Arizona Electric scores lower coal costs due to rail rate case

A reduction in coal-haul rates from the Union Pacific and BNSF railroads, which Arizona Electric Power Cooperative (AEPCO) was forced to get through a U.S. Surface Transportation Board-decided complaint, has sharply reduced coal costs for the cooperative’s Apache plant.

AEPCO on July 5 filed with the Arizona Corporation Commission for a rate increase. On Sept. 11, a commission administrative law judge laid out a procedural schedule for the case that includes March 2013 deadlines for the parties to file briefs, an April 2013 deadline for rebuttal briefs and a July 29, 2013, hearing start.

In the cooperative’s July 5 filing was testimony from Gary Pierson, employed by Sierra Southwest Cooperative Services as the Manager of Financial Services. Under agreements that Sierra Southwest has with AEPCO and Southwest Transmission Cooperative, which provides wholesale transmission services to AEPCO, he handles various matters, including rate design and implementation for these two cooperatives.

AEPCO had rail transportation contracts with two railroads that expired at the end of 2008. When it became evident that new agreements with the railroads could not be reached, AEPCO became a common carrier customer, Pierson noted. After analysis of the common carrier tariff rates and terms of service, AEPCO decided that the tariff rates were unjust and filed a complaint with the Surface Transportation Board (STB) in 2008, seeking rate relief and the establishment of reasonable rates and other terms of service for its unit coal train transportation service.

In 2008, AEPCO had filed a complaint challenging the reasonableness of the joint rates established by BNSF and UP for unit train coal transportation service from New Mexico and the northern portion of the Powder River Basin in Wyoming and Montana, to Apache, located near Cochise, Ariz. In its November 2011 decision, the board found that AEPCO had shown that defendants have market dominance over those movements, and that their rates were unreasonable.

The board established new lower rail rates for the period 2009 through 2018 and also awarded AEPCO $9.2m in reparations for rail transportation costs paid in 2009, 2010 and 2011. Because the amount of reparations has been appealed by the defendants in the board complaint proceeding, AEPCO has recorded the $9.2m received as a deferred credit until such time as the matter is finally resolved. When that happens, Pierson said that AEPCO will discuss with the commission a mechanism to distribute all or some portion of those reparations to its customers.

“But, as a result of the new tariff rates and terms of service, AEPCO has been able to negotiate new coal supplies for 2012 at a much lower cost than was recorded in the [2011] test period,” Pierson added. “Taking these new coal commodity rates and rail transportation rates into account, AEPCO has included a pro forma reduction in test year coal expenses of approximately $11 million and, correspondingly, the effect is to increase margins by that amount.”

Black & Veatch says Apache coal units should be good until 2035

Also, attached to the July 5 rate filing is a May 2011 life-of-plant assessment report for Apache from consultant Black & Veatch. The plant includes both gas- and coal-fired units. Apache Units 2 and 3 (also known as ST2 and ST3) are essentially identical units commissioned in 1979, each having a gross nameplate rating of 195 MW. Coal is the primary fuel, but the units have been modified to achieve full load on either coal or natural gas. “AEPCO may also consider co-firing of the two fuels in the future,” Black & Veatch noted.

Apache Units 2 and 3 are equipped with hot-side electrostatic precipitators (ESP) for particulate control, wet limestone flue gas desulfurization (FGD) for SO2 control, and overfire air (OFA) for NOx control. Plant staff advised that typical SO2 removal is in the 80%-85% range and is considered marginal. Equipment upgrades over and above those currently in progress will be required to achieve 95% SO2 removal. Upgrades recommended in a 2004 Radian study included additional trays and loop spray header, higher capacity slurry recycle pumps. Conversion to forced oxidation may also be required to support higher removal rates. Plant staff advised Black & Veatch that selective catalytic reduction (SCR) and FGD upgrades are projected for the 2014 timeframe.

AEPCO adds calcium bromide to coal during reclaim to reduce mercury levels by approximately 50%. The mercury is captured in the FGD waste and stored in a lined on-site surface impoundment. Use of hydrogen bromide or other chemical process would be required to meet higher required levels of mercury removal. Plant staff has not been advised of any impact of the calcium bromide on the salability of the fly ash, Black & Veatch said. Plant staff speculated that there may be some impact on ESP operation, but this possibility needs further investigation, it added.

Plant staff advised Black & Veatch that some ESP upgrades were suggested in a 2004 study, but these were not specifically identified. Staff did advise that the ESP controls are adjusted annually to reduce ash carryover. No other ESP related issues were noted.

Based on information gained from the cooperative, and Black & Veatch’s experience with other units of similar design and vintage, it is anticipated the ST2 and ST3 can continue operation to 2035 provided AEPCO continues to maintain good operations, maintenance and safety practices and expand the capital required for periodic replacement/refurbishment of the equipment, the May 2011 report said.

“It should be noted that B&V’s evaluation did not consider the impact of future environmental requirements on the unit,” the report said. “Impacts such as mandated CO2 capture, installation of SCR for NOx reduction, etc. can impact the economic viability of future operations. Evaluation of the regional market power prices in light of environmental compliance costs that increase the AEPCO operating costs would need to consider both the AEPCO costs and the costs that will be incurred by other generators in the region. Such a market evaluation is beyond the scope of this effort.”

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.