A pledge by Mercedes-Benz to give U.S. dealers a 10-year moratorium on making facility changes is unusual.
Mercedes-Benz dealers, once they’ve updated their stores to the brand’s second-generation Autohaus image standards, won’t be required to make more changes to their dealerships until January 2024 at the earliest.
The pledge, announced this year to the Mercedes dealer network, is unusual. It follows the contentious launch of the original Autohaus standards in 2008. That initiative kicked off a period of tension in which dealers of many brands objected loudly to automakers’ demands for dealership image changes.
Work on the 2024 pledge was initiated under former Mercedes-Benz USA CEO Steve Cannon, who left the company at the end of 2015. But the brand’s current U.S. chief says he’s fully behind it.
“It was the right thing to do,” Dietmar Exler told Automotive News. “There is no backtracking from that. We’ve made a commitment to the dealers.”
The reasoning for the 2024 timing is that the first dealerships to convert to the second-generation standard, also referred to as Autohaus2 or Autohaus Black, launched in early 2014, Mercedes spokeswoman Donna Boland said. The intent is to provide a 10-year cushion.
Most of Mercedes’ 379 dealerships have yet to complete Autohaus2. Dealers were required to submit renovation plans to the company by last Sept. 30. Work is to be completed by June 30, 2018.
With the move, Mercedes takes a kinder, gentler approach to dealership image standards. The brand’s dealers generally applaud the move. They also note that Mercedes was bound to certain time restrictions in some states because of a wave of franchise law changes that passed this decade.
“Mercedes hit the sweet spot,” said Jeff Aiosa, a Mercedes dealer in New London, Conn., and the brand’s line representative for the National Automobile Dealers Association. “Ten years is a good number for the state statutes across the country.”
The Alliance of Automobile Manufacturers estimates that 13 states have passed seven- or 10-year limits on how often manufacturers can demand dealership updates. At least one state, New Hampshire, has a 15-year provision.
It’s a common issue in state franchise law fights, alliance spokesman Dan Gage said. The alliance would prefer no time limit, he added. If one is inevitable, the automakers favor seven years “but have accepted 10 years in state-specific negotiations.”
Though the law in many states spells out a minimum period between dealership updates, automakers rarely provide them unless required, dealership experts said.
Dealer lawyer Mike Charapp of McLean, Va., called the Mercedes move unusual but not surprising.
Here are key dates and details in the Autohaus image standards for Mercedes-Benz dealers.
- Autohaus launch: Jan. 1, 2008
- Autohaus original program end: Dec. 31, 2010
- Cost for original program: $1.4 billion total spending from dealer network
- First Autohaus2 dealerships launched: Early 2014
- Deadline to submit Autohaus2 plans: Sept. 30, 2016
- Deadline to complete Autohaus2: June 30, 2018
- Estimated average cost to complete Autohaus2: Undisclosed but less than for original
- Earliest changes would be required beyond Autohaus2: January 2024
Source: Mercedes-Benz USA, dealers, Automotive News archives
Some dealers who were late finishing the first round of Autohaus improvements likely come under the protection of the updated state statutes. In 2011, Virginia, for instance, adopted a 10-year provision.
“The commitment is probably part of the sales effort by MBUSA for dealers who can claim state law protections by giving them comfort if they go along with the latest plan,” Charapp said.
Mercedes didn’t get such buy-in during the first iteration of Autohaus.
Many dealers objected, saying it would require them to raze perfectly fine, even luxurious, facilities at a cost of many millions of dollars. Some had only recently completed expensive new dealerships or expansions, but their updates didn’t fit the sleek, contemporary styling prescribed by Autohaus. That the timing coincided with the dramatic falloff of auto sales during the Great Recession compounded dealer worries.
Sonic Automotive Inc. even filed a lawsuit in 2008 against Mercedes over the demands before settling with the company in 2012.
The exact costs for the original Autohaus are unclear. Mercedes says its dealers put a total of $1.4 billion into facilities as part of the program, and previous estimates in Automotive News put the per-dealership cost at $4.7 million for the roughly 300 stores that had agreed to renovations at that time. Boland, the Mercedes spokeswoman, said that per-store figure isn’t a good number but declined to provide an updated figure.
Today, five or six dealerships haven’t upgraded to the original Autohaus look, Exler said. He described them as small stores in rural locations that may be dualed with other brands. “It’s a tough economic case” for those dealerships to spend the money, he said.
Regardless of the earlier cost, Autohaus2 won’t be on the same scale, Boland said. For many stores that were updated to Autohaus, it means changing out paint and carpet and refinishing some furniture. “For others, it is more substantial, but overall, we expect much less investment necessary from the network,” Boland said.
Support from dealers
Mercedes proposed the Autohaus2 changes this decade but put a required update on hold for U.S. dealers even as Mercedes dealers in other countries were asked to move to the design earlier.
Dealer Paul Walser, who last year acquired Mercedes-Benz of Wichita in Kansas, praised the 10-year pledge by Mercedes. “That’s a fair time frame,” said Walser. His Wichita store moved to a new Autohaus facility in late 2013.
The Mercedes-Benz Dealer Board supports the 10-year pledge.
“Dealership facilities have gotten terribly expensive in the last 10 or 15 years,” said Ken Schnitzer, a Texas dealer with four Mercedes stores and chairman of the dealer board. “It’s impractical to ask dealers to renovate their facilities in any time frame less than 10 years.”
FERC v. Invisible Hand:
The Evolution from Cost- to Market-Based Rates
Federal Energy Regulation Fall 2004
Martin Boyle Joseph Tino Craig Thrift
Traditionally, the Federal Energy Regulatory Commission (“FERC” or “Commission”) used a cost-of-service standard to approve and set the rates at which electric utilities could sell wholesale electricity. In general, a cost-based rate (“CBR”) is a rate established according to a cost-of-service standard. CBRs were the dominant rate structure for the electric utility industry for over fifty years. Within the past two decades, however, the Commission and the industry have shifted away from the traditional CBR regime toward a less regulated structure in which the market itself determines rates. As explained below, the recent shift from CBRs to market-based rates (“MBRs”) resulted from various forces and events that exposed the weaknesses of traditional cost-of-service standards.
Part I of this paper discusses the history, development, and changing structure of government regulation in the electric industry. Specifically, in the context of ratemaking, it examines the traditional cost-of-service standard, the FERC’s interpretation of the “just and reasonable” standard for CBRs and MBRs, and the forces behind the recent industry shift in rate structure. Part II outlines and explains the initial tests that the FERC adopted to determine whether an entity would be authorized to charge market-based rates. These original tests hinged on a company’s generation and transmission market power, the potential for erecting barriers to market entry, and preventing affiliate abuse or reciprocal dealing. Finally, Part III examines subsequent FERC market power tests that evolved as the industry structure changed. Part III focuses on the Supply Margin Assessment screen, the creation of regional transmission organizations and independent system operators, Order No. 2000, and the new market power test employed by the FERC.
I. An Overview of Federal Regulation of Electric Utility Rates and Analysis of the “Just and Reasonable” Standard of Sections 205 and 206 of the FPA
Part I examines the history, application, and eventual disfavor of CBRs in the wholesale electric industry. First, it explains the historical use of traditional cost-of- service standards in state and federal ratemaking. Second, it sets out the components of the cost-of-service rate formula and discusses how the FERC uses the formula to establish cost-based rates. Third, it describes the “just and reasonable” 1 (“J&R”) standard and how this standard affects the FERC’s ratemaking authority. Finally, it outlines what factors caused the shift away from CBRs, and it discusses how the Commission and courts synchronized MBRs with the “just and reasonable” standard. In essence, Part I lays the foundation for a meaningful comparison of traditional cost-based standards with new methods of market-based pricing.2
A. The History and Development of Federal Regulation of Electric Utility Rates
Soon after electricity was first generated and distributed in the 1880s, the electric industry rapidly developed into an unregulated competitive market. Electric utilities proliferated and, as a result of the new and competitive market, innovations in technology led to larger integrated utilities, higher output, and lower costs to consumers. By the late 1920s, however, the industry was consolidated, and a small number of large electric utility holding companies controlled the vast majority of the nation’s electric industry.3 Stock manipulation and similar abuses were widespread within these unregulated utility holding companies. In addition to initially creating higher prices for consumers, these corporate abuses facilitated the eventual market failure of the industry. Coupled with the
1 16 U.S.C. 824d(a) (2004).
2 See generally Appendix A, infra, and accompanying notes.
3 Douglas W. Hawes, Utility Holding Companies § 2.03 (1987).
stock market crash of 1929, the unregulated electricity market failure spawned a traditional system of pervasive government regulation of the electric industry.4
Initially, many states began to regulate the utilities’ intrastate electricity sales and transmission, and they established retail rates to protect local consumers from excessive prices. State regulation of retail sales was relatively successful and secured the public a stable supply of electricity at reasonable rates. In return, the public utility commissions set rates that allowed utilities to recover all operating costs and provided the opportunity to earn a reasonable rate of return. In exchange for an exclusive service area within the state, a utility assumed an obligation to serve every person in that area. Under this “regulatory compact,”5 the electric industry was essentially transformed into a regulated natural monopoly.6 The government established the rates the utility could charge customers. The rates allowed the utility an opportunity to earn a reasonable return on its prudent capital investment.7 This traditional cost-of-service rate formula incorporated a utility’s costs plus a reasonable rate of return. For the most part state regulation succeeded, and the newly regulated electric industry began to recover.
A jurisdictional gap between the state and federal governments was soon exploited by the utilities in an attempt to avoid regulation and earn higher profits. The Attleboro Gap8, as it came to be known, allowed utilities to charge unregulated rates for
electricity sold or transmitted interstate. In Attleboro, the United States Supreme Court
held that the interstate commerce clause precluded states from regulating interstate
4 Joseph P. Tomain, Electricity Restructuring: A Case Study for Government Regulation, 33 Tulsa L.J. 827, 830 (1998).
5 Id. at 833-34.
7 Id.at 832.
8 Pub. Util. Comm’n of R.I. v. Attleboro Steam & Elec. Co., 273 U.S. 83 (1927).
electricity sales and transmission.9 Because no federal regulation was then in place, and states were confined to intrastate retail sales, this jurisdictional gap permitted unregulated interstate transactions.
Partly as a response to the Attleboro Gap, and amid growing public outcry against utility abuses,10 the federal government became more involved in regulating the electric industry with the passage of Part II of the Federal Power Act of 193511 (“FPA”). The FPA gave the Federal Power Commission authority to regulate interstate transmission and sales of wholesale electricity. Most importantly, it granted the Federal Power Commission ratemaking authority. Similar to state regulation, federal ratemaking also followed the traditional “regulatory compact” structure. The Federal Power Commission, which was reorganized as the Federal Energy Regulatory Commission in 1977,12 adopted the traditional cost-of-service standard that state regulators applied in ratemaking proceedings.
During the mid-1960s, following the “golden age”13 of the flourishing regulated electric industry, the regulatory structure that had previously stabilized the industry began to backfire. Within the federal and state regulatory structure, technological advances slowed, economies of scale flattened, and the cost of doing business increased.14
10 Congress passed the Public Utility Holding Company Act of 1935 (“PUHCA”), 15 U.S.C. § 79 (2004), in an attempt to remedy the rampant corporate corruption among large, intricately structured utility holding companies. Passed concomitantly with the FPA, PUHCA delegated federal authority over public utility holding companies to the Securities and Exchange Commission (“SEC”). PUHCA required every holding company – a company controlling 10% or more of the voting securities of a public utility – to register with the SEC. Under PUHCA, the SEC could regulate a utility holding company’s sale or issuance of securities, and the SEC had authority to examine and simplify the organizational structure of the company.
