CED Wheatland v. MPSC

2022 MT 87

Opinion

05/10/2022

DA 21-0250 Case Number: DA 21-0250

IN THE SUPREME COURT OF THE STATE OF MONTANA 2022 MT 87

CED WHEATLAND WIND, LLC,

Petitioner and Appellant,

v.

THE MONTANA DEPARTMENT OF PUBLIC SERVICE REGULATION, MONTANA PUBLIC SERVICE COMMISSION and NORTHWESTERN CORPORATION d/b/a NORTHWESTERN ENERGY,

Respondents and Appellees.

__________________________________________

CED TETON COUNTY WIND, LLC, and CED PONDERA WIND, LLC,

Petitioners and Appellants,

THE MONTANA DEPARTMENT OF PUBLIC SERVICE REGULATION, MONTANA PUBLIC SERVICE COMMISSION and NORTHWESTERN CORPORATION d/b/a NORTHWESTERN ENERGY,

Respondent and Appellees,

and

THE MONTANA CONSUMER COUNSEL,

Respondent-Intervenor and Appellee.

APPEAL FROM: District Court of the First Judicial District, In and For the County of Lewis and Clark, Cause No. ADV-2020-1292 Honorable Mike Menahan, Presiding Judge COUNSEL OF RECORD:

For Appellants:

Michael J. Uda, Anna M. Kecskes, Colson R. Williams, Lowell J. Chandler, Uda Law Firm, P.C., Helena, Montana

For Appellees:

Benjamin J. Alke, Crist, Krogh, Alke & Nord, PLLC, Billings, Montana (for NorthWestern Energy)

Sarah N. Norcott, NorthWestern Energy, Helena, Montana

Clark Robert Hensley, NorthWestern Energy, Missoula, Montana

Jason Brown, Montana Consumer Counsel, Helena, Montana

Ben W. Reed, Lucas R. Hamilton, Aimee Hawkaluk, Public Service Commission, Helena, Montana

Submitted on Briefs: November 10, 2021

Decided: May 10, 2022

Filed: q3,,---, 6mal•-.— 4( __________________________________________ Clerk

2 Justice Laurie McKinnon delivered the Opinion of the Court.

¶1 CED Wheatland Wind, CED Teton County Wind, and CED Pondera Wind—three

wholly owned subsidiaries of Consolidated Edison Development (“CED”)—appeal the

April 19, 2021, Order on Petitions for Judicial Review issued by the First Judicial District

Court, Lewis and Clark County, which partially affirmed and partially reversed two earlier

Orders on Reconsideration issued by the Montana Public Service Commission (“The

Commission”). The Commission’s orders set the terms and conditions for three CED wind

farm projects that were to be undertaken with NorthWestern Energy Corporation

(“NorthWestern”). On appeal, CED raises four issues, which we restate as follows:

1. Whether the District Court erred in upholding the Commission’s determination that CED’s three qualifying facilities were responsible for bearing the network upgrade costs required to upgrade NorthWestern’s transmission system for each of the three QFs.

2. Whether the District Court properly upheld the Commission’s decision to calculate avoided energy costs using a proxy model.

3. Whether the District Court properly upheld the Commission’s decision to calculate ancillary service deductions based on NorthWestern’s proposed rates.

4. Whether the District Court properly upheld the Commission’s determination that 15-year contract lengths were appropriate for all three of CED’s projects.

¶2 We affirm in part, reverse in part, and remand for further proceedings.

FACTUAL AND PROCEDURAL BACKGROUND

¶3 Under the Public Utility Regulatory Policies Act of 1978 (“PURPA”), public utility

companies are required by federal law to purchase electricity generated by “qualifying . . .

3 facilit[ies].” 16 U.S.C. § 824a-3(a). NorthWestern, is a public utility company subject to

16 U.S.C. § 824a-3(a). CED Wheatland Wind, LLC, CED Teton County Wind, LLC, and

CED Pondera Wind, LLC are self-certified qualifying facilities (“QFs”) under PURPA,

which grants them the right to sell energy and capacity to a public utility such as

NorthWestern. In the absence of a formal contract between a public utility and a QF, the

Federal Energy Regulatory Commission (“FERC”) has stated—under its PURPA

authority—that a QF can still sell power to a public utility in the event that a “Legally

Enforceable Obligation” (“LEO”) is found to exist between the parties. 18 C.F.R.

§ 292.304(d)(2).

¶4 Authority to enforce PURPA is also delegated, in part, to state regulatory agencies

like the Commission, due to their localized knowledge and expertise. As a result, shortly

after PURPA’s passage, Montana enacted its own “Mini-PURPA” law, which provides

that if a utility provider and a QF cannot agree on contractual terms, “[t]he [Montana Public

Service] Commission shall determine the rates and conditions of the contract upon

petition” from either party. Section 69-3-603(2)(a), MCA. CED filed petitions asking the

Commission to determine its contract terms with NorthWestern for three projects: a

proposed 75-megawatt (“MW”) wind farm to be located in Wheatland County, Montana

(“Wheatland facility”), a 19-MW wind farm to be located in Teton County, Montana

4 (“Teton facility”), and a 20-MW wind farm to be located in Pondera County, Montana

(“Pondera facility”).1

¶5 Negotiations between CED and NorthWestern regarding power purchase

agreements (PPAs) for each of the three facilities began in July 2018, September 2018, and

May 2019 for the Teton, Wheatland, and Pondera facilities, respectively. As part of the

negotiation process, CED requested that NorthWestern complete a Large Generation

System Impact Study (“LGSIS”) analyzing the potential impact of each facility on

NorthWestern’s system. Relating specifically to the Wheatland facility, NorthWestern

studied the project as both Network Resource Interconnection Service (“NRIS”) and

Energy Resource Interconnection Service (“ERIS”). The LGSIS identified “no additional

upgrades beyond the [point of interconnection]” necessary to interconnect through ERIS.

However, under NRIS, the LGSIS indicated the Wheatland facility would cause overloads

to NorthWestern’s system and identified the corresponding need for a new 230 kilovolt

(kV) transmission line to accommodate the increased generation. The LGSIS provided

interconnection cost estimates of approximately $6 million for ERIS and $128 million for

NRIS, subject to change. CED elected to interconnect through NRIS. The record indicates

1 PURPA and Montana’s “Mini-PURPA” requires that for QFs between 3 and 80 MW avoided-costs be established between the QF and the purchasing public utility through a negotiated contract, on an “as available” basis, or pursuant to an LEO, whereas small QFs under 3 MW receive a standard avoided-cost rate set by the Commission every two years. MTSUN, LLC v. Mont. Dep’t of Pub. Serv. Regulation, 2020 MT 238, ¶ 5, 401 Mont. 324, 472 P.3d 1154 (citations omitted).

5 CED was aware of the estimated costs for ERIS and NRIS and apparently did not dispute

the initial estimates or its responsibility for some of those costs.

