09/27/2016
DA 15-0612
Case Number: DA 15-0612
IN THE SUPREME COURT OF THE STATE OF MONTANA
2016 MT 239
NORTHWESTERN CORPORATION,
doing business as NORTHWESTERN ENERGY,
Petitioner and Appellant,
v.
THE MONTANA DEPARTMENT OF PUBLIC
SERVICE REGULATION, MONTANA PUBLIC
SERVICE COMMISSION,
Respondent and Appellee,
NATURAL RESOURCES DEFENSE COUNCIL,
HUMAN RESOURCE COUNCIL, DISTRICT XI,
and MONTANA CONSUMER COUNSEL,
Intervenors.
APPEAL FROM: District Court of the Second Judicial District,
In and For the County of Butte/Silver Bow, Cause No. DV-13-399
Honorable Brad Newman, Presiding Judge
COUNSEL OF RECORD:
For Appellant:
Al Brogan, NorthWestern Corporation d/b/a/ NorthWestern Energy,
Helena, Montana
For Appellee:
Jason Brown, Jeremiah Langston, Justin Kraske, Montana Public Service
Commission, Helena, Montana
For Intervenors:
Robert A. Nelson, Montana Consumer Counsel, Helena, Montana
Charles Magraw, Human Resource Council, District XI, Natural
Resources Defense Council, Helena Montana
Submitted on Briefs: August 10, 2016
Decided: September 27, 2016
Filed:
__________________________________________
Clerk
2
Justice Jim Rice delivered the Opinion of the Court.
¶1 Appellants NorthWestern Corporation, doing business as NorthWestern Energy
(NorthWestern), the Natural Resources Defense Council (NRDC), and Human Resources
Council, District XI (HRC), appeal the decision of the Second Judicial District Court
affirming the Final Order of the Montana Public Service Commission (Commission),
which disallowed $1,419,427 in claimed excess electric regulation costs and adjusted
energy efficiency savings calculations. We affirm, considering the following issues:
1. Did the Commission apply the correct legal standard in reviewing
NorthWestern’s claim for excess outage costs?
2. Were the “free ridership” and “spillover” calculations adopted by the
Commission supported by substantial evidence?
FACTUAL AND PROCEDURAL BACKGROUND
¶2 This matter involves a challenge to the Commission’s Final Order in
NorthWestern’s 2011–2012 annual tracker filing.1 Therein, NorthWestern requested,
inter alia, a $1,419,427 increase in rates for unexpected electricity supply costs due to an
outage at its Dave Gates Generating Station (DGGS), located near Anaconda.2 As part of
the proceeding, the Commission also ordered NorthWestern to present evidence for
purposes of conducting a “true-up” to actual costs for lost revenues that had been
previously estimated in NorthWestern’s demand-side management (DSM) programs.
Ultimately, the Commission (1) denied NorthWestern’s request to include the DGGS
1
In re NorthWestern Energy’s 2011–2012 Electricity Supply Tracker, Mont. Pub. Serv.
Comm’n, Dkt. D2012.5.49, Order No. 7219h (Oct. 28, 2013).
2
The DGGS was formerly called the Mill Creek Generating Station.
3
outage costs in customer rates, and (2) rejected NorthWestern’s expert’s conclusion that
the “free ridership” and “spillover” values of its DSM programs were perfectly offsetting,
adopting instead the same expert’s actual calculations used in a draft report.
DGGS Outage Costs
¶3 In 2008, NorthWestern sought Commission approval to build the DGGS. The
DGGS was intended to provide regulation and frequency response service in
NorthWestern’s service area. The Commission approved the project in 2009, and the
DGGS commenced commercial operation on January 1, 2011.
¶4 The DGGS was a first-of-its-kind facility that NorthWestern presented as having
“the potential to be a model facility for the supply of regulation service.” It consisted of
three generation units made by Pratt & Whitney Power Systems, Inc. (PWPS) and was an
application of a simple cycle natural gas turbine generator designed to increase or
decrease generation (ramp) in response to variations in NorthWestern’s load, “on a
moment-by-moment basis.” NorthWestern’s General Manager of Generation testified
that the plant had a “very unique” control mechanism and “early on we knew that the
plant was going to have a very unique control application.”
¶5 NorthWestern was aware that the ramp capabilities of the DGGS were critical to
its operation and that the DGGS was a first-of-its-kind application, stating:
[The DGGS] is one of the first power plant installations to be built
specifically for electrical transmission grid regulation duty. The design
requirements for grid regulation are stringent since they require the plant to
continually change load in a short time frame (seconds to minutes).
