This discussion of Gas Resource Planning for Electric Generation was presented to an EUCI Conference, “Natural Gas in the Decarbonization Era,” in January 2020. The document will examine the following related topics:
• An overview of the Integrated Resource Planning (IRP) process
• Traditional IRP best practices, and the advantages and disadvantages of natural gas for electric generation
• A high-level overview of emerging gas resource trends
• Addressing potential new natural gas policies
OVERVIEW OF THE INTEGRATED RESOURCE PLANNING PROCESS
Resource planning provides the strategic direction guiding a utility’s long-term resource acquisition. Through the planning process, utilities analyze how to meet customer demands for energy and capacity using supply-side resource procurement and demand-side resources. Planning focuses on two resource areas:
• Energy-related planning – electricity generation and wholesale energy procurement.
• Capacity-related planning – construction of new power plants, electric transmission and/or distribution facilities.
Resource planning is a dynamic and flexible process. It requires iteration and testing to determine a combination of resources that offer maximum value over a range of likely scenarios and over both short- and long-term planning horizons. It is a continual, ongoing process that must reflect market forces and an ever-changing regulatory environment. Decisions made in planning affect customer costs, service reliability, risk management, and the environment.
The resource planning process differs depending on the utility, the state and region in which the utility operates. Whether operating in a state with IRP requirements, market-based solutions or hybrid approaches, resource planning is a core function of all energy utilities. The factors impacting differences in the planning process include the following:
• The utility – Is it public or investor-owned, vertically integrated or “restructured”?
• Local, State and Regional Needs – Determines planning scope and provides policy direction regarding energy portfolios, such as resource priority, fuel diversity, and emissions reductions.
• Stakeholder Involvement – Many stakeholders participate in planning processes and the related decisions. Participants include:
Stakeholder participation in resource planning typically begin with utility regulators and may include municipal governments, state and local policy-makers, regional organizations, environmental groups, and customer alliances. Collaboration at the regional level often occurs through regional transmission organizations (RTOs).
Resource planning includes certain key elements:
Planning Standards – Such factors as reserve margin, deliverability, degree day planning, hydro and other plant availability, integration of state-mandated renewable portfolio standards (RPS), distributed generation, consumer risk tolerance thresholds, environmental adders (CO2, mercury), among others.
Regulatory Strategies – Approaches to align utility interests with those of its customers and regulators, such as risk sharing mechanisms, accelerated cost recovery programs and pre-approval on rate treatment.
Financial Issues – The appropriate discount rate and key financial variables for the evaluation of purchase options, sensitivity testing, and balance sheet effects associated with transaction alternatives.
Retail Load Uncertainties – Impact of Demand-Side Management (DSM) on load planning, economic growth, retention and attrition rates, load factor changes from industrial load losses, and any obligations for provider of last resort (POLR).
Most states have IRP filing requirements but they can vary widely, along with their resource approval criteria. The map below indicates those states with formalized IRP requirements. The average IRP forecast horizon is 20 years but varies from 8 (CO) to 30 (WY) years. The most frequent submission cycle is every two years; the minimum cycle is one year (NC, VA) and the maximum cycle is five years (WV).
As states evaluate the IRP model, opportunities exist for utilities to co-opt regulators, staff and many other stakeholders.
Source: State Commission Profiles, RRA/S&P Global Database.
GAS RESOURCE PLANNING BEST PRACTICES, ADVANTAGES AND DISADVANTAGES FOR ELECTRIC GENERATION
A. Traditional IRP Best Practices
IRP’s make use of scenario planning, which provides internally consistent views of the future. The use of stochastic modeling tests probabilities of future events that could influence the timing, size or type of new resources. Confidence intervals are used to express results (e.g., value at risk statements), which provide a range of values computed in such a way that it contains the estimated result a high proportion of the time. For example, the 95% confidence interval is constructed so that 95% of such intervals will contain the result.
IRP’s represent a “closed system” approach; that is a defined network, with relatively known issues and solutions, that is not penetrated by new market entrants. Therefore, IRP’s work well for addressing the traditional resource planning questions.
B. Natural Gas Advantages for Electric Generation
Natural gas has a range of applications; it’s flexible, efficient, and scalable. Natural gas is a good fit for renewables support (wind, solar) and it doesn’t require subsidies to be competitive. It has a short cycle time versus baseload coal or nuclear. Natural gas turbines can be sited and built with reasonable certainty and are relatively cheap to construct. don’t require subsidies. Natural Gas is a cleaner fuel than coal and low natural gas prices have led to significant increase in economic gas fired generation. Sustained low gas prices leads to cheaper baseload use than coal and more constant hourly generation.
Natural gas can serve as a “bridge” resource to full decarbonization. It is a reliable peaking resource and is suitable for insuring system adequacy. However, there will be implications for these natural gas roles as electrification and decarbonization accelerates, including battery and other storage advancements.