11 16 U.S.C. § 824-824m (2004); Joseph P. Tomain & Richard D. Cudahy, Energy Law 267 (West 2004).
12 History of FERC, at https://www.ferc.gov/students/whatisferc/history.htm (last visited Nov. 8, 2004).
13 Leonard S. Hyman, Andrew S. Hyman, & Robert C. Hyman, America’s Electric Utilities: Past, Present and Future, ch. 18 (7th ed. 2000).
14 Joseph P. Tomain, Electricity Restructuring: A Case Study for Government Regulation, 33 Tulsa L.J.
Professor Joseph Tomain aptly described the devastating economic and political effects of this period of destabilization in the following passage:
In economic terms, starting approximately in 1965, the marginal costs for a utility began to exceed its average costs resulting in a profitability squeeze. This economic situation is disastrous for a regulated firm whose earnings are calculated on prudently incurred historic costs. The traditional rate formula is based on historic (average) costs. As a firm continues to take advantage of economies of scale, its average costs decline and the firm can expand its capital investment, thus earning a reasonable rate of return on that investment. However, increasing marginal costs mean lower profits for utilities; and those profits will continue to decline until rates are set at marginal cost. One consequence of the traditional rate formula encouraging capital investment was plant expansion because returns were calculated on capital investment. Unfortunately, just as microeconomic theory predicts, increased costs bring higher prices and higher prices mean declining demand. In other words, the traditional rate formula contributed to excess capacity as utilities over-invested in new plants, especially nuclear power plants.
During this period, utilities, with the rest of the economy, faced inflation, rising labor costs, the collapse of the nuclear power industry and the OPEC and Iranian Oil Embargoes. These economic indicators put great pressure on utilities to raise prices at unprecedented rates, causing rate shock among consumers and dramatic political repercussions in state regulatory commissions. Rising prices also revealed that there was more price elasticity of demand for electricity than previously assumed. As utilities overexpanded and tried to capture their high fixed costs, electricity rates rose and consumers, contrary to expectations, consumed less electricity than predicted.15
Coincidentally, in an effort to decrease American dependency on foreign sources of energy and increase domestic energy conservation, Congress passed the Public Utility
827, 833 (1998).
15 Id. at 833-34 (citations and footnotes omitted).
Regulatory Practices Act of 197816 (“PURPA”). An unanticipated result of PURPA was the introduction of a new class of independent electricity producers, or “qualifying facilities”17 (“QFs”), which were exempt from many of the stringent regulations of the FPA18 and PUHCA.19 QFs consisted of small power production facilities20 and cogeneration facilities21, each of which had to meet certain criteria in order to qualify for the exemptions.22
To further promote these independent sources of generation, the FERC required local public utilities to purchase excess power from QFs at a “full avoided cost” rate.23 The “avoided cost” rate is essentially marginal cost; it is the rate at which a utility would have to purchase additional power from a non-QF generator, or the utility’s cost of self- generating the additional power.24 PURPA’s introduction of new independent energy generators led to a proliferation of QFs because they potentially allowed investors a higher return on their investment, and also provided incentives for new companies to enter the market. Most importantly, however, PURPA set the stage for the eventual shift
16 16 U.S.C. § 824a-3(h) (2004).
17 18 C.F.R. § 292.101(b)(1) (2004) (“Qualifying facility means a cogeneration facility or a small power production facility that is a qualifying facility under Subpart B of this part.”).
18 18 C.F.R. § 292.601(c) (2004) (“Any qualifying facility…shall be exempt from all sections of the Federal Power Act, except: (1) Section (sic) 1-18, and 21-30; (2) Sections 202(c), 210, 211, 212, 213, and 214; (3) Sections 305(c); and (4) Any necessary enforcement provision of Part III with regard to the sections listed in paragraphs (c)(1), (2) and (3) of this section.”).
19 18 C.F.R. § 292.602(b) (2004) (“A qualifying facility…shall not be considered to be an ‘electric utility company’ as defined in section 2(a)(3) of the Public Utility Holding Company Act of 1935.”).
20 16 U.S.C. § 796(17)(A) (2004) (“”small power production facility” means a facility which is an eligible solar, wind, waste, or geothermal facility, or a facility which– (i) produces electric energy solely by the use, as a primary energy source, of biomass, waste, renewable resources, geothermal resources, or any combination thereof; and (ii) has a power production capacity which, together with any other facilities located at the same site (as determined by the Commission), is not greater than 80 megawatts;”).
21 18 C.F.R. § 292.202(c) (2004) (“Cogeneration facility means equipment used to produce electric energy and forms of useful thermal energy (such as heat or steam), used for industrial, commercial, heating, or cooling purposes, through the sequential use of energy;”); see also 16 U.S.C. § 796(18)(A) (2004).
22 See 18 C.F.R. § 292.203-.206 (2004).
23 See Am. Paper Inst., Inc. v. Am. Elec. Power Serv. Corp., 461 U.S. 402, 416-417 (1983).
24 18 C.F.R. § 292.101(b)(6) (2004) (“Avoided costs means the incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source.”).
towards competitive market-based rates.
The Energy Policy Act of 199225 (“EPAct”) is the final piece of federal legislation that set the stage for the shift to MBRs. In passing the EPAct, Congress made clear its support of and attraction toward establishing a competitive market for wholesale electricity. In fact, the legislative history of the EPAct highlights Congress’s desire to restructure the industry.26 As parts II and II of this paper will explain, the resulting industry shift towards MBRs and away from the traditional CBR standard occurred rapidly and continues to evolve even today. Before in-depth discussion of these changes, however, it is first necessary to analyze the traditional cost-of-service standard used for cost-based ratemaking.
B. The Traditional Cost-of-Service Standard
For fifty years or so following the passage of the FPA, and before the industry began serious reconstruction efforts in the late-1980s, cost-of-service standards were the generally accepted methodology for regulating the rates charged by both publicly and privately owned utilities.27 The standard cost-based ratemaking formula can be set forth as the following equation:
R = O + (B × r)
“R” represents the utility’s allowed revenue requirement, which is the total
25 Energy Policy Act of 1992, Pub. L. No. 102-486, 106 Stat. 2776 (1992).
26 Patrick J. McCormick III & Sean B. Cunningham, The Requirements of the “Just and Reasonable” Standard: Legal Bases for Reform of Electric Transmission Rates, 21 Energy L.J. 389, 392-394 (2000) (“This approach is also consistent with the legislative history of EPAct, which nevertheless did not expressly authorize MBRs. According to Senator Wallop, market-based rates in certain cases will fall within the zone of reasonableness: “In cases where the relevant market for delivered bulk power is competitive, the market price will best reflect the true value of the use of facilities and promote the economically efficient allocation of resources.” 138 Cong. Rec. S17,566, S17,618 (daily ed. Oct. 8, 1992) (statement of Sen. Wallop).).
27 See J. Bonbright, Principles of Public Utility Rates 67 (1961).
amount of money the utility is allowed to earn.28 “O” is the utility’s total operating expenses. “B” equals the rate base, or capital investment, which is the net amount of capital invested by a utility.29 “r” equals the rate of return a utility is allowed to earn on its net capital investment (i.e., the rate base).30 Figure 1,31 seen below, illustrates how regulators might use a typical CBR formula to calculate a utility’s rates:
Example of a Simple Utility Cost-of-Service Formula
O – Operating Costs $100,000,000 (Includes power, operating, maintenance, administrative, transmission & distribution costs)
B – Rate Base $30,000,000
(Book value of depreciated value of assets; i.e., gross value of assets – accrued depreciation)
r – Allowed Rate of Return on Investment 11%
” Return on Investment $3,300,000
R – Total Utility Revenue Requirement $103,300,000
÷ Test Year Sales 1,000,000,000 kWh
= Cost-Based Rate 10.33¢ per kWh, or $103.3 per MWh
Operating costs typically comprise the largest part of the revenue requirement and include all operating expenses such as labor, supplies, maintenance, and taxes. In establishing the total amount of operating expenses, the FERC must determine which items should be allowed as expenses and, in turn, what value should be assigned to each
28 Richard J. Pierce, The Regulatory Treatment of Mistakes in Retrospect: Canceled Plants and Excess Capacity, 132 U. Pa. L. Rev. 497, 511 (1984).
29 Joseph P. Tomain & Richard D. Cudahy, Energy Law 130 (West 2004).
31 Matthew H. Brown & Richard P. Sedano, A Comprehensive View of U.S. Electric Restructuring with Policy Options for the Future, Electric Industry Restructuring Series, National Council on Electricity Policy, at https://www.ncouncil.org/restruc.pdf (June 2003) (modified version of example in original).
expense item.32 The rate base is calculated by deducting the utility’s accrued depreciation from the gross value of the utility’s tangible and intangible property.33 The rate base is crucial for the profitability of a utility because it is the variable against which the rate of return is measured.34 In valuing a utility’s rate base, the FERC must overcome tremendous practical and methodological difficulties; however, determining the proper rate and amount of return on the utility’s investment may be an even greater challenge, as both a matter of policy and economics.35
When the FERC finally values the rate base and fixes a rate of return, it multiplies these two figures to calculate the utility’s expected return on its capital investment. Next, the Commission adds operating costs to the estimated return to yield the utility’s total allowed revenue requirement. Finally, the FERC divides the revenue requirement by the volume of electricity sold during the applicable test year – generally the previous year’s sales – to set the rate at which the utility may charge its customers for electricity. From the inception of federal regulation until the mid-1980s, the FERC consistently employed this standard cost-of-service formula to establish CBRs for utilities engaged in interstate sales of wholesale electricity.
C. Just and Reasonable Rates: Sections 205 & 206 of the Federal Power Act of 1935
Part II of the Federal Power Act of 193536 contains the statutory guidelines for federal regulation of electric utility companies that are engaged in interstate commerce. Section 205 of the FPA requires that the rates set for sales of wholesale electric energy
32 Joseph P. Tomain & Richard D. Cudahy, Energy Law 131 (West 2004).
33 Id. at 130.
35 Patrick J. McCormick III & Sean B. Cunningham, The Requirements of the “Just and Reasonable” Standard: Legal Bases for Reform of Electric Transmission Rates, 21 Energy L.J. 389, 424 (2000). 36 16 U.S.C. §§ 824-824m (2004).
must be “just and reasonable”37 and cannot be “unduly discriminatory or preferential.”38 Section 206 authorizes the FERC to determine whether a proposed rate is just and reasonable and, if it is not, to fix the rate itself.39 The J&R requirement protects the public’s interest by prohibiting excessive rates, while also guaranteeing regulated utilities an opportunity to recover the cost of prudently invested capital plus a reasonable return on that investment.40 This careful balancing of competing consumer and utility interests represents the FERC’s essential duty under both the regulatory compact and the Constitution.
As discussed above, the Commission traditionally approved rates as J&R based on the supplier’s cost-of-service. However, the FPA does not limit the FERC to cost- based methodologies. In interpreting Sections 205 and 206, the United States Supreme Court has granted the FERC broad discretion in choosing an appropriate methodology to guarantee J&R rates,41 and the courts have generally deferred to the FERC’s reasonable choice of ratemaking methods.42 Accordingly, FERC has wide discretion to consider a variety of factors when it determines whether a rate is just and reasonable.43
The FPA’s “just and reasonable” standard was created as a result of early
37 16 U.S.C. § 824d(a) (2004) (“All rates and charges made, demanded, or received by any public utility for or in connection with the transmission or sale of electric energy subject to the jurisdiction of the Commission… shall be just and reasonable, and any such rate or charge that is not just and reasonable is hereby declared to be unlawful.”).
38 16 U.S.C. § 824d(b) (2004) (“No public utility shall…(1) make or grant any undue preference or advantage to any person or subject any person to any undue prejudice or disadvantage, or (2) maintain any unreasonable difference in rates, charges, service, facilities, or in any other respect, either as between localities or as between classes of service.”).
