James Van Nostrand
September 5, 2013
Senator Joe Manchin (Dem., W.V) had scheduled a field hearing of the U.S. Senate Energy and Natural Resources Committee on the future of the coal industry, to be held in Morgantown on Wednesday, September 4. The hearing was postponed, given the events in Syria and the need for Senator Manchin to be in Washington, DC for meetings and hearings regarding U.S. military action. This author was asked to testify as part of the second panel at the hearing, regarding “Regulatory Hurdles for Cost Recovery for Coal Plant Maintenance and Upgrades.” Here is the testimony that I filed with the Subcommittee on Public Lands, Forests and Mining, and about which I will testify when the field hearing is rescheduled.
Coal-fired power plants are currently facing challenges on two fronts: Environmental regulations are requiring costly retrofits to address air and water pollution issues, while efficient natural gas-fired power plants are becoming increasingly cost competitive as natural gas prices remain low. In the face of these challenges, many coal-fired power plants have been identified by their owners/operators for retirement, with more likely to come over the next decade. According to a July 27, 2012 report from the Energy Information Administration (EIA), plant owners and operators have reported that they expect to retire almost 27 gigawatts (GW) of capacity from 175 coal-fired generators between 2012 and 2016. In 2011, there were 1,387 coal-fired generators in the United States, totaling almost 318 GW. The 27 GW of retiring capacity thus represents about 8.5 percent of total 2011 coal-fired capacity. More recent announcements of retirement plans suggest that by 2015, over 52 GW (or over 16 percent of the existing coal-fired generating capacity in this country) will be retired.
According to a July 31, 2012 report from the EIA, the generators most vulnerable to retirement are older generators with high heat rates (lower efficiency) that do not have flue gas desulfurization (FGD) systems installed. About 43 percent of all coal-fired plants did not have FGD systems installed as of 2010. Coal plants without FGD systems will likely be required to install either a FGD or dry sorbent injection (DSI) system to continue operating in compliance with the EPA’s Mercury and Air Toxic Standards (MATS).
The focus of this panel’s testimony concerns the impact of these retirements on the operations of existing, older plants, which will be forced to run more often than similarly aged plants have operated in the past. The issue we are asked to address is “[w]hat are the hurdles to upgrading these plants while keeping them economically competitive and within the rate base?”
The answer largely depends on the regulatory framework within which the coal plants operate, as the hurdles are far different for plants owned and operated by investor-owned utilities in traditional rate- regulated markets versus independent “merchant” plants that are dispatched through competitive wholesale power markets. (In this region, that wholesale power market is PJM.)
Traditional Rate-Regulated Coal Plants
As a general matter, the regulatory hurdles are lower for recovering the costs of upgrades for coal plants operated by investor-owned utilities in jurisdictions that use traditional rate-of-return regulation, such as West Virginia. Assuming the costs of these upgrades are found by regulators to be prudently incurred (as discussed further below), they can be included in the “rate base” upon which the utility earns a return, and any higher operating costs can be recovered in rates as well. Under traditional rate-of-return regulation, the utility recovers from retail customers a “revenue requirement” (RR) calculated by applying the following formula:
RR = (Rate Base X Rate of Return) + Operating Expenses + Taxes + Depreciation
The incremental capital costs associated with plant upgrades would be included in the rate base, and the utility in subsequent years would earn a return, or profit, on that investment at a rate equal to the weighted average cost of capital as determined by the regulators. [NOTE: The weighted average cost of capital includes the interest paid on outstanding debt, as well as a return on equity (ROE) on outstanding common stock. Assuming a 10.0 percent ROE and debt rate of 7.0 percent on outstanding debt, for example, the weighted average cost of capital would be 8.5 percent for a utility having a 50/50 capital structure (i.e., 50 percent debt and 50 percent common equity).] Operating expense includes any fuel and operating and maintenance (O&M) expenses associated with the plant, while depreciation would include an amortization of the capital investment in the upgrade over the plant’s expected useful life. [NOTE: Assuming a capital investment in upgrades of $500 million and a useful life of 25 years, for example, the utility would include $20 million each year as depreciation expense related to this investment in calculating its revenue requirement.]
