College of Law Center for Energy and Sustainable Development

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Articles tagged with: coal

9 Jan

Beren Argetsinger
January 9, 2014

On September 20, 2013, the US Environmental Protection Agency (EPA) issued proposed new source performance standards (NSPS) for carbon dioxide (CO2) emissions from new electric power plants pursuant to Section 111(b) of the Clean Air Act (CAA). EPA published the rules in the Federal Register today, officially marking the start of the 60 day public comment period. Comments must be received by EPA on or before March 10, 2014.

Because power plants emit nearly 40 percent of total greenhouse gas (GHG) emissions in the US, significant emission reductions from the power sector is crucial to meeting long-term climate and clean energy goals. Today’s rules will set the first uniform national limit on the amount of carbon pollution allowed from future power plants and are fundamental to achieving the broader climate and energy goals set forth in President Obama’s Climate Action Plan, announced in June 2013, and the Obama Biden Energy Plan. Together, these plans set a goal of achieving a 17 percent reduction in CO2 emissions by 2020 from 2005 levels and an 80 percent reduction by 2050.

Under the proposed rules, future coal plants will be required to meet an emission standard of 1,100 lbs of CO2/MWh. EPA estimates that even the most efficient coal plants being constructed today emit approximately 1800 lbs of CO2/MWh, on a net basis. EPA identified partial carbon capture and storage technology as the best system of emission reduction (BSER) available for future coal plants to meet the new standards. New natural gas fired power plants will be required to meet an emission standard of 1,000 lbs of CO2/MWh for large units and 1,100 lbs of CO2/MWh for small units. Because natural gas plants release approximately half the CO2 as coal plants, most new natural gas plants will not require the addition of CCS, or other pollution control technology, to meet the new standards.

The World Coal Association (WCA), which advocates for the deployment of a full range of energy efficient and low carbon technologies to address the challenge of climate change, notes that CCS is a proven technology that has been in use for decades. CCS has only recently been coupled with power plants to reduce CO2 emissions however, and applying the technology to the power sector has proven expensive. Cost of pollution control is only one factor EPA considers when setting NSPS. EPA also considers whether the standards will foster continued innovation and development in pollution control technology. EPA addressed this issue in today’s rule stating “a determination that [high efficiency generating] technology alone, as opposed to CCS, is the BSER [Best System of Emission Reduction] for CO2 emissions from new coal-fired generation likely would inhibit the development of technology that could reduce CO2 emissions significantly, thus defeating one of the purposes of the CAA’s NSPS provisions.” The ability of a standard to incentivize technological innovation has long been a guiding principal in setting performance standards under the CAA and today’s rule reflects that central tenant of CAA implementation.

Next Steps

The 111(b) NSPS rules regulating CO2 emissions from new power plants are expected to be finalized by June 1, 2014. At that time, EPA is expected to propose rules to regulate CO2 emissions from existing power plants pursuant to section 111(d) of the CAA. Those rules are expected to be finalized by June 1, 2015 along with a requirement that states submit state implementation plans by June 30, 2016. The Center for Energy and Sustainable Development will be presenting a conference on February 24, Regulation of CO2 Emissions from Power Plants: Flexibility and the Path Forward for Coal Dependent States, that will examine issues surrounding the EPA’s anticipated rules governing emissions from existing power plants.

28 Oct

Beren Argetsinger
October 28, 2013

S. 1392 and H.R. 1616: Energy Savings and Industrial Competitiveness Act of 2013

Energy efficiency programs across the country offer energy and cost savings for consumers and support thousands of jobs. The reduction in CO2 emissions achieved from energy efficiency may also count toward compliance with forthcoming EPA regulations aimed at reducing CO2 emissions from power plants. Earlier this year, the Senate Committee on Energy and Natural Resources overwhelmingly passed the “The Energy Savings and Industrial Competitiveness Act of 2013,” S. 761. The bill was introduced by Senators Jeanne Shaheen (D – N.H.) and Rob Portman (R – Ohio) to encourage greater use of energy efficiency technologies in residential, commercial and industrial buildings, and foster new job creation. The Senators introduced S. 1392, a revised version of S. 761, for consideration on the Senate floor at the end of July. It was subsequently removed from the Senate calendar, however, to make room for the budget and debt ceiling discussions. With those issues temporarily resolved, energy watchers are looking for the Senate to put the bill back on the calendar.

Major provisions of the Shaheen-Portman bill include: directing the Department of Energy (DOE) to develop model building codes to make new homes and commercial buildings more energy efficient; assistance to states to develop and adopt codes that exceed the model codes; authorizing DOE to provide grants to universities for career training in the design and operation of energy efficient buildings; revision of industrial efficiency programs at DOE to promote efficient manufacturing technology; establishment of the Supply Star program to identify and promote practices, companies and products that use highly energy efficient supply chains; and guidance to federal agencies on adopting energy efficiency protocols.

