College of Law Center for Energy and Sustainable Development

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.”

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 2½ 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 2½ 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.

James Van Nostrand
July 16, 2012

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 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:

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 is a “mine mouth” project, and thus fuel arrives by overland conveyors directly from a nearby mine 4 ½ 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.

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.

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.

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.”

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.

International Energy Agency
December 13, 2011

Medium-Term Coal Market Report 2011

The International Energy Agency issued a report, MEDIUM-TERM COAL MARKET REPORT 2011, which predicts that global demand for coal will continue expanding over the next several years. The report says the main reason for the projected increase in coal demand over the next five years is surging power generation in emerging economies. More than half the demand in the next five years is expected to come from China. “For all of the talk about removing carbon from the energy system, the IEA projects average coal demand to grow by 600,000 tons every day over the next five years,” IEA Executive Director Maria van der Hoeven said in a statement accompanying the issuance of the report. Among the troubling findings in the report is that events and decisions in China could have an outsized effect on coal prices – and thus electricity prices – around the world over the next five years. China’s domestic coal market is more than three times the global coal trade: Only 15% of global coal demand is met through international trade, yet more than half of global coal demand during the outlook period is projected to come from China. Thus, according to Ms. Van der Hoeven, “what happens in China over the medium term may impact the prices for electricity that consumers everywhere will have to pay.”

Other key findings of the report include:

• Growth in coal demand over the next five years will mostly occur in non-OECD countries, with China and India accounting for the majority.
• Growing demand means poorer deposits will have to be exploited, which will likely lead to upward pressure on mining costs and therefore on coal prices.
  Despite the rise of new exporting countries, traditional exporters will meet the bulk of demand growth.
• While coal has traditionally been considered a cheap and secure energy resource, this perception may be tested in the years ahead. Six countries account for more than 80 percent of global coal exports, and as demand surges markets could experience more of the infrastructure bottlenecks that in recent years caused coal prices to more than triple.

What are the implications for West Virginians? The good news is that there is plenty of demand for whatever coal is extracted from the ground in West Virginia. Whether or not dozens of coal-fired electric generating plants around the country are retired in the coming years – as is currently being predicted, and blamed largely (and unfairly) on EPA – there will be plenty of buyers for West Virginia coal, primarily from China and India. The bad news is that the utilities serving West Virginia are heavily dependent on coal-fired generation. So as domestic coal prices soar in response to international demand for coal, our electricity prices will continue to increase substantially over the next few years. Utilities in this state have done virtually nothing over the past decade to diversify their generating portfolio, and have relied almost exclusively on coal to satisfy electricity demands, to the exclusion of renewable energy and investments in energy efficiency and conservation programs. More recently, utilities have announced plans to switch to natural gas, thanks to the abundant supply and low prices of natural gas due to shale gas plays across the region and the country. But it takes years to diversify away from the current heavy reliance on coal-fired generation, and in the meantime West Virginia utility ratepayers will be paying the price. The IEA study confirms the urgent need for utilities in this state to engage in rigorous long-term system planning to identify and implement a resource acquisition strategy that will be in the long-term best interests of utility ratepayers. Utilities throughout the country have been engaged in “integrated resource planning” – a process that guides the selection of power plants as well as investments in demand-side efficiency measures – for decades, and it is about time that West Virginia utilities start following the lead. Our ratepayers cannot afford sole reliance on coal any longer.

Bloomberg
December 7, 2011

Coal Shares Slip After Goldman Sachs Downgrade
Associate Press

Goldman Sachs lowered its view on the coal sector from “attractive” to “neutral” this week, causing a broad decline in stock prices for coal companies, led by a 5.1 percent decline in Peabody Energy Corp. shares, notwithstanding Peabody’s exposure to Asia, where coal demand is moving in a favorable direction. Goldman analyst Andre Benjamin wrote that it is unlikely that the coal sector will perform any better than other stocks because of flat U.S. heating prices, falling prices for coal, and lower volumes in the U.S., as well as continued cost pressures. Benjamin’s analysis also stated that demand for coal is likely to be hurt by the impact of proposed federal regulations on coal plant emissions (Goldman predicts that 51 gigawatts of coal-fired power plant capacity is on its way out), lower gas prices next year and in 2013, and lower demand growth as customers become more energy-efficient. Benjamin expects coal prices to be stable in 2012 and to fall in 2013 and 2014 as growing supplies catch up with demand.

In its note to coal-sector investors, Goldman named Pennsylvania-based Consol Energy as a bright spot. That is primarily because Consol has significant natural gas and oil assets in the Marcellus and Utica shale basins underlying Ohio, Pennsylvania, New York and West Virginia. Shares in Consol Energy declined by only 2.7 percent following the Goldman downgrade for the sector.