While the calculation of the revenue requirement impact of capital investments in necessary upgrades may be relatively simple as a mathematical exercise, the analysis does not end there. There are a few considerations that come into play that may be characterized as “regulatory hurdles.” The first is the necessary finding, noted above, that the expenses were “prudently incurred.” Under the prudent investment standard uniformly followed by utility regulators, a utility must demonstrate that the course of action leading to the expense for which it is seeking rate recovery is reasonable and necessary. A utility seeking to recover in retail rates the costs of an upgrade to an existing coal plant would need to demonstrate to the satisfaction of regulators that this was a reasonable and necessary expenditure in the long-term interests of its ratepayers. This demonstration, typically in a contested case proceeding, would include an analysis of anticipated loads and resources (i.e., why the plant continues to be necessary to serve the anticipated loads of the utility), and a discussion of the alternatives available to the utility that may make this investment unnecessary (e.g., investments in other, cheaper generating resources, or demand-side management options such as energy efficiency and demand response (DR) programs).
A second possible hurdle is the requirement that the utility undertake a long-term system planning process known as “integrated resource planning” in its resource acquisition decisions. The Energy Policy Act of 1992 included a ratemaking standard that would require utilities to engage in “integrated resource planning,” which is defined as “a planning and selection process for new energy resources that evaluates the full range of alternatives . . . in order to provide adequate and reliable service to [an electric utility’s] customers at the lowest system cost.” Thirty-nine of fifty states have a rule or requirement for long-term planning or procurement, as noted in a Discussion Paper prepared by the Center for Energy and Sustainable Development. A key element of integrated resource planning is the requirement that demand- and supply-side resources be treated on a “consistent and integrated basis.” In other words, when a utility evaluates its options for meeting its future system needs, the utility must consider energy efficiency and conservation measures (demand-side resources) on the same footing as the addition of generating capacity (supply-side resources). This feature is the “integrated” aspect of integrated resource planning.
Another important element of integrated resource planning is the objective of achieving the “lowest system cost” for an electric utility’s customers. Integrated resource planning comes into play in the analysis of coal plant upgrades in a manner very similar to the application of the “prudent investment” principle, in that the utility would be required in a rate proceeding to demonstrate that the investment in the upgrade was consistent with a long-term planning process showing that this course of action would result in the “lowest system cost” over time for the utility’s customers, taking into account both supply- and demand-side options, and the availability of other alternatives that may have a lower revenue requirement impact over time. This is where the economic case for coal plant upgrades is essential, and may involve some of the same market factors that come into play in the case of merchant coal plants, discussed below. For example, the availability of cheaper and more efficient natural gas-fired plants, low wholesale power prices, or lower cost energy efficiency programs may suggest that the lowest cost, long-term resource acquisition strategy for utility customers lies on a path different than investing in the upgrades necessary to sustain a coal plant’s useful life.
A third possible hurdle is the challenge faced by utilities operating in multiple retail jurisdictions, and the implications of retail rate regulators reaching different decisions regarding the merits of a utility’s resource acquisition decisions. In West Virginia, for example, American Electric Power (AEP) and its subsidiary Appalachian Power (APCo) have faced the consequences of conflicting decisions from regulators regarding the ratemaking treatment of its resource acquisition decisions. In July 2012, AEP announced that it was abandoning its plan to build a full-scale carbon capture and sequestration (CCS) facility at its Mountaineer plant in West Virginia. While the West Virginia Public Service Commission (PSC) had approved APCo’s proposal for rate recovery of the costs associated with the CCS demonstration project in the case of APCo’s West Virginia ratepayers, the Virginia Corporation Commission (CC) rejected the proposal with respect to APCo’s Virginia ratepayers. Without rate recovery assured in both jurisdictions, a portion of the costs of the project would have been borne by AEP’s shareholders, thereby eroding the economic case for the project. More recently, the Virginia CC on July 31 rejected APCo’s proposed acquisition of portions of the Mitchell and Amos coal plants from an AEP affiliate. While they approved the Amos purchase, Virginia regulators rejected the purchase of Mitchell. Appalachian Power has a companion case currently pending before the West Virginia PSC. Without approval from regulators in both states, APCo will seemingly lack the authority to proceed with the purchase of Mitchell, regardless of the West Virginia PSC’s ruling on the issue. Thus, the need to obtain consistent regulatory treatment across jurisdictions represents a significant hurdle for multi-jurisdictional utilities operating in this region, and throughout the country. [NOTE: I have personal experience on this issue in his my representation of PacifiCorp from 1999 through 2007 while I was in private law practice in the Pacific Northwest. PacifiCorp operates in six Western states, and often faced under-recoveries due to inconsistent rate treatment of its generating resources from the six PUCs. This was particularly true with respect the rate treatment in the West coast jurisdictions of California, Oregon and Washington of the costs associated with its substantial fleet of coal-fired plants located in Wyoming and Utah.] While one commission may find that a utility sustained its burden to demonstrate that the investment in plant upgrades was reasonable and necessary and in the ratepayers’ interest, another commission looking at the same evidentiary record could reach a different conclusion and determine that the investment was imprudent, thereby thwarting the investment due to the utility’s legitimate concerns about rate recovery.
