Financial data raises doubts about whether deregulation benefits outweigh costs.
Margot Lutzenhiser is associate economist at the Public Power Council.
This year, U.S. electricity consumers will spend more than $1 billion financing the operation of six regional transmission organizations (RTOs).1 RTO costs have nearly doubled since 2001 and now outweigh nearly all of the benefits anticipated by the national cost-benefit studies.
Operating costs consist of salaries, employee benefits, leases, facility costs, legal and consulting services, amortization and depreciation on capital costs, insurance, travel expenses, and the like. Since 2000, the total annual U.S. RTO operating expenses increased by 143 percent-growing at an annualized rate of 20 percent per year (see Figure 1). Individually, the existing RTOs exhibit a similar trend. Costs at the Pennsylvania-New Jersey-Maryland Interconnection (PJM), the first to introduce a bid-based wholesale energy market, have grown from $21.4 million in 1997 to $215 million in 2004.2 With the most pronounced growth, spending by the Midwest Independent System Operator (MISO) jumped from $20.7 million in 2000 to a budgeted $210 million in 2004 (914 percent in 4 years).3 Others, like ISO New England (ISO-NE), orchestrated a slower expansion, increasing costs from $57.5 million in 1998 to a budgeted $122 million in 2004.4 Figure 2 displays the operating costs for each RTO/ISO including amortization, depreciation and interest (in 2003 dollars).
This upward trend reflects an expansion of the RTOs' organizational size and scope. The RTOs have grown in response to internal pressure (e.g., requests from members, staff directed projects) and external pressure (e.g., FERC initiatives, state regulation, and legislation). The Electric Reliability Council of Texas (ERCOT)-the only non-FERC jurisdictional RTO-is contained within the state of Texas and thus is not subject to FERC regulation, which applies only to interstate energy commerce. In response to state deregulation legislation, ERCOT expanded its staff and constructed two new buildings (an administrative headquarters and a new control center) in 2000. ERCOT quickly became Texas' single control area for Texas in 2001 and instituted a massive retail choice program in 2002. ERCOT and the Texas Public Utility Commission (PUC) are now undertaking a wholesale market redesign effort called Texas Nodal Pricing.
One measure of growth is how quickly a business adds employees. Figure 3 shows the employee levels for each of the RTOs.5
PJM systematically has added markets—some at the request of its membership. PJM was the first to introduce a bid-based wholesale energy market in 1997. The following year, a locational marginal pricing system (location-based energy prices reflect congestion on the transmission system) was implemented to manage congestion. PJM added real-time energy and capacity markets in 1999, and a spinning reserves market in 2002. Most RTOs have expanded in similar ways. ISO-NE launched a wholesale energy market in 1999; began a demand response program and created five new departments in 2002; and rolled out a major market redesign in 2003. In contrast, development of the California ISO often is described a "big bang" where the majority of functions were built into the initial market design and large investments were made upfront.
Most RTOs also have made considerable efforts to comply with FERC initiatives such as standard market design (SMD). ISO-NE implemented an SMD market redesign in March of 2003. New York ISO (NY-ISO), currently in the process of implementing SMD, is trailing close behind. MISO has integrated SMD into its market design (launch date March 2005), and PJM is working with MISO to develop a common market design. The California ISO is performing market simulations and is implementing the first stages of its SMD redesign (MD02).
Although it is easy to develop a laundry list of costs for each ISO, it is difficult to make an objective comparison without putting these numbers into a larger context. Three of the U.S. ISOs serve a single state (California, New York, and Texas), while the other three serve multiple states. To make a fair comparison, it is useful to consider the size of the area served by each RTO as measured by annual energy demand. MISO serves the largest electrical load, followed by PJM, ERCOT, California ISO, NY-ISO, and finally, ISO-NE.6 With the exception of PJM, the annual demand of the ISOs has remained fairly constant. Consequently, PJM is the only RTO whose budget has been driven, in part, by geographical expansion.
