Threading the needle on gas/electric coordination: Who has to change and who has to pay?

Vol. 45 No. 5

Andrea Chambers and Katie Leesman are attorneys with the law firm of Ballard Spahr LLP, representing electric utilities and natural gas pipeline end-users.

Thanks to a decrease in natural gas prices and a federal regulatory push to reduce greenhouse gas emissions from coal-fired power plants, electric generators increasingly rely on natural gas as a cheaper, cleaner fuel source. This trend raises significant implications for natural gas pipeline capacity as gas-fired generators, local utilities, industrial consumers, and other natural gas consumers jockey for access to this important resource and the pipeline infrastructure necessary to transport it. The growing demand for natural gas brings into sharp focus the expanding interdependence between the gas and electric industries.

As the chief regulator of the country’s interstate pipeline system, the Federal Energy Regulatory Commission (FERC) began to pursue regulatory strategies to improve gas and power coordination over a year ago, holding a series of five public conferences in 2012. Since then, the discussion of gas-electric coordination crystallized around three major issue areas: improving communications, coordinating operations, and increasing pipeline capacity. With respect to the first two issues—communications and operations—regulatory proposals and stakeholder debate are already underway. Increasing capacity, the largest and thorniest issue of the three, remains unaddressed, and questions surrounding that issue, such as cost causation, remain unanswered.

Expanding communications

One theme that emerged from the discussion concerned the need for increased communication between natural gas pipeline system operators and electric transmission system operators. Many market participants expressed the view that expanding communication between the gas and power sectors, particularly in times of market stress, such as extremely cold weather in the Northeast, would improve the overall reliability of the nation’s electric infrastructure. Extreme weather events, such as one in February 2011 where the southwestern United States experienced unusually cold and windy weather, first drew attention to the importance of such communications. During that event, 4.4 million electric customers and tens of thousands of gas customers suffered significant service disruptions. After-the-fact analysis of that event revealed the need for robust communication between the gas and electric control centers to ensure both systems operate safely and effectively.

While many of the challenges inherent in improving gas-electric coordination stem from the overall lack of sufficient pipeline capacity to serve the increase in gas-fired generation, addressing the problem of increasing communications does not raise the same financial and economic hurdles. Thus, improving communications between pipeline and transmission system operators is generally regarded as the “low-hanging fruit” for improving coordination. FERC viewed improving communication between gas and electric operators as a necessary first step of a broader effort to address gas-electric coordination. In November 2013, FERC published a Final Rule (145 FERC ¶ 61,134 (2013)) revising its regulations to explicitly authorize interstate natural gas pipelines and public utilities to share nonpublic operational information for the purpose of improving communication. FERC noted that “existing barriers—real or perceived—to the sharing of nonpublic, operational information could impede transmission operators’ ability to reliably manage the operation of interstate natural gas pipeline and electric transmission systems.” While FERC removed the barriers by permitting the sharing of nonpublic operational information between pipeline and transmission system operators, there are some limitations. Specifically, FERC clarified that a “no conduit rule” prohibits public utilities and pipelines—as well as their employees, contractors, consultants, and agents—from disclosing—or using anyone as a conduit for disclosure of—nonpublic, operational information that they receive under this rule to a third-party or to its marketing function employees.

The sharing of nonpublic operational information between electric system operators and gas pipeline operators that would otherwise not be available to the public, such as when there is insufficient pipeline capacity to serve electric generators and gas distributors because of a well freeze-off in the supply region in the Southwest, or insufficient capacity due to increased demand due to cold temperatures in the Northeast, is a new and untested practice. Some market participants expressed concern that too much confidential market information could be revealed to the operators, not just the information needed for reliable operations, or that market information might be revealed selectively, providing an unfair competitive advantage to certain market participants. In a request for clarification of the Final Rule, the Natural Gas Supply Association, along with other entities representing market participants, such as the Process Gas Consumers Group, asked FERC to provide an opportunity to evaluate the impact of the new rule one year after its adoption. This request for clarification remains pending before FERC.

Coordinating operations

FERC and the industry are currently grappling with the matter of coordinating the “gas day” and the “electric day,” and the pipeline nomination and scheduling cycles, as the gas and electric sectors each operate differently.