39 16 U.S.C. § 824e(a) (2004) (“Whenever the Commission [determines that a rate or charge is]…unjust, unreasonable, unduly discriminatory or preferential, the Commission shall determine the just and reasonable rate, charge, classification, rule, regulation, practice, or contract to be thereafter observed and in force, and shall fix the same by order.”).
40 Michael J. Gergen, George D. Cannon, Jr., & David G. Tewksbury, Market-Based Ratemaking and the Western Energy Crisis of 2000 and 2001, 24 Energy L.J. 321, 322-331 (2003).
42 Louisville Gas & Elec. Co., 62 FERC P 61016, 61143-61144 (1993).
questions over the constitutionality of regulating a utility’s rates.44 Under the Fifth Amendment, the government may not take private property for public use without providing “just compensation.”45 The FERC may violate the Takings Clause of the Fifth Amendment, applicable to the states under the Fourteenth Amendment, if the rate it sets does not give the utility just compensation for the public use of its private property.46 In the context of ratemaking, at least since the Railroad Commission Cases,47 the United
States Supreme Court has held that public utilities have a constitutional right to earn a reasonable rate of return; that is, the government must allow a regulated utility to earn a reasonable return on its capital investment because an unreasonably low rate would cause an unconstitutional taking of the utility owners’ property without just compensation.48 Accordingly, the FPA’s just and reasonable standard for utility rates is the progeny of the constitutional requirements of “just compensation” and a “reasonable rate of return.”
(i) The “Fair Value” or “Present Value” Standard
Both courts and agencies have faced the persistent and contentious issue of precisely which capital investments or expense items a regulator must include when setting a utility’s rate or rate base.49 In originally answering this “embarrassing
44 See Smyth v. Ames, 169 U.S. 466 (1898).
45 Patrick J. McCormick III & Sean B. Cunningham, The Requirements of the “Just and Reasonable” Standard: Legal Bases for Reform of Electric Transmission Rates, 21 Energy L.J. 389, 397 (2000).
46 Id. at n.34; see also Duquesne Light Co. v. Barasch, 488 U.S. 299, 308 (1989) (“If the rate does not afford sufficient compensation, the State has taken the use of utility property without paying just compensation and so violated the Fifth and Fourteenth Amendments.”).
47 Railroad Comm’n Cases v. Farmers Loan & Trust Co., 116 U.S. 307 (1886).
48 Patrick J. McCormick III & Sean B. Cunningham, The Requirements of the “Just and Reasonable” Standard: Legal Bases for Reform of Electric Transmission Rates, 21 Energy L.J. 389, 397 (2000); see also Bluefield Waterworks & Improvement Co. v. Pub. Serv. Comm’n of W. Va., 262 U.S. 679, 691 (1923) (“[R]ates which are not sufficient to yield a reasonable rate of return…are unjust, unreasonable, and confiscatory, and their enforcement deprives the public utility company of its property in violation of the [Fifth and] Fourteenth Amendment[s].”).
49 See generally Permian Basin Area Rate Cases, 390 U.S. 747, 790 (1968) (“[N]either law nor economics has yet devised generally accepted standards for the evaluation of rate-making orders.”).
question,”50 the Supreme Court adopted the “fair value” standard to measure the amount of a utility’s capital investment that was “used and useful to the public.”51 The Supreme Court first articulated the fair value standard in Smyth v. Ames,52 and later sustained it in Bluefield Waterworks & Imp. Co.53 In espousing the fair value standard, the Court held
that the Constitution requires rates to be set according to the actual present value of the assets employed in the public service.54
In Smyth, the Court held that “the basis of all calculations as to the
reasonableness of rates to be charged [by a utility]…must be the fair value of the property being used by it for the convenience of the public. And, in order to ascertain that value, [regulators must consider]…the present [value] as compared with the original cost of construction.”55 The Court also stated that under the fair value standard, a “company is entitled to ask…a fair return upon the value of that which it employs for the public convenience,” while on the other hand, “the public is entitled to demand…that no more be exacted from it for the use of [utility property] than the services rendered by it are reasonably worth.”56 This attempt at balancing the competing interests of the utility and the public was intended to mimic the operation of a competitive market, which rewards the utility for sound capital investments and penalizes it for imprudent investments.57 Nonetheless, the Court’s fair value standard established a narrow rule that the Takings Clause required the “present value” method of valuation.58
50 Smyth v. Ames, 169 U.S. 466, 546 (1898).
51 Id. at 547.
52 Id. at 540.
53 Bluefield Waterworks & Imp. Co. v. Pub. Serv. Comm’n of W. Va., 262 U.S. 679, 692-93 (1923).
54 Duquesne Light Co. v. Barasch, 488 U.S. 299, 308 (1989).
55 Smyth v. Ames, 169 U.S. 466, 546-547 (1898).
56 Id. at 547.
57 See Duquesne Light Co. v. Barasch, 488 U.S. 299, 308-09 (1989).
58 Patrick J. McCormick III & Sean B. Cunningham, The Requirements of the “Just and Reasonable”
The fair or present value standard suffered from practical difficulties that led to its abandonment as the sole test of a rate’s constitutionality. One of the most serious problems regulators faced was the difficult and seemingly impossible task of determining the ‘present value’ of the capital invested by a utility. As one commentator observed, “there is no objective, unequivocal method of ascertaining the cost of capital, even for a particular regulated company at a particular time and place; the process requires the exercise of a good deal of judgment, and judgments will inevitably differ as to the results.”59 Also, the reasoning supporting the rule was circular; because it depended upon the anticipated earnings made under the rate to be established, the fair value of the investment could not be determined accurately.60 Furthermore, the exchange value of certain utility assets, such as power plants, could not be ascertained by reference to a market price because such assets were rarely bought and sold.61
(ii) The “Prudent Investment” or “Historical Cost” Rule
Frustrated by the practical problems accompanying the fair value rule, Justice Brandeis advocated a different approach known as the “prudent investment” or “historical cost” rule.62 Proponents of the prudent investment rule believed that it could serve as a bright-line ratemaking test for regulators, thus alleviating the practical burdens
Standard: Legal Bases for Reform of Electric Transmission Rates, 21 Energy L.J. 389, 398 (2000); see also Richard J. Pierce & Ernest Gellhorn, Regulated Industries 97-98 (1994).
59 Alfred E. Kahn, The Economics of Regulation 43 (1998).
60 Patrick J. McCormick III & Sean B. Cunningham, The Requirements of the “Just and Reasonable” Standard: Legal Bases for Reform of Electric Transmission Rates, 21 Energy L.J. 389, 398 (2000). 61 Duquesne Light Co. v. Barasch, 488 U.S. 299, 309 n. 5. (1989).
62 Missouri ex rel. S.W. Bell Tel. Co. v. Pub. Serv. Comm’n, 262 U.S. 276, 293 (1923) (Brandeis, J., dissenting) (“The compensation for which the Constitution guarantees an opportunity to earn is the reasonable cost of conducting the business. Cost includes not only operating expenses, but also capital charges. Capital charges cover the allowance, by way of interest, for the use of the capital, whatever the nature of the security issues therefore; the allowance for risk incurred; and enough more to attract capital. The reasonable rate to be prescribed by a commission may allow an efficiently managed utility much more. But a rate is constitutionally compensatory, if it allows to the utility the opportunity to earn the cost of the service as thus defined…”).
of determining the fair or present value. Although it aimed to simplify ratemaking, the prudent investment rule, like the fair value rule, nonetheless sought to establish a specific methodology to satisfy the requirements of the Takings Clause.63 Despite this shortcoming, the prudent investment rule nevertheless foreshadowed the modern J&R standard by shifting the focus away from the present value or reproduction cost of the rate base to the utility-investor interest in a return on capital investment.64
(iii) The Hope “End Result” Test
The United States Supreme Court incorporated the prudent investment rule’s shift in focus from present value to investor interests in the seminal case of F.P.C. v. Hope Natural Gas Co.65 In Hope, the Court settled the question of whether the prudent
investment rule or the fair value rule, or both, were necessary to set a constitutional rate. The Hope Natural Gas Company challenged the validity under the Natural Gas Act of 193866 (“NGA”) of an FPC order reducing its rates. Rather than establishing a new, single methodology for ratemaking, the Court held that because “Congress…has provided no formula by which the ‘just and reasonable’ rate is to be determined,”67 the FPC is “not bound to the use of any single formula or combination of formula in determining rates.”68 The Court declared that the end result of the ratemaking process,
63 Patrick J. McCormick III & Sean B. Cunningham, The Requirements of the “Just and Reasonable” Standard: Legal Bases for Reform of Electric Transmission Rates, 21 Energy L.J. 389, 398 (2000). 64 Id.
65 F.P.C. v. Hope Natural Gas Co., 320 U.S. 591, 603 (1944).
66 15 U.S.C.A. § 717, et seq. (2004).
67 F.P.C. v. Hope Natural Gas Co., 320 U.S. 591, 600 (1944).
68 Id. at 602 (“Under the statutory standard of ‘just and reasonable’ it is the result reached not the method employed which is controlling. It is not [the] theory but the impact of the rate order which counts. If the total effect of the rate order cannot be said to be unjust and unreasonable, judicial inquiry under the Act is at an end. The fact that the method employed to reach that result may contain infirmities is not then important.” (citations omitted)).
and not the method used to calculate the rate, determines the rate’s constitutionality.69 In addition to establishing the end result test for J&R rates, the Court reaffirmed that the Commission’s rate orders and decisions carry a strong presumption of validity, which requires great judicial deference and imposes a heavy burden on the challenging party.70 Most importantly, the “end result” test reflected the Court’s shift away from attempts to define a specific constitutional ratemaking methodology, and its move towards “withhold[ing] its legislative hand.”71
In Duquesne Light Co. v. Barasch,72 the Court reaffirmed its holding in Hope and
further stated that “whether a particular rate is ‘unjust’ or ‘unreasonable’ will depend to some extent on what is a fair rate of return given the risks under a particular rate-setting system, and on the amount of capital upon which investors are entitled to earn that return.”73 The Court upheld the Pennsylvania Public Utility Commission’s use of an historical cost/prudent investment system for ratemaking, primarily because the utilities challenging the system attacked its theoretical inconsistency74 rather than the end result of the rate.
(iv) The “Zone of Reasonableness”
In subsequent decisions, the Supreme Court followed the end result test set forth
69 Id. (“[I]t is the result reached not the method employed which is controlling.”).
70 Id. (“Moreover, the Commission’s order does not become suspect by reason of the fact that it is challenged. It is the product of expert judgment which carries a presumption of validity. And he who would upset the rate order under the Act carries the heavy burden of making a convincing showing that it is invalid because it is unjust and unreasonable in its consequences.”).