Annual demand provides an objective measure for comparing RTO operating costs. Although ISO New England has the lowest annual expenditure of any U.S. RTO, its dollar per megawatt hour ($/MWh) unit carrying cost is second only to the California ISO. Conversely, although PJM has one of the highest operating costs, its membership and geographical scope have expanded, and thus its unit carrying cost has remained among the lowest (see Figure 4). The weighted average carrying cost of the U.S. RTOs/ISOs for 2004 is $0.73/MWh (2003 dollars). MISO is excluded from this calculation because no reliable annual energy data are available.7
Review of Cost-Benefit Studies: Order No. 2000
In Order No. 2000, FERC asserts that its "best estimate of cost savings from RTO formation is $2.4 billion annually, with potential cost savings estimated to be as high as $5.1 billion annually. This represents about 1.1 percent to 2.4 percent of the current total costs of the U.S. electric power industry."8 This analysis is the result of an environmental assessment (EA) performed as a precursor to the order. The EA did not take into account RTO startup or operating costs. This year, existing RTOs in the United States will spend a little more than $1 billion (in operating costs) at a weighted average of $0.73/MWh. By applying this average rate to the remaining national load, we can estimate national RTO expenditure at $2.4 billion per year ($1.03 billion + $0.73 /MWh *1934 TWh).9 Assuming no increase in operating costs over 2004 levels, FERC's "best estimate" of benefits is completely offset by new annual costs.
Although the EA study ignored operating costs, FERC provided an explanation of its assumptions regarding costs. FERC replied that concerns over costs "fails to account for the flexibility we have built into this rule. ... Accordingly, we do not believe it will be necessary to expend the same level of resources that were expended, e.g., in California. ... The Final Rule will allow RTOs to create streamlined organizational structures that are not overly costly."10
Five years ago, when Order No. 2000 was written, the California ISO was spending from three to 10 times more than the other ISOs. Although the California ISO remains the most expensive, today it is not even twice as expensive as any of the other RTOs. While ISO-NE, NY-ISO, and ERCOT remain in the $120 million to $140 million per-year level, PJM and MISO closely trail California's level of spending ($229.2 million in 2004). Moreover, ERCOT is forecasted to match California's current spending level in the next three years ($228.6 million in 2007). Clearly, the California ISO is no longer an outlier.
Moreover, FERC asserted in Order No. 2000 that "with five ISOs now operating in the United States, there is considerable experience available regarding what works and what does not with respect to regional transmission entities. This experience should make it somewhat easier, and more cost-efficient, to create new RTOs."11 No doubt, the existing ISOs can provide volumes in the way of experience. However, keeping costs low does not seem to be one of them. In 2000, the average annual cost of the four established U.S. ISOs, excluding California, was $41.9 million per year. Average operating costs of the same four entities in 2004 is $160.5 million, nearly four times more.
In April 2003, the Department of Energy's Energy Information Administration (EIA) released a report titled Impact of the Proposed Federal Energy Regulatory Commission's Proposed Standard Market Design (SMD). SMD is a FERC initiative based on the assumption that all areas will be served by RTOs and that RTOs must to be standardized to remove impediments to functioning, competitive wholesale markets. The EIA study analyzes the costs and benefits associated with establishing nine new standardized RTOs, and converting four existing RTOs (California ISO, NY-ISO, PJM, and ISO-NE) to SMD. The study shows a benefit of $1.8 billion per year in the near term (2005-2010), $1.6 billion to $1.7 billion in the mid-term (2011-2015) and $1.5 billion in the long term (2016-2020).12
According to the data provided in the EIA study, the nine new RTOs would cover 65 percent (2,350 TWh) of the annual electricity demand (the study excludes ERCOT).13 Using updated data, the 2004 weighted average unit cost for NY-ISO, ISO-NE, California ISO, and PJM is $0.81/MWh. If ERCOT is added into the mix, the weighted average drops to $0.73/MWh. Multiplying the annual energy demand (provided in the EIA study) by the updated average carrying costs results in an annual cost for the remaining RTOs of $1.7 billion to $1.9 billion per year. In the near term, the net benefit is roughly zero ($1.8 billion in benefits minus $1.7 billion to $1.9 billion in costs equals $100 million to -$100 million), suggesting that RTO creation may have a neutral impact on consumers. In the mid term, the net benefit ranges from zero to -$300 million per year ($1.6 billion to $1.7 billion in benefits minus $1.7 billion to $1.9 billion in costs). In the long term, the net impact on consumers is -$200 million to -$300 million per year ($1.5 billion in benefits minus $1.7 billion to $1.9 billion in costs).