¶6 In mid-2019, PPA negotiations for all three facilities stalled. On September 16,

2019, CED filed two separate “Petition[s] to Set Terms and Conditions for a Qualifying

Small Power Production Facility Pursuant to [] § 69-3-603[, MCA,]” before the

Commission for CED’s Teton and Pondera facilities. Later, on October 4, 2019, CED filed

a third petition with the Commission to set the terms for CED’s Wheatland facility

(“Wheatland matter”). On October 25, 2019, the Commission consolidated CED’s Teton

petition and Pondera petition into a single case before the agency (“Teton-Pondera

matter”). The Intervenor in the present matter—the Montana Consumer Counsel

(MCC)2—first intervened in both the Teton-Pondera and Wheatland matters before the

Commission.

¶7 The Commission held evidentiary hearings in the Teton-Pondera matter from

January 22-24, 2020, and entered a Final Order on March 23, 2020 (“Teton-Pondera Final

Order”). Both CED and NorthWestern filed motions with the Commission for

reconsideration of this decision. On July 9, 2020, the Commission issued its Order on

Reconsideration in the Teton-Pondera matter (“Teton-Pondera Reconsideration Order”),

which affirmed most aspects of the original Teton-Pondera Final Order.

2 The MCC is an office established by the Montana Constitution to advocate on behalf of the interests of Montana’s utilities consumers. Mont. Const. art. XIII, § 2.

6 ¶8 The Commission held evidentiary hearings in the Wheatland matter from February

10-11, 2020. The Commission issued a Final Order in this matter on April 22, 2020

(“Wheatland Final Order”). Once again, both CED and NorthWestern filed motions with

the Commission for reconsideration of this decision. On July 13, 2020, the Commission

issued its Order on Reconsideration in the Wheatland matter (“Wheatland Reconsideration

Order”), which also affirmed most aspects of the original Wheatland Final Order.

¶9 CED’s petitions before the Commission in the Teton-Pondera matter and the

Wheatland matter both presented eight identical issues for review. The following four

issues are pertinent to CED’s appeal: whether CED or NorthWestern should financially

bear the network upgrade costs for each of the three wind facility projects (Issue I); whether

the proper methodology was used for calculating the avoided energy costs for each facility3

(Issue II); whether the proper methodology was used for calculating ancillary services

deductions4—which are deducted from the avoided energy costs for each facility (Issue

III); and whether the contract length awarded for each facility was appropriate (Issue IV).

3 Avoided [energy] costs are defined as “the incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source.” 18 C.F.R. § 292.101(b)(6). Stated more simply, avoided energy costs represent the amount NorthWestern would spend to generate the electricity itself or acquire it from another source. 4 Ancillary services are services that support the transmission of capacity and energy from generating resources to load while maintaining reliable operation of the system. Ancillary service tariffs function as deductions from the avoided energy costs that NorthWestern is required to pay CED’s facilities for their power generation, in return for NorthWestern providing these ancillary services. NorthWestern proposed—and the Commission adopted—ancillary service deductions for the three CED facilities based on the Open Access Transmission Tariff or “OATT,” which is a form of ancillary services tariff that is accepted and approved by FERC. See 18 C.F.R. § 35.28(c). 7 ¶10 Under § 2-4-702, MCA (the provision of the Montana Administrative Procedure

Act (“MAPA”) permitting judicial review of agency decisions), CED petitioned the

District Court for review of the Commission’s Teton-Pondera Reconsideration Order and

the Commission’s Wheatland Reconsideration Order. CED’s petitions requested the

District Court’s review of the Commission’s decisions on all eight issues presented to the

Commission. The District Court consolidated CED’s two petitions into a single appeal and

heard oral argument on the matter. On April 19, 2021, the District Court issued its “Order

on [the] Petitions for Judicial Review” (District Court’s Order). The District Court

affirmed the Commission’s decisions on six of the eight issues raised, including the

Commission’s decisions on Issues I through IV. CED appeals the District Court’s Order

upholding the Commission’s rulings on Issues I through IV.

¶11 Additional facts are set forth within the relevant issues as necessary.

STANDARDS OF REVIEW

¶12 MAPA provides the standards of review governing appeals of administrative agency

decisions in a contested case. Section 2-4-704, MCA. In administrative appeals, this Court

applies the same standards of review as a district court. McGree Corp. v. Mont. Pub. Serv.

Comm., 2019 MT 75, ¶ 6, 395 Mont 229, 438 P.3d 326 (citing NorthWestern Corp. v. Mont.

Dep’t of Pub. Serv., 2016 MT 239, ¶ 25, 385 Mont. 33, 380 P.3d 787). This Court reviews

an administrative decision in a contested case to determine whether the agency’s findings

of fact are clearly erroneous and whether its interpretation of law is correct. MTSUN, ¶ 51

(citing Whitehall Wind, LLC v. Mont. Pub. Serv. Comm., 2010 MT 2, ¶ 15, 355 Mont. 15, 8 223 P.3d 907). Our review “must be confined to the record.” Section 2-4-704(1), MCA.

Accordingly, this Court may not substitute its judgment for that of the agency in weighing

factual evidence. Vote Solar v. Mont. Dep’t of Pub. Serv. Regulation, 2020 MT 213A,

¶ 36, 401 Mont. 85, 473 P.3d 963; Section 2-4-704(2), MCA. A finding of fact is clearly

erroneous if it is not supported by substantial evidence in the record, if the fact-finder

misapprehended the effect of the evidence, or if a review of the record leaves this Court

with a definite and firm conviction that a mistake has been made. McGree, ¶ 8 (citations

omitted). An agency’s interpretation of a statute is a conclusion of law that we review de

novo. McGree, ¶ 6 (citations omitted).

¶13 This Court may reverse or modify an agency decision if the substantial rights of a

party have been prejudiced because the agency’s decision: is in violation of constitutional

or statutory provisions; exceeds the agency’s statutory authority; is made upon unlawful

procedure; is affected by other error of law; is clearly erroneous in light of the whole record;

or is otherwise “arbitrary or capricious or characterized by [an] abuse of discretion.”

Section 2-4-704(2)(a)(i)-(vi), MCA. This Court may also reverse or modify an agency

decision if “findings of fact, upon issues essential to the decision, were not made” despite

being requested. Section 2-4-704(2)(b), MCA. While agencies possess specific, technical,

and scientific knowledge exceeding that of this Court, an agency must articulate a

satisfactory explanation for its actions and provide a rational connection between the facts

found and the choice made. MTSUN, ¶ 52 (citations omitted). This Court will not defer to

9 an agency’s incorrect or unlawful decisions but will only defer to an agency action within

permissible statutory bounds. MTSUN, ¶ 52 (citations omitted).