Another consideration, and a potential regulatory hurdle, is whether utility ratepayers can absorb the rate increases associated with coal plant upgrades. Electric utility ratepayers in West Virginia, for example, have borne substantial increases in electricity prices over the past decade as coal prices have doubled in response to worldwide demand. The price of delivered coal to the electric sector increased from $1.20 per million British Thermal Units (MMBtu) in 2000 to $2.64 per MMBtu in 2009a 220 percent increasefollowed by a decline to $2.39 per MMBtu in 2011, which still represents a price twice as high as prevailing prices in 2000. The electricity prices of the four utilities serving West Virginia, APCo and Wheeling Power (subsidiaries of AEP) and Monongahela Power and The Potomac Edison Company (subsidiaries of FirstEnergy), have similarly soared over this period, as the higher coal prices are ultimately reflected in electricity prices. From 2000 to 2011, AEP’s residential electricity prices increased by 68 percent, while FirstEnergy’s residential rates increased by 39.4 percent. While residential utility customers may be “captive” in that they have no alternative supplier, commercial and industrial customers have some ability, over the long run, to relocate their operations to surrounding utility service territories or regions with lower electricity prices (or at least the prospects of relatively stable electricity prices). Higher electricity prices can be a drag on a state’s ability to attract and retain industry, as large energy users can be expected to respond to higher energy prices by curtailing or ceasing operations in high-cost jurisdictions.
Related to the potential impacts on utility rates due to coal plant upgrades is the disparate impact of more stringent regulation of coal plant emissions across the regions of the country, which should be an important consideration for federal policymakers. Those states and regions with heavy dependence on coal-fired generation of electricity will bear a disproportionate economic impact flowing from the EPA’s adoption of more stringent emissions requirements for existing coal plants through MATS and the anticipated regulation of greenhouse gases from existing power plants. West Virginia’s net generation, for example, is 97 percent coal-fired, with Kentucky (93 percent) and Indiana (90 percent) close behind. Several other states have more than 70 percent coal-fired net generation, including Iowa (72 percent), Missouri (81 percent), Ohio (82 percent), New Mexico (71 percent), North Dakota (82 percent), and Wyoming (89 percent). With respect to regions of the country, the West North Central region, which includes seven Midwestern states, is 70 percent coal-fired, the East North Central regioncovering Ohio, Indiana and Illinoisis 63 percent coal-fired, the Mountain region is 55 percent coal-fired, and the East South Central region is 51 percent coal-fired. As utilities incur costs to meet the more stringent emissions requirements for coal-fired generation, ratepayers in these regions of the country will bear a disproportionate share of these costs through their utility bills. Correspondingly, the industries located in these regions will face a relative competitive economic disadvantage to their competitors located in other regions. Action at the Federal level may be necessary to address these regional disparities.
Merchant Coal Plants
The hurdles to cost recovery for plant upgrades in the case of merchant coal plants are far more daunting. Since the 1990s, the Federal Energy Regulatory Commission (FERC) has been following a consistentand largely successfulpath to promoting competition in the generation of electricity. Through Order 888, which required that transmission owners grant open, fair and non-discriminatory access to their transmission lines, and Order 2000, which encouraged the formation of regional transmission organizations (RTOs), FERC has created a competitive wholesale market for electricity. This competition has resulted in lower power prices at the wholesale level, and the benefits of these lower prices have generally flowed through to retail rates charged by local utilities.