71 Alfred E. Kahn, The Economics of Regulation 40, n. 45 (1998).
72 Duquesne Light Co. v. Barasch, 488 U.S. 299, 310 (1989).
74 Id. at 313; see also Patrick J. McCormick III & Sean B. Cunningham, The Requirements of the “Just and Reasonable” Standard: Legal Bases for Reform of Electric Transmission Rates, 21 Energy L.J. 389, 400 (2000) (stating that the utilities attacked “a ‘theoretical inconsistency’ in the legislation underlying the Commission’s method, namely a selective application of the ‘used and useful’ requirement normally associated with the old present value approach.”)
in Hope and continued to flesh out the substantive requirements of the J&R standard in
Sections 205 and 206. As a result, the FERC has come to possess very broad discretion in determining whether particular rates are J&R. Federal courts have held that the ratemaking methodology used by the Commission, whether it be cost-based, market- based, or some other type, must serve a legitimate statutory objective and produce a rate that is within a “zone of reasonableness.”75 This zone is “bounded at one end by
the investor interest against confiscation and at the other by the consumer interest against exorbitant rates.”76 Accordingly, the rate need only fall within a zone of reasonableness to satisfy the J&R standard,77 because “there is no single cost-recovering rate, but a zone of reasonableness…”78 Nonetheless, if the FERC adopted a ratemaking methodology that differed from its historical practice, the Commission was required to explain why the departure met those statutory objectives.79
- v) Ocean State, Citizens, & Heartland: Testing FERC’s Broad Rate Authority
In Ocean State Power,80 the FERC accepted proposed amendments to power sales
agreements of Ocean State (“OS”) that requested a departure from traditional CBRs and sought negotiated, market-based rates. Although the amended rates, like traditional rates, were based on the seller’s cost of service, OS’s agreements also included several provisions that would reduce the utility’s revenues in the event of construction delays and adjust payments according to the efficiency of the unit.81 The FERC found that these provisions gave OS a “direct incentive to construct and operate its generating unit as
75 Jersey Cent. Power & Light Co. v. FERC, 810 F.2d 1168, 1177 (D.C. Cir. 1987).
77 Patrick J. McCormick III & Sean B. Cunningham, The Requirements of the “Just and Reasonable” Standard: Legal Bases for Reform of Electric Transmission Rates, 21 Energy L.J. 389, 400 (2000). 78 FPC v. Conway, 426 U.S. 271, 278 (1976).
79 W. Sys. Power Pool, 55 F.E.R.C. P 61,099, 61,314 (1991).
80 Ocean State Power, 44 F.E.R.C. P 61,261 (1988).
efficiently as possible,” in contrast to traditional sales agreements that allowed recovery of fixed costs regardless of efficiency.82 The proposed rates also differed from traditional CBRs in that the rate of return was not based on OS’s actual cost of capital; rather, OS argued that its proposed rate of return mimicked the rate of return resulting from rates established by a competitive market.83 Fundamentally, OS requested that the FERC accept the proposed rates as within the zone of reasonableness, not based on cost-of- service principles, but rather because the rates would be the result of arm’s-length negotiations in a competitive power supply market.84
The FERC accepted OS’s arguments and proposed amendments, concluding that the rates provided for under the amended sales agreements were just and reasonable.85 In reaching this conclusion, the FERC stated that it can rely on market-oriented pricing to establish J&R rates “when a workably competitive market exists, or when the seller does not possess significant market power. A seller lacks significant market power if the seller is unable to increase prices by restricting supply or by denying the customer access to alternative sellers. Lack of market power is the key prerequisite for allowing market- oriented pricing.”86
The initial market-power test announced in Ocean State required first that the
seller cannot force the buyer to purchase at higher rates by withholding capacity at lower rates, and second that the seller does not own or control transmission facilities.87 In deciding that a workably competitive market ensures prices that fall within the zone of
85 Ocean State Power, 44 F.E.R.C. P 61,261 (1988).
86 Id. (citations omitted) (emphasis added).
reasonableness, thus satisfying the FPA’s J&R standard, the FERC also found that OS’s ratemaking approach met the FPA objectives of “promoting efficiency and assuring an adequate supply of energy.”88 The approval of market-based rates in Ocean State
represented the first clear indication that the FERC would accept MBRs for non-QF, traditional electric utilities. Nonetheless, the Commission explicitly stated that its decision “applies only to the specific circumstances presented by Ocean State.”89
Following Ocean State, the FERC issued several key orders that outlined the scope of and test for market-based rate authority. In Citizens Power & Light Corp.,90 the
FERC approved Citizen Power & Light’s (“CP&L’s”) proposed market-oriented rates. The Commission concluded that the traditional cost-of-service plus rate of return approach should not apply to CP&L because it was a power marketer and power broker.91 A power marketer is a type of seller that buys electric energy, transmission, and other services from traditional utilities and other suppliers, and then resells these services at wholesale; it does not own generation or transmission facilities and does not have a franchised service area.92 The FERC believed that these new power marketers like CP&L can increase efficiency in the power supply markets, ultimately lowering the cost of electricity.93 Although limiting its decision to the CP&L proposal,94 the FERC concluded that CP&L lacked market power and that its rates fell within the zone of
90 Citizens Power & Light Corp., 48 F.E.R.C. 61,774 (1989).
91 Id. at 61,776.
92 Id. (“Power marketers take title to electric energy. Power brokers, in contrast, do not take title; they are limited t a ‘matchmaking’ role of identifying trade opportunities and then arranging for the principals to make the trade. [The FERC has] found that power brokers are not public utilities.” Id. at n. 7.).
94 Id. (“However, at this point we wish to stress that we are just beginning to obtain experience with power marketers. In future cases, we may take actions different from or in addition to those taken today with respect to Citizens Power.”).
reasonableness.95 The FERC based its conclusion that CP&L’s MBRs were J&R on findings that the safeguards against potential market power abuses, as well as the avoided cost pricing mechanism, sufficiently established rates within the zone of reasonableness.96
CP&L primarily lacked market power because it did not own, and did not plan to own, generation or transmission facilities. In addition, because there would always be an arms-length transaction between the generator of electricity and CP&L as the purchaser, the FERC did not need to address the issue of potential self-dealing.97 After stressing its authority to allow pricing flexibility, the efficiency benefits, and ultimately the lower prices resulting from market-based sales, the FERC further conditioned its approval on CP&L’s agreement to file the buyers’ certifications that they were paying a rate equal to or less than the avoided cost rate.98 In sum, Citizens Power & Light Corp. paved the way
for new independent buyers, sellers, and brokers to enter the wholesale electricity market. More importantly, it underscored the FERC’s approval of market-based rates for power marketers and prefigured the looming restructuring of the electric industry.
In Heartland Energy Services, Inc.,99 the FERC approved Heartland’s proposed
rate schedule that requested market-based rates, even though the power marketer was an affiliate of a public utility.100 The Commission initially outlined the specific issues raised
95 Citizens Power & Light Corp., 48 F.E.R.C. 61,774, 61,776-777 (1989).
96 Id. at 61,777.
98 Id.at 61,779. (“[O]ur approval of [market-based] pricing is further conditioned on Citizen Power’s agreement to file with us the buyer’s certification that it is paying a rate which is less than or equal to its cost of alternative electric power. As previously mentioned, the Commission in recent cases has found the purchaser’s avoided cost an acceptable and legally sufficient price cap…”).
99 Heartland Energy Serv., Inc., 68 F.E.R.C. 62051 (1994).
100 Id. at 62,064.
by allowing a power marketer affiliate of a public utility to charge market-based rates.101 Next, the FERC clarified the appropriate standards to determine whether market-based rates are just and reasonable under the FPA.102 These standards for granting market- based rate authority essentially required that the entity did not have, or had adequately mitigated, market power in generation and transmission, and also prohibited the entity could from erecting other barriers to entry.103 For all future cases involving blanket approval of market-based rates, the FERC also required the entity to “voluntarily” offer comparable transmission services; that is, the power marketer and all of its affiliated utilities must have an open-access transmission tariff on file.104 Therefore, a power marketer or other independent entity seeking MBR approval could not demonstrate that its transmission market power had been adequately mitigated unless it “voluntarily” filed an open-access transmission tariff.105
The three orders discussed above mark the FERC’s initial attempt at defining standards to govern market-based rate approval. As Section II explains below, under these original market-power tests the number of entities authorized to charge MBRs rapidly increased. As the number of market participants increased, and as the FERC gained experience in adjudicating MBR applications, the Commission realized that its
101 Id.at 62,060. (“In general, affiliated power marketers present two issues: (1) market power that can be conferred by the affiliated public utility or utilities; and (2) potential affiliate abuse. Heartland’s request for authorization to transact at market-based rates provides an example of a power marketer that is affiliated with a public utility that owns (1) generation and transmission facilities and other inputs to electric power production and (2) has a franchised service area.”).
102 Id. at 62,060-61. (“The Commission’s general standard is to allow market-based rates if the seller (and each of its affiliates) does not have, or has adequately mitigated, market power in generation and transmission and cannot erect other barriers to entry…. In evaluating requests for open-ended, market rate authority, the Commission uses these same general standards but also implements reporting and periodic review requirements because it will not have the opportunity to examine the particular circumstances of each transaction.”).
104 Heartland Energy Serv., Inc., 68 F.E.R.C. 62051, 62,060 (1994).
105 Id. (Explaining that this requirement for transmission market power mitigation originated in, and was adopted from its standard for utility merger approvals).
initial market power tests needed further modification and development. The subsequent permutations of the original market power tests contain significant and intricate changes, which not only reflect the complexity of “light-handed” regulation in a competitive electricity market, but also mirror the natural evolution of a regulated industry.
A Move Towards Deregulation: The FERC Employs “Hub-and-Spoke” Analysis
While the Energy Policy Act of 1992 and concurrent FERC orders reflect the legislature’s desire to accelerate competition in wholesale electric power markets, in practice, it left electric utilities having to choose between “the noose and firing squad.” Beginning in the early 1990’s the FERC’s orders, taken together, evolved into a market power driven analysis that was used to decide whether to grant a utility the authority to charge market based rates. This approach centered on the determination of generation market power calculated using the “hub-and-spoke” test. The following discussion describes this market power analysis and how the test saddled the industry with draconian and inflexible arithmetic determination of market power.
The measurement of market power has always been the fulcrum in the FERC’s analysis of whether a particular market was competitive. While defining and identifying market power has always been a key issue before the FERC, past decisions under the “cost-based” rate regime were tempered through a practice of “light-handed regulation” using a “just and reasonable” standard where rates resulted from the functioning of a competitive market.106 However, the 1990’s saw a rapid increase in the number of utilities applying for market based rate approval and mergers which altered the competitive climate of the electric power markets. This change prompted the FERC to adapt a more
106 Albert V. Carr, Jr., John Jurewitz, John Mandt, Karl Moor, Patrick J. McCormick III, & Louis Harris, Toward an Effective Definition of Market Power: The Key to Competition for Delivered Bulk Power, Edison Electric Institute, Power Supply Monograph 1, 1 (January 1994).
rigid result-oriented approach to compensate for the FERC’s lack of statutory authority to directly compel transmission owners to provide services to third parties.107 This approach manifested itself within the framework of the FERC’s “hub-and-spoke” test and, in particular, the FERC’s dogmatic adherence to requiring open access transmission in cases where a utility possessing transmission market power sought approval for market based rates. Thus, the market power criterion became the crucial and sole determinant of any FERC determination of market competitiveness.
Throughout the 1990s, the FERC used the market power analysis (based on its traditional “hub-and-spoke” methodology) to determine whether to grant market-based rate authority to public utilities. The “hub-and-spoke” method served its policy purpose in that it allowed the FERC to jump-start wholesale competition by promoting open access transmission on a case-by-case basis. In addition, it accommodated new entry in the sense that it made it relatively easy for new competitors to be granted the right to charge
market-based prices rather than cost-based regulated rates.108
It is important to note that the market power analysis, bolstered by statutory filing requirements, also ensured the FERC of an ongoing watchdog and regulatory role even after the utility received approval to charge market based rates. The FERC required that utilities that pass the market power analysis to file an updated market analysis within three years of the date of the issuance of the FERC’s order granting market based rate authority, and every three years after.109 Alternatively, utilities that receive market based rate authority are required to notify the FERC on an ongoing basis of any change in status that would reflect a departure from the characteristics the FERC relied upon in approving
107 Id. at 2.
108 Craig R. Roach, Measuring Market Power in the U.S. Electricity Business, 23 Energy L.J. 51, 61 (2002).
109 AEP Power Mtkg. Inc., 97 F.E.R.C. P 61,219, 61,967 (2001).
market based pricing.110 The relevance of this filing requirement becomes apparent in the third section of this paper which details the FERC’s implementation of a new market power test in response to significant structural changes and corporate alignments that occurred in the electric industry.