DISCUSSION

¶14 1. Whether the District Court erred in upholding the Commission’s determination that CED’s three qualifying facilities were responsible for bearing the network upgrade costs required to upgrade NorthWestern’s transmission system for each of the three QFs.

¶15 NorthWestern calculated “interconnection network upgrade costs” of $3.27 million

for the Teton facility; $2.49 million for the Pondera facility; and $267.8 million for the

Wheatland facility–an increase from its initial estimate of $128 million. Approximately

$237 million of the Wheatland estimate related to a new transmission line necessary to

deliver the energy from the Wheatland facility to NorthWestern’s load centers.5 Before

the Commission, both parties agreed CED was responsible for the costs of interconnection

and network upgrades for the Teton and Pondera facilities, but CED argued it was owed a

refund for all costs and that NorthWestern could not deduct those costs from its avoided

costs payments to CED. Regarding the Wheatland facility, the parties agreed CED

remained responsible for interconnection costs, but CED contended it was not responsible

for any network upgrade costs, which included the entirety of the $237 million transmission

line and $30 million in additional related costs. CED argued the Wheatland facility was

5 The District Court erroneously attributed the $267 million price to the transmission line itself. The record indicates the transmission line cost approximately $237.5 million, with related costs adding an additional $30.3 million.

10 not a transmission service customer and should not be responsible for subsidizing

NorthWestern’s network by paying for the $237 million transmission line that would

benefit all NorthWestern customers. CED’s direct testimony made no adjustment for

interconnection costs because CED intended to directly fund up front the cost to

interconnect for each project. CED additionally made no adjustment to avoided cost for

the cost of network transmission upgrades, because CED intended to fund those up front

and expected to receive a reimbursement, consistent with NorthWestern’s Open Access

Transmission Tariff (“OATT”).

¶16 NorthWestern argued CED must be fully responsible for “interconnection network

upgrade costs” for all three facilities because any other approach would violate PURPA

and transfer those costs to NorthWestern’s customers. NorthWestern contended its

approach conformed with FERC orders and the Commission’s rules because it required the

qualifying facilities (“QFs”) to bear responsibility for any network upgrade costs associated

with the QFs that exceeded what NorthWestern would otherwise experience from adding

similar capacity to its system. NorthWestern argued any costs associated with transmission

network upgrades should be paid by CED, not NorthWestern’s customers. Regarding the

Wheatland facility, NorthWestern argued the $237 million transmission line was only

necessary because of CED’s siting decision for the Wheatland facility and thus, CED

should be solely responsible for the transmission line and its associated costs.

¶17 The Commission found CED solely responsible for the full network upgrade costs

for each project. The Commission’s orders did not provide for a refund for CED’s funds 11 toward the upgrades for any of the three facilities. The Commission’s Reconsideration

Orders found that CED failed to show the Commission’s decision was unlawful, unjust, or

unreasonable and largely upheld the Commission’s decision.6

¶18 On appeal, CED first contends the Commission exceeded its jurisdiction when it

found network upgrade costs were necessary for interconnected operations with

NorthWestern’s system and assigned costs to CED.7 Because the transmission line will be

used by other customers and affect interstate commerce, CED argues only FERC, and not

the Commission, has jurisdiction to determine cost responsibility. NorthWestern and the

Commission respond that the Commission has retained jurisdiction over this area since

1983 and the cost constitutes an interconnection cost CED is required to pay.

¶19 CED failed to raise its jurisdictional argument before either the Commission or the

District Court. We have long declined to consider a change in legal theory or new

arguments first raised on appeal, due to the fundamental unfairness of faulting the district

court for failing to rule correctly on an issue it was never given the opportunity to consider.

6 The Commission’s Teton-Pondera Reconsideration Order reversed the Commission’s decision to subtract $75,000 in network upgrade costs from the Teton and Pondera facilities, leading to the Commission finding CED responsible for the full amount of network upgrade costs for each project, with no deduction to avoided cost or refund. 7 On appeal, CED does not clearly challenge the Commission’s decision to forego refunds related to the Teton and Pondera projects, instead focusing much of its argument on the costs assigned to the Wheatland project. The record is further unclear as to the viability of refunds for these costs. We have recognized it is not our obligation to conduct research, guess at precise positions, or develop legal analysis to support parties’ positions. Stevens v. Novartis Pharms. Corp., 2010 MT 282, ¶ 85, 358 Mont. 474, 247 P.3d 244 (citations omitted). However, as we are remanding under this issue, the parties may address the issue anew on remand.

12 Schlemmer v. North Cent. Life Ins. Co., 2001 MT 256, ¶ 22, 307 Mont. 203, 37 P.3d 63.

However, notwithstanding CED’s failure to raise its jurisdictional argument below, we

conclude the Commission had authority to consider network upgrade costs associated with

CED’s interconnection to NorthWestern’s system.

¶20 Under the Federal Power Act (FPA), Congress provided FERC with jurisdiction

over “transmission of electric energy in interstate commerce” and “the sale of electric

energy at wholesale in interstate commerce.” 16 U.S.C. § 824(b). FERC has divided the

energy market into wholesale and retail sales, with retail sales including both bundled and

unbundled services. Bundled services means “that consumers paid a single charge that

included both the cost of the electric energy and the cost of its delivery.” New York v.

FERC, 535 U.S. 1, 5, 122 S. Ct. 1012, 1017 (2002). In 1935, when FPA became law, most

electricity was sold by vertically integrated utilities that had constructed their own power

plants, transmission lines, and local delivery systems. Most operated as separate local

monopolies subject to state or local regulation. Since the enactment of the FPA,

technological advancements have made it possible to generate energy across state lines in

regional, multi-state power grids thereby implicating interstate commerce concerns and

invoking FERC’s jurisdiction. The states possessed broad authority to regulate these

utilities, but their power was limited by the Commerce Clause. See generally New York

v. FERC, 535 U.S. at 5, 122 S. Ct. at 1017. In keeping with this history of state regulatory

involvement, FERC has exercised authority over unbundled retail services, but has

declined to exercise authority over bundled retail services, leaving their regulation to the 13 states. In re Promoting Wholesale Competition Through Open Access, Order No. 888, 61

Fed. Reg. 21,540, 24,577-21,578 (1996); reh’g denied Order No. 888-A, 62 Fed. Reg.

12,274, 12,303 (1997). NorthWestern provides bundled retail services to its customers.

