How the electric industry uses DSM and IRP to build load, ignoring basic truths found in fuel-cycle analysis.It was during the early 19th century that General von Clausewitz announced his nine principles of warfare. But he might have waited 100 years or so, to observe how 20th century electric utilities have taken ideas such as efficiency and conservation and turned them into marketing strategies that compete head on with natural gas.
Read on. In a book published in 1988, entitled "Strategic Marketing for Electric Utilities,"1 authors Clark Gellings and Dilip Limaye devote an entire chapter to the principles of von Clausewitz and how they apply in the case of electric utility programs such as demand-side management (DSM), integrated resource planning (IRP), and incentive rates for economic development.
Today we learn that "monopoly rate-of-return regulation of electricity has failed,"2 according to the "Electric Consumers' Power to Choose Act of 1996."
"The future is here," notes Federal Energy Regulatory Commission (FERC) chair Elizabeth Moler in Order 888. "And the future is competition. It is a global trend, and in North America, we are at the forefront of embracing it. There is no turning back."
Yet, certain anticompetitive aspects of well-intentioned studies of avoided costs and stranded investments should pose questions for those concerned with a level playing field. And the same goes for heightened efforts at environmental protection.
This article will examine how demand-side management (DSM) and integrated resource planning (IRP) have "failed" through anti-competitive abuse of "avoided costs" mechanisms that funded "energy efficiency" rebates and marketing campaigns. It will also analyze relationships between DSM and IRP "avoided costs" and "stranded investments" associated with the present restructuring of the electric utility industry through the Federal Energy Regulatory Commission's (FERC's) "mega-NOPR" and subsequent Order 888.
Above all, regulators must remain cognizant of the historical penchant that Adam Smith's "invisible hand of competition" has demonstrated for externalizing the environmental diseconomies of production. Robust competition should entail more than new markets for natural gas and electricity brokers; we should also find healthy competition on the demand-side between these end-use energy alternatives. Competition should take on an environmental perspective through fuel-cycle analyses of energy alternatives. Properly combined, all-source competitive bidding can balance least-cost energy planning and environmental safeguards with the benefits of increased competition.
A century ago von Clausewitz chose "surprise" as his eighth principle. In modern terms, surprise often means infiltration, counterintelligence, and propaganda. So it goes with utility competition. It's a war out there. And truth is the first casualty of war.3
Where the Truth Lies
The U.S. Department of Energy (DOE) recently issued a report compiled by its Energy Information Administration (EIA), The International Energy Outlook 1996, which stated that "[b]y 2015 world energy consumption increases 1.6 times the current level."4 Not surprisingly, the report adds that "[e]lectricity demand is projected to nearly double over the forecast period."5 and "world carbon emissions are projected to exceed 1990 levels by 54 percent (1.54 times)."6
In July 1996, the United Nations Intergovernmental Panel on Climate Change (IPCC) held a meeting in Geneva to discuss the ominous predictions contained within its Second Assessment Report. At that meeting, the United States Undersecretary for Global Affairs, Timothy Wirth, announced that the United States would agree to legally binding
targets for the reduction of greenhouse gas emissions.7 Subsequently, this position "has sent U.S. business groups running for cover."8
Relative to the EIA's latest predictions, the Electric Power Research Institute (EPRI) predicts an even more bullish increase in market share, as recently put forth at the 1993 POWER-GEN conference in Dallas, in which it concluded (along with the following graph), that "[r]eplacement of industrial and residential technologies that directly burn fossil fuels with electrotechnologies will help solve environmental problems."9
Predicted Electrical Energy Use (EPRI)
Considering the overall efficiency of electricity generation and transmission, EPRI's prediction opposes legitimate economic and environmental goals of IRP and DSM, and introduces obvious anticompetitive limitations upon consumer demand-side alternatives. Whether a given "electrotechnology" is superior or inferior to an end-use alternative directly fueled by natural gas requires a comprehensive fuel-cycle analysis, made specific to site and technology. The purpose of such a fuel-cycle analysis (and perhaps IRP itself) can be described as:
A process of comprehensively evaluating all relevant processes that occur between initial extraction, ultimate end-use, and environmental aftermath of energy consumed for the purpose of deriving and comparing the overall efficiency and emissions of energy alternatives.