4
This load requirement was necessary because NorthWestern “anticipated variable
operating conditions,” largely due to wind generation variations, and the DGGS needed
to be able to ramp up or down by at least 15 mega-watts (MW) per minute per unit to
“offset the continuous variation between system generation and system load.”
¶6 The contract between NorthWestern and PWPS included a waiver of
consequential damages, but NorthWestern purchased, with customer revenue, an
extended warranty to cover the innovative technology. NorthWestern did not purchase or
evaluate the feasibility of outage insurance in case the DGGS had an operational failure.
¶7 On January 31, 2012, thirteen months after NorthWestern brought the DGGS
online, it suffered a complete outage. Unit cycling had caused “thermal stresses” by
going from a cold state to a very high temperature, damaging the rotating equipment.
PWPS concluded the outage resulted from ramp rates “much greater” than anticipated,
excessive temperatures, and cycle-related hardware failures. The Commission was
unable to precisely examine the ramp data because NorthWestern failed to maintain
minute-by-minute records.
¶8 Pursuant to the extended warranty, PWPS repaired the damaged turbines at its
cost, including removal, installation, and shipping costs. However, due to the waiver of
consequential damages in the contract, PWPS was not obligated to cover the costs
associated with purchasing replacement regulation service during the outage. On
February 3, 2012, NorthWestern began purchasing replacement service from Powerex
Corp. (Powerex) and Avista Corp. (Avista). PWPS took “extraordinary measures” to
5
repair the DGGS as soon as possible. Individual generators were put back online as
PWPS restored them and NorthWestern proportionally decreased its regulation service
purchases accordingly. The DGGS was fully back online on May 1, 2012.
¶9 During the outage, NorthWestern customers continued to pay the fixed costs for
the operation of the DGGS ($6,742,625), including NorthWestern’s usual rate of return,
as well as the variable costs ($1,527,714) NorthWestern did not actually incur, but would
have incurred had the plant been operational. However, the outage caused NorthWestern
to incur an additional $1,419,427 in charges to Powerex and Avista for regulation service.
NorthWestern requested reimbursement of these costs, arguing they were reasonably
incurred because it obtained an extended warranty that covered all repairs, it purchased
regulation service on the competitive market at 2011 rates, it structured its regulation
market purchases to enable it to incrementally reduce the purchases as generators were
repaired, and it had worked quickly to get the DGGS back online.
¶10 The Montana Consumer Counsel (MCC) opposed reimbursement of the
replacement service costs, contending that NorthWestern failed to undertake risk
mitigation by failing to investigate whether outage insurance was available. The MCC
offered the testimony of Dr. John Wilson:
No. I don’t fault the company for not procuring it [outage insurance]. What
I think was imprudent was not looking into it, not evaluating it, not finding
out whether it was available and what the cost would be for a plan like this.
I think you have to do that before you make a determination as to whether
you acquire it or not.
6
The MCC argued that evaluation of insurance was fundamental to risk management
where the contract contained an exclusion for consequential damages:
[T]he most imprudent thing that occurred here, is the failure of the
company to take steps to protect itself against the outage, given the fact that
they had this exclusion under the warranty, given the fact that they knew
. . . that there were unknowns about this plant and where it was going to go
and how it was going to operate.
¶11 NorthWestern responded by providing evidence that in its experience it had never
purchased replacement power insurance and, instead, always relied on the market for
replacement power. NorthWestern’s General Manager of Generation testified that after
receiving inquiry from the Commission and the MCC regarding insurance, he “went and
solicited input from other utilities . . . [a]nd they indicated that they simply do not get
outage insurance because it is not economical to do so.” NorthWestern put on evidence
that outage insurance could be $1 million per year, thus potentially costing more than the
replacement power itself, but acknowledged it did not “investigate or purchase insurance
that might have covered the additional electricity supply costs.”
¶12 The Commission inquired into NorthWestern’s operation of the DGGS through
data requests and found that NorthWestern was aware the units needed to change load
quickly, that quick response was critical, and that the units could experience unique
thermal stresses due to ramping up and down. The outage was directly tied to “ramp
rates ‘much greater’ than anticipated, excessive temperatures and cycle-related hardware
failures,” yet NorthWestern used software allowing excessive ramping and did not retain
precise ramp rate data.
7
¶13 The Commission determined that NorthWestern’s management of the DGGS was
not reasonable and that the excess regulation costs were not prudently incurred because
NorthWestern (1) failed to prudently manage risks; and (2) did not “exhibit the level of
situational awareness that the Commission would expect from a utility managing a
one-of-its-kind power plant.” The Commission reasoned:
Given the warranty’s exclusion of consequential damages and the
uniqueness of DGGS, NorthWestern should have identified the risk of
incurring replacement costs in the event of an outage. . . . [NorthWestern’s]
failure to identify risk ensured that incremental costs of replacement service
would be incurred in the event of an outage.