The gas industry currently follows one standardized scheduling timeline for natural gas supply transportation for the entire United States, irrespective of time zone. The parceling out of the gas supply, as well as transportation of that supply, occurs under a process known as “nomination.” The unified gas day and pipeline nomination, confirmation, and scheduling processes (when gas flows) is a twenty-four-hour cycle, which begins at 9 am Central Time (CT). The current day-ahead nomination deadline for the “timely cycle” (Cycle 1) is 11:30 am CT the day before gas flows, with the confirmation deadline at 3:30 pm CT, and posting of scheduled quantities at 4:30 pm CT. There is one additional day-ahead and two standard intraday nomination cycles, each with deadlines tied to specific times within the CT zone.

In contrast, the electric industry’s market dispatch scheduling timelines vary by region and do not align with the gas market. Electric utilities rely on a “balancing entity,” such as a power pool, Regional Transmission Organization, or an Independent System Operator (ISO) in organized markets, to estimate the electricity demand for the next day; the electric generators plan for natural gas deliveries to their plants accordingly. Electric utilities experience cyclical use throughout the day by their residential customers, and the utilities must have the ability to respond to the customers “on demand.” Many generators are unable to secure gas supplies after they are dispatched by the electric system operator because they do not know if they are dispatched until after the timely nomination cycle for the day. Even when they are able to nominate, it can be so late in the gas day that there is no gas supply available and/or the gas market is no longer liquid. Thus, a critical challenge lies in coordinating electric operations and the pipeline deadlines for nominations.

To address the division between the two industries, FERC issued a Notice of Proposed Rulemaking (NOPR) on March 20, 2014, proposing significant alterations to the start of the gas day and to gas nomination and scheduling cycles. FERC proposed to begin the gas scheduling process at 4:00 am CT to ensure gas-fired generators are able to provide power during critical periods, and to move the timely nomination cycle to 1:00 pm CT to allow the electric industry to finalize scheduling prior to that deadline so generators could obtain gas supply. The NOPR also proposes to increase the intraday nomination cycles to give all shippers added flexibility. If the NOPR were implemented, the number of standard intraday cycles would increase from two to four. However, FERC noted that the “natural gas and electricity industries are best positioned to work out the details” and required the industries to work through the North American Energy Standards Board to develop a consensus position within 180 days, or by September 29, 2014. FERC provided an additional 60 days for interested parties to file comments, or by November 28, 2014.

Expanding capacity

Regardless of changes in communication rules and scheduling procedures, there is no substitute for additional infrastructure: the expansion of pipeline capacity is the largest of the issues and it has yet to be addressed. In some parts of the country, particularly the Northeast, more pipeline delivery capacity is clearly needed to meet the surging demand for natural gas. This concern has been highlighted by extreme weather events, such as the recent “polar vortex” experienced through much of the United States this winter, which led to increased demand for natural gas for heating homes in the Northeast and decreased the amount of gas pipeline capacity available to electric generators.

However, the issue of who will pay for the additional capacity remains difficult to resolve. Financing new construction generally depends upon a guaranteed revenue stream such as long-term firm contracts signed by shippers, who then ship gas on the pipeline once the pipeline is constructed. These long-term contracts ensure that shippers will have the necessary infrastructure for delivery to the market and that investors will receive a return on their investments in new projects from this revenue stream. Pipeline companies generally do not build on the premise of “if we build it, they will come,” but rather build new pipelines on the model of “if the shippers come, we will build it.” The March 20 NOPR attempts to increase the efficient use of existing pipeline capacity by requiring interstate pipelines to allow multiparty agreements, which will allow multiple shippers to share under a single agreement; however, it does not address building new capacity.

Generators in organized markets are skeptical about their ability to recover the costs associated with these types of contractual commitments under the current market design and, therefore, may be unable or unwilling to sign long-term firm contracts that would underwrite new pipeline construction projects. Moreover, some generators question the wisdom of committing to pay for pipeline capacity that they might realistically only need to use a few days out of the year. Other parties argue that generators have already invested in land, buildings, turbines, and plants to provide service even though there is no guarantee a particular plant will be dispatched, and that incurring the small cost of building additional pipeline capacity is no different than the costs of the plant. So, if more pipeline capacity is needed (at least in some parts of the country) and if generators in organized markets cannot sign long-term contracts to support new pipeline construction, the issue remains as to who will step up to pay for this new pipeline capacity.

These three issues facing the energy industry—communications, operations, and capacity—raise numerous questions, and there are no simple solutions. It remains to be seen which industry changes will be adopted and how the costs of those changes will be distributed among the various stakeholders. What is clear is that interested parties, working with FERC, will continue to try to weave a solution to these matters that will serve to enhance coordination between the gas and electric industries. The decisions they make will have a major impact on how all market participants do business.

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