Natural gas could be a “hedge” not just a “bridge,” in case some of the optimistic assumptions for renewables don’t arrive as expected; some examples below:
• A continued steep decline in renewable energy costs
• Electric vehicles become the norm for new automobile buyers
• A network of hydrogen storage and refueling stations arrive at affordable cost
C. Natural Gas Disadvantages for Electric Generation
Electric utilities often raise concerns related to committing to multi-year fuel commitments due to perceived risk of gas price volatility. Long-term commitments to natural gas could limit the ability to meet Green House Gas (GHG) targets and the impact on climate change.
Exclusive reliance on natural gas to replace baseload coal limits diversity in generation technologies. As natural gas replaces baseload coal, it can place extreme stress on pipeline and storage infrastructure in winter and risk service reliability for homes and businesses.
HIGH-LEVEL OVERVIEW OF EMERGING TRENDS
Integrated Resource Planning is facing some common challenges. Consideration of energy efficiency and demand-side management as resources within the IRP model has become a common addition. The level of public involvement (e.g., advisory groups) has increased. The IRP process can provide constituents a unique opportunity to influence utility decision-making broadly, which could be useful to the utility in regulatory proceedings where the degree of support required in seeking cost recovery for acquisition efforts is increasing.
Scope creep can also occur in the form of emerging utility scale “clean” resource options, as well as complications from the expansion of the scope of IRPs to include transmission and distributed energy resources (DER) planning within the electric distribution grid.
A. The IRP Landscape is Changing
State politics and public policy; regional influences and fuel mix; growing demands from regulators and stakeholders; and emerging opportunities and threats from electrification efforts are all impacting the IRP landscape and natural gas’ role in electric generation.
The traditional “regulatory compact” between utilities and their regulators is being re-defined. Public policy and stakeholders are seeking social and environmental outcomes from traditional utility regulation by state utility commissions. Under the traditional definition, the regulator grants the utility company a protected monopoly franchise – the sale and distribution of electricity or natural gas in a defined service territory. In turn, the utility company commits to supply the full energy quantities demanded by customers at a price to cover all operating costs plus a “reasonable” return on invested capital. Under the new emerging definition, the regulatory relationship requires the utility to satisfy the regulator’s standards for performance at the lowest feasible cost by acting prudently and efficiently, and to pursue its customers’ legitimate interests free of conflicting objectives. The regulator establishes compensation commensurate with performance.
B. Regional Influences on the Use of Natural Gas
Clean energy mandates and electrification, including moratoriums on natural gas use, are growing across the U.S.; some examples below:
• The state of New Jersey’s Energy Master Plan
• Xcel’s Energy’s Pathway to Electrification in Colorado and Minnesota
• Legislative activity primarily in west and east coastal states, including natural gas moratoriums, fuel switching incentives, and customer choice debates
• Current state legislation in Maine allows utilities to provide Electric Heat Pumps to customers
• The District of Columbia’s mandate for 50% reduced GHG emissions by 2032, requiring deep electric retrofits in 20% of non-residential buildings
• Communities have proposed or are considering moratoriums on new natural gas customers and other climate initiatives (see map references, below)
Several state jurisdictions have recently initiated reviews of utility line extension policies and the implications of these policies on future natural gas use. There is critical need for comprehensive gas/electric coordination in New England, where gas-fired electric generation is the marginal peaking resource, due to recent history of high winter peak electricity costs and several counties with gas moratoriums due to upstream pipeline capacity constraints.
At the same time, natural gas system expansion programs of utilities have been prevalent during the last decade and some still exist today. Forty states have active gas pipeline infrastructure replacement programs. A pattern of increased use of natural gas for electric generation to replace coal is occurring in some mid-Atlantic states and the Midwest. There still remains a large role for natural gas in the rest of the country.
C. Implications for the Future of Natural Gas Use
There is a direct relationship between using natural gas in an end use such as residential and commercial heating and water heating applications and the ability to economically use natural gas for power production. If gas end uses decrease and throughput decreases on gas transmission pipelines, more costs will shift to power production. Other implications for the rise in uncertainty of the future of natural gas include:
• Loss of economies of scale
• Increasing costs per customer
• Investor hesitation
• Lower utility credit ratings
• Higher required return on equity (ROE) for investor-owned utilities
• Lower economic benefits for customers
ADDRESSING POTENTIAL NEW NATURAL GAS POLICIES
Questions abound regarding natural gas for electric generation in the new era of decarbonization. Will the current resource planning tools be adequate? A representative list of the potential issues follows:
• Integrated resource planning models
• Public utility commission prudence standards
• Ratebase and return on investment regulation
• Utility investment analysis
• Lifecycle GHG analysis
• Traditional public involvement processes
• Legislative energy policy actions
A range of approaches will certainly be needed, not the least of which is to develop a clear understanding of the changing landscape, including:
• State and local politics and policies
• Regional influences and fuel mix
• Growing demands from regulators and stakeholders
• Assessing and addressing emerging threats as potential opportunities