The economic impacts of the bill were recently analyzed by the American Council for an Energy Efficient Economy (ACEEE). According to the ACEEE, the bill would create between 66,000 and 81,000 jobs, and save $2.1 – $3.3 billion by 2020. In addition to direct benefits of job creation and cost savings, the ACEEE report estimated the bill would achieve between 16.4 – 25.1 million tons of carbon dioxide (CO2) emissions reductions by 2020. CO2 emission reductions from energy efficiency may provide important benefits to power plants under new EPA rules.

Pursuant to its authority under the Clean Air Act, the U.S. EPA is expected to propose rules that will limit CO2 emissions from existing power plants in June 2014. The rules are expected to take effect by June 2015. Many states, regulated entities, environmental organizations, and other stakeholders maintain that energy efficiency represents the most cost-effective means to meet CO2 emission reduction standards and are urging EPA to allow energy efficiency savings to count toward compliance with the new rules.

A recent World Resources Institute (WRI) report found that Pennsylvania’s Energy Efficiency Resource Program has the state on track to achieve an 11% reduction in CO2 emissions from 2011 levels from the power sector by 2020. Energy efficiency represents a significant portion of the reductions Pennsylvania is achieving through existing policy mechanisms that have the state on track to meet “moderately ambitious” future emission standards for existing power plants. States that rely heavily on coal-fired electric generation, such as West Virginia, are especially likely to find energy efficiency an attractive strategy to reduce energy costs for consumers, support new job creation and provide cost-effective tools for power plants to comply with new EPA rules.

Representatives David McKinley (R – W.V.) and Peter Welch (D – Vt.) introduced H.R. 1616, the House version of the Energy Savings and Industrial Competitiveness Act in April. While not identical, the House and Senate bills include many similar provisions. The Shaheen-Portman and McKinley-Welch bills support greater use of energy efficiency technologies, foster new job creation and enhance the ability of states to develop energy efficiency programs. Congress should take action on this legislation to support state efforts to reduce energy costs for consumers and provide additional resources for power plants to comply with new EPA rules.

2 Oct

James Van Nostrand
October 2, 2013

International Energy Agency
September 2013

World Energy Outlook Special Report 2013: Southeast Asia Energy Outlook

A new report issued by the International Energy Agency, Southeast Asia Energy Outlook, predicts that Southeast Asia’s demand for energy will spike more than 80 percent by 2035, with coal as the “fuel of choice” for the region’s exploding power sector. According to the report, electricity generation between 2011 and 2035 will increase by more than the current power output of India. Coal’s relative abundance and affordability in the region boosts its share of electricity generation from less than one-third today to almost one-half in 2035, mainly at the expense of natural gas and oil. This shift is already underway, with about three-quarters of the thermal capacity now under construction being coal-fired. The report notes that the average efficiency of the current fleet of coal plants is only 34%, and thus deploying more efficient coal-fired plants should be a major priority in the region. Most of the plants currently under construction, however, are not taking advantage of the latest technology; 70 percent of the coal-fired plants under construction in the region were subcritical designs, the least efficient.

As the Appalachian region struggles with declining coal production, the impact of coal plant closings, and the anticipated impact of EPA regulation of greenhouse gases from new and existing coal plants, it is worth noting that the global trend will be far different. Developing nations are quickly ramping up their electricity generation, and coal remains the “fuel of choice” for baseload generation.

5 Sep

Recovering the Cost of Coal Plant Upgrades

Samantha | September 5th, 2013

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 2009—a 220 percent increase—followed 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 region—covering Ohio, Indiana and Illinois—is 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 consistent—and largely successful—path 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 country—including PJM, which serves this region—coordinate 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 markets—through periodic auctions for a forward period—and 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 rates—the 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 Longview—its heat rate of 8,728 Btu/kWh is far superior to the average of the coal plants in the PJM of 11,000 Btu/kWh—it 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.

TABLE 1

09.05.13 Table 1

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.

Conclusion

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.

17 May

James Van Nostrand
May 17, 2013

CERES, Natural Resources Defense Council
May 2013

Benchmarking Air Emissions of the 100 Largest Electric Power Producers in the United States

Despite an increase in overall electricity generation, the nation’s largest power producers cut emissions of major air pollutants in 2011, according to a new report from CERES and Natural Resources Defense Council. According to the report, the increase in the use of natural gas (due to low prices) and the adoption of renewable energy resulted in reduced emissions of nitrogen oxide (NOX), sulfur dioxide (SO2) and carbon dioxide (CO2) in 2011. CO2 emissions have dropped steadily since 2007. Although CO2 emissions have increased by 20 percent since 19990, emissions have gone down by 7 percent between 2008 and 2011.

The report is based on data from the Energy Information Administration and the EPA, and focuses on the top 100 power producers, which accounted for 86 percent of the electricity produced in the United States in 2011. AEP, which serves West Virginia through its Appalachian Power subsidiary, is the second largest electricity producer in the country, and the largest CO2 source. FirstEnergy, which serves portions of West Virginia through its Mon Power and Potomac Edison subsidiaries, is the fourth largest emitter of CO2 in the country.