See In re NorthWestern 2018 Rate Case, Order 7604u, ¶¶ 135-37 (Dec. 20, 2019). FERC

Order No. 2003 noted FERC “[does] not address interconnection issues related to [QFs]

under [PURPA].” Order No. 2003 expressly delegated authority over interconnection costs

related to QFs to the states, concluding “[w]hen an electric utility is obligated to

interconnect under Section 292.303 of [FERC’s] regulations, that is, when it purchases the

QF’s total output, the relevant state authority exercises authority over the interconnection

and the allocation of interconnection costs.” FERC Order No. 2003, ¶ 813. Finally, CED’s

initial petition to the Commission acknowledged both CED’s request “that NorthWestern

purchase the output from the QF under PURPA” and the Commission’s jurisdiction under

PURPA to set the terms of its PPA with NorthWestern. CED’s Form 556, filed with FERC,

additionally identified NorthWestern as the only electric utility “that are contemplated to

transact with the facility” and represented that NorthWestern would not transmit CED’s

power to third parties. We conclude the Commission had jurisdiction to consider network

upgrade costs and turn to the substance of the issue presented.

¶21 Costs of interconnection are to be assessed to the QF. 18 C.F.R. § 292.306 provides:

“[e]ach qualifying facility shall be obligated to pay any interconnection costs which the

State regulatory authority . . . may assess against the qualifying facility on a

nondiscriminatory basis with respect to other customers with similar load characteristics.” 14 CED does not contest its responsibility for interconnection costs. CED does contend that

the Commission discriminated against CED because it ordered CED to pay for network

upgrade costs—as compared to interconnection costs—without the benefit of a refund,

whereas non-QF generators are entitled to refunds for payment of network upgrade costs.

¶22 In contrast to interconnection costs, costs of network upgrades are assessed to the

electric utility. “Network upgrades provide a system-wide benefit, expenses associated

with owning, maintaining, repairing, and replacing them shall be recovered from all

[t]ransmission [c]ustomers [electric utility] rather than being directly assigned to the

[i]nterconnection [c]ustomer [QF].” Standardization of Generator Interconnection

Agreement and Procedures, Order No. 2003-A, 106 FERC ¶ 61,220 at ¶ 424. Furthermore,

“longstanding Commission policy establishes that the costs of network upgrades may not

be directly assigned to the interconnection customer because network upgrades are not

‘sole use’ facilities and they provide a benefit to all transmission system users.” Public

Serv. Co. of Colo., 167 FERC ¶ 61,141, 61,747 (2019). Pursuant to its responsibility to

allocate interconnection costs, the Commission’s rules mirror FERC’s treatment of

interconnection costs and responsibility. See Admin. R. M. 38.5.1901(2)(d) (defining

interconnection costs); Admin. R. M. 38.5.1904(3) (assigning interconnection costs to

QFs).

¶23 Here, the Commission ordered CED to pay “interconnection network upgrade

costs.” Unfortunately, the Commission’s reasoning and subsequent assessment of

“interconnection network upgrade costs” to CED combined, rather than differentiated, 15 interconnection costs and costs associated with upgrades to NorthWestern’s transmission

network. It is important to distinguish interconnection costs from network upgrade costs,

rather than jumbling their meanings, because they express two distinct concepts.

Importantly, distinguishing them is necessary for purposes of fairly and reasonably

assessing costs in the complex arena of interconnecting a QF to a network. It is thus

important to examine the statutory definition of “interconnection costs.”8

¶24 Interconnection costs are defined in PURPA. Interconnection costs are:

the reasonable costs of connection, switching, metering, transmission, distribution, safety provisions, and administrative costs incurred by the electric utility directly related to the installation and maintenance of the physical facilities necessary to interconnect with a qualifying facility, to the extent such costs are in excess of the corresponding costs which the utility would have incurred if it had not engaged in interconnected operations, but instead generated or purchased an equivalent amount of electric energy or capacity from other sources.

18 C.F.R. § 292.101(b)(7). CED never contested that it must pay the basic costs needed to

establish interconnected operations, even if some of that includes costs associated with

transmission. CED does argue the Commission’s order far exceeded what can reasonably

be considered an “interconnection cost” because the Commission ordered it to pay the

entire cost of upgrading NorthWestern’s transmission system. We agree. The

8 While “network upgrades” are not defined in PURPA, NorthWestern’s policies define “network upgrades” as those “required at or beyond the point” at which the interconnection facilities connect to the transmission provider’s transmission system. NorthWestern Corporation, Standard Large Generator Interconnection Procedures 12 (Jan. 15, 2021), https://perma.cc/52HS-J2T9. NorthWestern’s policies do not apply directly to all QFs, which are often not transmission customers. Nonetheless, they are illustrative of NorthWestern’s practice of distinguishing the two concepts.

16 Commission’s and NorthWestern’s singular focus on “transmission,” noting it is an explicit

element of “interconnection costs,” ignores important language in the statutory definition.

While the definition of interconnection costs necessarily must be flexible to allow

regulators to assess costs based on the diverse circumstances each interconnection presents,

the costs for a QF to interconnect must nonetheless remain “reasonable” and “directly

related” to the installation and maintenance of the physical facilities “necessary” to permit

interconnected operations. These requirements dovetail with PURPA’s mandate that

utilities purchase electricity generated by QFs at rates that are “just and reasonable” to the

consumer, “in the public interest,” and nondiscriminatory to the QF. Vote Solar, ¶ 41

(citing 16 U.S.C. § 824a-3(b)). When assessing costs, these competing obligations require

the Commission to fairly balance the interests of its ratepayers with that of the QF such

that it complies with PURPA and encourages QF development while making the ratepayer

indifferent as to the energy source. Vote Solar, ¶ 41.

¶25 NorthWestern argues its customers should not be responsible for CED’s costly

siting decision of the Wheatland facility. However, if a QF seeking interconnection for

transmission purposes locates its plant far from the utility’s lines with the expectation that

the interconnection costs would be spread among the utility’s customers, the utility could

simply refuse to transmit power. Although the utility would still have an obligation to

purchase the QF’s output, the QF, rather than the utility’s customers, would pay for the

interconnection. A QF could not afford to take this risk and would therefore do all it could

17 to keep costs of interconnection to a minimum. See Western Mass. Electric Co., 66 FERC

¶ 61,167, 61,336 (1994).

¶26 The Commission has previously found the term “interconnection costs” in both

FERC and the Commission’s rules “encompasses the costs associated with both

interconnection facilities and network upgrades.” In re the Petition of Kenfield Wind

Park I, LLC and KWP-LC7, LLC to Set Terms and Conditions for Qualifying Small Power

Production Facility, Order No. 7068b, ¶ 80, Dkt. D2010.2.18 (June 23, 2010). The

Commission has also found interconnection costs apply equally to both parties. If a QF

allows a utility to avoid or defer interconnection network upgrade costs, the QF receives

an increased avoided cost payment. Conversely, if the QF causes NorthWestern to incur a

cost it would not otherwise incur, the QF is responsible for such costs. Kenfield Wind,

Order No. 7068b, ¶ 83. Here, however, the Commission’s assessment of the entire cost of

transmission upgrades to CED as “interconnection network upgrade costs” obscured the

distinction between network costs and interconnection costs and resulted in a

discriminatory assessment of costs to the QF. It failed to consider the proportionate amount

of power Wheatland would generate in relation to costs, as well as other generation projects

utilizing, or potentially utilizing, the transmission line.

