CED Wheatland v. MPSC ( 2022 )

05/10/2022
DA 21-0250
Case Number: DA 21-0250
IN THE SUPREME COURT OF THE STATE OF MONTANA
2022 MT 87CED 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,
v.
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:
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__________________________________________
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
37