Billy Jack Gregg, who regularly criticizes FirstEnergy‘s (NYSE: FE) Monongahela Power and Potomac Edison subsidiaries over coal-buying issues, on Nov. 2 took some largely-redacted shots at the latest coal purchasing in testimony filed at the West Virginia Public Service Commission.
Gregg, a consultant working for the state Consumer Advocate Division, reviewed the Expanded Net Energy Charge (ENEC), Temporary Transaction Surcharge (TTS) and Energy Efficiency and Conservation Surcharge (EEC) filings made by Mon Power and Potomac Edison. Their amended request seeks to increase Mon Power and Potomac Edison’s ENEC, TTS and EEC rates in West Virginia by a net total of $144.5 million.
Mon Power currently owns or has the right to the output of 3,730 MW of generating capacity (nameplate ratings). There is 3,569 MW of generation assets currently owned by Mon Power at the Ft. Martin and Harrison coal-fired stations, and by Mon Power’s subsidiary Allegheny Generating Co. (AGC) at the Bath County pumped-storage facility. Mon Power’s generating units, after a wave of coal plant shutdowns earlier this decade, now burn approximately 7 milllion to 8 million tons of coal a year.
On a daily basis Mon Power bids all of its generation resources into the PJM Interconnection market and buys all of the power needed to serve its West Virginia retail load from the PJM market. Revenues from Mon Power’s generated power sold into the PJM market is flowed through the ENEC and reduces the net energy costs of West Virginia ratepayers. Because the companies are now “long” on capacity and energy, that is, it has capacity and energy in excess of the needs of its West Virginia retail customers, they generate more off-system sales revenues and has lower ENEC rates when PJM prices for capacity and energy are high.
Well over 95% of Mon Power’s generation is fueled by coal, and coal remains the single largest O&M expense for the companies, accounting for over 95% of expanded net energy costs.
Gregg wrote about coal prices in general: “During the first half of 2014 coal prices oscillated between $55 and $60/ton, but in mid-2014 coal prices began a long and inexorable decline as cheap natural gas displaced coal as the fuel for substantial amounts of electric generation within PJM, reducing demand for coal. By the third quarter of 2015 the price of Northern Appalachian coal had fallen to the low $40 range.”
The average price of coal delivered to Mon Power plants during the 2014/2015 review period was 245.8 cents MMBtu ($61.85/ton), 1% lower than the previous review period. The delivered coal costs peaked in 2012 and have declined since an asset transfer in October 2013. As a result of the asset transfer, the companies now purchase approximately 70% of annual coal supply for Harrison and 30% for Ft. Martin. Through 2014 the delivered cost of coal to Harrison was substantially cheaper than the cost of coal delivered to Ft. Martin. However, for 2016 overall coal costs are forecast to be slightly higher because costs at Harrison will rise and offset lower costs at Ft. Martin.
“The historical cost profiles of the two plants appear at first glance to run counter to logic,” wrote Gregg. “Ft. Martin is located on the Monongahela River and takes coal deliveries by barge, whereas Harrison is not on a navigable river and takes coal deliveries by conveyor belt, rail and truck. While barge delivery is generally cheaper than land-based coal delivery, the large amount of coal delivered to Harrison over the CONSOL conveyor belt essentially negates this transportation cost advantage for Ft. Martin. However, the primary cause of the historical cost disparity between Ft. Martin and Harrison has been the prices charged under the coal contracts supplying both plants.”
Some facts of note emerge around heavily redacted passages
At this point, much of the Gregg testimony about coal contract specifics is redacted from the public version of the filing. In some unredacted points from the filing:
- “Because of its location on the river, Ft. Martin should be able to purchase attractively priced coal from a wide area. Instead, Ft. Martin has been saddled with high-priced contract coal and high-priced coal shipped from the Powder River Basin (‘PRB’) in Wyoming. Ft. Martin has also been used as a dumping ground for coal from FE affiliated companies.”
- “As discussed in previous cases, the Anker coal was delivered at this lower price in an attempt to mitigate damages related to the litigation for failure to perform under the Sycamore mine contract. With the final settlement of the litigation in April 2015, Anker’s mitigation deliveries to Harrison ceased.” That refers to a long-running contract dispute with then-Anker Coal parent International Coal Group, which was acquired in 2011 by Arch Coal (NYSE: ACI).
- “Mon Power’s job of managing coal inventories has become substantially easier following the asset transfer for three reasons. First, there are only two plant stockpiles to manage and Mon Power owns 100% of both plants. Second, there are a smaller number of contracts remaining to supply the two plants. Third, since Ft. Martin no longer receives low-Btu PRB coal, it will no longer be necessary to maintain a separate stockpile at Ft. Martin to manage blending of the PRB coal with eastern bituminous coal.”