¶27 The Wheatland facility would be located near an existing 230kV transmission line

running from Great Falls to Broadview. The Large Generator System Impact Study

identified this line would be overloaded by Wheatland’s interconnection. However,

numerous existing generation projects currently connect to that line. These projects 18 together can supply over 200 MW of power. The Wheatland facility is one of six future

interconnectors with plans to interconnect to the existing line. Three projects are in the

queue ahead of Wheatland, sending their output to the current line. Wheatland and at least

two subsequent projects may depend on transmitting their output via the capacity created

on the new line.

¶28 This understanding requires an assessment of the proportional scale of Wheatland’s

generation. NorthWestern asserts the Wheatland facility’s 75-MW output may be the

additional output that overloads the entire existing line. However, up until Wheatland

interconnects, the current line will have accommodated some 500 MW of power—the

present 200 MW from existing projects along with approximately 300 MW from the three

projects ahead of Wheatland in the interconnection queue.9 The assignment of $267

million in costs to CED, then, comes down almost solely to its place in the interconnection

queue. In order to interconnect Wheatland, NorthWestern wants to construct a second

transmission line of equal length and capacity, essentially doubling its transmission service

and providing additional reliability to its network at CED’s expense. In other words, the

new line does far more than simply deliver Wheatland’s power to a NorthWestern

substation—it would be a significant addition to a long-distance transmission corridor with

9 Calculating the MW capacity of a transmission line of a certain voltage is complicated and depends on various factors. However, according to NorthWestern’s testimony, it remains clear that the current 230kV line in this corridor will accept about 500 MW of power from various generators prior to Wheatland overloading it.

19 a capacity disproportionate to Wheatland’s output. This results in discriminatory treatment

toward the Wheatland facility and, accordingly, fails to comply with PURPA.

¶29 NorthWestern’s limited capacity requires it to purchase power generated beyond its

own facilities. The Wheatland facility constitutes one 75-MW project among six scheduled

interconnections totaling over 500 additional MW in the same corridor. Thus, Wheatland’s

excess costs, as considered in the definition of “interconnection costs,” are entirely

disproportionate to its added capacity to NorthWestern’s system. However, given

NorthWestern’s need, and the concurrent need for increased transmission capacity and

reliability, the Wheatland facility should bear some of the cost burden—but not all $267

million, as the Commission erroneously ordered.

¶30 We conclude the Commission erred in assigning $267 million in network upgrade

costs to CED. The Commission’s precedent obscures “interconnection costs” and

“network upgrades” into “interconnection network upgrade costs,” which do not exist.

Interconnection costs are defined by both federal and Montana regulations.

NorthWestern’s policies define network upgrades as distinct from facilities required for

interconnection and the associated costs. NorthWestern and the Commission’s attempts to

mire these distinct concepts in technicalities cannot result in discriminatory costs for QFs,

as they did here. PURPA’s mandate of just and reasonable rates that are nondiscriminatory

requires assessing the costs incurred in the interconnection process in proportion to the

QF’s added load to NorthWestern’s system. This ensures QFs bear the reasonable costs

directly related to interconnecting to NorthWestern’s system, while simultaneously 20 preventing discriminatory costs disproportionate to the project’s impact and ensuring

ratepayer indifference.

¶31 The record indicates CED was aware of an early estimate of the costs associated

with interconnecting through the Network Resource Interconnection Service. Thus, while

CED may be held responsible for costs related to the proportional impact of its projects

upon NorthWestern’s system, the District Court erred in concluding the Commission’s

decision to allocate $267 million in network upgrade costs to CED was lawful. CED is

responsible for all costs reasonably incurred by NorthWestern because of interconnection,

which may include operation and maintenance costs, the costs of installing equipment

elsewhere in the utility’s system necessitated by interconnection, and other reasonable

costs. However, in assessing CED’s interconnection costs, the Commission must consider

the amount of MW which will be generated by Wheatland in relation to those costs, the

nondiscriminatory purpose of PURPA, the interconnection of other facilities, and who is

the primary beneficiary of the network upgrades. CED does not dispute its responsibility

for some costs, only that it is unreasonable for it to pay the entire $267 million. We agree,

and remand for reconsideration incorporating the proportionality analysis set forth above.

¶32 2. Whether the District Court properly upheld the Commission’s decision to calculate avoided energy costs using a proxy model.

¶33 CED calculated its avoided costs based on the Commission’s most recently

approved methodology. This methodology utilized the PowerSimm model, which

incorporates a variety of factors, including market forecast and generation schedules. CED

21 incorporated a monthly aggregation of the hourly modeling results typically produced by

PowerSimm to develop its estimate. CED presented testimony indicating it chose this

method not for its accuracy, but because CED thought it was the Commission-approved

methodology. Using this approach and assuming a 25-year contract, CED calculated

avoided costs for the Teton facility at $54.88/MWh during heavy load hours (HLH),

$36.99/MWh during light load hours (LLH), and $46.65/MWh around-the-clock (ATC).

For the Pondera facility, the approach yielded avoided costs of $54.35/MWh during HLH,

$36.93/MWh during LLH, and $46.68/MWh ATC. CED’s calculations for the Wheatland

facility yielded $52.51/MWh during HLH, $36.51/MWh during LLH, and $45.11/MWh

during ATC.

¶34 NorthWestern also relied upon the PowerSimm model to calculate its avoided costs.

However, NorthWestern developed its calculations directly from the hourly model results,

rather than from monthly aggregated data. NorthWestern’s calculations, assuming a

15-year contract and a declining heat rate, produced avoided costs of $15.90/MWh ATC

for the Teton facility, $15.47/MWh for the Pondera facility, and $15.86/MWh for the

Wheatland facility. NorthWestern additionally modeled avoided costs without an assumed

declining heat rate, resulting in avoided costs of $18.63/MWh for the Teton facility,

$17.74/MWh for the Pondera facility, and $19.43/MWh for the Wheatland facility.10 The

10 NorthWestern later filed corrected avoided costs after discovering an error in the script it used to derive the estimates.

22 MCC supported the use of NorthWestern’s hourly PowerSimm results over the use of

CED’s monthly aggregated data, arguing the hourly model better reflected the realities of

generator scheduling, dispatch and energy trading. Notwithstanding its support, the MCC

cited the Commission’s previous rejection of the hourly model and noted that the MCC

agreed with the Commission’s concerns regarding the hourly model’s lack of tractability

and transparency.

