Xcel Energy asks to delay Minnesota natural gas projects, but solar energy a priority
The company provided a status report regarding changes in the company’s resource needs, including those resulting from changes in the Midcontinent ISO’s reserve requirements by October 2014
Northern States Power told the Minnesota Public Utilities Commission on Sept. 23 that a recent downward revision its power demand forecast calls into question the need in the near term for new purchased power agreements for gas-fired capacity.
The company provided a status report regarding changes in the company’s resource needs, including those resulting from changes in the Midcontinent ISO’s reserve requirements by October 2014, according to GenerationHub.
Xcel also filed Draft Power Purchase Agreements with Calpine and Invenergy, and price terms for its own gas-fired Black Dog Unit 6 self-build option, so that the commission can determine which of these project(s), if any, best addresses the company’s overall system needs.
It also filed a draft power purchase agreement with Geronimo Energy for commission review to ensure that the negotiated terms for the Aurora solar power project, which is a series of distributed solar projects, are consistent with the public interest.
“We have spent the summer negotiating contracts and developing pricing terms with the parties consistent with the Commission’s Order, which we provide with this filing,” said this Xcel Energy unit. “However, based on our updated resource need assessment, we believe it would be beneficial to our customers to delay the addition of any thermal resources to our system. Instead, we recommend the Commission afford us the opportunity to work with Calpine and Invenergy to renegotiate PPAs with pricing to reflect in-service dates ranging from 2019-2021 and similarly refresh our Black Dog 6 self-build proposal. We would then bring the revised agreements and our Black Dog 6 pricing terms, along with any new resource need information, back to the Commission by May 1, 2015.”
With respect to solar, however, given the expected step-down of the Investment Tax Credit (ITC) at the end of 2016, Xcel said it believes a different approach — and some urgency – is needed. As it discussed in a recent status update in its Solar RFP proceeding, it received competitive pricing on a range of solar proposals, and believes the commission would benefit from an overall look at the addition of solar resources to the system. Thus, it believes the commission’s public interest determination for the Aurora solar project in this proceeding could be informed by the PPAs it develops through the separate Solar RFP process.
A May 23 commission order required the company to negotiate draft PPAs for acquiring new supply resources with Geronimo Energy, Calpine Corp. and Invenergy Thermal Development – and to develop price terms for its own Black Dog Unit 6 — and submit the terms for commission approval no later than Sept. 23.
As for its revised power need forecast, the company said: “While we have been seeing stronger than expected sales in the recent past, our peak demand over the last two summers has not shown the same growth. In fact, our current forecast indicates a slight downward correction, projecting average growth over the 2017-2022 period to be less than 0.60 percent compared to the September 2013 update, which indicated average growth of 0.90 percent.
“This lower expected growth rate in customer demand represents a 22 MW reduction in the forecasted median Peak Demand in 2017, growing to a 190 MW reduction by 2021, and a 388 MW reduction in 2024.
“In summary, our analysis indicates that we will have surplus capacity resources — over-and-above our MISO Reserve Margin — of approximately 250 MW in 2017, 175 MW in 2018, and nearly 100 MW in 2019. This changed assessment is the result of very modest changes in the Customer Demand forecast, but primarily greater confidence in the MISO resource adequacy paradigm.”
During the negotiation of the PPAs with the parties and prior to completion of a customer demand forecast update, it became apparent that, due to the passage of time, bidders were no longer able to meet a 2017 in-service date with their projects. As a result, Xcel began to investigate whether there may be any short-term capacity enhancements available. Xcel found two short-term resources that could be used as tools to further strengthen its resource adequacy position, if needed.
· Manitoba Hydro — Xcel Energy and Manitoba Hydro are parties to three separate power supply agreements that terminate in April 2025. These agreements, in aggregate, provide the company with over 700 MW of accredited summer generation capacity for years 2015-2020, increasing to over 800 MW for years 2021-2025. One of these agreements is an exchange of generating capacity. “We are currently in discussions with Manitoba Hydro to increase our diversity exchange by approximately 75 MW,” the company noted.
· Blue Lake — Xcel investigated the remaining lives of some of its older peaking units. As part of past resource need assessments it assumed four of its older peaking units, Blue Lake 1-4, will be retired in 2019. Blue Lake Units 1-4 are oil-fired peakers that have been dispatched only a few times a year to provide energy during peak demand periods associated with extreme hot or cold weather conditions. These four units have combined capacity of 157 MW and can contribute about 153 MW toward MISO’s resource adequacy determination. “We believe we can accomplish a short extension to their operating life, to 2023, with a minimal, if any, increase in current fixed and variable O&M, since the units are operated infrequently – and by the same staff operating other peaking units at the plant site,” the company said. “Further, we anticipate only minor improvements and repairs in order to extend the life of these units through the 2020-2023 period.”
“Even with the uncertainty in resource need assessments, our analysis leads us to conclude that there is high probability we will have more than adequate generating resources through 2018 or 2019, and perhaps through 2023," Xcel told the commission. "If the commission agrees with our reassessment of our capacity needs, the terms and timing of the Power Purchase Agreements we have negotiated no longer coincide with our anticipated need.
“Even though the analysis suggests we can forgo generation additions until at least 2020, if not longer, we believe a conservative approach continues to be in order. Rather than start a whole new resource acquisition process, we recommend that the commission permit the company to return to the bidders for renewed discussions regarding the timing of these resources.
“We would work with bidders to refresh their proposals to reflect potential in-service dates in the 2019-2021 timeframe, as well as options to delay or cancel. We request that the commission require the company to report back in May 2015 with updated pricing for 2019-2021 in-service dates for all thermal PPAs and the Black Dog 6 unit if the company believes it can provide greater benefit.”
The outside gas-fired capacity where PPA talks have been ongoing are:
· Calpine Mankato Energy Center Expansion — Calpine proposed a 20-year PPA for the capacity of a 345 MW natural gas-fired combined cycle facility to be built at its existing 375-MW Mankato Energy Center combined cycle plant. At hearing, Calpine initially proposed a 2017 commercial operation date (COD), but upon request provided pricing information for CODs in 2018 and 2019.
· Invenergy Cannon Falls Expansion — Invenergy proposed a 20-year PPA for the capacity of a 179-MW combustion turbine peaking unit added to its existing 357-MW simple cycle plant site at Cannon Falls, Minnesota. Invenergy initially proposed a June 1, 2016, COD, but upon request during the course of the proceedings provided pricing information for a 2017 COD, when it was anticipated Xcel Energy’s need would begin, as well as for 2018 and 2019 CODs.
Also, Xcel Energy proposed a peaker, nominally a 215 MW combustion turbine, located within the power house at its Black Dog site in Burnsville, Minn. Only minor changes to the existing 115 kV switchyard will be required to connect Black Dog 6 to the transmission system, and no upgrades are required to the 115 kV transmission system.
Geronimo proposed a 20-year PPA for up to 100 MW of nameplate capacity from distributed solar facilities, ranging in size from 2 MW to 10 MW and located at up to 31 sites. Geronimo proposed a Dec. 1, 2016, COD to ensure that its project would qualify for the 30% ITC, and proposed a modified solar energy PPA form that was used in a Request for Proposal process conducted by another Xcel Energy operating company, Public Service Co. of Colorado.
Geronimo has since modified the number of sites to 24, which range in size from 1.5 MW to 10 MW. The maximum nameplate capacity Geronimo may deliver under the PPA is capped at 100 MW, and Geronimo has the discretion to determine which of the sites it will bring to COD to deliver capacity up to the cap.