The Commission found that outage insurance was available and, even though it may not
have been cost-effective, because NorthWestern failed to “evaluate the availability, price
and terms of outage insurance,” it “guaranteed that any incremental replacement costs
would be unavoidable in the event of an outage.” Citing both NorthWestern’s failure to
manage risk and reasonably operate the DGGS, the Commission denied NorthWestern’s
request to include the outage costs in customer rates.
DSM Program
¶14 Fixed costs are those the utility will incur regardless of how much energy it
actually sells to consumers. Utilities typically recover fixed costs through volume based
charges built into customer rates. Consequently, there is no financial incentive for a
utility to encourage energy efficiency because decreases in consumption would hamper
the utility’s recovery of its fixed costs. A lost revenue adjustment mechanism (LRAM) is
designed to compensate a utility for the revenue lost due to the utility’s energy efficiency
8
efforts. In essence, it allows the utility to estimate and recover the revenue it lost due to
energy efficiency efforts directly attributable to the utility, such as by DSM programs.
¶15 In 2005, the Commission approved the use of a LRAM to account for revenue
losses incurred as a result of NorthWestern’s energy efficiency efforts, finding that “the
lost revenue disincentive is real and puts at risk a full and complete ramp-up of
cost-effective energy efficiency resource acquisition programs in the near-term.” It
authorized NorthWestern to include in rates an estimate of the income lost due to DSM
programs with a requirement that, after the programs had been implemented, the
“estimated lost . . . revenue amount must be trued-up based on actual program activity in
[the given years] and again following a comprehensive program evaluation and
independent verification of actual savings.” This “true-up” ensures that NorthWestern is
only including in rates the revenue lost from its DSM programs, and not from
independent causes.
¶16 Analysis of a DSM program includes examination of “free ridership” and
“spillover.” Free ridership occurs when a consumer takes advantage of a program
incentive to install an energy efficient device, but would have installed the device with or
without the incentive. As such, the utility did not effectuate the customer’s usage
reduction and is not entitled to recover the associated lost revenue. On the other side of
the ledger, spillover occurs when a consumer does not respond to a DSM program
incentive, but later chooses energy efficient products or practices as a result of the
9
utility’s general advocacy. As such, the utility is credited with the energy reduction it
only indirectly induced, and can include those lost revenues in its LRAM.
¶17 NorthWestern selected Nexant Energy Management Group (Nexant) to evaluate
its DSM programs for its first true-up process in 2006–2007. Nexant measured free
ridership and spillover and included them in its final assessment. The Commission
adopted the Nexant assessment, concluding that it “satisfies the DSM program evaluation
and savings verification requirements” the Commission had established.
¶18 The next true-up of NorthWestern’s DSM programs was presented in the subject
proceeding. NorthWestern hired SBW Consulting (SBW), who partnered with Research
into Action (RIA), to conduct the required independent, comprehensive true-up for the
periods 2006-2007 to 2010-2011. In its draft report to NorthWestern, SBW included the
values for free ridership and spillover it had calculated. The draft report concluded that
NorthWestern was responsible for 79% of the energy efficiency savings it had estimated
and included in customer rates through the LRAM.
¶19 However, in its final report, SBW came to the conclusion that the values
calculated for free ridership and spillover should not be used in the assessment of
NorthWestern’s DSM programs. The final report assumed that the two values, since they
work in contradiction to each other, offset each other equally. In statistical terms, this
offset was considered a 1.0 net-to-gross (NTG), meaning the net is no different than the
gross savings. By completely offsetting spillover and free ridership values, SBW’s final
report concluded that NorthWestern was responsible for 87% of the energy efficiency
10
savings it had previously estimated in the LRAM.3 NorthWestern agreed that this
difference in over-collected revenues ought to be refunded to NorthWestern ratepayers.
¶20 During her testimony before the Commission, Dr. Marjorie McRae (Dr. McRae),
the RIA researcher responsible for free ridership and spillover calculations, explained that
when she met with NorthWestern to discuss the draft report, she had informed
NorthWestern that she believed “we are not able, as a profession, to measure these
accurately, and that the effects are offsetting.” Dr. McRae testified that NorthWestern
had advised her to revise the draft “according to [her] professional opinion.” Thus, the
final report utilized a 1.0 NTG value for comparison between the two values instead of
using the actual values derived from the research. Dr. McRae affirmed that she had
conducted the free ridership and spillover research using “national common practices,
and best practices,” and the actual data was “comparable to those found for similar
programs conducted by other respected program evaluators.” However, the SBW final
report stated that there were problems with using the calculated free ridership and
spillover calculations:
[T]he economic analysis [should] use the value 1.0 for the net-to-gross ratio
. . . [due to] known limitations to standard practices for the estimation of
free ridership and spillover estimation—limitations that confound their
effects and result in the overestimation of free ridership and the
underestimation of spillover—and on current net-to-gross practices in 31
3
NorthWestern had projected 309,336 megawatt-hours (MWh) of total energy savings. In its
final report, SBW was able to verify 270,564 MWh in savings.