Fuel-cycle analyses can also provide an appropriate environmental dimension and additional balance for comprehensively determining and comparing total societal costs and benefits of various DSM options. Such methods would "cut to the chase" the quantitative and qualitative differences between least-cost and less-costly energy policy options. However, federal willingness to support or even encourage the development of fuel-cycle analysis methods has proven very limited to date. For purposes of additional illustration, the following table lists the basic components of a fuel-cycle analysis comparing efficiencies electric motors to natural gas-fueled engines for delivering shaft horsepower:
As the fuel-cycle efficiency of end-use alternatives can be readily calculated, so can the associated emissions. Moreover, it is the resultant emissions that should impart the primary focus, not Btu efficiency. In either case, much of the information required to calculate fuel-cycle efficiency and emissions lies in the public record, contained within the FERC's Form 1 data and state emissions inventories.
Any comprehensive and objective fuel-cycle emissions analyses would tend to shift competition away from trade-restraining notions like "buying the business," and toward competition based upon merit (or the lack thereof) for specific end-use technology alternatives to provide society's energy services at the lowest overall cost (including non-monetary environmental costs). Again, using the previous table as an example, the efficiencies of these two-shaft horsepower alternatives appear relatively close. By improving the efficiency of any one segment, the environmental competitiveness gap can be affected by either side at any stage of the fuel cycle. Environmental competition in this manner would provide another form of market-based, least-cost emissions reductions.
For example, the replacement of traditional valve and cam systems with electro-magnetic valve actuators could improve reciprocating engine fuel efficiency by at least 15 percent from optimized combustion and lower friction10 and another 16 percent11 by unloading cylinders according to speed and power requirements. Considering that some 200 million or so reciprocating engines can be found operating in America's cars and trucks, just a one-percent efficiency increase would reduce the nation's greenhouse gases more than any single concept identified in the Clinton/Gore Climate Change Action Plan. Unfortunately, however, federal funding for research and development (R&D) for reciprocating engine technologies is virtually non-existent compared to that for electric utility power plants.
The cumulative effects of such federal R&D spending biases could cause EPRI's growth predictions to become a self-fulfilling prophecy.
"Avoided Cost" Studies: Regulatory Cover for Manipulative Strategies
Given the stated intentions of electric utility DSM and IRP programs to conserve energy and be "at least as profitable as load building,"12 in theory, electric utilities should show indifference towards, "ecowatts," "negawatts," or therms. Again, in theory, improved energy efficiency and/or strategies that reduce peak demand can provide an economical equivalent of capacity by freeing-up actual capacity for other purposes.
For example, more efficient motors or lighting systems can reduce electrical consumption and demand. In addition, motor and lighting loads can be reduced or turned off through various control strategies. Assuming that the incremental cost of adding an incremental Kw of traditional capacity costs $500 and the costs of removing one Kw through efficiency improvements and/or demand reduction costs less than $500, then the latter can be viewed as a superior investment and customer rebates (up to $500) can be rationalized. In fact, many states with formal DSM and IRP programs allow consumer financial incentives to be rate-based (like power plants) or at least expensed. Some states also allow utilities to recover ostensible "lost revenues." The same theory of avoiding power plants through DSM and IRP applies to cogeneration projects, whereby electric utilities must buy excess capacity from "qualified facilities" at their "avoided costs" of capacity and incremental energy. High avoided costs can encourage cogeneration and DSM/ IRP, while low avoided costs would have the opposite effect. Thus, avoided costs provide the primary motive force behind DSM and IRP "energy efficiency" rebates.
Since avoided costs are considerably higher for electric utilities that for natural gas distributors, electric utilities can spend significantly more to increase energy efficiency. Similarly, electric utilities can spend significant amounts, under the guise of energy- and/or demand-reduction programs to increase sales and many have become quite adept at manipulating DSM and IRP policies for this purpose. Thus, in practice, according to a recent DOE-funded study conducted by Oak Ridge National Laboratory, electric utilities are increasingly using DSM to build load.13 Based upon the combination of incentives to build load supplied by monopoly rate-of-return (cost-plus) regulation, along with traditional fiduciary duties of utility management to "grow the business" and an assortment of subsidies to assist them (such as IRS write-offs for DSM), it should have come as no surprise that "valley filling" and "strategic load growth" have become the preferred IRP/DSM load-shape objectives under the guise of energy "efficiency."
