Consultant addresses Appalachian Power actions in the coal area

The Appalachian Power unit of American Electric Power (NYSE: AEP) has paid liquidated damages lately to rail carriers due to undelivered coal, said consultant Billy Jack Gregg, working for the West Virginia Consumer Advocate Division.

The division on June 7 filed heavily redacted testimony from Gregg at the West Virginia Public Service Commission, which is currently reviewing the annual Expanded Net Energy Charge (ENEC) filing made by the West Virginia subsidiaries of the AEP – Appalachian Power (APCo) and Wheeling Power. Since Wheeling Power owns no power plant capacity, it is basically being excluded from this description of the Gregg testimony.

In a heavily redacted section, Gregg was asked about liquidated damages the company has paid related to coal transportation. “These liquidated damages penalties should be disallowed and removed from the energy portion of the ENEC actual cost balance for the review period,” he wrote. “It is the responsibility of APCo management to control the logistics of fuel supply in order to maximize security of supply and minimize costs.”

In another area of testimony, Gregg noted that AEP is including in this case costs related to the retirement of the Sporn 5 coal unit ($47.9m) and the abandonment of the SO2 scrubber project at the Muskingum coal plant ($41.8m). Sporn Unit 5 was permanently retired earlier this year,

When asked about plant shutdowns over the next 10 years, Gregg said that APCo has announced plans to close all of its sub-critical coal units – Glen Lyn Units 5-6 (335 MW), Clinch River Units 1-3 (705 MW), Sporn Units 1 and 3 (300 MW), and Kanawha River Units 1-2 (400 MW) – totaling 1,740 MW of capacity, in the 2014-2019 timeframe. “However, Clinch River units 1 and 2 will be converted to gas with in-service dates of 2014/15,” he added. “At the same time, APCo is expected to receive ownership of Ohio Power’s interest in two West Virginia generation plants – Amos Unit 3 (867 MW) and Mitchell (1560 MW) – totaling 2,427 MW. Any additional capacity needs over the next ten years are expected to be met by a combination of combined cycle gas plants, combustion turbine gas peaking plants, and market purchases.”

Five coal contracts expire, four new ones signed

Asked if any coal contracts expired in the 2011 review period covered by this case, he said there were five: the Arch Coal contract to the Amos plant; the JP Morgan contract to Glen Lyn; the Magnum Coal contract delivering to Amos; the Oxford contract delivering to Mountaineer; and the Massey Energy contract delivering to Mountaineer. These contracts delivered about 700,000 tons per year to APCo plants.

APCo entered into three new long-term contracts during 2011 and one contract at the beginning of 2012, he added. The four new contracts were:

  • Arch Coal Sales – 400,000 tons per year (TPY) for Amos beginning in 2011;
  • Patriot Coal Sales – 340,000 TPY for Amos beginning in 2011;
  • Peabody COALTRADE – 500,000 TPY for Amos beginning in 2011; and
  • Consolidation Coal – 1,675,000 TPY for Amos and Mountaineer beginning in 2012.

Generally speaking (actual prices paid by APCo are redacted), coal prices for Central and Northern Appalachian coal rose steadily during 2010 from about $60/ton at the beginning of the year to almost $80/ton by the end, Gregg wrote. During 2011 coal prices moved “sideways” in a range near $80/ton for the first half of the year and then began a long slide toward the current price of $60/ton. NYMEX Central Appalachian coal futures for delivery during the forecast period closed at $59.31/ton on June 1, 2012.

Low natural gas prices impact off-system power sales

Asked if the companies’ forecast level of net realizations from off-system power sales is reasonable, Gregg responded: “While AEP’s forecast certainly seems low, forecasting off-system sales and margins depends on numerous volatile factors beyond the control of any of the market actors, such as weather and the price of natural gas. In such a situation, it probably always safer to err on the conservative side….Nevertheless, even a slight uptick in actual off-system sales can have a profound impact on ENEC monthly costs. If rates in this case were going to be based on forecast costs, I would be inclined to make an adjustment in the Company’s forecast of off-system sales. However, as previously discussed, such adjustments are unnecessary in this case.”

PJM energy prices began to drop last summer and declined continuously until a recent uptick in the last month, Gregg noted. PJM energy prices for the July 2012-June 2013 period now average $43.34/MWh. This compares to $54.41MWh one year ago.

“PJM energy prices and natural gas prices move in lock-step since natural gas generating units are the marginal, price-setting units in the PJM system,” Gregg added. “The price of coal has been affected by supply and demand issues that are unique to the coal industry. Even though prices have declined during 2011 and 2012, they have stayed relatively higher in price than other forms of energy over the past year. If natural gas stays cheap, gas-fired generators will remain economic within PJM and increase competition for whatever sales are made. This has the effect of squeezing the margins realized from off-system sales. If natural gas prices rise, PJM prices will rise as will AEP’s margins on off-system sales.”

If PJM energy prices stay low, it becomes cheaper to buy energy from the market than to run some of APCo’s more expensive plants, Gregg wrote. APCo’s sub-critical units are slated for retirement and are not expected to run much anyway during the forecast period, he added.

It is true that a number of changes could be made in APCo’s forecast, such as in the areas of coal costs, capacity charges and off-system revenues, Gregg said. “That is usually the case with any forecast in light of more recent information. However, since current rates are over-recovering current ENEC costs, and the Commission is now considering the issue of whether and how much of the under-recovery to securitize, the primary rate issue in this case is how fast the existing under-recovery balance continues to be amortized. As a result, I have not proposed any adjustments.”

Currently, the only construction surcharge in effect for APCo relates to the coal-fired Amos Unit 1 scrubber which went into service in January 2011. APCo is seeking to continue this surcharge and to increase revenues produced by the surcharge by about $2.6m, Gregg said. In addition, in an order in the last ENEC proceeding, the commission allowed APCo to begin deferring expenses related to the gas-fired Dresden plant when that plant went into service. Dresden went into service on Jan. 31 and APCo is seeking recovery in this case of $9.3m in deferred expenses related to Dresden for the February-June 2012 period. APCo is also asking that the commission authorize a separate surcharge for recovery of on-going Dresden costs over the next year.

About Barry Cassell 20414 Articles
Barry Cassell is Chief Analyst for GenerationHub covering coal and emission controls issues, projects and policy. He has covered the coal and power generation industry for more than 24 years, beginning in November 2011 at GenerationHub and prior to that as editor of SNL Energy’s Coal Report. He was formerly with Coal Outlook for 15 years as the publication’s editor and contributing writer, and prior to that he was editor of Coal & Synfuels Technology and associate editor of The Energy Report. He has a bachelor’s degree from Central Michigan University.