This is a liberal estimate of net benefits. The real negative impact of creating nine new standardized RTOs may be much larger. This estimate is based on the assumption that RTO costs will not increase over their 2004 levels. With the exception of the California ISO, no RTO shows signs of leveling costs. ERCOT's revenue requirement is slated to increase by roughly 60 percent in the next two years. In addition to conservative cost estimates, the theoretical benefits include income generated by increased transmission capacity in the four existing RTOs that are converted to an SMD platform. Removing these savings from the benefits calculation likely would tip the net benefits estimates into the negative realm for all time periods.
It should be noted that the EIA study also underestimated the costs of implementing SMD. It assumed zero incremental implementation cost for NY-ISO and ISO-NE, and limited increase for California ISO and PJM. In addition, it assumed that SMD generally would provide a 10 percent decrease in the annual operating cost of RTOs, resulting in an annual SMD cost of $0.22/MWh.14 Most RTOs have taken steps to implement SMD, resulting in increased operating costs and capital expenditures in 2003 and 2004.
FERC's Cost-Benefit Study
In 2002, FERC hired ICF Consulting to perform an economic assessment of RTO policy.15 ICF concluded that RTOs provide national annual benefits in the range of $405 million to $1.15 billion in the near term. As with FERC's earlier EA, ICF's study ignores the impacts of startup and ongoing operating costs. ICF claims that the projected $4.2 billion to $7.3 billion in startup costs "would be rewarded after several years with economic gains that appear to justify the initial expense."16 Further, ICF asserts that operating costs are a "relatively unimportant element of the overall economic impact of RTO policy once existing system operating costs are taken into consideration."
A cursory review of utility transmission operating expenses (i.e., considering a smattering of utilities in each RTO) indicates that RTOs have not, in aggregate, had the effect of decreasing utility-level operating costs. In some areas, such as California, the transmission operating expenses of the investor-owned utilities have increased substantially since the ISO was formed-226 percent for San Diego Gas and Electric Co. between 1997 and 2002, 23 percent for Pacific Gas and Electric, and 134 percent for Southern California Edison.17 If RTOs are not offsetting the operating expenses of utilities, then the additional costs of RTOs are an important element of the economic impact of RTO policy.
The range of benefits estimated by the ICF study varies widely depending on the assumptions used. Table 1 lists the assumptions used in two ICF model runs. The "RTO Policy" case is ICF's main model run (i.e., all other runs are variations of this case). The "Transmission Only" case is identical to the "RTO Policy" case with one exception-it does not include assumptions regarding generator improvements (6 percent improvement in heat rates, and a 2.5 percent improvement in generator availability). As shown in Table 2 on page 43 the magnitude of RTO benefits rely strongly on the assumed generator improvements.
Assuming that the benefits remain constant between the years listed in the ICF study (i.e., $405 million for the "Transmission Only" case benefits in 2004-2005, $356 million in 2006-2009, and so on), then the total estimated benefit for the "Transmission Only" case between 2004 and 2020 is $11.4 billion dollars. As previously described, applying the current 2004 $/MWh rate to non-RTO regions results in an estimated $2.4 billion per year to support nationwide RTO operations. Assuming no escalation, RTO costs between 2004 and 2020 would amount to $40.8 billion. The "Transmission Only" case over this time period would thus leave a net deficit of $29.4 billion.
Using the same assumptions, annual RTO costs exceed the benefits from the "RTO Policy Case" in the near term, accumulating a net deficit of $3.5 billion between 2004 and 2009. Consider a third case where benefits fall halfway between the "RTO Policy" level and the "Transmission Only" level (2004-$742.5 million, 2006-$1,272.5 million, 2010-$3,001 million, 2015-$3,562 million, 2020-$4,380.5 million). Again, in the near term, the costs outweigh the benefits, accruing to a net deficit of $7.8 billion by 2009. In 2010, the net benefit calculation turns to a positive $601 million ($3 billion in benefits minus $2.4 billion in costs). The deficit from the previous years ($7.8 million), however, nets out the small positive benefits until the year 2019.
