Dynegy (NYSE: DYN) on Jan. 1 retired Unit 1 (90 MW) at the coal-fired E.D. Edwards power plant in Illinois, leaving 585 MW of capacity still operating there within two units, and plans in June 2017 to retire the coal-fired, 1,528-MW Brayton Point plant in Massachusetts.
Those are among the facts that Dynegy revealed in its Feb. 25 annual Form 10-K report.
In November 2015, Dynegy announced that it expects to retire the final two units at the 465-MW Wood River Power Station in Alton, Illinois, in mid-2016, subject to the approval of the Midcontinent ISO. The decision to retire the Wood River coal facility was the result of a strategic review performed in the third quarter of 2015, and was primarily attributable to its uneconomic operation stemming from a “poorly designed” wholesale capacity market, said the company.
Dynegy’s Coal segment is comprised of 11 coal-fired facilities located in Illinois, Massachusetts, and Ohio with a total generating capacity of 8,420 MW. The Baldwin, Havana, Hennepin, and Wood River facilities, located in Illinois, operate in MISO with an aggregate net generating capacity of 3,008 MW. The Conesville, Killen, Kincaid, Miami Fort, Stuart and Zimmer facilities, located in Illinois and Ohio, operate in the PJM Interconnection region with an aggregate net generating capacity of 3,884 MW. Brayton Point facility, located in Massachusetts, operates in ISO New England and has an aggregate net generating capacity of 1,528 MW. Upon the completion of the planned retirements of the Brayton Point and Wood River facilities, the Coal segment will include 6,427 MW of generation capacity, of which 2,543 MW will operate in MISO and 3,884 MW will operate in PJM.
The Illinois Power Holdings (IPH) segment is comprised of five coal-fired facilities located in Illinois with a total generating capacity of 4,178 MW, and primarily operates in MISO. Joppa, which is within the Electric Energy Inc. control area, is interconnected to Tennessee Valley Authority and Louisville Gas and Electric systems but primarily sells its capacity and energy to MISO. Dynegy currently offers a portion of the IPH capacity into PJM. As of June 1, 2016, the Coffeen, Duck Creek, E.D. Edwards and Newton facilities will have 937 MW, or 22% of IPH’s capacity, that is electrically tied into PJM through pseudo-tie arrangements.
On the environmental compliance front, Dynegy report that the Illinois Multi-Pollutant Standard (MPS) SO2 limits started in 2010 for its IPH coal-fired facilities and would have declined in 2014 and 2015 and required compliance with the final SO2 limit beginning in 2017. However, the Illinois Pollution Control Board (IPCB) has granted IPH a variance which provides additional time for economic recovery and related power price improvements necessary to support the installation of flue gas desulfurization (FGD) systems at the Newton facility such that the IPH coal-fired fleet can meet the MPS system-wide SO2 limit. The IPCB approved the proposed plan to restrict the SO2 emissions through 2014 to levels lower than those required by the MPS to offset any environmental impact from the variance. The IPCB’s order also included a schedule of milestones for completion of various aspects of the installation of the Newton FGD systems.
The first board-imposed milestone relating to the FGD engineering design was completed in July 2015, while the last milestone relates to major equipment components being placed into final position on or before Sept. 1, 2019. The variance also requires additional environmental protections in the form of enforceable commitments to cap IPH’s SO2 emissions through Dec. 31, 2020, retire Edwards Unit 1 as soon as permitted by the MISO, and, during the variance period, use only low-sulfur coal at the Newton, Edwards and Joppa facilities and maintain operation of the existing scrubbers at the Duck Creek and Coffeen facilities to achieve a 98% annual average SO2 removal rate. In December 2015, the U.S. Environmental Protection Agency approved the variance as part of the Illinois regional haze state implementation plan (SIP). In February 2016, Dynegy said it issued a notice to the third-party contractor constructing the FGD systems directing them to temporarily suspend a portion of the work being performed.
As of Feb. 8, 2016, excluding Brayton Point, Wood River and non-operated jointly-owned generating units, Dynegy’s expected coal requirements for 2016 are 76% contracted and 73% priced. Forecasted coal requirements for 2017, excluding Brayton Point, Wood River and non-operated jointly-owned generating units, are 29% contracted and 24% priced. Coal transportation requirements are fully contracted for 2016 and 99% contracted for 2017. Coal transportation requirements are approximately 67% contracted for 2018 to 2020. “We recently entered into a new long-term coal transportation agreement for our Kincaid facility,” Dynegy noted. “The contract, which begins in 2017, reflects a reduction from the 2016 rate.”
In addition, Dynegy has entered into new long-term coal transportation agreements for the Duck Creek and Joppa facilities. The rate for Duck Creek is a reduction from the 2014 rate and began in April 2015. The new Joppa transportation contract will begin in 2018 and is also a reduction from the 2017 rate.
In the fourth quarter of 2015, the Brayton Point plant’s operating area experienced significantly warmer weather than normal, resulting in lowered demand and power prices for the period. “Dynegy has previously disclosed plans to retire the facility in June 2017, thus the temperate weather had a significant impact on the facility’s remaining cash flows, resulting in an impairment trigger,” said Dynegy. “We performed step one of the impairment analysis using undiscounted cash flows for the facility’s remaining operational years, and determined the book value of the asset would not be recovered. We performed step two of the impairment analysis using a DCF model, utilizing a 9 percent discount rate, and assuming normal operations for the remainder of its estimated useful life. For the model, gross margin was based on publicly available forward market quotes, operations and maintenance expenses were based on current forecasts, and capital expenditures assumed the minimum of cash expenditures required to continue running the plant until its anticipated retirement. The model resulted in a fair value of the facility of $86 million; therefore, we recorded an impairment charge of $25 million in Impairments in our consolidated statements of operations for the year ended December 31, 2015 to reduce the carrying value of the Brayton Point facility.”