The report also broke down CO2 emissions by state and found that states with a larger coal share generally had the highest CO2 emission rates. For example, Wyoming, which has an 86 percent coal share, and Kentucky, which has a 93 percent share, had the highest CO2 emission rates. West Virginia, with its 96 percent reliance on coal-fired generation, had the third highest CO2 emissions rate, and the tenth highest level of total CO2 emissions. Texas had the highest total CO2 emissions. The report observes that “[o]ne of the challenges in developing a policy to regulate power plant CO2 emissions will be to design an approach that recognizes the wide variability in the carbon intensity of the electric generating fleet.”

10 May

James Van Nostrand
May 5, 2013

Charleston Gazette
March 30, 2013

Sales of Coal Power Plants Raise Concerns
Ken Ward

As reported by Ken Ward in the Charleston Gazette, a number of questions are being raised about FirstEnergy’s proposal to transfer ownership of 80% of the Harrison coal plant to Mon Power. The Harrison coal plant is a huge, 1984-megawatt (MW) facility built in the early 1970s in Haywood, West Virginia. Mon Power currently owns 20% of the plant, and the remaining 80% is owned by an unregulated FirstEnergy affiliate, Allegheny Energy Supply Company. Due to coal plant closings, Mon Power is purportedly 938 MW short of capacity, and is proposing to acquire the 1576 MW installed capacity in Harrison that it does not already own. (As part of the deal, Mon Power is proposing to sell 100 MW of capacity in its Pleasants Power Station to AE Supply, for a net capacity addition of 1476 MW.) Approval of the proposed deal is currently pending before the West Virginia Public Service Commission (PSC).

From this author’s analysis of the application to the PSC, the proposed deal is a bad one for Mon Power ratepayers (and the author is one such ratepayer), and should be rejected by the PSC. Perhaps the terms of the deal can be rehabilitated through conditions that the PSC could attach to its approval. As currently proposed, however, the application is sorely deficient, and fails to meet the “public interest” standard necessary for its approval. The deficiencies include the following:

The Proposed transaction would give Mon Power more capacity than it needs, thereby precluding any role for energy efficiency, natural gas-fired generation, or wholesale market purchases. As noted above, Mon Power claims to be 938 MW short of capacity in 2013, and the transaction would add 1476 MW of new capacity (1576 MW from Harrison, less 100 MW of Pleasant being sold). Thus, Mon Power’s capacity needs will be much more than filled by additional coal plant capacity. Given the excess capacity situation that would be created, there will be a strong disincentive for FirstEnergy to promote energy efficiency (which would simply exacerbate the excess capacity position). Moreover, there will be no room in Mon Power’s resource strategy for the possibility of including some natural gas-fired generation in its portfolio of resources. Finally, there will be no room in Mon Power’s resource strategy for wholesale market purchases, which are substantially cheaper than the Harrison plant acquisition. PJM wholesale prices are down 29% over the past year, due largely to cheap natural gas-fired generation, and wholesale prices are likely to remain relatively low for the foreseeable future. By filling its entire capacity needs (and then some) with the Harrison plant purchase, Mon Power will be precluded from pursuing other, cheaper options, such as energy efficiency, natural gas-fired generation, and purchases from the wholesale market. The Center for Energy and Sustainable Development has prepared a Discussion Paper on Integrated Resource Planning that highlights the reasons for a diversified portfolio mix, including natural gas-fired generation, renewable energy resources, and energy efficiency.

FirstEnergy completely ignores energy efficiency as an alternative, even for a portion of the needed capacity. FirstEnergy’s “Resource Plan” states that “demand side resource options are not a viable solution capable of meeting Mon Power’s obligations . . . [as they] do not address energy shortfalls as significant as the shortfall faced by Mon Power.” [Resource Plan, p. 56] Admittedly, energy efficiency programs cannot be ramped up quickly enough to make up a [claimed] capacity deficit of 938 MW. But energy efficiency, at 3-4/kWh, is substantially less than the 7.4/kWh that FirstEnergy is proposing to charge Mon Power customers for Harrison’s output. FirstEnergy needs to start treating energy efficiency as a resource, alongside supply-side options; this is a good proceeding to illustrate the comparative advantages of investments in energy efficiency versus buying an over-priced 40+ year-old coal plant. FirstEnergy has virtually no energy efficiency program offerings for its West Virginia customers, to help them manage their energy costs. First Energy’s energy efficiency programs in West Virginia were established to save 0.5% in 5 years, which is lower than the level being achieved in 40 other states. As far as actual results, FirstEnergy didn’t even reach 0.1% savings in the first year. The Center for Energy and Sustainable Development has prepared a Discussion Paper on Energy Efficiency that makes the case for increased investments in energy efficiency in West Virginia, and by FirstEnergy in particular.

