Integrated Resource Planning

Another aspect of natural gas industry regulation is the integrated resource planning (IRP) process. In the electric industry overview discussion in Chapter 20, the evolution of the IRP process is presented, as well as standard industry cost and benefit evaluation techniques. Following is a brief discussion of IRP in the gas industry.

Decades of regulated pricing at the wellhead caused market aberrations, which in turn led to a natural gas shortage in the mid-1970s. Natural gas utilities had to constrain their marketing efforts and began to sign desperate contracts with pipeline suppliers to ensure that they would be able to meet their obligation to serve. Rapidly rising natural gas prices finally led to federal price deregulation phased in through 1985.

The natural gas shortage and resulting escalating prices led to significant voluntary conservation efforts on the part of customers, and the beginning of government-and gas utility-sponsored conservation programs. Additionally, more stringent energy efficiency appliance and equipment standards have led to significant natural conservation as individuals and businesses replace old equipment.

Gas utilities also began to negotiate interruptible gas sales for large industrial customers as a way to help ensure that they could meet peak winter demands. While conservation was not yet being specifically targeted by utilities and state public utility commissions (PUCs), it had become a supply planning consideration. The move toward interruptible contracts, however, was a significant step toward proactive supply planning through use of a demand-side management (DSM) tool. In other words, interruptible service has historically been, and continues to be, a DSM tool used by LDCs throughout the country.

Natural gas utility-sponsored DSM programs are fairly similar to those for electric utilities in terms of the basic load shaping strategies. These programs enable the gas utility to delay the purchase or building of low-load factor and, therefore, relatively high-cost peaking and storage supplies or facilities that are needed only for short duration. In addition, they serve to avoid gas purchases and costs associated with gathering, transmission, distribution, customer accounts, and general plant and other non-gas costs.

Load leveling programs, such as high-efficiency furnaces, enable the gas utility to get maximum use of its system delivery capabilities and contract reservation charges. Load building programs, such as those that encourage the use of gas-fired cooling technologies, are one way to achieve higher load factors with little or no incremental system cost. Load reduction or peak shaving programs generally involve interruption capability in exchange for reduced rates to customers that possess alternative fuel use capability. The goals for each of these load shape objectives are as follows:

• Conservation: The promotion of decreased gas use, primarily during peak periods, to reduce peak-day requirements and ensure adequate reserve margins. Examples include installation of building envelope insulation, high-efficiency burners, and heat recovery systems.

• Load building: The promotion of increasingly efficient use of existing capacity that can reduce rates by spreading fixed costs over greater sales units. Examples include fuel switching, natural gas vehicles, fuel cells, and application of prime mover technology for mechanical drive and electric generation.

• Seasonal load reduction: Changes in load shape that yield increased gas utility seasonal control over the level and/or timing of demand. Examples include high-efficiency furnaces and water heaters and gas heat pumps.

• Valley filling: The promotion of technologies that increase off-peak sales to improve utility load factor and generate additional revenue without increasing peak-day requirements. Examples include application of gas-fired cooling and dehumidification technologies and gas-fired electric peak shaving generators.

• Peak clipping: Options that reduce peak demand without adversely affecting off-peak sales. This involves storage deliverability service.

• Peak load shifting: The shifting of on-peak demand and energy use to off-peak periods, resulting in lower peak-day requirements and higher load factors. This involves various types of storage capacity.

On the supply side, gas utility IRP differs fundamentally from electric utility IRP. The native generation and off-system supply purchases of the electric utility are replaced with a variety of gas purchase, transportation, and storage contracts. Peaking facilities, such as liquefied natural gas (LNG) plants or propane-air injection facilities, may supplement these contracts. The chosen mix of these supply options is intended to meet the peak daily demand requirements of the system at lower cost.

Historically, LDCs evaluated opportunities to add load based on whether the added load would provide sufficient revenues over time to cover the cost to serve them and provide a fair rate of return. Hurdle rates, or rate-of-return tests, were established to determine if and how much a customer would have to contribute toward the cost of gas hook-up and associated construction required to provide gas service.

When considering the addition of a new resource that would allow it to serve new customer loads, the LDC would consider the change in average gas costs that would result to existing firm service rate payers. It would also consider the margins that would be earned on the new sales that would be used to reduce the revenue requirement of existing rate payers. These considerations assured that rate payers would not bear an increase in total revenue requirement as a result of the addition of new resources.

In natural gas IRP, this same logic is applied to consideration of all resource-related investments, be they supply-side options (e.g., contracting for new gas supplies, building new pipelines, or brokering capacity) or demand-side options (e.g., conservation or load building). Within an overall societal framework, gas utility IRP considerations go beyond revenue requirements. They seek to determine which combination of resource and marketing options provides the greatest benefits to customers, the gas utility, and society.

Gas utility IRP must still consider the commodity side for its native load. However, with the movement toward free market competition in gas commodity sales and the unbundling of services, the role of gas utility IRP will continue to shift away from the commodity side and focus more strongly on gas distribution services. With this shift, LDC-sponsored DSM programs have been de-emphasized. Since the LDC must now compete in a relatively free market for commodity sales, the obligation to include the commodity-side impact in IRP evaluation has also been reduced or eliminated. The result is that the cost-justification for administering DSM programs has been greatly diminished.

The transmission and distribution segments of both the gas and electric industries are similar in that transmission investments exhibit substantial economies of scale, and distribution in both industries has monopolistic features. However, the natural gas industry differs from the electric industry because gas can be more easily stored than electricity. With regard to IRP, the ability to easily store gas and to broker capacity has a significant impact on an LDC's marginal costs.

Reliability planning is also different for gas and electric utilities. LDCs plan for their own reliability, while electric utilities depend more on regional power pool planning since their transmission and distribution are interconnected with other electric utility systems. In addition, regulators have historically placed a higher priority on electric service reliability than on gas.

One important factor in the development of gas utility IRP has been the need to make quick decisions about new supply resources without the benefit of knowing when the next opportunity will occur. However, today's unbundled, competitive market for gas supplies, transportation, and capacity brokering has provided increased flexibility in terms of optimizing both short- and long-term resource portfolios.

As with the electric industry, the role of intensive IRP is seen as somewhat less critical given the replacement of regulatory control with competitive market forces. LDCs are obligated to make prudent resource acquisition decisions in order to remain competitive and financially viable. Still, the transmission and distribution of natural gas shall remain a heavily regulated area with limited access to market entry. Hence, IRP methods should still be required to overcome market imperfections brought about by regulation.

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