A recent coal burn test at Georgia Power‘s McIntosh plant shows that low-sulfur Powder River Basin is a viable option for that facility in place of the plant’s current Central Appalachia coal supply.
That was among the points that Georgia Power witnesses covered in June 7 rebuttal testimony filed with the Georgia Public Service Commission related to the utility’s January integrated resource plan (IRP) filing.
The Georgia Power witnesses filing joint rebuttal testimony were: Kyle Leach, Director of Resource Policy and Planning for Georgia Power; Garey Rozier, Manager of Resource Planning for Southern Co. Services; and Larry Legg, Manager of Market Planning for Georgia Power. The utility is a subsidiary of Southern Co. (NYSE: SO).
In summary, the utility in part seeks commission approval within the IRP of the:
- Decertification of Branch Units 3-4, Yates Units 1-5 and McManus Units 1-2 effective by the Mercury and Air Toxics Standards (MATS) compliance date of April 16, 2015, decertification of Kraft Units 1-4 one year past the MATS compliance date (by April 16, 2016), decertification of Boulevard Units 2-3 effective as of the date of the final order in this proceeding, and approval of expedited decertification of Bowen Unit 6 by April 16, 2013;
- A switch to natural gas as the primary fuel for Yates Units 6-7 and Gaston Units 1-4; and
- An amendment of the decertification date specified in the commission’s final order in a prior docket for Branch Unit 1 from Dec. 31, 2013, to coincide with the decertification of Branch Units 3-4.
Aside from Bowen Units 1-4, Wansley Units 1-2 and Hammond Units 1-4, and the coal-fired units for which the company seeks decertification, additional environmental controls will be required for the remaining coal units to operate on coal after the MATS compliance date of April 16, 2015. Specifically, Georgia Power said it plans to utilize a bromine additive at Scherer and switch McIntosh Unit 1 to operate on lower-priced Powder River Basin coal (pending a successful test burn and further study).
The IRP is focused, in part, on the company’s compliance plan for the U.S. Environmental Protection Agency’s MATS rule. In this IRP proceeding, the commission staff has performed an independent, from “scratch” analysis and come to conclusions regarding MATS compliance that are nearly identical to those of the company, the utility witnesses noted. While staff identified a few areas of disagreement concerning the company’s modeling process and critiques some of the company’s assumptions, such differences of opinion do not result in any fundamentally different conclusions and are largely tied to the unprecedented nature of the evaluation required in this case.
While staff comes to a slightly different conclusion with respect to the conversion of Plant Gaston due to a single changed assumption, staff also recognizes that Plant Gaston has the potential to benefit customers with very little downside risk. The company’s analysis of Plant Gaston confirms that the units are economic in all future scenarios and thus should be retained for the benefit of customers.
Among other issues, the June 7 testimony also responds to the concerns raised by staff regarding the company’s plans to supply natural gas to Gaston and Yates. They describe the company’s natural gas transportation procurement strategy for Gaston and Yates and the reasons why the company is confident that it will be able to obtain sufficient natural gas transportation to ensure that these units will be able to reliably serve customers. They also provide further evidence supporting a forecast of Powder River Basin (PRB) coal prices and report on the successful test burn of PRB coal at Plant McIntosh.
Company witnesses defend coal-to-gas switch at Gaston
On the issue of switching the Gaston coal plant to natural gas, the utility witnesses said: “There are a number of policy reasons why the Commission should approve the switch to gas as the primary fuel. First, as noted by Staff, retaining the units would provide protection against any unforeseen contingencies such as higher than expected load growth or unexpected plant unavailability. Second, Plant Gaston may be able to take advantage of low natural gas prices while providing a potential hedge against any unexpected volatility in coal prices. Third, given that Plant Gaston is an existing generation resource requiring comparatively modest capital costs to switch primary fuels, the reasonable course of action would be to retain Plant Gaston as an asset for customers. The Company believes that the Commission should retain for customers the potential benefit of this known generating asset, particularly in light of the fact that, even under Staff’s analysis, the potential downside risk is relatively low.”
The utility strongly disagrees with the assertion of a Southern Alliance for Clean Energy (SACE) witness that the company’s assumption regarding the remaining operating life of Plant Gaston Units 1-4 is unreasonable. The company’s history of reliable service including its industry leading Equivalent Forced Outage Rate (EFOR) is a testament to the company’s proactive maintenance practices at each of its generating units, the witnesses said. Currently, there are plants at Georgia Power and across the Southern system that have reliably operated for over 60 years (the age at which the SACE witness arbitrarily assumes retirement of Plant Gaston in his study) and can be expected to continue to operate reliably in the future. In other words, the SACE assumption that a unit cannot be assumed to reliably provide service beyond 60 years has already been disproven by the company’s actual operating experience.
As for the Bowen plant, where all units were temporarily shut in early April after an explosion at Unit 2, the company witnesses said: “The Company has determined that repairing the units and returning them to service is the best economic option for customers and is committed to returning Plant Bowen to full operation in a timely manner while ensuring safety and reliability. Plant Bowen Units 3 and 4 were returned to service at the beginning of May. The Company continues to evaluate what impact, if any, the incident will have on the schedule to install the MATS compliance equipment.”
As for the McIntosh coal test, they wrote: “Subsequent to the filing of the IRP, the Company completed a test burn on PRB coal with the use of MATS additives at Plant McIntosh. In March, Plant McIntosh Unit 1 tested the use of Activated Carbon Injection (‘ACI’) and Dry Sorbent Injection (‘DSI’) systems while burning PRB coal to evaluate MATS compliance. The results of the test burn confirmed the unit is fully capable of accommodating PRB coal and that it can comply with the stringent MATS requirements with ACI and DSI systems.”
They added that the updated economics are not fundamentally different from the economics presented for Plant McIntosh in the 2013 IRP Unit Retirement Study, thus confirming the recommendation to move forward with switching the primary fuel to PRB coal at Plant McIntosh as proposed in the IRP.
Here is an outline of some of the targeted units in the IRP:
- Branch Units 3-4 are fired with coal, have a total capacity of 509 MW and 507 MW, respectively, and were placed in service in 1968 and 1969, respectively.
- Kraft Units 1-4 are coal-fired units that were placed in service at various times between 1958 and 1971 and have a total capacity of 316 MW.
- McManus Units 1-2 are oil-fired steam facilities that went into service in 1952 and 1959, respectively, and have 43 MW and 79 MW of capacity, respectively.
- Yates Units 1–5 are coal-fired units that were placed into service at various times between 1950 and 1958 and have 579 MW of total capacity.
- Boulevard Units 2-3 are oil-fired combustion turbines (CT) rated at a capacity of 14 MW each, and were installed in 1970 along with Unit 1. Both units recently experienced a significant equipment failure and the company’s economic analysis demonstrates that the repairs are not in customers’ best interest. Boulevard Unit 1 is not damaged, remains cost-effective, and is recommended for continued operation.
- Bowen Unit 6 is a 32-MW oil-fired CT that is only permitted to operate during non-summer months due to ozone nonattainment requirements in the area.