To further illustrate these relationships, the following graphs compare the avoided costs for serving a typical gas or electric water heater:14
Figure 2. Avoided Costs
Natural Gas vs. Electricity
Since the vertical axes of the two graphs are based upon different units, the avoided-cost disparities are not readily apparent. However, by simultaneously inverting these values (i.e., energy per unit cost) and using the same units (i.e., Btu/¢), the disparity (in terms of the inverse of avoided costs) becomes much more obvious, as illustrated in the following graph:
Figure 3. Energy Content (Btu/¢)
Natural Gas vs. Electricity
On an equivalent energy basis in the case just illustrated, the avoided energy cost for electric generation is nearly two to three times greater than that for a gas utility.15 The difference between electric utility and gas utility avoided costs appears even more pronounced if new capacity additions are needed. On this basis, avoided electric costs range from four to seven times more than a gas utility needs to serve a similar portion of its load curve.16 Therefore, it stands to reason that for natural gas air conditioning (an offpeak load) versus electric air conditioning (a peak load) such differentials would be greater still. However, avoided costs are not limited to capacity costs; transmission and distribution (T&D) resources can also be avoided. T&D considerations can significantly increase overall avoided costs and may exceed capacity costs.
Some Concrete Examples
The following two graphs illustrate the overall effects of thermal storage based upon electric utility responses to data requests in intervention proceedings:17
Figure 4. Thermal Storage DSM: Energy Use Before & After (Composite Analysis)
Docket 11735, Texas PUC
Figure 5. Thermal Storage DSM:
Billing Demand Before & After
Docket 11735, Texas PUC
As illustrated above, energy consumption and peak summer demand increased instead of decreased as a result of thermal storage approved in the Texas Public Utilities Commission (PUC) docket. It is worth noting that this utility in question later received a national DSM award in recognition of its demand avoidance results for this program. It is also worth noting that thermal storage is being touted as the large-tonnage cooling method of choice for dealing with the resultant complexities of real-time pricing in a restructured electric utility environment. Unfortunately, offpeak thermal storage programs make up only one of many ways that electric utilities have thwarted conservation under the guise of DSM and IRP.
Moving to the residential sector, some areas within Texas subject to a decade of electric utility DSM programs have shown that the overall proportion of Texas households with electric space heating increased by over 40 percent, but decreased proportionately for natural gas. This trend was reported by a recent study through the Texas Railroad Commission.18 Also analyzed were life-cycle emissions and consumer operating costs that significantly increased as a result of the vast majority of electric utility DSM programs investigated within this study. It is important to recognize that the initial DSM/IRP enabling legislation in Texas called for the "conservation of resources" and most electric utilities in Texas quickly adopted the notion that "valley filling" and "strategic load growth" qualified as "conservation" through improved use of power plant "resources."
DSM and IRP: The Weakness
in the Total Resource Cost Test
DSM and IRP programs are supposed to follow concise regulatory guidelines and goals with the stated overall objective of
minimizing the present value of a
utility's long-run revenue requirements (or something similar). These guidelines require passing proscribed cost-effectiveness tests. Such tests are usually based upon "California Standard Practices," with perhaps the most widely adopted one being the Total Resource Cost Test (TRC). However, according to the Tellus Institute,19 natural gas utilities are frequently put at a further disadvantage if commission-approved DSM or IRP programs are allowed to ignore benefit/cost test standards that clearly call for including the diseconomies imposed upon the "fuel not chosen."20
The California Standard Practice Manual provides guidance for identifying the differences between conservation and load-building.21 Translated simply, the legitimate cost-effectiveness of utility DSM and IRP programs requires including those diseconomies imposed upon alternative energy providers (and their customers) to comply with these standards. For example, all propane and natural gas customers are also customers of an electric utility. Thus, it makes no sense (from the customer's perspective) to transfer money from one pocket to another, especially if funds are lost in the process. Including these diseconomies in benefit/cost tests provides important safeguards against these problems. However, some regulators seem to believe that "modifying" such requirements to ignore the diseconomies imposed upon alternative energy service providers and their
customers promotes "vigorous competition" that benefits consumers. In many cases, gas utilities have been categorically denied the ability to use avoided costs as incentive mechanisms (however minor they may be in comparison to those of electric utilities) since commission-approved DSM or IRP programs for natural gas simply do not exist. Therefore, the mathematical avoided-cost difference between gas and electricity can be viewed as infinite.