The price for the Harrison plant acquisition is inflated far above what utility regulators ever would allow, by reference to generally accepted ratemaking principles. The net book value of the plant, based on “original cost depreciated” (the basis for ratemaking under the FERC Uniform System of Accounts, and followed by virtually every PUC in the country), is $574 million [$1.24 billion less $667.3 million in accumulated depreciation]. FirstEnergy is proposing to include an “acquisition adjustment” of $589.6 million that would more than double the acquisition cost of the plant for West Virginia ratepayers, to $1.163 billion. This “acquisition adjustment” is purportedly based upon “a purchase accounting fair value measurement component . . . related to the completion of the FirstEnergy/Allegheny merger in February 2011.” [Wise Testimony, p. 7] FirstEnergy claims that without PSC approval to include the unamortized portion of the acquisition adjustment in rate based until it is fully amortized, “Mon Power will not proceed with the transaction.” [Wise Testimony, p. 7] As a regulatory attorney for 22 years in the Pacific Northwest who has handled the regulatory approvals for 7 different merger deals in front of 6 different PUCs in the West, this author can represent that these “fair value adjustments,” also known as “goodwill” adjustments, are NEVER recovered from utility ratepayers. Regulatory ratemaking principles simply do not allow it; rates are based on original cost depreciated of rate base assets, not some “fair market value adjustment” based on some utility deciding to overpay to acquire another utility. There is no basis for ratepayers being burdened with FirstEnergy’s foolish decision to overpay to acquire Allegheny. Most regulatory approvals of mergers, and all 7 of the deals in which this author was involved, impose conditions precluding the utility from ever seeking to recover such acquisition adjustments in rates. While this author has not personally reviewed the order approving the FirstEnergy/Allegheny merger, it is my understanding that FirstEnergy agreed to such a condition in connection with receiving regulatory approval of the merger.

The numbers for the transaction defy common sense, apart from what generally accepted ratemaking principles or the Uniform System of Accounts require. The value of the 20% of the Harrison plant already owned by Mon Power on its books is $319/kW, while the proposed purchase price for the remaining 80% is $767/kW. This price disparity is inexplicable, given that there is nothing physically different in the four-fifths of the plant not owned by Mon Power versus the one fifth of the plant that Mon Power already owns. Are the electrons coming from the Allegheny Energy Supply side of the plant really worth 2 times the value of the electrons from the Mon Power side of the plant? Try explaining that to the average FirstEnergy ratepayer in West Virginia.

The price for the Harrison plant acquisition is substantially overstated and does not reflect the current value of the plant. Recent, comparable coal plant transactions provide some guidance on what used coal plants are selling for these days. It is interesting that FirstEnergy claims an upward $589.6 million adjustment to the price of Harrison based on “accounting fair value” at the time of the FirstEnergy/Allegheny merger, yet does not want to consider what the Harrison plant’s fair market value might be today. Such an “accounting fair value” adjustment would go in the other direction, as Harrison is currently worth far less than the price being sought by FirstEnergy from Mon Power ratepayers. Based on recent transactions, even the original cost depreciated figure of $574 million is substantially higher than market value, and a bad deal for Mon Power customers.

  • In a transaction announced in March 2013, Dynegy is acquiring 4561 MW of super-critical coal capacity from Ameren for $825 million, or a cost per kW of $180.88
  • In a transaction announced in March 2013, Energy Capital Partners is acquiring 2868 MW of super-critical coal capacity and 1424 of natural gas-fired capacity from Dominion for $650 million, or a cost per kW of $130
  • In a transaction announced in August 2012, Riverstone Holdings is acquiring 2265 MW of super-critical coal capacity from Exelon for $400 million, or a cost per kW of $176.60

Under FirstEnergy’s proposed transaction price of $1.163 billion, the cost per kW is $785.91, or almost 5 times higher than the average per kW price from recent transactions. Even using original cost depreciated for Harrison of $574 million, the cost per kW would be $388, or almost 2 times higher than the average per kW price from recent transactions. The market value of Harrison, based on the average price from the above recent transactions ($171.45 per kW) is $253 million.

FirstEnergy’s “resource plan” fails to consider and properly evaluate the various alternatives. FirstEnergy included a “resource plan” in its filing, which attempted to justify the purchase of the Harrison plant as an outcome preferred to other “alternatives” purportedly analyzed in the document. Market purchases, or relying on power purchases from the wholesale market, was the primary alternative identified in the “resource plan.” But the wholesale price projections used in FirstEnergy’s “resource plan,” and upon which FirstEnergy rejected market purchases as an alternative, are based upon outdated, inaccurately high—about 30% too high—projections of Henry Hub natural gas market prices. On this point, compare Figure 16 on page 21 of the “resource plan” with recent natural gas price forecasts from the Energy Information Administration and the difference in obvious. The effect? The “analysis” substantially overstates the cost of the “alternative,” which makes the Harrison plant transaction look relatively cheaper by comparison.

Moreover, the “analysis” in the “resource plan” fails utterly to evaluate the risks associated with exclusive reliance on coal-fired generation. If the Harrison plant transaction is approved, it would preclude any diversification in Mon Power’s energy supply portfolio, which would be virtually 100% coal-fired. Mon Power would be dependent on two 40-plus year old coal plants (Harrison and Ft. Martin) for 90% of its internal generation. That lack of diversification very likely puts the ratepayers at risk for significant cost increases when replacement capacity is needed for those plants. The “resource plan” also does not analyze the risk to ratepayers from coal price volatility, even though they will be extremely exposed if this transfer goes through.

