The Monongahela Power and Potomac Edison units of FirstEnergy (NYSE: FE) on Aug. 16 filed opening testimony at the West Virginia Public Service Commission in its annual Expanded Net Energy Cost case, which touched on coal-buying issues.
Jay A. Ruberto, employed by FirstEnergy Service Co. as Director, Regulated Generation and Dispatch, testified on the ENEC review period of July 1, 2015, through June 30, 2016, and the forecast period beginning Jan. 1, 2017.
Overall, coal prices have decreased steadily throughout the review period, Ruberto noted. The primary factors in that are the early retirements of older coal-fired generation plants, low wholesale power prices, increased environmental regulation, and the increase in the production and competition of natural gas and renewables. This last factor caused more fuel switching to gas in the power generation markets, and therefore less demand for coal in the market.
Coal comprises the majority of Mon Power’s fuel mix and is critical to Mon Power‘s ability to generate electricity for its customers and the customers of Potomac Edison. During the review period, Mon Power consumed more than 7.6 million tons of coal at a cost of $463 million. Mon Power’s coal position is dependent upon various contracts, with terms ranging from a year or less to six years. The contracts are with suppliers ranging from small to large public and private corporations.
Mon Power has contracted 99% of its coal requirements for 2017 as of the filing of this ENEC. A portion of the 2017 contracted tonnage is subject to quarterly or annual price adjustments.
Mon Power entered into seven new contracts during the review period to meet its coal, transportation and environmental reagent requirements, but details are confidential.
There are three contracts with Harrison Refined Coal LLC (HRC) for refined coal to be used at the Harrison power plant in northern West Virginia. The process uses chemical sorbent additives to reduce the emission of NOx and for the capture of mercury (Hg) when coal is burned. These agreements allow HRC to purchase the raw coal from Mon Power, refine the coal using their equipment and proprietary chemical sorbent additives, and resell the refined coal to Mon Power.
Mon Power will receive from HRC up to $1.35 per ton of refined coal produced. HRC is responsible for the cost, installation, operations, and maintenance of the equipment, as well as the cost of additives. This allows HRC to receive tax credits for producing the refined coal which they will use to offset their costs as well as their payment to Mon Power. Mon Power also benefits from a reduction in NOx and Hg. The facility is expected to be operational by the end of 2016 and is expected to remain in operation until approximately Nov. 30, 2021, when the tax credits expire.
A new Coal Sales Agreement amended the existing Consolidation Coal (Murray Energy) supply contract for the Harrison County Mine for the Harrison Power Station by amending the delivery term and price, Ruberto noted. Carry over tons of approximately 1.2 million tons were included in a new Coal Sales Agreement from Jan. 1, 2017, to Dec. 31, 2017, to facilitate full delivery of the original 2014 and 2015 commitments. Deliveries in 2014 and 2015 were hampered by reduced bums related to reduced power demand and low wholesale power prices. The quality in the new Coal Sales Agreement was changed so that a modified moisture, ash and Btu content could be delivered to assist in meeting operational needs. To avert potential take-or-pay costs, the price for tonnage delivered in 2017 was amended by an agreed-to prior year reasonable inflationary rate.
The Harrison station has been impacted by requirements in its long-term coal contract, Ruberto added. “Harrison receives most of its coal from a belt fed directly from a mine and is in the final year of a three year contract. This contract, which was at favorable coal price and volume when it was signed in 2013, is now impacting the operation of the plant in the short term. The contract has a requirement for 5 million tons in 2016. Because of the low market prices, Harrison could not consume the 5 million tons if it operated only when the market price exceeded the variable cost of operation. If these tons are not received, the Company would be liable for take-or-pay costs that could vary from the difference between the contract price and the price the supplier could resell the coal at and the full contract price should the supplier be unable to resell the coal. Because of this requirement, Harrison has been operated in a manner that will allow it to consume sufficient coal to meet the contract requirements.”
He said the company has done several things to minimize the impact, including:
- taking the required delivery of the coal in 2016 and storing it. Harrison has on site storage as well as a storage site a few miles from the plant. Both of the locations now have stockpiles near their maximum capacity. This has allowed approximately 1.1 million tons to be stored rather than to be consumed at a loss. Additionally, the company investigated the possibility of using other sites for additional storage. However, the cost of these additional sites, which includes permitting, transportation, and storage, were in excess of the cost to consume the coal and untimely due to required permitting that would be needed;
- attempted to renegotiate contract changes to eliminate the required 2016 tons. While this was unsuccessful, the company did sign a new agreement that specifically permits carryover of tons, defines liquidated damages cost in case the company does not accept deliveries at the lower end of its estimated liability along with an improved contract structure for 2017;
- negotiated a 2017 contract for Harrison that eliminates energy losses by reducing variable costs when Locational Marginal Prices (LMP) decline so that variable costs cannot exceed market revenues. The contract executed this summer has variable coal price provisions that virtually guarantees Harrison will be able to operate at a high output with little chance of market losses.
NOx emissions may be future issue for Fort Martin coal plant
An issue coming up particularly for the Fort Martin coal plant is the fact that in November 2015, the EPA proposed an update to the Cross-State Air Pollution Rule (CSAPR) for the 2008 ozone National Ambient Air Quality Standards (NAAQS) by issuing the proposed CSAPR Update Rule. Starting in 2017, this proposal would reduce Seasonal NOx emissions from power plants in 23 states. The EPA modeled these revised Seasonal NOx allocations based on the assumption that all coal units had fully-operational Selective Catalytic Reduction (SCR) units and were utilizing those SCRs at 100%. This resulted in allocations based on a NOx rate of 0.06 Ibs of NOx per mmBtu.
West Virginia allocations were one of the most reduced allocations in the country, Ruberton said. Though emissions in 2015 during the ozone season were over 28,000 tons, allocations for the state have been reduced to 13,390, with strict rules and penalties for companies which cause the state to go over the assurance level of 121% allowed by the EPA. The Seasonal NOx allocation market for 2016 is currently $230. The forward market for Seasonal NOx allocations is non-existent or illiquid at best, as the Update Rule is still being finalized with respect to the carry-forward ratio from 2016 to 2017, which will directly affect the value of allowances in 2017.
The cost and availability of Seasonal NOx allowances in 2017 is still unknown. Mon Power’s Harrison units are equipped with SCRs and should be able to self-comply with the amount of allocations granted. But, Mon Power’s Fort Martin units do not have an SCR and only can operate down to a NOx rate of approximately 0.25 lbs/mmBtu. Mon Power will be managing the Seasonal NOx allowance requirements by accessing the markets two months in advance and will be making purchasing and dispatching decisions based on the value of the Seasonal NOx allowances at that time.
Mon Power owns 3,569 MW of generating capacity, comprised of 3,082 MW from supercritical coal generating units and 487 MW from hydro pumped storage generating units, as of June 30, 2016.
The coal units ran pretty strongly in 2015, with 80% being a normal rule of thumb for any coal unit in good repair and with strong power demand. They are:
- Fort Martin Unit 1, 552 MW, 78.4% capacity factor;
- Fort Martin Unit 2, 546 MW, 73.3% capacity factor;
- Harrison Unit 1, 662 MW, 58.6% capacity factor;
- Harrison Unit 2, 661 MW, 66.4% capacity factor; and
- Harrison Unit 3, 661 MW, 71.3% capacity factor.