Xcel Energy (NYSE: XEL) is in varying stages of winning regulatory approvals for power plant projects, including its ongoing work at the Minnesota Public Utilities Commission to decide whether to add self-built gas-fired capacity or outside capacity.
Xcel, in its third quarter earnings statement issued on Oct. 24, ran down the various approval processes involving power plants.
Northern States Power-Minnesota – Minnesota Resource Plan
In March 2013, the Minnesotia Public Utilities Commission (MPUC) approved NSP-Minnesota’s 2011-2025 Resource Plan and ordered a competitive acquisition process be conducted with the goal of adding approximately 500 MW of generation to the NSP System by 2019. Bid proposals were received in April 2013.
In September 2013, NSP-Minnesota submitted testimony to the MPUC and recommended a self-build, 215-MW natural gas combustion turbine at the Black Dog site, where the last coal-fired capacity is to be shut in 2015, and either Calpine’s Mankato combined-cycle natural gas project or Invenergy’s Cannon Falls combustion turbine natural gas project. The competitive acquisition schedule is expected to be as follows:
- Hearings are scheduled for Oct. 21-25;
- Administrative law judge (ALJ) report due Dec. 31, 2013; and
- A final MPUC decision in the first quarter of 2014.
In the first half of 2013, NSP-Minnesota also issued a Request for Proposal (RFP) for wind generation. In addition, NSP-Minnesota filed a petition with the MPUC and the North Dakota Public Service Commission (NDPSC) seeking approval of four wind generation projects. The potential projects are:
- A 200 MW ownership project for the Pleasant Valley wind farm in Minnesota, which is expected to be operational by October 2015;
- A 150 MW ownership project for the Border Winds wind farm in North Dakota, which is expected to be operational by 2015. The feasibility of the Border Winds project is dependent on transmission costs that will be determined by the Midcontinent Independent System Operator;
- A 200 MW purchased power agreement (PPA) with Geronimo Energy for the Odell wind farm in Minnesota; and
- A 200 MW PPA with Geronimo Energy for the Courtenay wind farm in North Dakota.
On Oct. 17, the four wind projects were approved by the MPUC. A decision from the NDPSC is anticipated by the end of 2013.
NSP-Minnesota Nuclear Project Prudence Investigation
In the NSP-Minnesota 2013 Minnesota electric rate case final order, the MPUC initiated an investigation to determine whether the costs in excess of those included in the certificate of need for the Monticello nuclear plant life cycle management (LCM)/extended power uprate (EPU) project were prudently incurred.
In October, NSP-Minnesota filed a summary report and witness testimony to further support the change in and prudence of the incurred costs. The filing indicated the increase in costs was primarily attributable to three factors: the original estimate was based on a high level conceptual design and the project scope increased as the actual conditions of the plant were incorporated into the design; implementation difficulties, including the amount of work that occurred in confined and radioactive or electrically sensitive spaces and NSP-Minnesota’s and its vendors’ ability to attract and retain experienced workers; and additional Nuclear Regulatory Commission (NRC) licensing related requests over the five-plus year application process
In September 2013, the Advisory Committee to the NRC on Reactor Safety recommended approval of the EPU license. The license is expected to be granted by the end of 2013 and the complementary MELLA Plus fuel license is anticipated to be received in March 2014. NSP-Minnesota has provided information that the cost deviation is in line with similar upgrade projects undertaken and the project remains economically beneficial. The results and any recommendations from the conclusion of this prudence proceeding are expected to be considered by the MPUC in NSP-Minnesota’s 2014 Minnesota electric rate case.
NSP-Minnesota – Minnesota 2014 Multi-Year Electric Rate Case
In November, NSP-Minnesota expects to file a multi-year rate plan for its Minnesota retail electric jurisdiction. The case will be based on a 2014 forecast test year (FTY) and will include a request for incremental rate recovery for certain capital related costs in 2015. The case is driven by substantial investment in the system, including: the replacement of the steam generator at the Prairie Island nuclear plant; the life extension at the nuclear plants; the recent return to service of the coal-fired Sherco Unit 3 after nearly two years off-line; and additional owned wind generation.
Interim rates, subject to refund, are expected to take effect in January 2014. NSP-Minnesota also anticipates introducing a mitigation plan, as part of the rate case, to lessen the impact on the customer bill. NSP-Minnesota’s mitigation plan could include further accelerating a theoretical depreciation reserve and/or utilizing expected Department of Energy refunds in excess of amounts needed to fund its decommissioning expense.
Colorado 2011 Electric Resource Plan and 2013 All-Source Solicitation
In January 2013, the Colorado Public Utilities Commission (CPUC) approved with modifications the 2011 Electric Resource Plan (ERP). In March 2013, PSCo issued an All-Source RFP for 250 MW by the end of 2018. PSCo also issued a separate wind RFP for PPAs only.
In September, PSCo filed its preferred plan with the CPUC for resources through 2018, which included:
- The addition of 450 MW of Colorado wind generation PPAs. This additional wind would bring the installed capacity on the PSCo system in Colorado to 2,650 MW;
- The addition of 170 MW of utility-scale solar generation PPAs. PSCo currently has about 80 MW of utility-scale solar and 160 MW of customer-sited solar generation;
- The addition of 317 MW of natural gas-fired generation PPAs, which would come from existing Colorado power plants that previously supplied PSCo, but at reduced prices.
PSCo also examined whether to continue operating two older company-owned power plants or to replace them with new generation resources. PSCo recommended:
- The permanent closure of the 109 MW, coal-fired Unit 4 at the Arapahoe Generating Station in Denver at the end of 2013;
- The permanent closure of the 45 MW, coal-fired Unit 3 at the Arapahoe Generating Station in Denver at the end of 2013; and
- The continued operation of Cherokee Generating Station’s Unit 4 in Denver as a natural gas facility after 2017 (the plant fuel source will be switched to natural gas from coal by the end of 2017 as part of the state’s Clean Air-Clean Jobs Act plan).
In October 2013, the CPUC approved the proposed wind PPAs, citing the significant benefit to customers of acquiring these renewable resources. The CPUC will consider the remaining recommendations later this fall with a decision expected before the end of 2013.