Load-building programs can be easily disguised to appear marginally cost-effective despite highly tenuous underlying assumptions, such as the "fundamental assumption that the program is targeted exclusively to segments of the residential new construction market that have chosen electric space heating."22 Accompanying benefit/ cost analyses are easily manipulated to attain a ratio greater than one (thereby deemed cost-effective and subsequently approved). Considering that many of these programs barely pass the primary cost-effectiveness tests as proposed and approved, subjecting them to the diseconomies imposed upon the "fuel not chosen," eliminating IRS write-offs, emissions reductions benefits, and a host of other highly sensitive statistical inputs for such models could easily cause such programs to fail these tests; in most cases, miserably.23 The primary strategy used by electric utilities to conceal these variables takes shape in the form of filings that are too heavy to lift, let alone read, and which are based upon complex, proprietary models requiring immense levels of expertise through specialized training and "consultants."
With relatively limited staffs and budgets, natural gas utilities intervene against such programs at great cost. They have also encountered difficulty in getting regulators to understand these complexities. Once final rulings are issued and electric utility DSM/IRP programs approved, "state action" doctrines may then effectively bar natural gas utilities from further civil recourse.
Mitigating Stranded Investment: Electric Marketing Through the Back Door
The FERC's electric utility restructuring "mega-NOPR" includes a nebulous expectation that electric utilities mitigate potential "stranded investments" through "marketing."24 According to John Anderson of the Electricity Consumers Resource Council (ELCON), FERC Order 888 "permits utilities to recover 100 percent of their uneconomic costs."25 These costs will be recovered through "exit fees" that can include far more than what was traditionally considered in calculating avoided costs (i.e., DSM, IRP, or deriving power purchases from cogeneration "qualifying facilities"). In addition to DSM/IRP investments, "exit fees" can include charges for nuclear decommissioning, retirement plans, and a virtually endless stream of other "prudent expenses."
The economic magnitude of exit fees can easily thwart competition (em either on the supply-side
of alternative electric service providers or on the demand-side as an alternative to electricity. While the concept of exit fees was envisioned to address situations in which an electrical consumer desires to switch electrical suppliers, thus "stranding" a "good faith" investment in the initial generating capacity, the concept has also been used by electric utilities to stifle competition by dissuading consumers from using nonelectric end-use alternatives and/or cogeneration A case in point is that of the ill-fated cogeneration project at the Massachusetts Institute of Technology. In theory, at least, such manipulative practices could be extended to preclude consumers from replacing any electrically powered appliance in favor of any end-use alternative fueled by natural gas.
The EPAct Mandates: A Few Workshops, but No Follow-through
The 1992 Federal Energy Policy Act26 (EPAct) presented a mixed bag for the electric utility industry. It clearly advocated that energy conservation should be at least as profitable as load-building,27 and it introduced the potential for new competitors in the form of "exempt wholesale generators" (EWGs).28 Without actually using the terminology of "environmental externalities," certain passages within this law (em namely, Title XVI (em also called for evaluating "all costs of production, transportation, distribution, and utilization" of energy.29 Assuming that the key word is all, this is no minor consideration given the growing understanding of the environmental impacts of energy production.30 However, relatively little if any progress has been made in this particular area of the EPAct.