RTO costs more than completely subsume benefits from transmission improvements (no transmission rates, low export fees, lowered reserve margins, increased capability, and increased capacity sharing). For regions where improvements in heat rates are likely to be small, the costs appear to outweigh by far the benefits. To provide net benefits between 2004 and 2020, the nation must realize at least half of the assumed generator improvements.
It should be noted that the "RTO Policy Case" is the second most optimistic model run provided in the study and assumes only five RTOs (including ERCOT). Several RTOs have engaged in merger discussions (MISO/PJM, NYISO/ISO-NE, MISO/Southern Power Pool [SPP]), though no mergers have been implemented to date. Consequently, the assumption of four large RTOs and ERCOT is unrealistic in the near term.
In conclusion, so far, the war over deregulation has been fought with rhetoric by the true believers and the naysayers. FERC appears to fall in the true-believer camp-its policy on RTOs was not based on a comprehensive analysis of the possible costs, benefits, and risks. Rather, it was based in an optimistic assumption-"competition in wholesale electricity markets is the best way to protect the public interest and ensure that electricity consumers pay the lowest price possible for reliable service."18
Unfortunately, the path to competitive wholesale power markets has been littered with market crises (most notably but not uniquely in California), bankruptcies (among them, Pacific Gas & Electric, Texas Commercial Energy, Mirant, Enron, NRG, and Northwestern Corp.), and near bankruptcies (such as energy marketers Aquila Energy, Allegheny Energy, and Reliant Energy). Moreover, competition has not produced the highly touted price reductions. Some, like former Enron CEO Kenneth Lay, argued that state restructuring should be expected to produce savings of 20 percent to 40 percent (in a 1998 letter to then Gov. George Bush).19 Generally, state legislators and regulators were promised that deregulation would lower retail rates in the near term. In an attempt to ensure success, protect retail customers, and smooth over the transition to deregulated markets, many states (among them California, New Jersey, Ohio, Maryland, Illinois, and Virginia) instituted retail rate caps or mandatory rate reductions.
In many cases, customers face large rate increases when caps are removed. New Jersey is a particularly bad case; utilities racked up deficits (or "deferred balances") of more than $1 billion while rate caps were in place (1999-2003). This translated to a $171 to $794 per customer bill, depending on which utility served them.20 In California, the average residential electricity bill increased 20 percent between 1997 and 2002.21 This July, rate caps were removed for a few Maryland utilities-Pepco raised residential rates 16 percent and Conectiv raise them 12 percent.22 Similarly, residential power prices in Texas increased 16 percent between 2000 and 2003.23
The success or failure of deregulation cannot alone be measured by these rate increases. Additional factors such as increased fuel prices directly influence energy prices. Still, restructuring the energy industry was more costly and more risky than anticipated, and reasonable estimates of RTO costs outweigh nearly all of the benefits anticipated in the national cost-benefit studies. Considering the escalation in both prices and RTO costs, additional analysis clearly is needed to determine whether restructured markets are, in fact, providing net benefits.
Operating Costs, Amortization, Depreciation, and Interest Expense: 1997-2003 (FERC Form 1 submissions); 2004 (Approved 2004 Budget and Service Category Rates, 10/28/2003).
Annual Energy: 1997-1999 (1999 Annual Report on Operations); 2000 (2000 Annual Report on Operations); 2001 (2001 Annual Report on Operations); 2002-2003 (Corresponding Annual Reports); 2004 (Approved 2004 Budget and Service Category Rates, 10/28/2003).
Staffing Levels: 1998-2001 (FERC Form 1 submissions); 2002 (448 employees as of 9/30/2002 noted in PJM's 2002 3rd Quarter Financial Statement); 2003 (NYISO 2003 Budget Review for the Budget, Performance, and Standards Committee, 9/30/2002).
Startup Costs: PJM staff indicated that they have not calculated their overall startup costs. Estimate provided by the Ontario IMO 2001-2003 Business Plan, 11/13/2000, p. 41.