When applying a market power analysis, the FERC used a four-part test to decide whether to grant a public utility market-based rate authority. The test turns on four separate conclusions: one, whether an individual entity and its affiliates have the ability to exercise generation market power (hub-and-spoke test); two, whether the applicant has transmission market power; three, whether the applicant can erect barriers to entry; and finally, whether there is the potential for affiliate abuse and reciprocal dealing. Each of the four parts are discussed in turn.
A. Generation Market Power
Before examining the first part of the test, it is necessary to develop a basic definition of market power and the key steps in any market power analysis. By definition, market power is the ability to profitably increase prices above competitive levels for a sustained period of time.111 Traditionally, most measures of market power are “indirect” meaning that they use market shares or derivative measures of market concentration to demonstrate that competitors in a market have the ability to profitably raise prices.112 Regardless of the method used to measure market power, the first step necessarily involves defining the geographic scope of the market and the product types to be assessed. Applying a basic market analysis, simple economics implicitly assumes that the larger the scope of the market, in geographic terms or product types, the less likely it is
111 Craig R. Roach, Measuring Market Power in the U.S. Electricity Business, 23 Energy L.J. 51, 52 (2002).
that market share or market concentration will be high enough to trigger market power concerns. In the particular market of energy generation, the applicant utility determines whether it can exercise market power by applying the “hub-and-spoke” test. To do this, the utility computes its market share of both installed and uncommitted generation capacity in its control area market and separately for each of the control area markets to which it is directly interconnected (first-tier markets).113 Simply, for an applicant that is a traditional utility, those utilities directly interconnected with the applicant via electric transmission lines are classified as “first-tier” utilities. Subsequently, each of these “first- tier” utilities is included in a market power analysis.
(i) Geographic extent of the market
Ultimately, applicants pass or fail the “hub-and-spoke” test based on their market share. In the most basic terms, market share is calculated by dividing the applicant’s capacity by the market’s capacity. Defining the geographical regions of the relevant markets determines the markets’ capacities and thus, directly determines the outcome of the “hub-and-spoke” test.114 The regions are based on which suppliers various customers can reach directly and which suppliers the customer can reach through open access tariffs. In terms of the geographic extent of the market, “the first-tier utility being assessed becomes the ‘hub’ market and it is assumed that the suppliers that can compete in the hub market are: (a) generators in the hub, (b) generators in any directly interconnected utility territory, plus (c) generators that could reach the hub using the transmission facilities of the applicant via its open access tariff (utilities linked to the hub
114 Steven Stoft, An Analysis of FERC’s Hub-and-Spoke Market-Power Screen, Prepared for Electricity Oversight Board of California, Contract No. 800-00-007, (2001).
in this way are called “second-tier” utilities).”115 A key feature of the “hub-and-spoke” test is that the geographic scope of the market is defined in terms of open access transmission. In the late 1980’s and early 1990’s, the FERC circumvented its inability to facially order a utility to open its transmission system for use by competing suppliers by ordering open access in only specific cases where the utility wanted to charge market- based rates. Thus, the FERC was still able to achieve its goal of promoting competition without having sweeping authority to order open access. If a utility wanted the freedom to charge market-based rates in nearby wholesale markets, then the FERC, by using “hub- and-spoke”, encouraged that utility to open its transmission system.116
(ii) Product types
The “hub-and-spoke” test typically employs two distinct product types: one, total installed generating capacity (Installed Capacity), which is used to indicate competition for the sale of electric energy; and two, uncommitted generating capacity, which is used to indicate competition for year-round electric capacity sales.117 Installed Capacity is the sum of the capacity of all the power plants in the geographic scope of the market. During the time when the FERC began to apply the “hub-and-spoke” methodology, many electric markets were only partially deregulated. In this business climate, only some of the suppliers had power plant capacity freed up to compete in the wholesale market.
Uncommitted capacity is simply a measure of the power capacity available for competition in the wholesale market. Uncommitted capacity is total Installed Capacity
115 Craig R. Roach, Measuring Market Power in the U.S. Electricity Business, 23 Energy L.J. 51, 52 (2002).
117 Id. at 52.
less the needs of a supplier’s (utility’s) retail customers still receiving regulated service (“native load obligations”).118
(iii) Calculating Market Share
The applicant calculates its market share of both committed and uncommitted capacity in its immediate control area (the “hub”) and, separately, in each directly connected area (the “spokes”)119. The FERC then compares these percentages with its market-power standard. The FERC did not employ a bright-line test to determine that a utility can excise market generation power, rather it looked to a benchmark for generation market power of whether a seller had a market share of 20 percent or less in each of the relevant markets.120 If the electric generator applying for market-based rate authority has a market share of less than 20% to 30%, then the applicant was declared not to dominate the market (“neither it, nor its affiliates, has market power in generation”) and the FERC would generally grant it the right to sell at unregulated prices in the wholesale market.121 It is interesting to note that while the FERC has specified that market share be calculated from installed capacity and from uncommitted capacity, neither corresponds to the definition of market share given in any economics or business text. Both classic economics and business define the market share of a supplier to be its sales divided by the market’s total volume of sales. Under the classic model, a supplier is not given credit for unused plants.
118 Id. at 53.
119 Hunton & Williams LLP, Client Alert, FERC Launches Major Market Power Initiatives, https://www.hunton.com/files/tbl_s10News%5CFileUpload44%5C10887%5CFERC_Supply_Margin_Alert
120 Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation Policy, 107 F.E.R.C. ¶ 61,018 (2004).
121 Louisville Gas & Elec. Co., 62 F.E.R.C. P 61,016 (1993) contains an explanation of generation market power analysis and barriers to entry or reciprocal dealing. See Heartland Energy Serv., Inc., 68 F.E.R.C. P 61,223 (1994) for an explanation of transmission market power.
In order to be approved for market-based rates for bulk power sales, the seller must be deemed to lack market generation power in any relevant market. In Louisville
Gas & Elec. Co., the FERC set forth a framework to determine whether an applicant has
market generation power in both the short-run and long-run product markets.
- Short-run Market
Market shares are measured in both in installed capacity and uncommitted capacity. These two indicators focus of the existing generating capacity of a utility because only those utilities which have such capacity are able to compete in the short-run market. When analyzed together, installed and uncommitted capacity provide an accurate projection of the short-term markets that a public utility faces. In the order the FERC states describes the probative value of measuring uncommitted capacity,
“A firm’s share of the uncommitted capacity available in a market is a general indication of its ability to dominate firm sales in the short-run market. Because of the need to meet native and other firm load at the system peak, the capacity that a seller can commit to new firm sales for more than a year’s duration is limited to that above the amount needed to meet this load.”122
Installed capacity, or the maximum existing capacity actually available for all types of sales, was also used to measure additional market power. The capacity that a seller can offer for shorter-term sales and for non-firm sales is not limited to the uncommitted portion. Installed capacity is relevant in any short-term market power determination, when native load and other firm load is less than its annual peak…and some additional capacity is freed up for shorter-term firm sales. Sellers can also use capacity freed up by load variations to make non-firm sales because it can be quickly withdrawn to meet firm commitments.123
122 Louisville Gas and Elec. Co., 62 F.E.R.C. P 61016, 61146 (1993).
In Louisville, the FERC concluded that the both the market share of both the
short-term uncommitted capacity and installed capacity was below 20%, the standard that the FERC used to as a benchmark to indicate when market power existed.
- Long-run Market
Implicitly, long-run market sales are generally made with a more protracted planning horizon and for longer durations than that which is found in short-run markets. The principal supply source for the long-run market is new capacity expressly built to serve the needs of a particular buyer.124 The ability of both existing utilities and new entrants to construct and market new capacity resources is what drives the long-run market. To support a finding that Louisville did not possess long-run market power, the FERC notes various examples of competitive capacity procurements by other utilities in the relevant geographic markets as well as citing nationwide industry trends consistent with these findings.
B. Transmission Market Power
In Heartland Energy Serv., Inc., the FERC laid out clearly the standard that
utilities must meet in order to implement market based rates. The order states, “the [FERC’s] practice has been to require transmission-owning public utilities to provide open access transmission tariffs when the utility or its affiliate power producer proposes open ended, market rate authority.” 125 The purpose of this requirement is to ensure that non-affiliated sellers are not barred from competing by the applicant utility by denial of transmission service.126 For identical reasoning, power marketers affiliated with the transmission owner are also required to abide an open access transmission tariff if they
124 Id at P 61,146.
125 Heartland Energy Services, Inc., 68 F.E.R.C. 61,223, 62,061 (1994).
intended to benefit from the same market based rate.127 Further, the affiliated power marketer is required to take its transmission services under that same tariff. If the market-rate applicant is a transmission-owning public utility or an affiliate of a transmission-owning public utility, the filing of an open access transmission tariff by the transmission-owning utility is usually sufficient for the FERC to find that transmission market power has been sufficiently mitigated.128 Instead of making a case-by-case determination on whether the applicant utility did indeed have transmission market
power, the FERC required all the utilities seeking approval of market based rates to adopt an open access tariff to overcome the presumption of transmission market power. The end result of the FERC’s strict application of the market power analysis is inevitably,
“a finding that if a utility owns transmission it has the ability to foreclose competition and therefore has market power. FERC has nearly always required a utility possessing such ‘market power’ to mitigate that market power by submitting a generic transmission filing, in the form of an open access transmission tariff as a quid pro quo for market based rates and merger approvals.”129
Although the Commission rejected only a few of the several hundred applications for market based pricing submitted during the early 1990s, each of the rejected applications involved utilities or affiliates of utilities that owned transmission facilities130. In each of these cases, the FERC concluded as a result of the transmission capabilities of the applicants, it followed that the utilities and their affiliates possessed market power and would be permitted to charge market-based rates only when the utilities had agreed to mitigate that market power through an open access transmission
127 Id. at 62,061.
128 Report of the Committee on Electric Utility Regulation, 19 Energy L.J. 139, 161 (1998).
129 Albert V. Carr, Jr., John Jurewitz, John Mandt, Karl Moor, Patrick J. McCormick III, & Louis Harris, Toward an Effective Definition of Market Power: The Key to Competition for Delivered Bulk Power, Edison Electric Institute, Power Supply Monograph, 1, 10 (January 1994).
130 Id. at 10.
tariff. The following orders demonstrate the difficulties utilities faced under the transmission market power standard.
In Teco Power Services, the FERC ruled that Seminole Electric Cooperative’s
affiliate, Tampa Electric Company, had transmission market power because it could have foreclosed some potential suppliers from responding to the solicitation of the parent utility for bids through the of transmission facilities located in Tampa’s service area.131 In addition, the FERC found transmission market power was not mitigated because did not offer to provide transmission access to competing suppliers within its service area.132 The FERC’s conclusion did not seem to take into account the fact that Seminole was not interconnected with Tampa (though it was with other utilities) and therefore, could not have relied on Tampa’s transmission system to serve its needs anyway.133
Terra Comfort involves the FERC’s rejection of a bulk-power sale to Iowa Electric Light and Power Company from Terra Comfort Corporation which was an affiliate of Iowa Southern Utilities Company because of a finding of generation and transmission market power.134 Terra Comfort was dependent upon its affiliate Iowa Southern for transmission. Terra Comfort, however, argued that Iowa Electric was interconnected with six utilities in addition to Iowa Southern. In addition, Iowa Electric had access to two other utilities through a part ownership in a transmission line. The record showed that Iowa Southern provided wheeling service to others but had not been asked to wheel for the proposed Iowa Electric transaction or by anyone else. The FERC
131 TECO Power Servs. Corp. & Tampa Elec. Co., 52 F.E.R.C. P 61,191 (1990).
132 Id. at P 61,700
134 Terra Comfort Corporation, 52 F.E.R.C. P 61,241 (1990).
dismissed these arguments ruling that the existence of an interconnection did not necessarily imply open access transmission. The Commission based its order on the potential for Iowa Southern to preclude Iowa Electric from accessing other available seller’s in Iowa Southern’s service area that might provide alternatives at a lower cost. The FERC dismissed the argument that Iowa Southern had not, at the time of the filing, received a single request to utilize their transmission services for the transaction by offering an unfounded allegation that potential suppliers had not requested access because they knew any attempts were futile.