11
jurisdictions with active energy efficiency programs, many of which
recognize that free ridership and spillover are offsetting phenomena.4
¶21 Dr. McRae concluded that researchers cannot truly ascertain free ridership and
spillover values, and opined the Commission should use a 1.0 NTG ratio that treats the
numbers as if they perfectly offset each other. To support her conclusion, Dr. McRae
cited various studies, one notably finding that thirteen regulatory jurisdictions used a 1.0
NTG, while two jurisdictions, Michigan and New York, used a 0.9 NTG.
¶22 Under cross-examination, Dr. McRae admitted she cannot know what the actual
values are due to the state of the science. “I would say that’s [(measuring spillover and
free ridership)] not possible with any methods that I know to know what they are.” In
response to questions from Commissioner Kavulla about whether there was data to
support her conclusion that free ridership and spillover perfectly offset in a 1.0 NTG
relationship, Dr. McRae admitted:
If you take 1.0 as the null hypothesis that these effects are offsetting, then, I
think the burden is—especially if you’re going to be in a lost revenue
calculation or something like that, I think the burden of proof is to say, no,
these aren’t offsetting. These savings would have happened anyway. . . . I
don’t think we have a way of saying that the null hypothesis is rejected, that
it’s anything other than what 1.0. And if you want to say for argument’s
sake it’s [0].9, well, then for argument’s sake why don’t we say it’s 1.1.
4
Specifically, Dr. McRae opined that while the free ridership and spillover numbers were
reliable (they consistently returned similar results from similar data sets), the numbers were not
valid because researchers are unsure what the research was actually measuring. For free
ridership, Dr. McRae stated various biases were the core of the problem, notably asymmetric
perceptions of gains versus losses, attribution errors, cognitive dissonance, and the inability to
accurately report events and predict participants’ behavior. For spillover, McRae noted difficulty
identifying non-incentivized efficiency actions, estimating baseline energy usage, and showing a
causal relation to an efficiency program.
12
Commissioner Kavulla’s asked: “why is the 1.0 rather than a [0].09 or a 1.1 the null
hypothesis?” Dr. McRae concluded: “I think in the absence of any other information,
you just assume that one is positive and one is a negative; they’re offsetting. That’s how
I think of it.”
¶23 The Commission rejected Dr. McRae’s conclusion that free ridership and spillover
perfectly offset each other in a 1.0 NTG ratio and, instead, adopted the values she
provided in her draft report. The Commission held that “[a]lthough free ridership and
spillover may be difficult to estimate, the remedy is not to discard the only empirical data
that attempts to ascertain those values.” The Commission disagreed with Dr. McRae’s
conclusion that offsetting meant equal offsetting:
Offsetting does not imply perfectly offsetting, and NorthWestern has not
demonstrated that an NTG of 1.0 is more reasonable as a null hypothesis
than an NTG of 0.9 or any other fixed relation of the effects of free
ridership and spillover. Because SBW did not test the null hypothesis
proposed by [Dr.] McRae, it cannot be supported.
Noting the Commission’s duty to “approve an accurate level of savings and associated
lost revenues,” the Commission reasoned that Dr. McRae’s conclusions were problematic
because they forced the Commission to assume both that: (1) a fixed ratio (1.0 NTG)
between free ridership and spillover was more accurate than actual measured numbers;
and (2) 1.0 NTG was a better assumption than any other fixed value, for example, 0.9
NTG. Using the data from the draft report indicating a 0.908 NTG correlation between
free ridership and spillover, the Commission lowered NorthWestern’s true-up realization
rate from 87% to 79%.
13
Procedural History
¶24 NorthWestern appealed the Commission’s order on both issues to the Montana
Second Judicial District Court, Silver Bow County. The District Court affirmed the
Commission’s Final Order. NorthWestern, NRDC, and HRC appeal.
