NorthWestern says ALJ decision denies it gas plant cost recovery

NorthWestern Corp. (NYSE: NWE) on Oct. 22 appealed to the full Federal Energy Regulatory Commission a Sept. 21 decision by a FERC administrative law judge that it said improperly disallowed passthrough of about $8m per year of its costs for the new, gas-fired Dave Gates Generating Station (DGGS) in Montana.

“This case tests both the Commission’s promise that utilities can recover the costs they prudently incur to meet NERC Reliability Standards and its commitment to the development of a robust ancillary services market necessary to integrate variable energy resources,” said the appeal. “At issue here are the expenses NorthWestern incurs to provide the regulating reserves needed to comply with BAL-001. Unable to supply such reserves from its limited generation resources or to secure the reserves from an illiquid market, NorthWestern constructed a gas-fired plant to provide them. The reasonableness of the plant costs has never been in dispute; the question is NorthWestern’s right to recover a pro rata share of those costs from the transmission customers taking Schedule 3 Regulation and Frequency Response service. The Initial Decision fundamentally erred in answering that question, leaving NorthWestern with an $8 million yearly shortfall, a revenue recovery well below the stipulated cost of service, and an unreasonable return on its $183 million investment.”

This case dates back to 2006, when NorthWestern said it began facing a problem encountered by utilities nationwide—increasing demand for regulation service triggered by the integration of variable energy resources (wind generation). Unlike other utilities, NorthWestern had no generation assets equipped to provide regulation service. The company said it also was confronted with huge price increases in purchasing regulating reserves from third parties and later with a lack of suppliers able to provide sufficient regulating reserves on a long-term basis.

In the face of these problems meeting its mandatory duties under BAL-001, the company began planning the construction of a gas-combustion plant dedicated exclusively to providing firm regulation service. The plant, DGGS, was designed to provide sufficient regulating reserves to cover load and wind generation and quick ramp rates to minimize Area Control Error and meet Reliability Standards.

“Aware of the novelty of building a single plant dedicated to regulation service, NorthWestern apprised the Commission of its plans and secured approval from its state regulator,” NorthWestern noted. “In this proceeding, no party disputed the prudence of constructing DGGS, which went into service in January 2011. No party challenged the reasonableness of the costs of constructing DGGS, the depreciation schedule, or return on equity. In fact, a stipulation was entered as to the justness and reasonableness of the fixed annual cost requirement, and no party contested the reasonableness of the variable costs, most notably fuel, associated with operating the plant. Despite the stipulation, the Initial Decision failed to set a rate permitting NorthWestern to recover the revenue requirement. The Initial Decision instead reduced the proposed Schedule 3 rate by almost 80%, to a level almost half of what NorthWestern earlier was paying third-party suppliers for regulating reserves under Commission-approved contracts.”

NorthWestern claims ALJ decision lacks coherent rationale

The ALJ’s decision offered no coherent rationale for the drastic rate reduction, NorthWestern argued. “The Initial Decision did not find (nor could it) that NorthWestern violated cost causation principles by assigning DGGS costs to the customers for whom the plant was built. Also absent was a finding that the allocation of DGGS costs was incorrect and that retail customers should pay a greater share of the costs of DGGS. The Initial Decision further did not find that NorthWestern should have allocated some of the costs to non-regulation services with an unmet demand. Indeed, the evidence showed that no such demand existed. The Initial Decision reduced NorthWestern’s revenue recovery in two ways: by (1) overstating the capability of DGGS and, conversely, ignoring the reserves needed to ensure firm regulation service; and (2) understating the capacity required to service wholesale customers. Both actions were predicated on the false notion that the methods by which vertically-integrated utilities with fleets of generation units set ancillary service charges fairly allocates costs for a single-purpose unit consistent with cost causation.”

The company added: “The Initial Decision’s decision to deny NorthWestern compensation for the capacity and fuel needed to provide regulation ‘down’ rested on a similar misapplication of older Kentucky Utilities and Allegheny Power orders that set Schedule 3 rates based on the costs of service from generation units dedicated primarily to serving retail load. The Initial Decision failed to follow far more relevant precedent—the Commission’s recent decisions in Order No. 755 and Order No. 764 where the Commission expressly mandated compensation for the legitimate costs associated with regulation ‘down.’”

The ALJ further erred in denying NorthWestern’s right to recover the fuel costs of running DGGS, the company said. “No party disputed the reasonableness of those charges, and the Commission has never prohibited, and in fact has permitted, charging fuel costs through Schedule 3. The Initial Decision nevertheless denied NorthWestern recovery of those costs, on the theory that NorthWestern picked the wrong ancillary service Schedule to recover the costs. However, charging fuel costs under Schedule 3 is more consistent with cost causation than charging them under Schedule 4. For example, the hours in which customers have imbalances are fewer than the hours in which DGGS burns fuel. Further, charging fuel costs under Schedule 4 could create an improper rate subsidy, as the largest Schedule 4 customer does not take regulation service under Schedule 3. The Initial Decision dismissed these points, claiming that NorthWestern should have filed a test case to see whether the Commission would reject an amended Schedule 4. The Initial Decision further assumed that its denial of the fuel cost recovery could be cured by a new Section 205 filing, despite being alerted that the ban on retroactive ratemaking may bar recovery of such charges.”

To meet its needs, NorthWestern purchased three 50 MW gas turbines for DGGS. The turbines were chosen for their ability to ramp up or down quickly as needed for efficient and flexible regulation service. The usable output from a 50 MW turbine is typically less than 50 MW and varies due to factors such as ambient air conditions, fuel type, air quality permit requirements, and equipment performance and availability, the company noted. NorthWestern’s operational plan was to keep two DGGS units in service at all times, with the third unit put into service during times of peak regulation demand.

Construction on DGGS began in 2009 and the plant was put into service on Jan. 1, 2011. The project was completed on time and under budget. NorthWestern submitted detailed data on the construction costs and 2011 and 2012 operating costs and operational data during the discovery process in this proceeding. The reasonableness of the construction and operating costs were not disputed at the hearing, the company said. Staff and NorthWestern entered into a stipulation as to the justness and reasonableness of the fixed annual revenue requirement, which no other party disputed.

DGGS ran without incident in 2011. However, on Jan. 31, 2012, NorthWestern personnel detected vibrations in the turbines along with mechanical damage. As a result, all three units were taken out of service. Due to its obligations as a Balancing Authority, NorthWestern said it immediately contacted potential suppliers of regulating reserves. NorthWestern attempted to get capacity to replace the DGGS capability but was only able to secure 85 MW from Powerex and Avista. The commission approved Powerex’s emergency request to provide regulation service at market-based rates and Avista’s sale at cost-based rates. The contracts with both companies had terms of less than one year. Initial repairs to the turbines were finished in April 2012 and DGGS returned fully to service by May 1, 2012. After that point, NorthWestern did not call further on the Powerex and Avista contracts for regulating reserves.

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.