharing, and reliability. As is well-recognized, the use of natural gas for electricity generation is increasing for a variety of reasons including the low cost of natural gas, abundant domestic supplies, and the impending retirement of some of the nation’s coal-fired generation facilities.”
Some regions, such as New England, face immediate electric reliability challenges due to pipeline capacity constraints and an electric market that currently does not incent or compensate power generators for holding firm fuel supply, including natural gas, fuel oil, or dual fuel capability, INGAA noted. Other regions, such as the one served by the Midwest Independent System Operator (MISO), may not face the immediate electric reliability concerns of the northeast, but could have them in the not-too-distant future depending on the timing and scale of coal-fired retirements, among other factors. Other regions, such as the southeast, don’t seem to have electric reliability concerns in connection with greater utilization of gas-fired generation given the integrated nature of utilities in that region and their ability to recover the costs of firm transportation from ratepayers.
INGAA said even with these differences, it heard several common messages across regions:
- Gas-fired generation will increase;
- The issue is how to ensure electric reliability, with this not about the reliability of natural gas as a fuel source;
- Electric market rules in restructured markets do not price power in a way that reflects the cost of ensuring electric reliability by enabling generators, regardless of fuel choice, to recover costs associated with firming up their fuel supply;
- Generators within integrated electric utilities are able to price electric reliability into their power costs, which allows them secure a portfolio of transportation services including firm natural gas transportation and storage services, when necessary, to ensure electric reliability. The generators within integrated utilities also can support any necessary gas pipeline infrastructure development because those utilities can recover the cost of such prudent expenses from ratepayers; and
- The FERC model for building interstate pipelines works well.
FERC needs a strong role in the integration process, INGAA says
“We continue to believe that strong FERC leadership and guidance, in conjunction with the state commissions, Planning Authorities and the North American Electric Reliability Corporation (NERC), where appropriate, is necessary to ensure that each region addresses how it will ensure electric reliability,” INGAA wrote. “In addition, continued FERC leadership can ensure that all stakeholders, including natural gas pipelines, have a seat at the table to evaluate and monitor any proposed solutions to identified issues.”
INGAA pointed out that several ISOs, Regional Transmission Organizations (RTOs) and regulators are studying the adequacy of pipeline capacity in their regions. Gas pipeline companies agree that each RTO/ISO in wholesale electric markets or each electric utility in bilateral markets, in conjunction with FERC, state commissions, planning authorities, and NERC, as appropriate, is in the best position to determine the fuel and transportation choices available in its region (or service territory) and the level of firm backup power needed to ensure electric reliability, it added.
“It is not the role, nor the competence of, the pipeline industry to opine on the level of natural gas supply, transportation and storage capacity for which the generators within each region should contract in order to ensure electric reliability,” INGAA wrote. “Regardless of the resources a region wishes to rely upon for electric reliability, the RTO/ISO, electric utility, or other appropriate agencies and regulators, must ensure that generators in its region (or service territory) have contracted adequately to ensure that the appropriate amount of fuel will be available when needed.”
As FERC reviews issues it can address in the near-term, INGAA urged it not to lose sight of the more challenging, yet crucial, longer-term issues such as ensuring that wholesale power markets assign appropriate costs to achieve desired levels of electric reliability. No matter what market structure or fuel type a region employs, the electric industry needs to factor electric reliability into the electric pricing structure.
An important element of FERC’s successful model for building pipeline infrastructure is the commission’s incremental rate policy, which has facilitated pipeline expansions by helping customers avoid, or at least minimize, many contentious cost-allocation and cross-subsidization issues that can delay a project’s regulatory approval, INGAA noted. “Several customers at the technical conferences commented that they would oppose strongly attempts to change the FERC incremental rate policy or any changes that would result in all customers subsidizing expansions that primarily benefit generators,” it said. “In addition, FERC’s requirement that pipelines solicit from shippers any potential turn-back capacity in conjunction with expansion projects, and pipe-on-pipe competition to serve market demand, ensure projects are sized properly and that only needed interstate pipeline capacity is built.”
Dominion emphasizes fuel diversity issues
There have been scattered post-conference comments filed by other parties with FERC in this docket, with INGAA’s the most recent. Another series of comments, for example, were filed on Oct. 12 by the Dominion Resources Services unit of Dominion Resources (NYSE: D). Dominion’s Virginia Electric and Power knows well many of these issues, since it has targeted coal units at its Yorktown and Chesapeake plants for retirement in the next few years and is building major new gas-fired power plants to make up for those retirements and to also meet system load growth needs.
Dominion said it believes there are a few key points to take away from the technical conferences.
- First, the maintenance of existing fuel diversity is an important mitigant to the risks of reliance on a single-source fuel supply. New environmental laws and regulations may cause certain unit retirements or de-ratings. However, the commission and the RTOs must be careful designing rules that don’t cause premature retirements by suppressing price signals for reliability needs or sending price signals only to gas-fired resources.
- Second, in RTO regions facing gas reliance concerns, the region should favor market-based solutions over mandated solutions that could distort the market, Dominion noted. To allow market-based solutions to arise, the commission must ensure that the basic market design for the region is working properly by sending appropriate and transparent price signals to all market participants. Only then can the commission, the RTOs, state regulators and market participants accurately evaluate any problems and whether modifying price signals will improve the development of efficient market solutions.
- Finally, there are significant regional differences with respect to gas-electric coordination. The commission should recognize that some areas, such as New England, have a unique combination of physical characteristics and market rules that may require solutions that do not apply in other regions, Dominion said.
“Fuel diversity can be maintained by ensuring that markets send appropriate price signals to all resources,” wrote Dominion. “The Commission should be wary of narrowly focused market design changes that single out gas-fired resources due to the impact on fuel diversity. A single-source remedy will distort price signals and force inefficient market solutions at the expense of other resources, leading to less fuel diversity as non-gas resources are driven from the market. For example, ISO-NE, as part of its Strategic Planning Initiative, has raised a potential proposal that would ‘tranche’ the forward capacity market into separate segments based on unit characteristics needed to meet system operational needs. This proposal creates a number of significant concerns. The top tranche, for flexible resources with firm fuel arrangements, would be procured first and by its very definition is targeted at incenting the development of gas-fired resources with firm transportation. While there are few details about how this might be implemented, the danger is that other capacity resources will subsidize the cost of the more reliable gas-fired resources.”
Under ISO-NE’s “tranche” proposal, gas-fired resources will receive a premium for backing their capacity with firm fuel arrangements, Dominion added. However, the overall cost of capacity will remain the same because non-gas resources could subsidize gas-fired resources through depressed capacity prices, it said. “The market would pay gas-fired resources with firm fuel arrangements more for their capacity but would pay less to other resources with fuel stored on site,” Dominion noted. “This may drive fuel diverse resources out of the region as they see depressed capacity price signals that do not reflect their reliability need. On the demand side, load never sees the significantly increased costs of new requirements to address gas constraints because load’s aggregate cost for capacity has remained the same.”