Xcel outlines coal procurement, retirements across its system

The Northern States Power system, with operations in Minnesota and Wisconsin, normally maintains approximately 41 days of coal inventory, but coal supply inventories at the ends of 2014 and 2013 were approximately 27 and 34 days usage, respectively.

As of the end of 2014, coal inventories were below optimal levels due to railcar congestion, said Xcel Energy (NYSE: XEL) in its Feb. 20 annual Form 10-K report. NSP-Minnesota’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Wyoming and Montana.

During 2014 and 2013, coal requirements for the NSP System’s major coal-fired plants were approximately 9.3 million tons and 7.3 million tons, respectively. Coal requirements for 2014 were higher as Sherco (also known as Sherburne County) Unit 3 was placed back in service after a long forced outage. The estimated coal requirements for 2015 are approximately 8.7 million tons, which reflects the retirement of the aged Black Dog Units 3 and 4 (215 MW net summer total) in Minnesota.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 88% of their estimated coal requirements in 2015, and a declining percentage of the requirements in subsequent years. The NSP System’s general coal purchasing objective is to contract for approximately 100% of requirements for the first year, 67% of requirements in year two, and 33% of requirements in year three. Remaining requirements will be filled through the procurement process or over-the-counter transactions.

NSP-Minnesota and NSP-Wisconsin have a number of coal transportation contracts that provide for delivery of 100% of their coal requirements in 2015 and 2016. Coal delivery may be subject to interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment, the company noted.

Xcel’s Public Service Co. of Colorado (PSCo) subsidiary normally maintains approximately 41 days of coal inventory. Coal supply inventories as of the ends of 2014 and 2013 were approximately 36 and 41 days usage, respectively. At Dec. 31, 2014, coal inventories were below optimal levels due to railcar congestion.

PSCo’s stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Colorado and Wyoming. During 2014 and 2013, PSCo’s coal requirements for existing plants were approximately 10.3 million tons and 11.3 million tons, respectively. The estimated coal requirements for 2015 are approximately 11.0 million tons.

PSCo has contracted for coal supply to provide 96% of its estimated coal requirements in 2015, and a declining percentage of requirements in subsequent years. PSCo’s general coal purchasing objective is like that of the Northern States Power companies. PSCo has coal transportation contracts that provide for delivery of 100% of its coal requirements in 2015 and 2016. Coal delivery may be subject to interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

Southwestern Public Service (SPS) purchases all of the coal requirements for its two coal facilities, Harrington and Tolk electric generating stations, from TUCO. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers.

The coal supply contract with TUCO expires in 2016 for Harrington (1,018 MW net summer) and Tolk (1,067 MW net summer). SPS normally maintains approximately 43 days of coal inventory. As of the ends of 2014 and 2013, coal inventories at SPS were approximately 17 and 42 days supply, respectively. At Dec. 31, 2014, coal inventories were below optimal levels due to railcar congestion. TUCO has coal agreements to supply 87% of SPS’ estimated coal requirements in 2015, and a declining percentage of the requirements in subsequent years. SPS’ general coal purchasing objective is like that of NSP and PSCo.

Coal-fired retirements in the works across the Xcel system

The Colorado Public Utilities Commission provided final approval to a PSCo resource plan in December 2013, which includes the following:

  • The addition of 450 MW of wind generation power purchase agreements (PPAs), which are expected to be operational in 2015. These additional PPAs will bring the installed wind capacity on PSCo’s system in Colorado to 2,650 MW:
  • The addition of 170 MW of utility-scale solar generation PPAs, which are expected to be operational in 2016. PSCo has approximately 80 MW of utility-scale solar and approximately 188 MW of customer-sited solar generation;
  • The addition of 317 MW of natural gas fired generation PPAs, which will come from existing power plants;
  • The accelerated retirements of the coal-fired Arapahoe Unit 3 (45 MW) and Unit 4 (109 MW), which occurred in 2013; and
  • The continued operation of Cherokee generating station’s coal-fired Unit 4 as a natural gas facility after 2017.

In addition, PSCo continues to execute on the remaining aspects of Clean Air-Clean Jobs Act (CACJA) compliance including the construction of a new natural gas-fired combined cycle unit at the Cherokee station and the addition of emissions controls at the Pawnee and Hayden coal stations. PSCo also expects to retire the Cherokee Unit 3 and Valmont Unit 5 coal-fired facilities by the end of 2015 and 2017, respectively.

In January 2015, NSP-Minnesota filed its 2016-2030 Resource Plan with the Minnesota Public Utilities Commission (MPUC), proposing to achieve a 40% reduction in carbon emissions by 2030 from 2005 levels. The plan positions NSP-Minnesota to be responsive to future environmental requirements and market trends, builds on the significant investments already made in the NSP System, and acknowledges the divergence in state energy policies within the NSP System. Key points of the resource plan include:

  • Adding 600 MW of wind by 2020 and 1,200 MW by 2027, bringing total wind power on the NSP System to over 3,600 MW;
  • Adding 187 MW of large-scale solar energy by 2016 and an additional 1,700 MW of large-scale solar and 500 MW of customer-driven small-scale solar; bringing total solar power on the NSP System to approximately 2,400 MW;
  • Operating the Monticello and Prairie Island nuclear plants through their current licenses; and
  • Continuing to run the coal-fired Sherco Unit 1 (680 MW net summer) and Unit 2 (682 MW net summer) with gradually decreasing reliance through 2030.