While the aforementioned Teco and Terra Comfort transactions were ultimately approved, the utilities simply resubmitted the same basic rates bolstered by cost-support data. The FERC, using the cost-based rate methodology, was able to accept the revised application and therefore did not have to reach a conclusion concerning the prior arguments directed at the FERC’s market power tests. United Illuminating Company,
however, provides an excellent example of a direct challenge to the FERC’s transmission market power standard.135 In this order, a myriad of evidence was put forth detailing the submission of over fifty competitive bids, the ability of the purchaser (UNITIL Power Corporation) to acquire the power it needed through numerous alternative suppliers, and the other potential suppliers’ lack of dependence on the winning bidder’s (United Illuminating Company) transmission system. Despite the overwhelming evidence to the contrary, the FERC concluded that since United Illuminating did not have an open access transmission tariff on file, it possessed transmission market power which had not been adequately mitigated.
135 Letter Order, United Illuminating Company, FERC Docket No. ER92-397-000 (July 2, 1992), mimeo.
Upon a request for a rehearing from United Illuminating, as well as the Antitrust Division of the United States Department of Justice, the FERC backpedaled and concluded that based on a reconsideration of the evidence, United Illuminating did not possess market power. This order is important, not because the FERC concluded that there was no evidence of market power, but because the order clearly evidenced the FERC’s one dimensional use of the “control of transmission” criterion as an all- encompassing talisman. In fact, the then-Commissioner Moler recognized this trend and noted in her concurring opinion,
This case will, I am sure, be used to argue that, even where there is robust bidding and no real concern as to whether the winner controlled transmission, there must still be ‘open access’ before the sale will be allowed at a competitive rate.136
Commissioner Trabandt expressed a similar concern in his concurrence stating that the FERC’s strict adherence to the transmission market power standard as,
[A]n almost ritualistic chant will lead to a situation in which ‘open access’ will serve as the only answer in the Commission’s electric policy game of ‘Name That Tune.’137
A brief examination of the FERC dockets throughout the 1990’s shows that this very apprehension was not unfounded. Under the transmission market power analysis, the FERC started with the premise that transmission is a natural monopoly. The utilities were faced with a difficult but rebuttable presumption of market power over bulk-power transactions where the utility owns transmission facilities in the vicinity of the relevant geographic area. The presumption excluded any consideration of the particular conditions surrounding the transaction in question. The only way an applicant utility
136 Concurring Opinion of Commissioner Moler, United Illuminating Company, FERC Docket No. ER92- 397-000 (July 2, 1992), mimeo at 2.
137 Concurring Opinion of Commissioner Trabandt, United Illuminating Company, FERC Docket No. ER92-397-000 (July 2, 1992), mimeo at 13.
could overcome this barrier was to mitigate its presumed market power by filing an open access transmission tariff prior to submitting a power sale proposal. In summation, “if a transmission owner desires FERC approval for, among other things, market-based pricing of delivered bulk power, it must mitigate its presumed market power by promising to make transmission available equally to any and all competitors.”138
C. Barriers to Entry
The third prong of the FERC’s market power test concerns barriers to entry. Under this criterion, market power is determined by analyzing the relative ease with which a competitor can acquire a foothold in the market. The greater the ease of entry, the faster a firm’s market power erodes as competition from new entrants gradually overcomes monopoly rents. Since short-run markets are composed of only existing capacity, they are unaffected by entry. However, ease of entry plays a vital role in determining makeup of long-term markets. Economic theory generally holds that market power is difficult to maintain over a significant time period barring any barriers to entry that might stymie competition.139 Without barriers to entry, buyers are able to compete and negotiate with existing suppliers or engage new energy suppliers to satisfy capacity requirements. With the growth of non-traditional suppliers such as QFs and IPPs, requirements easing existing barriers opened the doors for new suppliers to change the face of the traditional relevant market.140 Some common barriers to entry include: control of the sites that can be used for new capacity development, control of key inputs to generation, control over the transportation of the key inputs, and transaction
138 Albert V. Carr, Jr., John Jurewitz, John Mandt, Karl Moor, Patrick J. McCormick III, & Louis Harris, Toward an Effective Definition of Market Power: The Key to Competition for Delivered Bulk Power, Edison Electric Institute, Power Supply Monograph 1, 24-25 (January 1994).
139 Louisville Gas and Elec. Co., F.E.R.C. P 61016, 61147 (1993).
accommodation arrangements (i.e. restrictive purchase and sale provisions or covenants in long-term contracts).
D. Affiliate Abuse and Reciprocal Dealing
The FERC also requires that there be no reciprocal dealing or abuse of affiliate relationships from utilities seeking approval of market based rates. Affiliate abuse occurs when “the affiliated public utility and the affiliated power marketer transact in ways that result in a transfer of benefits from the affiliated public utility (and its ratepayers) to the affiliated power marketer (and its shareholders).”141
There are four key types of affiliate abuse that will be discussed in turn: one, preemption of transaction; two, non-sales services provided by the affiliate utility to the affiliated power marketer; three, power sales between the affiliated utility and the affiliated power marketer (self-dealing); and four, exchange of information between the affiliated power marketer and the affiliated utility.
(i) Preemption of Transactions
The first type of preempted transaction occurs when an affiliated power marketer purchases power that would have otherwise been purchased by the affiliated public utility. In this case, the affiliated power marketer receives the benefit that ordinarily flows through the public utility to the rate payers. However, this type of preemption is rarely policed since it is very difficult to prove that a public utility did not actively seek to purchase cheaper power for its rate payers.
A second type of preempted transaction occurs when an affiliated public utility fails to compete as a seller of power in order to benefit the affiliated marketer. Thus, the affiliated marketer is able to charge higher rates for the power it sells. The FERC
141 Heartland Energy Services, Inc., 68 F.E.R.C. 61,223, 62,061 (1994).
regulates this type of transaction by requiring both power marketers and affiliated power marketers to give the FERC notice of any transaction (purchase or sale of power or transmission service) with entities that have any business in the United States, Puerto Rico, Canada, and Mexico with any affiliate of the marketer.142
(ii) Non-Sales Services Provided by the Affiliated Utility to the Affiliated Power Marketer
This type of affiliate abuse can occur if the affiliated public utility provides non- sales services (legal, accounting, scheduling, etc.) to affiliated power marketer in a preferential manner. The affiliated power marketer must, upon FERC demand, be able to demonstrate that it pays for the services in question on a non-preferential basis (i.e. market value of the services). By prohibiting preferentially low rates, the FERC prevents the affiliated public utility from cross subsidization by the utility’s rate payers.
(iii) Power Sales Between the Affiliated Utility and the Affiliated Power Marketer (Self Dealing)
These types of sales/purchases are most susceptible to abuse since they necessarily involve the absence of arms-length transactions. As such, these sales and purchases are facially prohibited without separate filing and approval from the FERC.
(iv) Exchange of Information Between An Affiliated Power Marketer and the Affiliated Utility
This type of abuse can occur in numerous and distinct ways and an affiliated power marketer would have to demonstrate proper procedural safeguards (i.e. Chinese Walls) to prevent the flow of confidential and restricted information from passing between the marketer and utility.
(v) Code of Conduct Filing
142 Id. at 62,062.
The affiliate abuse requirement is often satisfied by the applicant filing a code of conduct governing the interaction of the applicant and its affiliates. This code of conduct requires the applicant to concurrently disclose to the public any market information it shares with its affiliates. This requirement extends to “any communication concerning the power or transmission business, broker related or not, present or future, positive or negative, concrete or potential, significant or slight.”143 The code of conduct may be circumvented if the utility is not affiliated with a registered holding company and has no affiliates engaged in electric service.144 Applicants seeking market based rates must also state separate prices for generation, transmission, and ancillary services in their market rate tariff. This often takes the form of a statement in the tariff assuring that the applicant will file a service agreement pursuant to its open access tariff for any transmission or ancillary services it or its customer needs with respect to power sold under the market rate tariff.145
E. Critical Flaws of the “Hub-and-Spoke” Market Power Analysis
While the “hub-and-spoke” market power analysis worked well throughout the 1990’s, the relevance of the model became strained as the electric industry underwent significant structural changes. As the 1990’s drew to a close, the fatal flaws of the “hub- and-spoke” market power analysis could not be ignored any longer. First, the geographic market definition accounts for a factor that was no longer relevant and for none of the factors that mattered in a competitive market.146 Second, the use of uncommitted shares registered more market power when the market itself was more competitive and less
145 Commonwealth Elec. Co. and Cambridge Elec. Co., 78 F.E.R.C. P 61,191, at 61,813 (1997).
146 Steven Stoft, An Analysis of FERC’s Hub-and-Spoke Market-Power Screen, Prepared for Electricity Oversight Board of California, Contract No. 800-00-007, (2001).
market power when it was less competitive.147 Thus, the test often read in reverse the impact of the market on the applicant. Third, the central market power problem of electricity markets, the inelasticity of demand, was not taken into account.148 Fourth, the huge fluctuations in supply elasticity that concentrated and intensified market power during a few critical hours were likewise ignored.149 Finally, the “hub-and-spoke” market power analysis made no determinations as to which utilities were “pivotal” suppliers to the market.150
The New Market Power Test: From “SMA” to the Present
In reaction to the decision to rely increasingly on market forces for energy pricing, the FERC focused on how to change the wholesale market’s pricing structure in a way that would encourage efficiency in the wholesale markets. As aforementioned, since it began to grant market-based rates to public utilities in the 1980s, the FERC primarily focused on the applicant and employed the “hub-and-spoke” analysis to establish whether an individual entity and its affiliates had the capability of exercising generation market power.151 The “hub-and-spoke” analysis’ problems led the FERC to rethink the model and to develop new systems for gauging market power.152 The chief problem with the “hub-and-spoke” system was its determination and calculation of market power. In the years following the “hub-and-spoke” the FERC changed the way that market power was determined.
As previously stated, under the “hub-and-spoke” analysis the applicant computes its market share of installed and uncommitted generation in a particular market in order to
147 Id. See also Appendix B.
151 Craig R. Roach, Measuring Market Power in the U.S. Electricity Business, 23 Energy L.J. 51, 61 (2002).
determine if it meets the market power “spoke” of the test. Market power interferes with the ability of consumers to influence prices through their buying choices.153 The standard the FERC employed for granting such market-based rate orders involved an assessment of whether the seller and its affiliates had generation market power or could effectively deter market entry by competitors, normally allowing up to a twenty percent (20%) share of the market in question to be adequate.154
“The “hub-and-spoke” analysis worked reasonably well for almost a decade when the markets were essentially vertical monopolies trading on margin and retail loads were only partially exposed to the market.”155 Recently, markets have changed considerably and have expanded into areas previously unanticipated by the FERC. Because of “significant structural changes and corporate realignments” that occurred in the electricity and power industries during the last fifteen (15) years (and which continue to occur), the FERC made a conscious decision to modify the “hub-and-spoke analysis” to sufficiently protect customers against generation market power of any one firm.156
A. The Supply Margin Assessment (SMA)
The FERC first developed the Supply Margin Assessment (“SMA”) screen to be used in the interim until a new market power test could be conceived and implemented.157 The SMA built on, improved, and expanded the existing “hub-and- spoke” analysis in two different ways. First the SMA considered transmission constraints in determining the geographic market. This led to a more accurate determination of what
153 Matthew H. Brown and Richard P. Sedano, A Comprehensive View of U.S. Electric Restructuring with Policy Options for the Future, National Council on Electricity Policy, (June 2003).