The transaction appears to be an integral part of FirstEnergy’s financial restructuring. Why should West Virginia ratepayers be expected to bail out FirstEnergy’s management for bad resource acquisition decisions? FirstEnergy’s baseload capacity factor was 64% in 2012, down from 84% in 2008. Low natural gas prices are clearly hurting FirstEnergy’s competitive generation segment. FirstEnergy is also targeting substantial debt paydown this year in its competitive generation segment ($1.4 billion), which appears to be a major driver of the Harrison plant transaction. In addition to selling off Harrison, it has announced plans to sell off some pumped hydro units and possibly additional assets.

The transaction, if approved, should reflect terms that are fair to West Virginia ratepayers, and that accommodate some resource diversity for Mon Power. The transaction, as currently proposed, is a bad deal for Mon Power customers. Mon Power would be substantially overpaying for a 40-year old coal plant that is in excess of its capacity needs, and the acquisition would preclude Mon Power from pursuing cheaper alternatives, such as natural gas-fired generation, wholesale market purchases, and energy efficiency. There is some sentiment, of course, for Mon Power “stepping up” to acquire this plant, given that most of the coal burned at the plant is from the nearby Robinson Run #95 mine, owned by Consol Energy. The argument is that failure to “do this deal” would jeopardize the plant’s future operation, and the mining jobs that are directly associated with the plant’s fuel supply.

These arguments miss the point, however, with respect to the impact on Mon Power ratepayers. The transaction, as currently proposed, is nothing but a financial bail-out for FirstEnergy’s shareholders. The plant will not cease operating if Mon Power does not do this deal. No coal miners will lose their jobs if Mon Power does not do this deal. Rather, FirstEnergy will be subject to the wholesale power marketplace, and will be forced to sell the output at competitively determined prices rather than the inflated price – 7.4 cents/kWh – FirstEnergy is proposing in this transaction. The transaction as currently proposed puts the consequences of FirstEnergy’s imprudent resource acquisition decisions on the backs of the Mon Power ratepayers, and that is an unjust and unreasonable outcome. FirstEnergy’s shareholders, not Mon Power ratepayers, should bear the consequences if the Harrison Plant output must be sold into the wholesale power markets at prices that fail to capture the profit margin that FirstEnergy’s unregulated affiliate deems necessary. The Public Service Commission needs to step up on this one and make a decision that is in the best long-term interests of Mon Power customers, and that properly places the impact of the Harrison Plant’s apparent uneconomic competitiveness on the backs of the FirstEnergy shareholders, where the risk belongs.

If the Commission decides that Mon Power should expand its ownership of the Harrison Plant beyond its current 20% share, that acquisition should be (1) scaled down in price to reflect no more than the current market value of the plant, and (2) scaled down in size to correspond with Mon Power’s current capacity needs, while leaving some room for cheaper alternatives such as natural gas-fired generation, wholesale market purchases, and energy efficiency. The best solution would be to require Mon Power to issue a Request for Proposals, to really test the market for the alternatives that currently exist to meet Mon Power’s existing capacity needs. The RFP process would allow FirstEnergy to offer a portion of the Harrison Plant on terms that need to be competitive with other market-based alternatives, and FirstEnergy’s shareholders would bear the consequences of any shortfall between covering the Harrison plant costs and the competitively derived price. And by scaling down the magnitude of the acquisition to something more closely corresponding to Mon Power’s claimed capacity needs – about 900 MW – rather than the 1476 MW proposed in the transaction, Mon Power would have the flexibility to pursue cheaper alternatives that are in the best long-term interests of its customers, such as natural gas-fired generation, wholesale market purchases, and energy efficiency.

17 Jul

James Van Nostrand
July 16, 2012

Longview Plant

Last week I had the pleasure of touring the Longview Power Project, which is located just north of Morgantown near the Pennsylvania border. At a cost of approximately $2.0 billion, Longview is the largest privately-funded project in West Virginia history. Longview came on line in December 2011, and generates 770 megawatts (MW) of power, or about 695 MW net of the service station requirements (i.e., the electricity consumed on site). Several features of this state-of-the-art coal plant are noteworthy:

  • It is a merchant plant. Unlike the plants owned by investor-owned utilities such as Mon Power (First Energy) or Appalachian Power (American Electric Power), Longview is owned by an independent power producer. (The plant is operated by GenPower.) An investor-owned utility owning and operating this plant would be assured of cost recovery, as the output would be sold to the “captive” ratepayers of the utility, and ratepayers would bear the costs of the plant’s operation through their electric bills. In the case of Longview, however, the investors are taking the risk that the output of the plant can be sold into the market at a price that covers its costs, and (hopefully) produces a profit.
Longview Generator
  • Longview is profitable. This plant 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. The efficiency is generally reflected in the “heat rate” at which the plant converts energy into electricity. While the average net heat rate of coal plants across the country is 10,600 Btu/kWh, the Longview plant has a heat rate of 8,728 Btu/kWh. That means the plant has lower operating costs, which is important given its status as a merchant plant. If the plant were inefficient and “out of the money” or “above market,” its output could not be sold in the wholesale power markets, and Longview’s investors would lose money.
  • Longview is cost-competitive. The output of Longview is sold into the regional wholesale power market, the PJM, which is short for Pennsylvania-Jersey-Maryland. PJM is a regional power market that coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. Its headquarters are located in Valley Forge, PA, about 20 miles northwest of Philadelphia. PJM essentially creates the marketplace where buyers and sellers of electricity meet, and is also responsible for operating and maintaining the region’s transmission network and “keeping the lights on,” at least at the transmission level. In its role as the market maker for wholesale electricity, PJM essentially dispatches all the power plants in the region, in order according to their variable operating costs, until supply equals demand (which establishes the market-clearing price). For example, nuclear plants, which have very low operating costs, are dispatched first, while “peaking” natural gas-fired plants (typically simple cycle combustion turbines) or older, inefficient coal plants are dispatched at the margin. PJM system operators will work their way up the dispatch cost curve until market equilibrium is achieved (i.e., supply equals demand). That is why the efficiency of Longview is so important. Because of the low-cost characteristics of Longview – its heat rate of 8,728 Btu/kWh is far superior to the average of the coal plants in the PJM of 11,000 Btu/kWh – it ranks very high in the dispatch order and the plant is virtually “in the money” 24 hours a day, 7 days a week.
  • Longview is relatively “clean.” Longview is equipped with state-of-the-art air emissions reduction technology. These systems include:
Longview Coal Flow

Low NOX burners with overfire air and selective catalytic reduction (SCR) technology
Hydrated lime injection system to reduce acid mist
Removal of particulate matter (PM) through 99% efficient fabric filter baghouse

  • SO2 removal through 98% efficiency wet flue gas desulfurization system (FGD). Although the combined effect of these systems achieves significant removal of mercury, it is noteworthy that the plant would not meet the requirements of the EPA’s new Mercury and Air Toxic Standards (MATS) rule if it were to be licensed as a new facility. As an existing source, however, Longview easily clears the standard of the top 12% cleanest emitters.
Longview Conveyor
  • Longview is a “mine mouth” project, and thus fuel arrives by overland conveyors directly from a nearby mine 4 miles away. Less than two hours passes from the time the coal is mined until it reaches the bunker at the plant. This mine mouth supply reduces the delivered cost and avoids the impacts associated with trucks, rail or barges. The mine is operated by MEPCO, which is based in Morgantown, WV. MEPCO is the largest independent coal operator in the region, with about 800 employees. MEPCO has a long-term contract to provide coal to Longview, which consumes about 275 tons per hour, or about 2.3 million tons annually. MEPCO also provides coal to two nearby First Energy plants (Hatfield’s Ferry Power Station and Fort Martin Power Station) under long-term coal supply agreements.
  • Longview provides about 100 good-paying jobs. In addition to the employees at Longview, the MEPCO coal mine producing the coal for Longview employs over 210 miners.
Longview Control Room

The Longview Power Project is an impressive facility, and makes a strong case for a continuing role for coal in the nation’s electricity future. In the face of historically low natural gas prices, which have resulted in depressed wholesale electricity prices, Longview is still in the money, and is returning profits to its investors. More important, this relatively clean facility is displacing older, dirtier generating units, thereby achieving a lower carbon footprint for the region’s electricity supply. Longview is succeeding in the competitive PJM power markets, thanks to its high-efficiency supercritical pulverized coal technology. With its extensive air quality control systems, Longview easily meets all currently effective emissions requirements (although it would not meet the EPA’s limits for CO2 emissions once the greenhouse gas regulations become effective for new sources).

The Longview story stands in sharp contrast to the dozens of coal plants throughout the country that are scheduled to be retired in the next few years. While most of the coal industry blames the extensive plant closures primarily on the “job-killing EPA,” the fact of the matter is that most of these plants are being closed due to simple economics: with natural gas prices at historical lows, inefficient coal plants simply cannot compete, and the dispatch stack at PJM (and similar market forces) are forcing retirement of plants that have long outlived their useful lives. Longview proves that coal – and relatively “clean” coal at that – can compete, if the electric utility industry chooses to invest in the latest generating and emissions reducing technologies.

13 Jul

U.S. Energy Information Administration

Monthly coal- and natural gas-fired generation equal for first time in April 2012

Recently published electric power data show that, for the first time since the U.S. Energy Information Administration (EIA) began collecting the data, generation from natural gas-fired plants in April 2012 was virtually equal to generation from coal-fired plants, with each fuel providing 32% of total generation. Preliminary data for April show net electric generation from natural gas was 95.9 million megawatthours, only slightly below generation from coal, at 96.0 million megawatthours. The EIA report notes that there are strong seasonal trends in the overall demand for electric power. In April, demand was low due to the mild spring weather. Also in April, natural gas prices as delivered to power plants were at a ten-year low. EIA predicts that with warmer summer weather and increased electric demand for air conditioning, demand will increase, requiring increased output from both coal- and natural gas-fired generators.