In February 2015, the MPUC approved the Competitive Acquisition Plan (CAP), in which NSP-Minnesota is required to add capacity to its system to meet a resource need as follows:

  • Enter into an agreement for 100 MW of distributed solar with Geronimo Energy LLC;
  • Enter into an agreement with Calpine Corp. for a 345 MW expansion at its gas-fired Mankato Energy Center; and
  • Construct a 215-MW Black Dog Unit 6, which would be a gas-fired combustion turbine, in part helping make up for the retirement of coal units at the Black Dog site.

The Form 10-K doesn’t indicate any negatives for Tolk and Harrington in the SPS resource plan summary.

Clean-air picture is somewhat hazy due to ongoing litigation

The Xcel subsidiaries are subject to various clean-air rules. For example, in 2011, the Colorado Air Quality Control Commission approved a state implementation plan (SIP) (the Colorado SIP) that included the CACJA emission reduction plan as satisfying regional haze requirements for the facilities included in the CACJA plan. In addition, the Colorado SIP included a best available retrofit technology (BART) determination for Comanche Units 1 and 2. The EPA approved the Colorado SIP in 2012. Installation of emission controls at Pawnee was completed in 2014 at a cost of $272.6 million. Installation of the emission controls at Hayden Unit 1 is scheduled for 2015 and Hayden Unit 2 is scheduled for 2016 at an estimated combined cost of $84.6 million.

In March 2013, WildEarth Guardians petitioned the U.S. Court of Appeals for the Tenth Circuit to review the EPA’s decision approving the Colorado SIP. WildEarth Guardians has stated it will challenge the BART determination made for Comanche Units 1 and 2. In comments before the EPA, WildEarth Guardians urged that current emission limitations be made more stringent or that selective catalytic reduction (SCR) be added to the units. In September 2014, the EPA filed a request with the court to remand the case to the EPA for additional explanation of the EPA’s decision approving the BART determination for Comanche Units 1 and 2. In October 2014, the court granted the EPA’s request and vacated the current briefing schedule. The EPA has provided required status reports.

In 2010, two environmental groups petitioned the Department of the Interior to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park. The following PSCo plants are named in the petition: Cherokee, Hayden, Pawnee and Valmont. The groups allege the Colorado BART rule is inadequate to satisfy the Clean Air Act (CAA) mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park. It is not known when Interior will rule on the petition, Xcel noted.

In 2009, the Minnesota Pollution Control Agency (MPCA) approved a SIP (the Minnesota SIP) and submitted it to the EPA for approval. The MPCA’s source-specific BART limits for Sherco Units 1 and 2 require combustion controls for NOx and scrubber upgrades for SO2. The MPCA concluded SCRs should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs. The combustion controls were installed first and the scrubber upgrades were completed in December 2014. These emission controls cost $46.6 million.

After the Cross-State Air Pollution Rule (CSAPR) was adopted in 2011, the MPCA supplemented its Minnesota SIP, determining that CSAPR meets BART requirements, but also implementing its source-specific BART determination for Sherco Units 1 and 2 from the 2009 Minnesota SIP. In June 2012, the EPA approved the Minnesota SIP for electricity generating units (EGUs) and also approved the source-specific emission limits for Sherco Units 1 and 2 as strengthening the Minnesota SIP, but avoided characterizing them as BART limits.

In August 2012, environmental groups including the National Parks Conservation Association and Sierra Club appealed the EPA’s approval of the Minnesota SIP to the U.S. Court of Appeals for the Eighth Circuit. NSP-Minnesota and other regulated parties were denied intervention. In June 2013, the Eighth Circuit ordered this case to be held in abeyance until the U.S. Supreme Court decided the CSAPR case. In October 2014, the Eighth Circuit set a briefing schedule that will be completed in early 2015. An argument date has not been set. If this litigation ultimately results in further EPA proceedings concerning the Minnesota SIP, such proceedings may consider whether SCRs should be required for Sherco Units 1 and 2.

Harrington Units 1 and 2 at Southwestern Public Service are potentially subject to BART. Texas developed a SIP (the Texas SIP) that finds the Clean Air Interstate Rule (CAIR) equal to BART for EGUs. As a result, no additional controls beyond CAIR compliance would be required. In May 2012, the EPA deferred its review of the Texas SIP in its final rule allowing states to find that CSAPR compliance meets BART requirements for EGUs. In December 2014, the EPA proposed to approve the BART portion of the Texas SIP, with the exception that the EPA would substitute CSAPR compliance for Texas’ reliance on CAIR. The EPA currently plans to issue its final rule in August 2015.

In May 2014, the EPA issued a request for information under the Clean Air Act related to SO2 control equipment at Tolk Units 1 and 2. In its December 2014 proposal, the EPA plans to disapprove the reasonable progress portions of the Texas SIP and instead adopt a Federal Implementation Plan. For SPS, the EPA proposed to require dry scrubbers on both Tolk units to reduce SO2 emissions to help achieve reasonable progress goals the EPA would establish for Texas and Oklahoma national parks and wilderness areas. As proposed, the dry scrubbers would need to be installed and operating within five years of the EPA’s final action, currently expected in August 2015. SPS plans to file comments objecting to the installation of dry scrubbers on the units. If required, the dry scrubbers would cost approximately $600 million.

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.