STANDARD OF REVIEW
¶25 In an administrative appeal, we apply the same standards of review that the district
court applies. Whitehall Wind, LLC v. Mont. Pub. Serv. Comm’n, 2015 MT 119, ¶ 8,
379
Mont. 119,
347 P.3d 1273 (Whitehall Wind II); Molnar v. Fox,
2013 MT 132, ¶ 17,
370
Mont. 238,
301 P.3d 824. Administrative appeals are governed by § 2-4-704, MCA. “A
district 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 the
law is correct.” Whitehall Wind, LLC v. Mont. PSC,
2010 MT 2, ¶ 15,
355 Mont. 15,
223
P.3d 907 (Whitehall Wind I); accord Molnar, ¶ 17 (conclusions of law are reviewed de
novo). Judicial review of a final agency decision “must be confined to the record.”
Section 2-4-704(1), MCA; Molnar, ¶ 17.
¶26 “The court may not substitute its judgment for that of the agency as to the weight
of the evidence on questions of fact.” Section 2-4-704(2), MCA; accord Whitehall
Wind II, ¶ 7. “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 the court with a definite and firm conviction that a mistake
has been made.” Williamson v. Mont. PSC,
2012 MT 32, ¶ 25,
364 Mont. 128,
272 P.3d
14
71. “In reviewing findings of fact, the question is not whether there is evidence to
support different findings, but whether competent substantial evidence supports the
findings actually made.” Mayer v. Bd. of Psychologists,
2014 MT 85, ¶ 27,
374 Mont.
364,
321 P.3d 819. The court may reverse or modify the agency decision if the
“substantial rights” of the appellant were prejudiced because the administrative findings
are “in excess of the statutory authority of the agency,” “affected by error of other law,”
“clearly erroneous in view of the reliable, probative, and substantial evidence on the
whole record,” or “arbitrary or capricious or characterized by abuse of discretion or
clearly unwarranted exercise of discretion.” Section 2-4-704(2)(ii), (iv), (v), (vi), MCA.
¶27 “Except as otherwise provided by statute relating directly to an agency, agencies
shall be bound by common law and statutory rules of evidence.” Section 2-4-612(2),
MCA. “The agency’s experience, technical competence, and specialized knowledge may
be utilized in the evaluation of evidence.” Section 2-4-612(7), MCA. “Substantial
evidence is evidence that a reasonable mind could accept as adequate to support a
conclusion; evidence beyond a scintilla.” Mayer, ¶ 27 (internal quotations omitted).
“Moreover, the court should give deference to an agency’s evaluation of evidence insofar
as the agency utilized its experience, technical competence, and specialized knowledge in
making that evaluation.” Knowles v. State ex rel. Lindeen,
2009 MT 415, ¶ 21,
353
Mont. 507,
222 P.3d 595 (citing § 2-4-612(7), MCA; Johansen v. Dept. of Natural Res.
and Conservation,
1998 MT 51, ¶ 29,
288 Mont. 39,
955 P.2d 653).
15
DISCUSSION
¶28 1. Did the Commission use the correct legal standard in reviewing
NorthWestern’s claim for excess outage costs?
¶29 NorthWestern argues that the Commission used the incorrect legal standard when
reviewing the outage costs associated with purchasing replacement regulation service
during the DGGS outage. NorthWestern contends that “prudently incurred electricity
supply costs,” § 69-8-210(1), MCA, is an objective, reasonable person standard, which in
the context of utilities, is a “reasonable utility standard.” NorthWestern notes that other
jurisdictions consider such costs under a reasonable utility standard. Under this standard,
NorthWestern argues that “prudently incurred” costs are those that a reasonable utility in
NorthWestern’s similar situation would have incurred, and argues that it acted as any
other reasonable utility would have in the same situation.
¶30 The Commission argues that “prudent” must be interpreted in light of the statutes
and Commission rules referenced by the statute. The Commission does not dispute that
the reasonable utility test is one factor to be considered, but argues that it is not the
complete definition of “prudent.” The Commission offers that it reviewed
NorthWestern’s actions to determine whether the electricity supply costs were prudent
pursuant to § 69-8-210(1), MCA, whether the assets purchased and owned by
NorthWestern were managed reasonably under §§ 69-8-419 and -421, MCA, and whether
rates that included the outage charges would be excessive or confiscatory pursuant to
§ 69-3-201, MCA. The Commission argues it applied the appropriate review and, under
the facts in this case, made an appropriate determination that the costs were not prudently
16
incurred because the plant was not reasonably managed, and that any rates that included
those costs would not be reasonable.
¶31 At issue in this case is the meaning of the word “prudent” in § 69-8-210(1), MCA,
which, as the parties note, is not defined by the Legislature. Section 69-8-210(1), MCA,
reads in full:
The commission shall establish an electricity cost recovery mechanism that
allows a public utility to fully recover prudently incurred electricity supply
costs, subject to the provisions of 69-8-419, 69-8-420, and commission
rules. The commission may include other utility costs and expenses in the
cost recovery mechanism if it determines that including additional costs and
expenses is reasonable and in the public interest. The cost recovery
mechanism must provide for prospective rate adjustments for cost
differences resulting from cost changes, load changes, and the time value of
money on the differences.