¶35 In rebuttal, CED criticized several aspects of NorthWestern’s approach, including

its marginal cost to serve load approach, its use of market price forecasts, and use of a

declining heat rate without adequate justification. CED’s rebuttal additionally presented

an alternative method of calculating avoided costs based on the fixed and operating costs

of the avoidable, or proxy, resource identified in NorthWestern’s 2019 Resource

Procurement Plan (“2019 Plan”). Notwithstanding its position on appeal, CED expressly

argued, in its initial post-hearing brief to the Commission, “If the Commission rejects

PowerSimm, it can set avoided energy cost using the Proxy Method.”11 CED noted the

Commission had recently used this proxy method as well, suggesting precedent supported

the approach. CED assumed a 25-year contract length and calculated avoided costs based

on the proxy methodology of approximately $35-36/MWh for the Teton and Pondera

11 CED contended its proxy methodology estimate was merely intended as a benchmark to demonstrate the reasonableness of its PowerSimm calculations and that it did not advocate for the proxy methodology to be applied to its projects. Its argument in the post-hearing brief does not reflect this position.

23 facilities and $70.78/MWh for the Wheatland facility. CED later noted these were not

exact recommendations but served as benchmark estimates. At the hearing for the Teton-

Pondera matter, CED presented testimony indicating its reliance on PowerSimm aimed to

adhere to the Commission’s past practices, but its proxy methodology was “cleaner and

simpler,” provided similar results, and should be utilized by the Commission going

forward.

¶36 The Commission took issue with CED’s PowerSimm calculations, noting its

selection of inputs deviated from Commission-approved methodology and consequently

led to higher avoided costs for CED. The Commission additionally noted the legitimate

concerns about NorthWestern’s calculations raised by CED’s rebuttal testimony and the

lack of evidence presented to rebut those concerns. At the hearing for the Teton-Pondera

matter, the Commission received testimony from NorthWestern indicating errors in the

PowerSimm model would exist for either the hourly or monthly results. Citing the lack of

reliability from both CED and NorthWestern’s calculations, the Commission adopted the

proxy methodology introduced by CED to calculate avoided costs for all three projects.

¶37 However, because CED introduced the methodology through rebuttal testimony

without supporting calculations or explanation of how its prices were reached, the

Commission elected not to rely on the avoided costs generated by CED’s proxy

methodology. Noting the lack of evidentiary support for the parties’ avoided cost

estimates, alongside the Commission’s statutory duty under Montana’s “Mini-PURPA” to

determine contractual rates within 180 days, the Commission adopted a proxy 24 methodology based on an incremental resource identified in the 2019 Plan. The

Commission noted it “would prefer not to pursue this course” but cited the parties’ support,

to varying degrees, for the proxy methodology, and explained the inputs it relied upon in

calculating avoided costs under this methodology. The Commission indicated it did not

view this as a deviation from Commission precedent, but nonetheless felt its decision not

to utilize the PowerSimm estimates was supported by its statutory timeline. Setting aside

the reliability concerns raised and the lack of support for CED’s proxy methodology, the

Commission found what remained was “testimony from both CED and NorthWestern

indicating that the proxy methodology is a reasonable alternative for estimating

NorthWestern’s avoided energy cost . . . This justifies deviation from the Commission’s

past practice of reliance on PowerSimm in favor of the proxy method here.”

¶38 Adopting the proxy methodology, both the Teton-Pondera and Wheatland

Reconsideration Orders arrived at an avoided energy cost rate of $24.99/MWh for the

Wheatland, Teton, and Pondera facilities, based on the awarded contract length of 15 years

per facility.12

¶39 On appeal, CED argues it is entitled to have the avoided costs calculated using the

existing methodology at the time of incurring its LEO. Alternatively, CED contends the

Commission exceeded its authority by arbitrarily adopting its own methodology for

12 This avoided energy cost figure was adjusted upward from the original Orders’ avoided cost of $24.18/MWh per facility after the Commission relied on a different proxy resource.

25 calculating avoided costs. In response, the Commission and NorthWestern argue both

NorthWestern and CED’s proposed avoided costs were flawed and that CED presented

evidence supporting the Commission’s decision to adopt its own proxy methodology to

calculate the avoided costs.

¶40 PURPA provides QFs the option of having avoided costs determined either at the

time of delivery or at the time the QF incurs a LEO. 18 C.F.R. § 292.304(d)(1)(ii). The

point of this statutory section is to calculate avoided costs accurately and reliably. Nothing

in PURPA requires or mandates the calculation of avoided costs based on unreliable or

inaccurate inputs, as was the case here. The record indicates unresolved reliability

concerns with the PowerSimm model present in both CED and NorthWestern’s estimates.

Implicit in CED’s argument is a request for this Court to find its monthly PowerSimm

results reliable, while rejecting NorthWestern’s hourly results. It would have been illogical

and arbitrary for the Commission to reject NorthWestern’s hourly PowerSimm rates, based

on the unaddressed concerns CED pointed out, but adopt CED’s PowerSimm rates, which

relied on the same underlying hourly results but aggregated on a monthly basis. It would

be just as illogical for us to do the same on appeal. We decline to substitute our judgment

for the Commission’s concerning the lack of reliability in the PowerSimm results. See

Vote Solar, ¶ 36. For these reasons, PURPA cannot be read to require a QF have its avoided

26 costs determined inaccurately, relying on the extant methodology, at the time it incurred a

LEO.13

¶41 Nor does CED’s contention the Commission exceeded its statutory authority and

acted sua sponte by adopting the proxy methodology prove persuasive. CED cites MTSUN

for the proposition that the Commission “has not been specifically conferred sua sponte

authority allowing to adjudicate undisputed issues.” MTSUN, ¶ 73 (emphasis added).

However, the avoided costs here were not undisputed, and CED’s reliance on MTSUN for

this proposition necessarily fails. Rather, as noted earlier in MTSUN, “the [Commission’s]

review is limited to making determinations in controversies.” MTSUN, ¶ 73 (internal

quotations omitted, citing § 2-15-102(10), MCA). The calculation of avoided costs here

constituted precisely the type of controversy the Commission retained statutory power to

determine. Acting in a quasi-judicial function while adjudicating § 69-3-603 petitions, the

Commission’s authority includes determining the fixing of prices. Section 2-15-

102(10)(g), MCA. The Commission acted squarely within its statutory authority here to

fix the avoided costs and, accordingly, did not exceed its statutory authority.14

13 CED’s claim of a due process violation fails for the same reason. CED did not have a vested property interest in having its avoided costs inaccurately determined at the time it incurred a LEO. 14 CED’s emphasis on the mandatory nature of Admin. R. M. 38.5.1910(2) (2018), rather than the immediately preceding word, proves similarly unpersuasive. Rule 38.5.1910(2) (2018) requires “The utility must provide an initial avoided cost calculation” based on the methodologies most recently approved by the Commission for that utility, along with all assumptions and inputs used in that calculation. CED’s reading of Rule 38.5.1910(2) (2018) imposes this duty on the Commission, contrary to the plain and unambiguous language of the text. The record does not indicate, and CED does not contend, NorthWestern, to whom this Rule actually applies, failed to comply with this requirement. 27 ¶42 Faced with unreliable calculations from the parties and its statutory duty to resolve

the case within 180 days, the Commission relied on its “specific, technical, and scientific

knowledge” and adopted an alternative method deemed reasonable by CED and supported

in the record, to varying degrees, by both CED and NorthWestern. See MTSUN, ¶ 52. The

Commission’s cost assumptions were drawn from the 2019 Plan, which guides the

calculation of avoided costs and was relied upon by CED in calculating its proxy

methodology estimate. The Commission incorporated inputs supported by the testimony

and rejected inputs it found unsupported, such as NorthWestern’s use of a declining heat

rate. We decline to substitute our judgment for the Commission’s regarding the reliability

of the three avoided cost estimates provided.