- Asked about recent contract amendments, Gregg responded: “The termination date of the CONSOL/Murray contract from Shoemaker mine to Ft. Martin was extended to the end of 2015 to allow CONSOL/Murray to deliver all of the tons called for by the contract.” Shoemaker is one of the Pittsburgh-seam longwall mines in northern West Virginia that Murray Energy bought in late 2013 from CONSOL Energy (NYSE: CNX).
- “The Commission will recall from previous cases that the Company and its affiliate AE Supply began bringing low-Btu PRB coal into Ft. Martin in 2004 in order to comply with SO2 limitations until the Ft. Martin scrubbers could be completed. In conjunction with the decision to purchase PRB coal, the Company also entered into a 5-year contract with [redacted] for rail transportation of the PRB coal from Wyoming and other western sources to a rail/barge transfer terminal on the Mississipp/Ohio inland waterway system. Because the Company overestimated the amount of PRB coal it could bum at its plants, it was not able to meet its annual transportation minimums under the [redacted] contract and had to pay substantial liquidated damages based on the annual rail tonnage shortfalls. … As a result, the Company still burned PRB coal at Ft. Martin even after the scrubbers were operational and even when the PRB coal was more expensive than eastern coal available in the vicinity of the plant.”
- “The Company has provided adequate documentation to show that the decision to not buy and transport PRB coal during the review period and to instead pay the liquidated damages was the most economic choice. The payment of liquidated damages and the buying of eastern bituminous coal was approximately [redacted] than buying and transporting the minimum amount of PRB coal in 2014.”
As a result of a Joint Stipulation in the last ENEC case, there were two issues carried over from that case: the issue of excess costs resulting from affiliated coal purchases; and the issue of the flow-through of royalties under the lease of the Buffalo coal reserve. Gregg’s testimony on both points was almost completely redacted. The Buffalo coal reserve was leased several years ago to a unit of Alliance Resource Partners LP (NASDAQ: ARLP) for the so far undeveloped Penn Ridge deep mine in Pennsylvania as part of a broader transaction that also included a coal supply contract with Alliance.
Gregg was heavily critical of the fact that the FirstEnergy fuel supply department no longer does internal audits of coal supply contract changes. “I recommend that the Commission require the Company to retain or employ auditors to review escalations and other price-related changes requested by coal suppliers,” he wrote. “The auditors can be internal employees or external contractors; however, they should have experience with coal supply contracts. Because of the small number of contracts which the Company now has, my personal opinion is that it would be more cost-effective to retain external contractors when and as needed. The Company should be required to report back to the Commission in the next ENEC proceeding on progress they have made in employing or retaining such auditors and actually auditing pricing claims by coal suppliers.”
Gregg was also critical of a company contention it doesn’t need heavy documentation for coal supply contract decisions because so many officials are involved in those decisions. “Frankly, I find it incredlble,” wrote Gregg about this rationale. “These decisions involve tens of millions of dollars and will always have to be explained to someone who was not involved in the decision-making process, whether that be senior management, the board of directors, or outside auditors. The lack of written analyses and documentation means there is no way to trace the bases for the decision and determine whether any expected benefits actually materialize, and if not, why not. Moreover, it is virtually impossible to conceive of any company making a decision to enter into contracts and contract amendments worth millions of dollars without preparing multiple, written financial analyses at the time the decision is made. To state that none exist strains belief.”
Gregg added on that point: “I recommend that the Commission require the Company to formally analyze, document and justify all of its fuel and fuel-related purchasing decisions. All decisions to enter into, terminate or amend any fuel or fuel-related contract should be reduced to writing and retained in the files of the Company. All financial analyses related to such actions should likewise be reduced to writing and retained by the Company. These requirements will result in a clearer understanding of the Company’s actions related to its fuel purchasing and fuel contract administration, not only by the Commission and outside reviewers, but by the Company’s internal management as well.”
The West Virginia commission in October 2013 approved a Mon Power application to transfer to its ownership the part of the coal-fired Harrison power plant it did not already own. Mon Power filed for this approval in November 2012 to address a looming generating capacity gap in part caused by the shutdown of some its other coal-fired capacity due to age and looming environmental regulations. Harrison has a full suite of emissions controls, including scrubber equipment added in the 1990s, so it is considered about as safe as any coal-fired capacity can be from near-term shutdown.
The commission authorized Mon Power and Potomac Edison, a FirstEnergy subsidiary with no generation of its own, to complete a generation resource transaction involving Mon Power’s ownership interests in the Harrison and Pleasants coal plants, to impose a temporary transaction surcharge until rates from the next base rate case are in effect, to enter into certain affiliated agreements, and to adopt modified Expanded Net Energy Cost rates. This deal increased the net installed capacity of Mon Power by 1,476 MW.
The transaction included the acquisition by Mon Power of the 79.46% interest then held by FirstEnergy’s unregulated Allegheny Energy Supply Co. LLC in Harrison, resulting in Mon Power being the sole owner of Harrison, and the acquisition by AE Supply of the 7.69% ownership interest held by Mon Power in Pleasants, resulting in AE Supply being the sole owner of Pleasants.