¶32 Section 69-8-210(1), MCA reflects the full authority the Legislature granted to the
Commission to review electricity supply costs. The Commission is an administrative
agency created by statute. Section 69-1-102, MCA; Schuster v. Northwestern Energy
Co., 2013 MT 364, ¶ 9,
373 Mont. 54,
314 P.3d 650. The Commission does not have
judicial powers, Schuster, ¶ 9, Williamson, ¶ 31, and its jurisdiction is “limited to the
regulation of rates and service as provided by the Montana statutes.” Billings v. Pub.
Serv. Comm’n,
193 Mont. 358, 370,
631 P.2d 1295, 1303 (1981); accord Great N. Utils.
Co. v. Pub. Serv. Comm’n,
88 Mont. 180, 203,
293 P. 294, 298 (1930) (“[T]he
Commission is a creature of, owes its being to, and is clothed with such powers as are
clearly conferred upon it by the statute.”); Mont. Power Co. v. Pub. Serv. Comm’n,
206
Mont. 359, 371,
671 P.2d 604, 611 (1983). As we noted in the cases following the
17
deregulation of the Montana electrical industry, see, e.g., Mont. Power Co. v Mont. PSC,
2001 MT 102, ¶ 46,
305 Mont. 260,
26 P.3d 91 (“[W]e observe that the Commission is
statutorily charged with applying and enforcing the [deregulation] Act.”), the
Commission was specifically charged with carrying out the statutes in question: “[t]he
commission shall establish an electricity cost recovery mechanism.” Section 69-8-
210(1), MCA (emphasis added). As such, the statute in question clearly confers authority
on the Commission for this purpose.
¶33 The meaning of “prudent” is largely self-evident. “Absent statutory definitions,
the plain meaning of the words used controls.” City of Great Falls v. Mont. Dept. of Pub.
Serv. Regulation,
2011 MT 144, ¶ 18,
361 Mont. 69,
254 P.3d 595; accord Williamson,
¶ 36. The word has been applied in prior Commission decisions, which have used such
terms for “prudent” as “marked by wisdom or judiciousness” or “circumspect or
judicious in one’s dealings” and its synonyms are “‘careful,’ cautious,’ ‘sensible,’
‘practical,’ ‘discreet,’ ‘wise,’ and ‘farsighted.’” In re Mont. Power Co., Mont. Pub.
Serv. Comm’n, Docket D2001.10.144, Order No. 6382d 12 (June 21, 2002) (internal
citations omitted). The Montana Legislature gave the Commission express latitude to
determine if the given costs were prudent—careful, sensible, practical, discreet, wise, or
farsighted or, more apt in the regulatory environment, avoiding unnecessary risks—
through its own fact finding and administrative authority. Further, this analysis is
undertaken in light of the statutory requirement that “prudently incurred electricity supply
18
costs” must be determined “subject to the provisions of 69-8-419, 69-8-420, and
commission rules.” Section 69-8-210(1), MCA.5
¶34 Section 69-8-419, MCA, governs the utility’s duties for building and maintaining
its “electricity supply resource” portfolio, including contracts for power generation or
capacity, electricity plants owned or leased by the utility, customer load management, or
any other means of providing reliable and adequate electricity service to customers.
Section 69-8-103(9), MCA (defining “electricity supply resource”). The provision
requires utilities to “plan for future electricity supply resource needs; manage a portfolio
of electricity supply resources; and procure new electricity supply resources when
needed.” Section 69-8-419, MCA. The utility is required to conduct this planning in
accordance with, inter alia, the following objectives: (1) “provide adequate and reliable
electricity supply service at the lowest long-term total cost”; and (2) “identify and
cost-effectively manage and mitigate risks related to its obligation to provide electricity
supply service.” Section 69-8-419(2)(a), (c), MCA. Thus, the utility must plan for future
needs, manage its portfolio, and procure resources when necessary at the lowest
long-term cost and, when doing so, identify and mitigate risks related to those
obligations.
¶35 Commission administrative rules also address prudent utility resource
procurement. “Prudent electricity supply resource planning and procurement includes
evaluating, managing, and mitigating risks associated with the inherent uncertainty of
5
Section 69-8-420, MCA, covers a utility’s utility procurement plan, which are not directly at
issue in this proceeding.