New York ISO
Operating Costs, Amortization, Depreciation, and Interest Expense: 2000-2003 (FERC Form 1 submissions); 2004 (NY-ISO 2004 Budget Report for the Budget, Standards and Performance Subcommittee, 11/12/2003).
Annual Energy: 2000-2002 (NYISO 2003 Gold Book - Load and Capacity Data); 2003-2004 (Backed into using revenue requirements and $/MWh rates in NYISO 2004 Budget Report, 11/12/2003).
Staffing Levels: 2000 (Annual Report); 2001 (NY-ISO Budget vs. Actual Results, February 2002); 2002 (2003 Budget Review, 9/30/2002); 2003-2004 (2004 Budget Overview, 9/26/2003).
Startup Costs: Tabors Caramanis RTO West Cost Benefit Study, 3/11/2002.
ISO New England
Operating Costs, Amortization, Depreciation, and Interest Expense: 1998-2002 (Corresponding Annual Reports); 2003 (2003 Final Audited Financial Statement, 3/3/2004); 2004 (ISO-NE March Forecast for End of Year 2004, March 2004).
Annual Energy: 1998-2004 (1999-2004 Annual Capacity, Energy, Loads, and Transmission (CELT) Reports, Note: 2004 is a forecast).
Staffing Levels: 1998-2001 (FERC Form 1 Submissions); 2002 (Annual Report); 2003 (NYISO 2003 Budget Review, 9/30/2002); 2004 (ISO-NE March Forecast for End of Year 2004, March 2004, Note: Projected FTE).
Startup Costs: FERC order, "Accepting for Filing and Suspending Cost Recovery Proposal, Subject to Refund and Establishing Hearing", Docket No. ER99-4235-000, 10/13/1999.
Operating Costs, Amortization, Depreciation, and Interest Expense: 1998-2002 (FERC Form 1 submissions); 2003 (December Monthly Financial Report, 12/31/2003 Note: Actual 2003 numbers - unaudited); 2004 (Proposed FY2004 Operating & Maintenance Budget and Capital Budget, 9/18/03).
Annual Energy: 1998 (2000 Annual Report on Market Issues and Performance, November 2001); 1999-2001 (2002 Annual Report on Market Issues and Performance, April 2003); 2002-2003 (2003 Market Performance Review from the Office of Market Analysis, April 2004); 2004 (Proposed FY2004 Operating & Maintenance Budget and Capital Budget, 9/18/03).
Staffing Levels: 2000-2001 (FERC Form 1 submissions); 2002 (Proposed FY 2003 Budget, 10/16/2002, Note: "revised and approved staffing" level); 2003 (December Monthly Financial Report, 12/31/2003); 2004 (Proposed FY2004 Operating & Maintenance Budget and Capital Budget, 9/18/2003 Note: projected FTE).
Startup Costs: Financing Plan Execution, 4/23/1998.
Operating Costs, Amortization, Depreciation, and Interest Expense:
2000-2003 (2003 Annual Report); 2004 (2004 Texas PUC rate filing [Docket No. 28832]).
Annual Energy: 2000-2004 (2004 Texas PUC rate filing -Docket No. 28832, Note: 2001-2002 are actuals, 2003 is part actual and part budgeted and 2004 is budgeted).
Staffing Levels: 2000, 2001, 2003 (2003 Annual Report); 2002 (Estimate based on rate filing information); 2004 (2004 Texas PUC rate filing [Docket # 28832]).
Startup costs: Tabors Caramanis RTO West Cost Benefit Study, 3/11/2002.
Operating Costs, Amortization, Depreciation, and Interest: 2000-2003 (Corresponding Annual Reports); 2004 (Updated 2004 Budget Presentation, 3/18/2004, Note: original budget from MISO Budget Advisory Committee Presentation, 12/10/03).
Annual Energy: MISO does not collect or compute annual energy demand at this time. An estimate of MISO's annual demand provided in the EIA cost benefit report entitled Impact of the Proposed Federal Energy Regulatory Commission's Proposed Standard Market Design, April 2003, p.14.
Staffing Levels: 2000 (MISO Order 2000 Compliance Filing [RT01-87-000]; 1/16/2001); 2001, 2002, 2004 (2004 Budget Advisory Committee Presentation, 12/10/2003.); 2003 (2003 Annual Report).