¶43 The Commission’s decision to adopt the proxy methodology was lawful and

substantially supported by the record. The District Court correctly affirmed the

Commission’s decision to adopt this methodology. However, because we are remanding

under Issue I, we likewise remand for clarification under Issue II to allow both

NorthWestern and CED to provide avoided cost estimates using the proxy method.

¶44 3. Whether the District Court properly upheld the Commission’s decision to calculate ancillary service deductions based on NorthWestern’s proposed rates.

¶45 CED testified it derived estimated ancillary service deductions based on a 2017

decision by the Commission. CED noted its belief that NorthWestern could absorb all

three QFs without any need for additional load-following products and accordingly

excluded deductions for those integration services. NorthWestern provided testimony

28 from Joe Stimatz providing extensive information about NorthWestern’s OATT, how the

rates are calculated, and an estimate under the OATT. Stimatz’s testimony additionally

rebutted CED’s testimony and proposed ancillary deductions. The MCC testified that

CED’s proposed ancillary services deductions were based on a 2017 case excluding

integration costs and thus outdated. MCC further testified CED’s estimate failed to reflect

the findings of a report identifying a need for integration services contained in the 2019

Plan. CED rebutted this testimony by noting the risk of “double-dipping” because ancillary

services were already included in the PowerSimm model and stating its belief that FERC

would reject NorthWestern’s OATT because it was unreasonably high.

¶46 Based on the testimony provided, the Commission found CED’s claims unsupported

and inconsistent with the 2019 Plan. The Commission provided for the possibility that

FERC would reject the OATT and allowed for a corresponding decrease in ancillary

deductions. The Commission additionally found CED’s concern of “double-dipping” was

mooted by the Commission’s decision to rely on the proxy method to determine avoided

costs. The Commission’s Reconsideration Orders largely upheld the ancillary service

deductions, ultimately finding CED was responsible for the ancillary service charges under

the OATT for each wind project.

¶47 CED does not dispute its responsibility for ancillary service deductions, but

contends it is entitled to ancillary service deductions based on the date the LEOs were

incurred. Alternatively, CED argues the Commission again acted arbitrarily and

unlawfully by failing to sufficiently justify its decision to charge CED for ancillary services 29 according to NorthWestern’s OATT, rather than CED’s proposed rate. NorthWestern and

the Commission respond that the record substantially supports the ancillary services

deduction and the OATT applies to every other generator connected to NorthWestern’s

system equally.

¶48 Under PURPA, QFs have the option to obtain a rate for energy and capacity (the

cost of purchase) as of the time of delivery or the date it incurs a LEO. 18 C.F.R.

§ 292.304(d). However, this does not pertain to rates for sales of services by a utility to a

QF, which is addressed in 18 C.F.R. § 292.305. This section requires rates be just,

reasonable, in the public interest, and similar to those paid by other generators, but it does

not require rates for sales of services provided to the QF to be fixed for the term of the

contract. 18 C.F.R. § 292.305. CED is not entitled to have its ancillary service deductions

calculated as of the date it incurred LEOs.

¶49 Ancillary services can include services related to energy losses, energy imbalances,

and system protection. Section 69-3-2003(1), MCA (repealed 2021). NorthWestern

provides ancillary services based on an OATT. An OATT applies standard requirements

to ensure system reliability and fairness. See 18 C.F.R. § 35.28. OATT schedules must be

just and reasonable and remain subject to approval by FERC.15 16 U.S.C. § 824d(a); 18

C.F.R. § 35.28(c).

15 Throughout the proceeding, NorthWestern’s OATT rates were interim and subject to final approval by FERC. The Commission addressed this interim status by finding that, to the extent CED was correct in its assertions that FERC would reduce or reject the rates, the ancillary charges would be adjusted accordingly. FERC ultimately approved the interim rates without adjustment 30 ¶50 The Commission’s decision to determine ancillary service deductions based on

NorthWestern’s OATT was supported by substantial evidence. NorthWestern provided

the OATT and related calculations to the Commission. MCC and NorthWestern rebutted

CED’s proposed rate, which excluded a service necessary under the 2019 Plan to integrate

the QFs. The Commission noted the lack of support for CED’s position and its

inconsistency with the 2019 Plan. The Commission implicitly distinguished the 2017 case

upon which CED relied by finding CED’s proposal inconsistent with the 2019 Plan.

Notwithstanding the lack of evidentiary support, the Commission addressed CED’s

concern that FERC would reject the OATT and eliminated the identified risk of

“double-dipping” through its adoption of the proxy methodology.

¶51 The Commission adequately articulated its reasoning. Its decision was not arbitrary

and it was supported by substantial evidence in the record. The District Court correctly

affirmed the Commission’s decision regarding ancillary service deductions.

¶52 4. Whether the District Court properly upheld the Commission’s determination that 15-year contract lengths were appropriate for all three of CED’s projects.

¶53 In its initial petition to set contract terms, CED argued it was entitled to a 25-year

contract as a matter of law, arguing a Montana district court order served as binding

precedent on the Commission. CED presented testimony noting its belief that a 25-year

contract was generally necessary for economic feasibility and reiterating its view that a

on January 29, 2021, with an effective date of July 1, 2019. See Northwestern Corp., 173 F.E.R.C. ¶ 63,020; Northwestern Corp., 174 F.E.R.C. ¶ 61,074.

31 25-year contract was required as a matter of law. CED further argued a 15-year contract

was insufficient to secure financing and discriminatory because NorthWestern amortizes

its generation assets over a period of 30 years. CED’s witnesses presented additional

statements alluding to previously experienced problems with 15-year contracts.

¶54 MCC and NorthWestern presented evidence of recent 15-year PPAs in Montana to

demonstrate the economic feasibility of 15-year contracts. NorthWestern noted contract

lengths may differ according to the factual circumstances and that the circumstances of this

case merited a 15-year contract duration. The MCC, recognizing the Commission’s

competing obligations to satisfy PURPA as well as provide fair and reasonable rates for

ratepayers, noted the risk longer contracts presented to ratepayers and argued that 15-year

contracts appropriately balanced the risk to ratepayers and the opportunity to secure

financing for QFs. Based on the evidence provided, the Commission found a 15-year

contract sufficiently satisfied its competing obligations.