2 Jul

Senator Rockefeller
June 20, 2012

Holding on to the Past Denies Coal’s Future

On June 19, the Senate voted 50-46 to reject a resolution offered by Senator James Imhofe (R OK) under the Congressional Review Act to block the EPA’s Utility MACT Rule. West Virginia’s Senator Jay Rockefeller voted against the resolution, and delivered a statement explaining the basis for his vote. Among other things, Senator Rockefeller points out that it is inaccurate to blame the “job-killing EPA” and the utility MACT rule for closing down many of the nation’s coal plants. Rather, “there also are smaller, older and less efficient coal-fired plants slated for closure, not because of EPA regulations alone, but – as corporate boards decided long ago and companies themselves will tell you – because they are no longer economical as compared to low-emission, cheaper natural gas plants.” He also admonished coal operators who “have yet to step up as strong allies and partners ready to lead, innovate and fight for the future.” The rest of his statement speaks for itself, and is worth repeating here:

“Instead of moving the conversation on coal forward, some in the industry have demanded all-or-nothing, time and again, for the ill-sighted purpose of a sound bite or flashy billboard. These efforts make no progress, they don’t pursue attainable policy change, and they certainly don’t create or save jobs.

Change is upon us – from finite coal reserves and aging power plants, to the rise of natural gas and the very real shift to a lower-carbon economy.

Denying these factors and insisting that the EPA alone is going to make or break coal is dishonest and futile. Feeding fears with insular views and divergent motivations will leave our communities in the dust.

West Virginians deserve better.”

9 Mar

Charleston Gazette
February 23, 2012

‘Just Say No’ to AEP’s Coal Addiction
Leslee McCarty

A bill passed by the West Virginia legislature and awaiting Governor Tomblin’s signature (SB 584 and HB 4350) would allow Appalachian Power to issue bonds to cover its higher power costs, rather than increasing current utility rates to recover these costs. Appalachian Power is currently facing an under-recovery in power costs of about $350 million. In other words, its electricity rates are set a level that fails to recover the costs it is currently paying to generate electricity. Why have electric rates gone up so much over the past few years? Coal prices have doubled over the past decade, and Appalachian Power has foolishly – “fuelishly” is more accurate – failed to diversify its resource portfolio, and is nearly 100% dependent on coal-fired electricity. While that might have made sense when coal prices were cheap – and in fact it produced rates for West Virginians that historically have been far below the national average – it no longer makes sense. Prudent utility management – i.e., one that engages in a rigorous long-term resource planning process – would have figured that out long ago and diversified its energy resource portfolio (and included, for example, natural gas, renewables, energy efficiency) rather than merely sticking utility ratepayers with ever-increasing electricity prices from coal-fired generation. Coal is an international commodity, and the prices will continue to surge with the industrialization of China, India and other developing nations.

What is Appalachian Power doing about it? Rather than managing its power supply costs and engaging in a meaningful least-cost planning process to try to hold utility rates down, it has come up with a creative way of trying to ease the pain of its higher power costs by “securitizing” them through issuance of bonds. The bill passed by the West Virginia legislature would allow Appalachian Power to issue $350 million of bonds, which ratepayers would pay off over a number of years, rather than raising rates immediately to cover these costs. A rate increase of this magnitude is simply unacceptable, both to Appalachian Power and to the Public Service Commission (PSC), so the idea is to spread it out over a number of years to avoid rate shock. Securitizing the debt would reduce the financing costs by having the PSC issue an order virtually guaranteeing repayment of the bonds regardless of subsequent events. This order, in turn, results in a more favorable credit rating on the bonds from the rating agencies, thereby lowering the financing costs.

What’s the problem with this approach? Where to begin. First, it deals with the symptom, not the cause. Appalachian Power has failed to control its power costs through its failure to engage in a rigorous long-term resource acquisition process, and this bill does absolutely nothing to address this issue. Instead, it gives Appalachian Power a pass, and leaves the ratepayers holding the bag, albeit spread over more years to ease the pain. To compound the insult, Appalachian Power opposed another bill (SB 162), introduced by Senator Dan Foster, that would have required the utility to engage in a least-cost planning process. Had Appalachian Power engaged in such a process a decade ago – like virtually all other utilities in the country – we likely would not be looking at the prospects of a $350 million rate increase, as Appalachian Power long ago would have seen the fuelishness of continuing to rely so heavily on coal rather than diversify its fuel supply. A rigorous least cost planning process – also known as “integrated resource planning” – would require sophisticated modeling of various resource scenarios, using a variety of assumptions, in order to determine a portfolio of resources that results in the lowest cost, over time, to utility customers. Such modeling would have included, for example, different coal price scenarios that would have highlighted the risk of heavy, and virtually exclusive, dependence upon coal-fired generation. A “high” coal price scenario, for example, would have shown natural gas-fired resources to be cost effective, and likely would have shown energy efficiency and conservation to be the most cost-effective means for Appalachian Power to meet its obligation to serve.