19
wholesale electricity markets and customer load.” Admin. R. M. 38.5.8219(1) (2016)
(emphasis added). The Commission has specifically identified sources of risk that,
among others, may be evaluated: fuel prices and price volatility, environmental
regulations and taxes, retail supply rates, supplier capabilities, construction costs, and
contract terms and conditions. Admin. R. M. 38.5.8219(1) (emphasis added). The
Commission’s rules require that the “utility’s strategy for managing and mitigating risks
associated with the identified risk factors should be developed in the context of the goals
and objectives of these guidelines and include an evaluation of relevant opportunity
costs.” Admin. R. M. 38.5.8219(2). Finally, prudence involves documenting and
carrying out the resource procurement plans:
The commission must allow a utility to recover all costs it prudently incurs
to perform this function. Whether the costs a utility incurs are prudent is, in
part, directly related to whether its resource procurement process was
conducted prudently. It is vital that a utility document its portfolio
planning, management and electricity supply resource procurement
activities to justify the prudence of its resource procurement decisions.
Admin. R. M. 38.5.8220(2).
¶36 Considering these sources, we disagree with NorthWestern that the “reasonable
utility standard”—i.e., what would a reasonable utility do in similar circumstances—is
the appropriate interpretation of “prudent” or the appropriate inquiry under Montana law.
The Montana Legislature used the term “prudent,” not “reasonable utility,” to describe
how the Commission was to review electricity supply costs. Adopting NorthWestern’s
proposed standard would read a contradictory idea into the statute. If “prudent” was
restricted to what a reasonable utility would do in similar circumstances, the Commission
20
would be deprived of its own discretion to evaluate and determine whether the utility’s
actions were prudent. Tying the outcome to evidence of what other utilities did or would
do would remove or reduce the discretion of the Commission to rely on its own expertise.
¶37 In sum, § 69-8-210(1), MCA, grants authority to the Commission to determine
whether energy supply costs were prudently incurred—i.e., the utility’s incurred costs
were wise, judicious, or sought to avoid unnecessary risk—in light of the planning
requirements set forth in § 69-8-419, MCA, § 69-8-421, MCA, and Commission rules,
which specifically require risk analysis and mitigation, including an examination of the
relevant contract terms. The Commission was correct to apply these standards.
¶38 The remainder of NorthWestern’s arguments challenging the Commission’s
decision assumes that the reasonable utility standard governs the outcome. Having
rejected that view, we need not address all of NorthWestern’s further arguments based
thereon. In brief, and to the extent that the reasonable utility standard is an appropriate
factor to consider, as the Commission did, the Commission’s determination was
supported by the record. The DGGS was a “one-of-a-kind” plant and the purchase and
installation contract contained a provision that excluded consequential damages. Waiver
of consequential damages on a first-of-its-kind regulation plant without extensive
industry use supported the Commission’s determination that NorthWestern’s failure “to
identify risk ensured that incremental costs of replacement service would be incurred in
the event of an outage,” and was imprudent. To defend its actions, NorthWestern asked
other utilities—after the MCC and the Commission inquired into its risk mitigation
21
efforts—about their insurance practices and presented evidence that those utilities did not
purchase it. However, this is risk justification, not risk management.
¶39 Even if it is accepted that insurance was cost-prohibitive and would not have been
a viable alternative, the Commission also determined that NorthWestern did not
reasonably manage the DGGS and that the outage costs were also imprudent for that
reason.6 NorthWestern was aware that the DGGS had “very unique” controls and was
different from other plants. NorthWestern was also aware, as the Commission found:
(1) “[T]he units need[ed] to change load rapidly” as measured in “MW
change per minute,” and that a single engine in operation could “ramp up or
down at a rate of at least 15 MW per minute”; (2) “the ability to respond to
demand within seconds” was critical to the operational mission of DGGS;
and (3) the units could experience unique “thermal stresses,” and that going
“from a cold start to a very high temperature” can cause “a lot of distress
within rotating equipment.”
(Internal quotations in original.) The outage specifically resulted from these known
factors. PWPS’s investigation concluded “[o]ver temperatures resulted in reduction of
material properties,” “[h]igher motion resulted in higher stress on the affected parts,” and
“hardware failures are cycle related.” NorthWestern admitted the ramp rate was “much
greater” than NorthWestern had requested due to software configuration and
NorthWestern had not installed anything to monitor the actual ramp data on a per-minute
basis. In addition, NorthWestern cycled each unit frequently, which PWPS concluded
was the cause of the hardware failures.
6
Section 69-8-421(9), MCA, allows the Commission to “disallow rate recovery for the costs that
result from the failure of a public utility to reasonably manage, dispatch, operate, maintain, or
administer electricity supply resources in a manner consistent with 69-3-201, 69-8-419, and
commission rules.”
