By Tom Kleckner
Xcel Energy has upped the ante in Lubbock Power & Light’s bid to disconnect from SPP and join ERCOT in 2019, asking FERC for an $88.7 million interconnection switching fee should the municipal utility proceed with its plan.
The Minnesota-based company filed a request with FERC on May 24, asking the commission to approve the switching fee by Sept. 21 (ER16-1772).
Xcel made the filing on behalf of its Southwestern Public Service subsidiary, which serves LP&L’s load. It told FERC it was requesting the fee “to mitigate the impact of the LP&L disconnection on SPS’ other transmission customers” and recover the costs of transmission infrastructure built in the Lubbock area since the 1980s.
“If LP&L leaves the SPP regional grid, the costs of infrastructure installed to serve LP&L would be shifted to Xcel Energy’s remaining retail and wholesale customers,” Xcel said in a statement. It said LP&L’s move “will increase their rates unless the interconnection switching fee is implemented.”
LP&L is the third-largest municipal load-serving entity in Texas, providing electricity to the City of Lubbock in West Texas. It is interconnected to the SPS transmission system in SPP and announced last year it planned to join ERCOT in 2019, a move it said would reduce its annual energy and capacity costs by $60 million. (See Integrated System to Join SPP Market Oct. 1; Lubbock Looking at ERCOT.)
LP&L plans to take about 72% of its 605-MW peak load to ERCOT; about 172 MW would remain within SPP through SPS.
Xcel told FERC the load migration “would result in a shift of approximately $13.8 million of zonally allocated ‘sunk’ transmission costs per year to other wholesale and retail customers in the SPS zone of SPP” and “$4.5 million of regionally allocated costs per year to customers throughout the entire SPP region.”
The fee, Xcel said, would “obligate LP&L to hold the remaining wholesale and retail customers in the SPS zone harmless from sunk costs incurred to provide transmission service to LP&L’s load.”
Xcel is basing part of its argument on the exit fee paid to SPP by departing members. It told the commission the RTO does not “provide a mechanism for recovering such costs from wholesale customers or load-serving entities such as LP&L if they withdraw their loads from [SPP], even though the financial impact of such a withdrawal can be similar to that resulting from the withdrawal of an SPP member.”
The filing also said SPP has considered an addition to its Tariff that would have imposed a “network service termination costs” charge on customers withdrawing a portion of their load if it is not later served by another service agreement within the RTO. SPP said Friday the Tariff revision has never been approved by any of its organizational groups nor formally considered.
LP&L said it “is not currently, nor has it ever been, a member of” SPP, and noted it is “merely a customer” of Xcel.
The utility “does not believe that Lubbock ratepayers should be responsible for investments made by Xcel Energy or its subsidiary company beyond the conclusion of the current power agreement,” it said.
LP&L’s contract with Xcel expires in May 2019, at which point it said it will have “fully honored all contractual obligations.” The utility has also said it will continue to honor a 25-year power supply agreement beginning June 2019 for 172 MW.
The utility is currently completing an ERCOT interconnection feasibility study that would need to be approved by the Public Utility Commission of Texas. It said its board and the Lubbock City Council have determined joining the ERCOT market “was in the best long-term interest of the LP&L ratepayers.”
ERCOT Staff IDs Preferred LP&L Integration Option
Meanwhile, ERCOT staff Thursday shared a draft of its LP&L integration study that identified transmission facilities that would be required to connect the utility’s load and system, a 115/69-kV network with about 20 substations. The study will be filed with the PUC after it is first presented to ERCOT’s Board of Directors on June 14.
The analysis looked at more than 40 options, before settling on one of three preferred alternatives that staff said would “minimize societal costs.”
“The selection really came down to economics, capital costs and production costs,” Jeff Billo, ERCOT’s senior manager of transmission planning, told the Technical Advisory Committee.
Staff recommended “option 4ow” as the most efficient alternative, saying it aligned with a 2014 roadmap for future upgrades to accommodate the Panhandle’s vast wind energy resources.
The three alternatives cost between $312 million and $364 million, involving the construction of as much as 141 miles of 345-kV transmission lines. They would also allow up to more than 4,200 MW of energy to be exported from the Panhandle.
The SPP-AECI Interregional Stakeholder Advisory Committee (IPSAC) reviewed and discussed changes to the scope document, which was first unveiled in April. (See “SPP, AECI Begin Biennial Joint-Study Process,” 
The Public Utility Commission approved a somewhat unusual “settlement stipulation” that committed the City of Frisco to paying more than half of the bill for a hybrid above/below-ground route. The 2.9-mile 138-kV project, which received more than 3,000 comments in protest of various above-ground proposed alternatives, was approved with the stipulation that more than 90% of it be installed underground. Built and operated by the Brazos Electric Power Cooperative, the line will run west along Frisco’s Main Street from an existing Oncor line tap to a new Stonebrook substation.
Xcel Energy officials last week outlined millions of dollars in options for improving electric service in North Dakota and told state regulators that its Fargo system is fundamentally sound despite a recent rash of power outages.
Enel Green Power North America has begun building the 150-MW Lindahl wind project in North Dakota. The project is designed to generate about 625 GWh annually to meet the electricity needs of more than 50,000 households.
Renewable Energy Systems is considering a 121-turbine, 150-MW wind energy project on the Michigan Upper Peninsula that would be roughly five times larger than the only wind farm on the peninsula, according to documents obtained by Midwest Energy News using a Freedom of Information Act request.
Opponents to a Duke Energy plan to build a $750 million natural gas-fired plant near Asheville are asking an appeals court to waive a requirement that they post a $10 million bond if they appeal regulators’ approval of the project.
DTE Energy has opened a facility in Bad Axe, Mich., that will serve as an operations center for its renewable energy operations.
Energy Transfer Partners has started construction of the Dakota Access pipeline in three of the four states that the 1,150-mile pipeline will cross, but a discovery of a site in Iowa that may be culturally significant to Native Americans could delay approval there and force rerouting.
A plan by Puget Sound Energy to buy back bonds at a discounted rate isn’t going over well with some of the bond’s owners, who say they deserve better terms. Puget Sound wants to retire $250 million in 6.974% bonds that aren’t due until 2067 as a way to lighten its balance sheet.