The RTOs across the countryincluding PJM, which serves this regioncoordinate the competitive marketplace where energy and capacity are traded among buyers and sellers and manage the transmission grid within their region. PJM’s region, for example, covers 14 states and stretches from Illinois to New Jersey, and Pennsylvania to North Carolina, including the District of Columbia. Sellers of electric generation compete to offer their output in both the capacity marketsthrough periodic auctions for a forward periodand the energy markets, whether real-time or day ahead. As a general matter, the RTOs (sometimes referred to as ISOs, or Independent System Operators) dispatch generating plants according to their cost characteristics, with the lowest cost plants dispatched first (and most often), followed by higher cost plants in sequential order (based on cost) until market equilibrium is reached (i.e., a market-clearing price where the generating units on line are sufficient to meet the scheduled loads). FERC provides market oversight to ensure that regional wholesale markets are competitive, that no individual buyer or seller has market power, and that no price manipulation is occurring.
As a result of this competitive market structure, for plant owners it is all about costs and efficiency. In the case of fossil fuel-fired plants, it is all about heat ratesthe efficiency of converting the fuel source (coal or natural gas) to electricity. The lower the heat rate, the greater the efficiency, and the more likely the plant will be at the “low” end of the dispatch curve, i.e., “in the money” in that its costs are covered by the market-clearing price established through the regional competitive wholesale market. As an example, the Longview plant located just north of Morgantown uses the latest in supercritical pulverized coal (SCPC) technology, and thus operates at efficiency levels far greater than virtually all other coal plants in the nation’s fleet of coal plants, which have an average net heat rate of 10,600 Btu/kWh. Because of the low-cost characteristics of Longviewits heat rate of 8,728 Btu/kWh is far superior to the average of the coal plants in the PJM of 11,000 Btu/kWhit ranks very high in the dispatch order and the plant is “in the money” virtually 24 hours a day, 7 days a week. [NOTE: On August 30, 2013, Longview Power filed for bankruptcy protection, citing “construction failures and defects [that] have prevented the power plant from operating reliably at its designed capacity.” Having the capability to generate electricity efficiently is a separate issue from whether there are construction defects that affect the ability of the plant to operate reliably.]
According to the EIA, the coal plants most vulnerable to retirement are older generators with high heat rates (lower efficiency) that do not have flue gas desulfurization (FGD) systems installed. Most of the generators projected to retire are older, inefficient units primarily concentrated in the Mid-Atlantic, Ohio River Valley, and Southeastern U.S. where excess electricity generation capacity currently exists. The EIA has also analyzed the relative efficiency of the plants planned for retirement as compared with earlier retirements; according to its analysis, plants planned for retirement are moving up the efficiency curve (i.e., they are more efficient than previously-retired plants). By 2015, the retiring coal-fired units will have average tested heat rates of about 10,700 British thermal units per kilowatthour, which are approximately 12% more efficient than the group of units, on average, that retired during 2009-2011, but 5% less efficient than the average coal unit. Table 1 below shows the results of the EIA analysis.
Given the harsh realities of the competitive wholesale electricity market, it will be a significant challenge to maintain the competitiveness of coal-fired generation while bearing the additional burdens associated with the costs of necessary plant upgrades. As noted above, heat rates are a critical driver to the economic viability of coal plants. Recoverability of plant upgrade costs thus largely turns on whether these upgrades will lead to lower heat rates. Generally, the installation of emissions control technology lessens the efficiency of the generating unit, as emissions controls usually require additional electricity from the unit to operate. Moreover, it will be increasingly difficult for merchant coal plants to recover the capital costs associated with plant upgrades. Capacity prices in PJM are declining, meaning that plant owners will face a declining revenue stream to cover the capital investment. In the most recent PJM capacity auction, prices for the June 2016-May 2017 period were generally lower than for the year earlier period in the May 2012 auction. According to PJM, “[p]rices were generally lower than last year’s auction due to competition from new, gas-fired generation, low growth in demand because of the slow economy and increased imports from other regions, primarily to the west of PJM.” A PJM spokesman stated that almost 10,000 megawatts of coal-generated electricity did not “clear” the auction, meaning that it was not cost competitive with other sources offered.