Politico
December 6, 2011

Who’s Killing the Coal-Fired Power Plant?
Erica Martinson

This article from Politico suggests that many companies are shutting down older, dirtier coal plants because it makes economic sense, not because of the impact of new air pollution regulations from the U.S. Environmental Protection Agency. The economic case is due largely to the discovery of the Marcellus Shale in the mid-Atlantic region, along with more cost-efficient hydraulic fracturing due to changing technology, which has resulted in natural gas prices dropping dramatically in recent years and they’re expected to stay that way. As reported in a previous blog energy [November 29, NERC Finds that Grid Reliability May Be Jeopardized by EPA Rules], the North American Electric Reliability Corp. says in its most recent report that the main new sources of power added to the grid in the immediate future will be natural gas, solar and wind power projects. In addition to the impact of low natural gas prices, the recession has cut into demand for electricity, and many utilities do not expect power demand to hit pre-recession levels until 2012. While there is no question that EPA rules — particularly EPA’s Cross-State Air Pollution Rule and its mercury and air toxics rule for power plants — are forcing or accelerating shutdowns of many older, polluting coal-fired power plants, there are other economic forces at work. It is thus unfair to lay the blame for the decline in coal-fired electric generation over the next several years entirely at the doorstep of the EPA, as popular as that may be in many political circles.

International Energy Agency
November 9, 2011

World Energy Outlook: The Authoritative Source of Energy Analysis and Projections

Early last month, the International Energy Agency issued its 2011 World Energy Outlook. The publication looks at current trends, and provides robust analysis and insight into global energy markets over a 25-year period, through 2035. The Fact Sheet contains a number of interesting findings:

• Global energy-related emissions of CO2 jumped by 5.3% in 2010 to a record 30.4 gigatons (Gt). The report projects that emissions will continue to rise, reaching 36.4 Gt in 2035 – an increase of 20%. This trajectory is consistent with a long-term global temperature increase of more than 3.5°C.
• The Report includes a “450 Scenario,” which is the benchmark of limiting CO2 concentrations of 450 parts per million in order to limit temperature increase to 2⁰ Celsius – the globally agreed goal under the United Nations Framework Convention on Climate Change. (The current level of CO2 concentration in the atmosphere is 389.78 ppm.)
• The long economic lifetimes of much of the world’s energy-related capital stock mean that there is little scope for delaying action to move onto the 450 emissions trajectory without having to retire some stock early. 80 percent of the cumulative CO2 emitted worldwide between 2009 and 2035 in the 450 Scenario is already “locked-in” by capital stock – including power stations, buildings and factories – that either exists now or is under construction and will still be operational by 2035, leaving little additional room for maneuver. If internationally coordinated action is not taken by 2017, the Report projects that all permissible emissions in the 450 Scenario would come from the infrastructure then existing, so that all new infrastructure from then until 2035 would need to be zero-carbon, unless emitting infrastructure is retired before the end of its economic lifetime to make headroom for new investment.
• In the power sector, nuclear generation grows by about 70%, led by China, Korea and India. Renewable energy technologies, led by hydropower and wind, account for half of the new capacity installed to meet growing demand. Overall, modern renewables grow faster than any other energy form in relative terms, but in absolute terms total supply is still not close to the level of any single fossil fuel in 2035.
• Natural gas is projected to play an increasingly important role in the global energy economy. World demand is projected to increase at an average rate of 1.7% per year, and global gas consumption almost catches up with coal consumption by 2035. By sector, power generation is the leading contributor to the global increase in gas demand.
• Unconventional gas – tight gas, shale gas and coalbed methane – is set to play an increasingly important role, accounting for roughly half the estimated global resource base of over 800 tcm; its share in output rises from 13% in 2009 to above 20% in 2035 “on the assumption that the industry is successful in dealing with environmental challenges.”
• Fossil-fuel consumption subsidies worldwide amounted to $409 billion in 2010, with subsidies to oil products representing almost half of the total. Persistently high oil prices have made the cost of subsidies unsustainable in many countries and prompted some governments to try to reduce them. In a global survey covering 37 countries where subsidies exist, at least 15 have taken steps to phase them out since the start of 2010. Without further reform, the cost of fossil-fuel consumption subsidies is set to reach $660 billion in 2020, or 0.7% of global GDP (at market exchange rates).
• The share of energy subsidies going to renewable energy is poised to continue to grow. Global renewable-energy subsidies increased from $39 billion in 2007 to $66 billion in 2010, in line with rising production of biofuels and electricity from renewable sources. Despite a projected decline in unit production costs due to cost reductions and rising wholesale prices for electricity and transport fuels, subsidies would need to expand even further to meet existing targets for renewable energy production. In 2035, subsidies to renewables are projected to reach almost $250 billion.