Another EPAct requirement for electric utilities only calls for a joint report from the DOE and the Federal Trade Commission to the
President and Congress by October 24, 1994, that analyzes "whether any unfair, deceptive, or predatory acts exist, or are likely to exist, from implementation of such [electric utility IRP] programs."31 This study was published March 1995 by DOE's Office of Utility Technologies (OUT), as chapter 6 of a larger report. This chapter, entitled "Small Business Impacts," essentially limited its anticompetitive issues and discussion to the long-term animosities that exist between independent HVAC contractors and some utilities that have traditionally sold and serviced HVAC equipment.32 Virtually nothing was discussed about the anticompetitive effects of widespread "electrotechnology" promotional efforts under the guise of IRP, in spite of the fact that natural gas and propane trade organizations (which are almost all small businesses) commented extensively on such issues prior to this report.33 In fact, the Office of Utility Technologies (OUT) specifically requested comments through the Federal Register,34 and stated that the report relied upon those comments.35
Administration of DOE's DSM and IRP programs is the responsibility of OUT; whose mission statement follows:
"The Office of Utility Technologies leads the federal government's efforts to help America's electric power producers develop clean, renewable, and more economical forms of energy."36
The only noteworthy involvement that OUT had with the
natural gas industry was a one-time workshop, co-funded by the Gas Research Institute (GRI), for the purpose of assessing the largely academic status of fuel-cycle analysis models.37 The Edison Electric Institute (EEI) apparently assumed that the purpose of this workshop was to better quantify environmental externalities; this confusion reduced the productivity of the workshop. However, the general consensus of the workshop "clearly stated that there is a need for an analytical method to perform full and consistent comparisons of energy conversion technologies throughout the total fuel cycle of an energy resource"38 and recommended that DOE consider the following activities:39
s Establish a fuel-cycle-assessment focus group
s Conduct an assessment of alternative total-fuel-cycle analysis approaches
s Further analyze the models presented at the workshop
s Identify/develop data elements to support total-fuel-cycle analysis.
Apparently, the effects of this workshop continued to be misconstrued as advocating the issue of environmental externalities. Around the time of DOE's well-publicized congressional funding problems, certain individuals close to OUT's programs explained that EEI had stated its intention to influence congressional budget cuts if OUT pursued anything even remotely associated with environmental externalities. OUT then attempted to restructure its IRP program into a new "competitive resource strategies" program. Apparently, OUT's efforts proved too little too late, as the budget for IRP was still eliminated. However, it is expected that this successor to IRP will continue to be funded through "reallocations." DOE is also reported to be considering offering its services to the electric utility industry for a fee.
The Texas Solution:
Competitive Bidding Among All Sources
Texas provides a much better example of how DSM, IRP, and competition may be integrated. Final IRP rules were recently adopted by the Texas PUC that effectively call for "exhausting all cost-effective alternatives to power-plant certification because that will lower costs to consumers."40 The theoretical cornerstone of IRP in Texas is all-source bidding for least-cost energy services. The IRP rules state: "Nothing in the integrated planning progress shall inhibit the development of competitive markets for electric power or energy services"41 Further: "The commission believes that IRP will foster and compliment the development of competitive markets."42 However (up to this point), the term "all-source" has primarily been interpreted as some sources (i.e., "electrotechnologies") and "least-cost" has primarily been interpreted as perhaps a little less costly (at best). Consequently, the PUC has voiced the following concerns:
s "[L]imited retail competition ... occurs among electric utilities and the suppliers of natural gas and propane fuels."43
s "[M]onopoly electric utilities may use revenues from one sector of their operations to subsidize activities in partially competitive markets."44
s "[E]lectric utilities may use customer information acquired in their role as monopoly electric service providers to prepare a competitive bid."45
s "DSM practices may inhibit energy-service markets and may result in subsidies not intended by the societal objectives of energy efficiency and the conservation of resources."46
In essence, the Texas PUC recognized past mistakes in "interfering in the energy services sector" through approval of "regulations that allow utilities to exclude the bids of competitors at the utilities' sole discretion." It acknowledged that such regulations "are subject to abuse."47 Consequently, regulatory language contained within revisions of the Texas Public Utilities Regulatory Act (PURA) recently affirmed by the Texas PUC attempts to undertake the difficult process of moving all and least closer to their clear meaning. These words also convey a challenge with regard to the level of accomplishment expected toward reaching these goals.