Appalachian Power has resisted implementation of least-cost planning in West Virginia, and has opposed Senator Foster’s bill, SB 162. The basis for its opposition: Appalachian Power does not want the term “least cost” to appear in the legislation. In other words, it does not want to be obligated to defend its resource acquisition strategy to the PSC (and other stakeholders) against a “least cost” requirement. This, in and of itself, provides some explanation of why Appalachian Power finds itself with a $350 million shortfall. If a utility denies any obligation to manage its power supply costs in a manner that results in reasonable electricity rates for its customers, we should hardly be surprised that its power costs are out of control. Rather than prudently managing its power costs, Appalachian Power is using its creativity to hire lawyers to draft a bill that sticks the consequences of its imprudence to customers, through issuance of bonds. As a matter of federal law, utilities are required to engage in integrated resource planning – the requirement was included as part of the Energy Policy Act of 1992 – and the process is geared to produce “the lowest system cost” for utility ratepayers. Why is Appalachian Power so strongly resisting the type of rigorous long-term utility planning that virtually all other utilities in the country are following? And why are West Virginia utility customers being asked to bear the consequences for this mismanagement?

Second, securitization is the wrong remedy for this problem. The tool itself is financially sound, and one cannot argue with the numbers, and the fact that the mechanism will result in lower costs for customers by being able to finance the shortfall at a lower interest rate due to the advantageous credit rating the bonds will receive. (Of course, the reason the bonds are so attractive to Wall Street is that ratepayers are on the hook to repay the bonds, regardless of any changes in circumstances down the road. In fact, even if Appalachian stops delivering power, ratepayers will still have to pay. If a large industry tries to drop off the grid and self-generate, it will still have to pay. The boilerplate in this bill is so one-sided in favor of the utility and against the customers as to shock the conscience. And, in the electricity business, the correct word is indeed “shocking.”) I am quite familiar with the concept of securitization in the electric utility business. A former client of mine, Puget Sound Energy (PSE), invented it back in the mid-1990s, and it has all the advantages that Appalachian describes. The trouble is, the tool does not fit with these circumstances.

Securitization should never be used to finance ongoing, routine operating expenses. That’s what Appalachian Power is trying to do here: its fuel costs (and revenues from wholesale sales) are out of whack with what it expected, and it needs to raise rates to cover the shortfall. It is a misuse of securitization, however, to finance normal operating expenses through issuance of bonds. It has never been done before, with good reason. It is financially irresponsible. When PSE first used securitization, for example, the tool was to spread out over time PSE’s investment in energy efficiency measures. These investments (insulation, windows, HVAC, high-efficiency furnaces, etc.) have useful lives that extend many years. Securitization allows the repayment of these investments to be refinanced at lower interest rates over a time period that corresponds to the useful life of the underlying asset. Securitization has not been, and should not be, used to finance normal operating expenses. Appalachian Power refers to these fuel costs as “extraordinary” in the fact sheet it distributed to legislators. Yes, they are extraordinarily high, due to Appalachian Power’s mismanagement, but they are normal, routine operating expenses that need to be paid by current customers, not spread out over some future period. It is a violation of fundamental financial management principles to finance operating costs through long-term debt. Yet that is what Appalachian Power seeks to do with its “consumer rate relief bonds.” American Electric Power (AEP), Appalachian’s parent company, includes a discussion of securitization on its website, and virtually all the examples it cites where securitization has been used involve long-term assets (transition and stranded costs associated with above-market generating assets; costs of environmental control equipment; and financing utility system infrastructure). AEP cannot cite an example where securitization has been used to finance fuel costs. Long-term debt simply cannot be used to cover ordinary, routine operating expenses. The same folks who brought you the Wall Street meltdown must love this stuff, as it is exactly the sort of financial gimmickry that can wreak havoc on the marketplace if misapplied in the manner proposed by Appalachian Power.

Third, it is a violation of fundamental ratemaking principles to force future ratepayers to bear the costs that are being incurred by current customers. This is known as the “matching principle”: those who cause the costs, bear the costs. Under Appalachian Power’s proposed misuse of securitization, current ratepayers would not have to bear the costs incurred by Appalachian Power to serve them. Rather, securitization allows the costs to be shifted to future customers. There is a complete mismatch between costs incurred and revenue received when the bonds are paid back in future years. Current ratepayers get subsidized; future ratepayers get burdened with costs not associated with the costs incurred by Appalachian Power to serve them at the time. It’s great if you’re an Appalachian ratepayer in 2012, since you are dodging the bullet of paying the actual costs of serving you. It’s not so great if you’re an Appalachian Power ratepayer in 2017, when you are paying utility rates completely unrelated to the costs incurred by the utility in serving you in 2017. It’s a mismatch. It’s not fair. And utility commissioners abhor such practices in setting rates. Yet Appalachian Power’s securitization bill embraces this mismatch, as it avoids the current pain of the $350 million under-recovery caused by its mismanagement.

Other utility industry veterans are reaching the same conclusion. The Power Line contains a similar analysis (When Half Truth = No Truth), and Keryn Newman provides an excellent commentary (HB 4530: We Need a Solution, Not a Band-Aid). Stop the madness. This bill needs to be rejected, and the next legislature should enact the least-cost planning bill proposed by Senator Foster. It’s time to deal with the cause, not the symptom.