22
¶40 The Commission did not commit clear error in finding that NorthWestern had
failed to appropriately plan for and operate the DGGS. The Commission’s decision to
disallow the outage costs incurred by NorthWestern when the DGGS went offline was
well within its authority to determine whether those costs were “prudently incurred.”
Section 69-8-210(1), MCA. Accordingly, the Commission’s order regarding the outage
costs is affirmed.
¶41 2. Were the “free ridership” and “spillover” calculations adopted by the
Commission supported by substantial evidence?
¶42 NRDC and HRC argue that the Commission erred when it adopted the free
ridership and spillover values presented in Dr. McRae’s draft report when she, as the only
witness to testify on the subject, repudiated those very numbers in her testimony. This,
they argue, was clearly erroneous because there is no evidence in the record supporting
the use of those numbers.
¶43 Citing problems with the methodology, the SBW final report concluded that the
actual calculations for free ridership and spillover should not be used. SBW concluded
that the best approach was to assume the numbers perfectly offset each other. Dr. McRae
echoed this conclusion in her testimony before the Commission.
¶44 However, NRDC and HRC are incorrect to argue that there was no testimony
regarding actual free ridership and spillover calculations. When pressed on her
conclusions, Dr. McRae hedged her testimony in several ways. First, Dr. McRae stated
affirmatively that actual free ridership and spillover calculations were conducted using
“national common practices, and best practices,” and that the actual data derived was
23
“comparable to those found for similar programs conducted by other respected program
evaluators.”
¶45 Second, Dr. McRae testified her opinion of the state of the science is that she
simply cannot know what the actual values are, including the 1.0 NTG she suggested the
Commission adopt. “I would say that’s not possible with any methods that I know to
know what they [free ridership and spillover] are.” Regarding whether there was actual,
hard data to support her conclusion for a 1.0 NTG, Dr. McRae testified there was no way
to prove or disprove her conclusion:
If you take 1.0 as the null hypothesis that these effects are offsetting, then, I
think the burden is—especially if you’re going to be in a lost revenue
calculation or something like that, I think the burden of proof is to say, no,
these aren’t offsetting. These savings would have happened anyway. . . . I
don’t think we have a way of saying that the null hypothesis is rejected, that
it’s anything other than what 1.0. And if you want to say for argument’s
sake it’s [0].9, well, then for argument’s sake why don’t we say it’s 1.1.
(Emphasis added.) When asked why 1.0 would be used instead of 0.9 or 1.1, Dr. McRae
responded: “in the absence of any other information, you just assume one is positive and
one is negative; they’re offsetting. That’s how I think of it.”
¶46 The Commission was faced with: (1) an expert’s conclusion that one cannot know
the precise spillover and free ridership numbers; and (2) testimony stating they could
neither prove nor disprove that given hypothesis. The same expert provided a range of
hypothetical values from 0.9 to 1.1 and provided anecdotal evidence of other states using
a 0.9, while some used 1.0. Finally, the expert admitted the only hard research available
24
in the proceeding was done according to best practices and was comparable with that
done by other respected researchers.
¶47 Our role is not to re-weigh the evidence, but rather, to determine if substantial
evidence existed “and not whether, on the same evidence, [we] would have arrived at the
same conclusion.” Johnson v. W. Transp., LLC, 2011 MT 13, ¶ 18,
359 Mont. 145,
247
P.3d 1094 (citing Ward v. Johnson,
242 Mont. 225, 228,
790 P.2d 483, 485 (1990)). We
hold the Commission’s facts were supported by substantial evidence. The actual data
collected by Dr. McRae and SBW provided a 0.908 NTG, which falls in the range of
hypothetical values provided by the expert. It is also in the range of values used by other
commissions, as testified to by Dr. McRae. Dr. McRae admitted there was no actual,
hard data to support her conclusion that the values perfectly offset each other. And,
finally, the only hard data available was collected per best practices and was consistent
with the research done by other respected firms.
¶48 As an administrative agency, the Commission’s “experience, technical
competence, and specialized knowledge may be utilized in the evaluation of evidence.”
Section 2-4-612(7), MCA. The Commission had substantial evidence to rely upon and it
appropriately used is expertise to evaluate that evidence. As such, the Commission’s
determination to adopt the calculated values for free ridership and spillover is affirmed.
¶49 For the foregoing reasons, the Commission’s Order No. 7219h is affirmed.
/S/ JIM RICE
25
We concur:
/S/ MIKE McGRATH
/S/ JAMES JEREMIAH SHEA
/S/ PATRICIA COTTER
/S/ MICHAEL E WHEAT
26