155 Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation Policy, 107 F.E.R.C. P 61,018 (2004).
157 Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation Policy, 107 F.E.R.C. P 61,018 (2004).
available energy supply could reach buyers to compete with the applicant.158 This made rational sense given the change in market dynamics which had occurred since the “hub- and-spoke” had been implemented.
The SMA also established a threshold based on whether an applicant was pivotal in the market for purposes of determining the size that triggered generation market power concerns. When an applicant was in fact deemed pivotal, the net effect was that said applicant was in a position to demand a sales price above competitive levels and be assured of selling at least some of its excess capacity in the market.159 An applicant was deemed pivotal if its capacity exceeded the market’s surplus of capacity above peak demand.160 Consequently, an applicant failed the SMA screen if the amount of its capacity exceeded the market’s supply margin. This differed from the “hub-and-spoke” method, where a company passed the test if its market share were less than twenty percent (20%), even if its capacity were deemed pivotal. This was an important new change given the change in market dynamics. The SMA’s supply margin threshold was a better screen for market power because, unlike the twenty percent (20%) market share screen, the new test took into account the relative scarcity of the power supply available from suppliers other than the applicant in the applicable market. It expanded on the notion that not all suppliers would be captured by the prior test. For practical purposes, “the supply margin threshold identified whether the applicant was a must-run supplier needed to meet peak load in the control area.”161 As a result, the supply margin was sensitive to the potential for the applicant to successfully horde supplies in the market,
159 Market-Based Rates for Public Utilities, 107 FERC P 61,019 (2004).
160 Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation Policy, 107 F.E.R.C. P 61,018 (2004).
161 Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation Policy, 107 F.E.R.C. P 61,018 (2004).
which would have the indirect effect of raising prices.162
The SMA analysis was applied differently to non-independent system operators (“ISO”s) and non-regional transmission organizations (“RTO”s) than actual ISO/RTO markets.163 An RTO is an entity that manages the interstate transmission facilities in a selected region, but neither owns or controls the generation and distribution assets connected to the facilities in question. An RTO may take a variety of forms, such as an ISO, under which vertically integrated utilities retain ownership of the transmission network but must relinquish operational control to the ISO, or a transco, which is a for- profit company that both owns and manages the transmission facilities.
In non ISO/RTO markets, the first step that FERC took was to consider the control area market where the applicant was located. Next, FERC considered the markets outside the applicant’s control area market. An applicant satisfied the test if it or its affiliates owned, or controlled/managed through contract, power capability located in a control area which was less than the supply margin in the control area. The margin included the amount of generation that could be imported into the control area limited by the total transfer capability (“TTC”) of the transmission system.164 Market sales (including bilateral sales) into an ISO or RTO with FERC-approved market monitoring and mitigation was determined to be exempt from the SMA and, instead, was determined to be governed by the specific thresholds and mitigation provisions approved for the particular markets.
The SMA test was very heavily criticized in the electric industry because many
people thought it was too restrictive.165 Under the SMA, traditional (old-economy) utilities were virtually guaranteed to fail the analysis in their own control areas. The test was also criticized for the automatic mitigation it brought with it, a factor that weighed heavily in future changes to the test.166 Many commenters found that the SMA was unsuited to its task, creating little or no improvement in the prevention of market power from that of the “hub-and-spoke.”167
B. RTO Reform and Order No. 2000
The SMA also took little into account by way of membership in (or alignment with) RTOs, which is a problem when trying to reform transmission rates. In response to this drawback, the FERC issued Order No. 2000.168 In Order No. 2000, the FERC “acknowledged that the development of regional markets for wholesale power in the wake of Order Nos. 888 and 889” had “placed new stresses on regional transmission systems.”169 The FERC decided that in order to alleviate such stresses and encourage transmission expansion, all transmission facilities should be operated by RTOs. However, rather than mandate RTO participation, the FERC chose to rely on a voluntary approach, giving prospective RTO participants the “flexibility to develop mutually agreeable regional arrangements….”170 The FERC also made its tri-annual review include the provisions of Order No. 2000 and its RTO reform resolutions.
165 Peter Fox-Penner, Gary Taylor, Romkaew Broehm, and James Bohn, Competition in Wholesale Electric Power Markets, 23 Energy L.J., 281, 281-348 (2002).
166 Harry Tidwell, Changing Dynamics in the Electric Markets, Roston-Sayers 038, (2003).
167 Peter Fox-Penner, Gary Taylor, Romkaew Broehm, and James Bohn, Competition in Wholesale Electric Power Markets, 23 Energy L.J., 281, 281-348 (2002).
168 North American Electric Reliability Council, Reliability Assessment 1999-2008 7 (May 2000); Comments of North American Electric Reliability Council on FERC’s Notice of Proposed Rulemaking, Regional Transmission Originals, Docket No. RM99-2, 15 (Aug. 23, 1999); Order No. 2000, Regional Transmission Organizations, III F.E.R.C. Stats. & Regs. P 31,089, 30,998 (1999).
169 Patrick J. McCormick III & Sean B. Cunningham, Order No. 2000 and Incentives for RTO Formation, 20 Energy L.J. 204 (2000).
170 Regional Transmission Organizations, 18 C.F.R. 35.34(e)(2) (2000).
To promote its new and improved policy of voluntary RTO formation, the FERC provided for “favorable” rate treatments to facilitate RTO formation.171 The FERC (through Order No. 2000) went on to admit the possibility of requiring RTO participation as a necessary condition for receiving approvals for market-based rates and company mergers.172 This acknowledgement that RTO membership “might” be conditional foreshadowed the present day circumstance of pseudo-required RTO participation. The FERC went on further to state that it:
“believe(d) that it (was) critically important for RTOs to develop ratemaking practices that… provide(d) incentives for transmission owning utilities to efficiently operate and invest in their systems. In particular, the [FERC] encourage(d) RTOs to develop and propose innovative ratemaking practices, particularly with respect to efficiency incentives.”173
In particular, Order No. 2000 provided for the FERC’s consideration of a multitude of “innovative” rate treatments, including performance-based pricing models, return on equity (return on non-debt) reforms, accretion/dilution goals, Regal methods174, and non-traditional cost-valuation methods. Order No. 2000 paved the way for different pricing and market structures to be adopted while simultaneously foreshadowing an end to non-RTO market-based rate adoptions.
C. The New Market Power Test
In response to the electric industry’s outcry for different pricing and market structures, the FERC adopted two new screens to assess generation market power and quell possible abuses of the SMA (and expand on Order No. 2000) analysis in April of
172 Order No. 2000 at 31,034.
173 Order No. 2000 at 31,040.
174 The Regal analysis is a cost-based efficiency score.
- 175 The new screens were intended to replace the SMA generation market power analysis adopted by the FERC as an interim screen in November 2001. The new screens would also be applied in the tri-annual review process of companies as the previous screens had been. The two new screens created by the order were (1) the pivotal supplier analysis and (2) the market share analysis. The new screens were to apply to all pending and future market-based rate applications. Furthermore, and probably most importantly, the two new screens were to apply to all three-year market-based rate reviews on an ongoing basis. The April 2004 order also eliminated the exemption from FERC’s market power analysis for parties that sell power into ISOs or RTOs. As previously stated, under the SMA, lack of market power was assumed where energy sales were made inside an ISO or RTO that had a FERC-approved market monitoring plan.
FERC developed the pivotal supplier analysis to evaluate the applicant in relation to overall market supply and demand. The pivotal supplier analysis is quite similar to the Residual Supplier Index and determines whether an applicant owns or controls generation market power that will be needed to serve load during peak demand conditions in a given control area.176 The test implicitly asks whether the free energy capacity owned or controlled by the applicant is greater than the surplus supply in the wholesale market.177 If power demand in a specific market cannot be met without at least some power from a supplier, that supplier is pivotal and faces a rebuttable presumption that they possess market power.178 An example would be as follows: “If demand in a single hour is 100 MW and the total uncommitted supply of sellers other than Supplier X is 90 MW, then
175 Fortnightly, Volume 142, No. 7, (July 2004).
176 Peter Fox-Penner and Romkaew Broehm, Deregulated Electricity Pricing in the U.S: Dramatic New Rules from the FERC, April 2004.
178 Peter Fox-Penner and Romkaew Broehm, Deregulated Electricity Pricing in the U.S: Dramatic New Rules from the FERC, April 2004.
demand cannot be met unless X sells at least 10 MW to the market. Intuitively, if X’s supply is needed to keep the lights on, X is probably able to charge extremely high prices for at least a portion of its supply.”179
Although the pivotal supplier analysis is intuitive, there are a number of variables required to specify the proper test parameters, including product definition and geographic market.180 One of the many controversial metrics used when completing the market power analysis is a utility’s ability to sell in a short-term energy market.181 Most commenters argue that traditional utilities have an obligation to serve native load, and thereby uncommitted capacity should be used to make additional spot sales. The FERC agreed and chose to define the uncommitted capacity as total capacity controlled less capacity unavailable to the market. The native load commitment, however, is measured as an average daily peak load of the needle peak month. Hence, under this test, the product is defined as the annual peak load less the average daily peak load of the peak month. The FERC also defined potential competing suppliers as all generators in the same control area, plus those generators in the first-tier control areas that are able to supply power which does not exceed the simultaneous transfer limit. In short, if an applicant’s uncommitted capacity is equal to or less than the net uncommitted supply, the applicant passes (See Figure 2 and Appendix C).182
The market share analysis looks at seasonally adjusted supply and evaluates an applicants’ size in relation to other suppliers in the market. If the applicant has more than a twenty percent (20%) market share of the total uncommitted capacity in the market in any season, market power is presumed. The market share test measures the seller’s share of the uncommitted capacity market. Interestingly, while the FERC recognized that “a more thorough analysis of market concentration would be more informative about the likelihood of coordinated behavior,” it decided that any applicant with a share below twenty percent (20%) would receive a rebuttable presumption that coordinated behavior was not a concern.183 This leads to the possibility that large sellers in highly concentrated markets will be declined market-based rates, while smaller ones in the same market may pass. This test also allows for a large seller in a competitive market to be declined market based rates when market power (failing of the pivotal supplier analysis) is present in a
183 Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation Policy, 107 F.E.R.C. P 61,018 (2004).
subsidiary or affiliate carrier of the large seller. In short, if an applicant’s uncommitted capacity is equal to or less than the net uncommitted supply, they pass (see Figure 3 and Appendix C).184
Failure of either the pivotal supplier analysis or market share analysis creates a presumption that generation market power exists for the applicant. If an applicant is found to possess generation market power in any market, it will be required to implement measures to mitigate its market power.185 An applicant may propose mitigation measures tailored to its particular market circumstances. If the FERC finds the proposed mitigation to be inadequate, it will require implementation of cost-based rates. Unlike the SMA policy, mitigation requirements are not limited to spot market sales.186
Applicants for market-based rates may rebut the presumption of market power by
185 Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation Policy, 107 F.E.R.C. P 61,018 (2004).