Specifically, electric utilities now have the burden of proof for ruling out all alternatives (em i.e., all-source competitive bidding (em before constructing additional power plants. Comprehensive energy-service contracts derived through integrated energy audits of commercial and industrial customers could provide the basis of such bids. Conceptually, quick payback energy conservation, such as lighting improvements, would be bundled with more capital intensive applications, such as cogeneration or gas cooling, to bid against other demand-side and supply-side alternatives. However, electric utilities already appear to be thwarting such opportunities through recently proposed mergers with their natural gas competitors (em namely, TU Electric's proposed merger with Enserch (hence, Dallas-based Lone Star Gas) and Houston Lighting & Power's proposed merger with NorAm (hence, Houston-based Entex). Respectively, Lone Star and Entex represent the first- and second-largest natural gas utilities in Texas and provide service to the majority of the state's natural gas consumers.
Back to Reality: Some Final Thoughts
According to the "general principle" for restructuring the electric industry, as announced by the National Association of Regulatory Utility Commissioners48 (NARUC), "consumers should have access to adequate, safe, reliable, and efficient energy services at fair and reasonable prices at the lowest long-term cost to society. Structural changes in the [electric] industry should be encouraged when they result in improved
economic efficiency and serve the broader public interests."
However, in the words of one veteran of gas-versus-electric DSM/IRP,49 "conservation incentives can be distorted to provide promotional funding for improved-efficiency electric appliances that are still inferior to certain gas appliance options, which are not receiving support. Many electric utilities are now comfortable and familiar enough with these policies to try manipulating them."
Accordingly: "The line has to be drawn when the utility's plan for what it calls 'competition' perpetuates the monopoly powers that can be used to thwart true competition."50 Unfortunately, the overall preponderance of evidence does not frequently indicate a regulatory willingness to draw such lines.
The major regulatory challenge to ensure that diverse energy alternatives fairly compete on both the supply and demand side is the impartial development and refereeing of what has so far been an elusive level playing field. Ultimately, however, the natural gas utility industry and its trade associations must also rise to this occasion. Similar conclusions were reached in December 1992 in a National Petroleum Council (NPC) report requested by DOE, The Potential for Natural Gas in the United States:
"The gas industry's challenge for technology development and commercialization involves continued funding by the producing segment of the industry, increased incentives for investing in technology by the regulated segments, and justification for investment in commercialization of end-use technologies. Also, the low level of federal government spending on gas-related technologies, relative to other energy sources, suggests a need to reexamine the potential benefits of investments in this segment, particularly in light of evidence that natural gas is an abundant natural resource with superior environmental qualities."
Hopefully, this discussion has helped to identify some of the issues that need to be reexamined to increase, rather than decrease, competitive alternatives. t
Mark Krebs is director of market planning at Laclede Gas Co., St. Louis., MO, and chairman of the American Gas Cooling Center's education committee.
Considering that some 200 million or so reciprocating engines can be found operating in America's cars and trucks, just a one-percent efficiency increase would reduce the nation's greenhouse gases more than any single concept identified in the Clinton/Gore Climate Change Action Plan.
Unfortunately, federal funding for R&D for reciprocating engine technologies is virtually non-existent compared to that for electric utility power plants.
In theory, electric utilities should show indifference towards, "ecowatts," "negawatts," or therms.
Since avoided costs are considerably higher for electric utilities than for gas distributors, electric utilities can spend significantly more to increase energy efficiency.
According to a recent DOE funded study conducted by Oak Ridge National Laboratory sponsored by DOE, electric utilities are increasingly using DSM to build load.
"Valley filling" and "strategic load growth" have become the preferred IRP/DSM load shape objectives under the guise of energy "efficiency."
Gas utilities have been denied the chance to use avoided costs as incentive mechanisms, however minor they may be in comparison to electric utilities, since regulatory approved "DSM" or "IRP" programs for natural gas simply do not exist.
Articles found on this page are available to Internet subscribers only. For more information about obtaining a username and password, please call our Customer Service Department at 1-800-368-5001.