Startup Costs: MISO 2000 Annual Report
Operating Costs, Amortization, Depreciation, and Interest Expense: 1999-2002 (Corresponding Annual Reports); 2003 (2003 Final Audited Financial Statement, 1/12/04); 2004 (IMO Business Plan 2004-2006 Financial Overview, 9/30/2003).
Annual Energy: Demand Overview section of Ontario IMO's Web page: http://www.theimo.com/imoweb/media/md_demand.asp.
Staffing Levels: 2000, 2002 (IMO Business Plan 2001-2003, 11/13/2000); 2002 (Annual Report); 2003-2004 (IMO Business Plan 2004-2006 Financial Overview, 9/30/2003 Note: 2003 is projected, 2004 is budgeted).
Startup Costs: Ontario IMO 2001-2003 Business Plan, 11/13/2000.
Total U.S. Annual Demand: North American Electric Reliability Council (NERC) 2003 Electricity Supply and Demand Database.
1. The California Independent System Operator (California ISO), New York ISO (NY-ISO), Pennsylvania-New Jersey-Maryland Interconnection (PJM), Midwest ISO (MISO), ISO New England (ISO-NE) and the Electric Reliability Council of Texas (ERCOT). "RTO" is used in this article as a general term to include both regional transmission operators and independent system operators.
2. 1997 PJM FERC Form 1 Submission (2003 dollars); Approved 2004 Budget and Service Category Rates, 10/28/2003.
3. 2000 Annual Report; Updated 2004 Budget Presentation, 3/18/2004.
4. ISO-NE 1998 Annual Report (2003 dollars); ISO-NE March Forecast for End of Year 2004, March 2004 (2004 dollars).
5. Many of the RTOs do not consistently report staffing levels. Whenever staffing data reported consultants they were excluded, so that the data as closely as possible represents the core staff of each organization.
6. MISO does not collect or compute annual energy demand, so this is based on an estimate taken from Energy Information Administration report, Impact of the Federal Energy Regulatory Commission's Proposed Standard Market Design, April 2003, p.14 Table 3.2.
7. Once MISO's wholesale market design is in place, it will calculate annual energy.
8. 18 CFR Part 35, Order No. 2000, Docket No. RM99-2-000, pp. 95-96.
9. Calculated using RTO/ISO annual demand levels (data sources by ISO/RTO in endnotes) and projected 2004 U.S. annual demand reported in the North American Electric Reliability Council's (NERC) 2003 Electricity Supply and Demand Database.
10. Id. p. 91.
11. Id. p. 91-92.
12. Impact of the Federal Energy Regulatory Commission's Proposed Standard Market Design, April 2003, p. 23 Table 3.6, (Same near and long-term results for both 5 percent and 10 percent increase in tax capability cases).
13 Id. p. 14 , Table 3.2, (excludes ERCOT).
14. ICF Economic Assessment of RTO Policy, 2/26/2002, Docket No. RM01-12 (http://www.ferc.gov/industries/electric/indus-act/rto/cost/02-26-02-repo...).
15 Id. p. 79.
16. FERC Form 1 data for each utility.
17. ICF Economic Assessment of RTO Policy, 2/26/2002, Docket No. RM01-12, p. vi.
18. Letter sent 11/16/98 available at http://www.thesmokinggun.com/archive/bushlay11.html.
19. State of New Jersey Deferred Balances Task Force Report, 8/30/02 p. 1.
20. EIA data: Historical 1990 through Current Month Retail Sales, Revenues, and Average Retail Price of Electricity by State and by sector, available at http://www.eia.doe.gov/cneaf/electricity/page/at_a_glance/sales_tabs.html.
21. Average Retail Price of Electricity by State and by Sector, available at: http://www.eia.doe.gov/cneaf/electricity/page/at_a_glance/sales_tabs.html.
22. Maryland Office of People's Council Web site announcement, "People's Council to Assist Pepco and Connectiv's Residential Customers with Electricity Rate Increases" at http://www.opc.state.md.us/.
23. EIA data source listed above.