186 Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation Policy, 107 F.E.R.C. P 61,018 (2004).
submitting a more robust market power study (the Delivered Price Test (“DPT”)), submitting a mitigation proposal tailored to its circumstances, notifying the FERC that it will adopt default cost-based rates, or proposing other cost-based rates with cost support for such rates. The applicant must fail either the pivotal supplier analysis or market share analysis before the FERC will consider the DPT.187 Furthermore, it is the only additional market power screen the FERC will allow an applicant to submit. The DPT assesses the competitiveness of a market by calculating each supplier’s “economic capacity” which is the generating capacity that can be used to deliver energy to the market at a competitive market price. The applicant’s economic capacity is used to determine its market share, a Herfindahl-Hirschman Index188 score for the market, and whether the applicant is a pivotal supplier.189 Applicants who choose to conduct the DPT must estimate the shares of seller capacities that can be physically and economically delivered to an area within five percent (5%) of the market price prevailing during a season and load period. DPTs are more complex than the share analysis, but if the data and transmission representations are accurate they can reveal much more about the true product and geographic markets.
Figure 4190 shows the sequential approach which applicants will now have to
progress through as they determine their eligibility for market-based rates under the new market power test.
187 New England Power Co., 82 FERC P 61,179, at 61,662 (1998) (denying request to use alternate test unless applicant is unable to pass primary test); New York State Elec. & Gas Corp., 78 FERC P 61,309, at 62,329 n.7 (1997) (discussing circumstances in which submission of alternate analysis will be considered). 188 The Herfindahl-Hirschman Index (“HHI”) is a commonly accepted measure of market concentration. It is calculated by squaring the market share of each company competing in a given market and then summing the resulting numbers. For example, for a market consisting of four companies with shares of thirty (30), thirty (30), twenty (20) and twenty (20) percent (%), the HHI is 2600 (302 + 302 + 202 + 202 = 2600).
189 18 C.F.R. 35.34(e)(1).
190 Peter Fox-Penner and Romkaew Broehm, Deregulated Electricity Pricing in the U.S: Dramatic New Rules from the FERC, April 2004.
Each of the components that make up the new market power test have strengths and weaknesses. Although few observers contest the basic premises of the tests, there is often room for disagreement over the correct measures of the product, the geographic market, and the data used to establish these two measures.191 “For example, when the merger creating Progress Energy is analyzed, it can be discovered that no simultaneous transfer limit had ever been estimated for one geographic area.”192 “Recognizing this, the new order directs all transmission providing utilities seeking or retaining market-based rate authority to measure and file the simultaneous transfer limit into their control areas or to pass the tests without considering any control area imports whatsoever.”193
“Although the FERC acknowledged that regions smaller than one control area could be legitimate geographic markets, applicants and other parties must determine this
191 18 C.F.R. 35.34(g)(5) (Comments to Proposed Rulemaking).
192 Testimonies of Peter Fox-Penner (Exhibit No. CF-400) and Stanley H. Williams (Exhibit No. CF-500), Docket No. EC00-55-000 and ER-1520-000.
193 Order on Rehearing and Modifying Interim Generation Market Power Analysis and Mitigation Policy, 107 F.E.R.C. P 61,018 (2004).
themselves.”194 As the traditional hypothetical monopolist test for defining geographic markets is not obviously correct for power markets, there remains no accepted test for a geographic power market.195 Because load pockets and other constrained sub-areas often have the greatest vulnerability to market power, this aspect of the new framework is unexplored and important. In addition, while the FERC withdrew the portion of its prior SMA approach that exempted sellers within ISOs and RTOs from requiring tests, it allows applicants to argue that the entire area under the control of an RTO is a single geographic market.196 This new development has a far-reaching affect on applicants who may be able to “slide” in through a “loophole” as an RTO.
Another possible concern under the new market power test lies in determining accurate simultaneous transfer limits (“STL”s) are not generally available for all control areas at all peak times. Many assumptions are required to estimate STLs, and these have not been filed or litigated in open court all that often.197 The true STL in any one electric market is going to depend strongly on system conditions over multiple control areas over multiple spectrums of time.198 More generally, transmission providers and RTOs/ISOs must focus on providing timely and accurate grid data required for these analyses.
“The default cost-based rates that will be imposed on a party who fails the new market power test are: (1) the applicant’s incremental cost plus a ten percent (10%) adder for sales of power of one week or less; (2) an embedded cost “up to” rate reflecting the costs of the unit providing the service for sales of power of more than one week but less than one year; and (3) an embedded cost-of-service rate for sales of power for more than
194 Peter Fox-Penner and Romkaew Broehm, Deregulated Electricity Pricing in the U.S: Dramatic New
Rules from the FERC, April 2004.
one year, with the contract to be filed at the (FERC) for review.”199
“The two new forms of analysis and proposed mitigation measures are intended to be interim procedures pending a generic review of methods for comprehensively analyzing market power.”200 FERC has since initiated a rulemaking proceeding to determine (1) whether the FERC should retain or modify its existing test (i.e., (a) whether the applicant has generation market power; (b) whether the applicant has transmission market power; (c) whether the applicant can erect barriers to entry; and (d) whether there are other affiliate abuse or reciprocal dealing concerns) and (2) whether the FERC should promulgate specific regulations for market-based rate filings.201
D. Benefits of the New Market Power Test
Businesses and customers benefit from the new FERC screens because of the assurance that those utilities with generation market power will not be allowed to sell at market-based rates.202 Furthermore, less rate flexibility and more reporting requirements (and thus more transparency) for those found to have unmitigated market power will exist in time. In short, customers that purchase electricity in wholesale markets will benefit from the protection of not having to buy power at excessive rates from suppliers with market power.203 This protection will inevitably extend to all wholesale product markets (not just spot sales, as under the SMA analysis).204
Regulators will also benefit from the new screens.205 Regulators benefit by having
greater accountability from those found to have market power (through greater reporting
202 Statement of Paul R. Moul, Southern California Edison Company, Docket No. ER97-2355-000, at 1.
203 NERC, Reliability Assessment, 1999-2008 34 (May 2000).
requirements), which in turn will lead to greater transparency for all entities involved. Competitors that still have market-based rate authority will benefit from not being required to deal with the administrative obligations that will now be shouldered by their competitors with market power.206 These changes will thus lead to a more even playing field among companies in the electrical utility industry.
E. Drawbacks of the New Market Power Test
The drawbacks of the new market power test will not be evident for years to come. However, one drawback with the new market power, that is already present, involves declining market based rates to large sellers when a subsidiary or affiliate (of the large seller) possesses generation market power. Under the current rule, if a carrier in a geographically distant state from that of their subsidiary or affiliate qualifies for market based rates, and their subsidiary or affiliate does not qualify for market based rates, in most instances, the large seller/carrier will be denied market based rates. The rule is implicitly unfair and does not promote good policy going forward. The FERC must address this problem in the near future.
F. Businesses Coping
As the FERC transforms the electric industry from a regulated industry in which ratepayers receive tariffs based upon cost-of-service, to a commoditized business in which customers demand contracts based upon the best price, businesses must alter their business models to cope with the changes.207 The business model that results from the new market power test must require that utilities join RTOs to succeed in market-based
207 Patrick J. McCormick III & Sean B. Cunningham, The Requirements of the “Just and Reasonable” Standard: Legal Bases for Reform of Electric Transmission Rates, 21 Energy L.J. 389, 392-394 (2000).
As customers demand evolution in electricity pricing models, the ever-changing electrical-utility industry follows suit. The FERC’s new approach to market-based rates is a gigantic leap ahead in cleverness and consistency from that of the SMA and the “hub- and-spoke.” Parties now have a wide range of market alternatives predicated on a reasonable economic foundation of efficiency and fairness. This new ability ensures that a more efficient and effective pricing and economic market structure will arise in time. At the valence level, the FERC’s original checklist for allowing market-based rates “included three factors beyond an absence of generator market power: absence of transmission market power, absence of entry barriers, and affiliated company issues.”209 Market power ascendancy in the public and private utility sector must take the form of tests and mitigation, “always against a backdrop of changing industry structure, physical plant, and rules.”210 The road ahead (for the most part) seems brighter and more promising.
208 Patrick J. McCormick III & Sean B. Cunningham, The Requirements of the “Just and Reasonable” Standard: Legal Bases for Reform of Electric Transmission Rates, 21 Energy L.J. 389, 392-394 (2000). 209 Peter Fox-Penner and Romkaew Broehm, Deregulated Electricity Pricing in the U.S: Dramatic New Rules from the FERC, April 2004.
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Comparison of Wholesale Market Pricing Under Cost- and Market-Based Rates211
211 Taken from: Matthew H. Brown & Richard P. Sedano, A Comprehensive View of U.S. Electric Restructuring with Policy Options for the Future, Electric Industry Restructuring Series, National Council on Electricity Policy, at https://www.ncouncil.org/restruc.pdf (June 2003) (modified from original).
Effect of Uncommitted Shares on Market Power in Competitive and Uncompetitive Markets Under the “Hub-and-Spoke” Model212
212 Taken from: Steven Stoft, An Analysis of FERC’s Hub-and-Spoke Market-Power Screen, Prepared for Electricity Oversight Board of California, Contract No. 800-00-007, (2001).
Examples of FERC Market-Based Rate Tests (Simplified)213
Pivotal Supplier Analysis Examples:
Example 1: Market A has an annual peak load of 5,000 MW and the average daily peak in the annual peak month is 4,000 MW. The short-term demand for wholesale power (or wholesale load) as defined by FERC for Market A is 1,000 MW (5,000-4,000). The Applicant owns and controls 6,000 MW, and the uncommitted supply of competing suppliers, which includes those inside Market A and first-tier suppliers, is 3,000 MW. Applicant’s uncommitted capacity is 2,000 MW (6,000-4,000), yielding total uncommitted supply in Market A of 3,000 MW (2,000+1,000). The net uncommitted supply, therefore, is 2,000 MW, which is the total uncommitted supply minus the wholesale load (3,000-1,000).
Result: Applicant fails the test.
Example 2: Load conditions in Market A and Applicant’s generation are the same as those described in Example 1, but the uncommitted supply from competing suppliers is now 1,001 MW. The net uncommitted capacity is 2,001 MW, yielding one MW more than Applicant’s uncommitted capacity.
Result: Applicant passes the test.
Market Share Analysis Example:
|Firm||Uncommitted Capacity (MW)||Share (%)|
Firms A, C, D, and E are first-tier utilities in Market A, and Firm B is located inside the market. Total uncommitted capacity of the first-tier utilities is 3,150 MW but they can only import 1,500 MW into Market A due to the simultaneous transfer limit. While the uncommitted capacity of Firm B remains at 1000 MW, the uncommitted capacity of A, C, D, and E are reduced according to their pro rata share of transmission, i.e., 500, 143, 357, and 500 MW respectively. Thus, the market shares of Firms A, B, C, D, and E are 20, 40, 6, 14, and 20 respectively.
Result: Firms C and D pass the test. Firms A, B, and E either have to mitigate or conduct a DPT analysis.
Delivered Price Test Analysis:214
Available Economic Capacity (MW)
|Share (%) and HHI|
|A||750||549||25% / 622|
|B||700||700||32% / 1012|
|C||300||220||10% / 100|
|D||500||366||17% / 277|
|E||500||366||17% / 277|
|Total||2750||2000||100% / 2287|
Suppose five percent (5%) over market price in Summer-peak period of Market A is
$100/MWh and potential suppliers are the same as those in our market share analysis example. The DPT model would calculate market shares of potential suppliers in Market A along with the HHI based on each supplier’s economic cost of delivering power in Market A. Column  of Table 3 lists the amount of available economic capacity that each supplier can deliver to Market A. But since STL in Market A is 1,500 MW and the total potentially-available economic capacity from outside Market A is 2,050 MW, the transmission capacity must be allocated to Suppliers A, C, D, and E. Columns  and  present the shares and HHI results when the transmission capacity is allocated based on pro rata. In this example, Supplier E passes the test as its share is below twenty percent (20%) threshold and the HHI is 2287, which is less than 2500.