¶55 The Commission’s Reconsideration Orders noted the lack of evidence supporting

CED’s position and remarked that CED framed its position as arguing a 25-year contract

was necessary to obtain financing. The Commission found “In light of its position, it would

be helpful for the Commission to have evidence as to the financing terms available to the

project or direct evidence (not conclusory statements) that a 15-year term is not viable . . .

That evidence did not exist here.” The Reconsideration Orders upheld the 15-year contract

decision for all three projects.

32 ¶56 CED argues the Commission failed to sufficiently justify its decision to set CED’s

contracts for 15 years, rather than the 25-year duration CED requested. Contract terms

must enhance the economic feasibility and must allow for a return on investment, and the

Commission’s decision failed to weigh these considerations, CED contends. In reply, the

Commission and NorthWestern point to language in Vote Solar that 15-year contracts are

not per se unreasonable, notes that CED failed to provide specific testimony that would

render the 15-year decision unreasonable and argues CED’s net worth minimizes concerns

of economic feasibility for the projects.

¶57 PURPA and Montana law encourage long-term contracts between utilities and QFs

in order to enhance the economic feasibility of the QF. 16 U.S.C. § 824a-3(a); § 69-3-

604(2), MCA. FERC provides that long-term contracts balance out any overestimations or

underestimations of avoided costs so that neither the utility nor the QF is negatively

impacted by market fluctuations. This in turn creates certainty regarding a return on

investment for QF investors. FERC Order No. 69 at 12,224. While long-term contracts

are encouraged, neither PURPA, FERC, nor Montana law provides a definition of

“longterm.” Balancing these concerns and adopting an appropriate contract duration thus

falls to the Commission and, upon petition for judicial review, the courts.

¶58 The record contains sufficient evidence supporting the Commission’s decision to

adopt 15-year contract lengths. NorthWestern and MCC pointed to recent Commission

decisions awarding 15-year contracts to wind generators in Montana to demonstrate the

economic feasibility of 15-year contracts. NorthWestern noted contract lengths may differ 33 according to the factual circumstances of the case. The MCC argued a 15-year contract

struck the appropriate balance between enhancing economic feasibility for QFs and

protecting Montana’s ratepayers from unnecessary risk presented by longer contracts.

These considerations informed the Commission’s decision, which complied with our

holding in Vote Solar, wherein we noted “the requirement that service commissions

consider both the length of contracts alongside contract prices, recognizing the synergistic

effect of these dual considerations.” Vote Solar, ¶ 72. The Commission considered the

evidence presented and the effect a 15-year contract could have on the corresponding

avoided cost rate, ultimately finding the rate would not be discriminatory.

¶59 Conversely, the record lacks substantial evidence to support CED’s requested

25-year contract duration. In its petition to set contract terms, CED argued it was entitled

to a 25-year contract as a matter of law, citing the Eighth Judicial District Court’s ruling

reversing a 15-year contract in Vote Solar, which we affirmed on appeal. Vote Solar, ¶ 73.

However, our holding in Vote Solar does not support CED’s position. In Vote Solar, we

reversed the Commission’s decision to adopt a 15-year contract because it “was based

almost entirely on a 2014 North Carolina Utilities Commission decision.” Vote Solar, ¶ 69.

We cited the Commission’s lack of knowledge regarding QF development policies in North

Carolina and noted the lack of evidence explaining why 15-year contracts balanced the

need for certainty regarding a return on investment. Vote Solar, ¶ 70. That is not the case

here. The Commission’s decision relied on recent Montana contract decisions, not out of

state considerations, and the record indicates NorthWestern and MCC provided testimony 34 explaining how the 15-year contract balanced the competing interests of QFs and

ratepayers and allowed for economic feasibility.

¶60 While we concluded in Vote Solar, given the lack of record support, the Commission

acted arbitrarily, we noted “15-year contracts, standing alone, are not per se unreasonable.”

Vote Solar, ¶ 73. It is this language CED relies on in urging us to reverse the Commission’s

decision. Doing so would effectively require 20- to 25-year contracts for every QF,

regardless of circumstances. While district court decisions do set precedent, CED’s

position would effectively strip the Commission of the ability to evaluate each request to

set contractual terms on the basis of its individual facts, such as economic conditions,

financing environment, and energy market forecasts, while insulating QFs and exposing

ratepayers to greater risk. We decline to take such a position. If a QF believes the

Commission erred, that decision can be reviewed by the courts following the filing of a

petition by the QF. See Krakauer v. State, 2016 MT 230, ¶ 41, 384 Mont. 527, 381 P.3d

524 (disagreeing with the premise that a district court order in one scenario binds the

Commissioner of Higher Education in subsequent cases).

¶61 Neither CED’s testimony that 25-year contracts generally prove necessary for QF

feasibility nor its vague assertions concerning “problems” with 15-year contracts convince

us the Commission erred. This testimony, and the general assertions of discrimination,

fails to identify specific issues with the 15-year contract length. The Commission found

these general, conclusory statements unconvincing and insufficient to support a 25-year

contract. The Commission noted its belief that the Eighth Judicial District Court decision 35 in Vote Solar was not binding and that contract lengths may vary depending upon

circumstances. The Commission pointed to several recent 15-year contracts, as well as a

decision in which the Commission established a 20-year contract due to the unproven

hybrid nature of the generator in that case, to demonstrate the factual basis upon which it

establishes contracts.

¶62 Our review is confined to the record before us. The record provides no support for

CED’s conclusory statements that a 15-year contract duration was not viable for its

projects. The record supports the Commission’s decision to adopt a 15-year contract. The

District Court correctly upheld the Commission’s decision on contract length.

CONCLUSION

¶63 The District Court erred in affirming the Commission’s orders as related to the

interconnection costs associated with the transmission line under Issue I. On remand, the

Commission’s assignment of interconnection costs requires analysis concerning the

proportional impact of QF projects on NorthWestern’s system.

¶64 The District Court did not err in affirming the Commission’s orders as related to

Issues II through IV. Substantial evidence supported each of the Commission’s decisions

under Issues II through IV, and we are not convinced these decisions were clearly

erroneous, arbitrary, capricious, or characterized an abuse of discretion. Section 2-4-

704(2)(a), MCA. However, as we are remanding under Issue I, we likewise remand under

Issue II to allow both parties to present avoided costs estimates using the proxy

36 methodology adopted by the Commission. The District Court’s Order is affirmed in part,

reversed in part, and remanded for proceedings consistent with this Opinion.

/S/ LAURIE McKINNON

We concur:

/S/ MIKE McGRATH /S/ JAMES JEREMIAH SHEA /S/ BETH BAKER /S/ INGRID GUSTAFSON /S/ DIRK M. SANDEFUR /S/ JIM RICE