In addition to the challenge of having a coal plant “in the money” in the PJM capacity and energy markets, another complicating factor is the reduced revenues for merchant coal plants that are being dispatched in PJM due to the tighter price differentials between natural gas and coal in recent years. A recent report by Dr. Susan Tierney of The Analysis Group describes how the lower market-clearing price established by natural gas-fired generation adversely affects the revenue stream of merchant coal plant operators:
“[T]he power supply curve . . . indicates that in the PJM region . . . coal‐fired power plants dispatched at higher prices in 2010 compared to 2007, with the reverse true for natural gas‐fired power plants. In this regional power market, the revenues for plants reflect the selling price of the last plant dispatched to meet loads. So, for example, a coal plant dispatched at a 125,000‐MW level of demand sold power at $24/MWh in 2007. At a higher demand level (e.g., 150,000) that same year, the clearing price would be $56/MWh, set by the dispatch of a natural gas plant. In that high‐demand hour, the referenced coal plant would receive revenues of $32/MWh (reflecting the $56/MWh clearing price less the coal plant’s own production cost (including fuel) of $24/MWh). By contrast, in 2010, the coal plant dispatching at 125,000 MW demand level sold power for $32/MWh, while the gas plant dispatched at a 150,000 MW load level was selling at $40/MWh. In 2010, therefore, the referenced coal plant would receive net revenues of $8/MWh in that high‐demand hour.”
Thus, even for a coal plant that is “in the money” and being dispatched by PJM, the lower market-clearing price arising from the improved cost characteristics of the natural gas-fired plant at the margin results in reduced revenues for the coal plant operator, thereby eroding the economic case for continued operation.
There is some good news for merchant coal plant operators in the region. Energy prices in the PJM Interconnection climbed by 21.6 percent in the first half of 2013. According to the report of the PJM Market Monitor, the price of natural gas in the first half of 2013 was higher than it was in the same period of 2012. Natural gas prices were above coal prices in the first months of 2013, with prices above $10/MMBtu for some days. Although coal prices also increased during the first six months of 2013, they remained relatively flat in comparison to 2012. These trends contributed to an increase in coal-fired generation relative to gas-fired generation. Coal units provided 44.3 percent of the power in the first half of 2013, compared with 40.3 percent in the first half of 2012. Gas-fired units provided 15.7 percent of the power in the first half of 2013, compared with 19.4 percent in the first half of 2012.
In addition, there is the possibility of the revenue stream provided by “reliability must run,” or RMR, contracts in the event PJM determines that some coal plants must continue to run to maintain reliability in the region. PJM recently requested that FirstEnergy continue to operate its Hatfield’s Ferry and Mitchell units in western Pennsylvania, which were scheduled for retirement by October 9, 2013. PJM expressed concern that FirstEnergy’s plan to retire the units will affect the reliability of the transmission grid and has asked the company to keep the plants operating. According to a spokesman for PJM, the upgrades to the transmission system that are needed to reduce the effects of the planned retirements will not be completed by the proposed retirement date. Rates for an RMR contract are determined by FERC rather than through the competitive marketplace.
The hurdles associated with recovering the cost of plant upgrades depend largely on the regulatory framework within which the coal plants operate. For plants owned and operated by investor-owned utilities in traditional rate-regulated markets, the ability to recover the plant upgrade costs in rates is relatively straightforward, assuming the costs are demonstrated to be prudently incurred and consistent with a reasonable long-term resource acquisition strategy. For utilities operating in multiple jurisdictions, the recovery can be more complicated, given the need to obtain consistent regulatory treatment from multiple commissions. The disparity of rate impacts across regions of the country suggests a need for federal action to address the issue, as states and regions with a greater dependence on coal-fired generation will bear a disproportionate burden of the costs associated with plant upgrades.
The challenges for cost recovery for independent merchant plants that are deployed through operation of competitive wholesale power markets are far greater. Coal plants already face significant competitive challenges from natural gas-fired generating resources, which have pushed some of the less efficient coal plants up the dispatch curve and “out of the money” and driven down the market-clearing price in wholesale markets, thereby reducing the revenue stream of the coal plants that remain operating. The addition of emissions controls on coal plants does not improve the cost-competitiveness of these plants. Moreover, the prices in the capacity markets are declining, imperiling the ability to recover the capital costs of plant upgrades. To a large extent, the hurdles will depend upon the spread between natural gas and coal prices, which more recently have been trending in coal’s favor.