NIPSCO Industrial Group, and, Indiana Office of Utility Consumer Counselor v. Northern Indiana Public Service Company , 2015 Ind. App. LEXIS 292 ( 2015 )

Apr 08 2015, 10:25 am
ATTORNEYS FOR APPELLANT, ATTORNEYS FOR APPELLEE,
NIPSCO INDUSTRIAL GROUP INDIANA UTILITY REGULATORY
Todd A. Richardson COMMISSION
Bette J. Dodd David Lee Steiner
Jennifer W. Terry Deputy Attorney General
Joseph P. Rompala Office of the Indiana Attorney General
Lewis & Kappes, P.C. Indianapolis, Indiana
Indianapolis, Indiana
Beth Krogel Roads
ATTORNEYS FOR APPELLANT, Andrew J. Wells
INDIANA OFFICE OF UTILITY Indiana Utility Regulatory Commission
CONSUMER COUNSELOR Indianapolis, Indiana
A. David Stippler ATTORNEYS FOR NORTHERN
Randall C. Helman INDIANA PUBLIC SERVICE
Lorraine Hitz-Bradley COMPANY
Jeffrey Reed
Indianapolis, Indiana Brian J. Paul
Kay E. Pashos
ATTORNEYS FOR AMICUS CURIAE, Kelly S. Earls
INDIANA ENERGY ASSOCIATION Ice Miller, LLP
Indianapolis, Indiana
Wayne C. Turner
Patrick Z. Ziepolt Claudia J. Earls
Bingham Greenebaum Doll, LLP Erin Casper Borissov
Indianapolis, Indiana NiSource Corporate Services – Legal
Indianapolis, Indiana
ATTORNEYS FOR NLMK, INDIANA,
A DIVISION OF NLMK USA
Richard E. Aikman, Jr.
Anne E. Becker
Lewis & Kappes, P.C.
Indianapolis, Indiana
Court of Appeals of Indiana | Opinion 93A02-1403-EX-158 |April 8, 2015 Page 1 of 31
IN THE
COURT OF APPEALS OF INDIANA
NIPSCO Industrial Group, and, April 8, 2015
Court of Appeals Cause No.
Indiana Office of Utility 93A02-1403-EX-158
Consumer Counselor, Appeal from the Indiana Utility
Regulatory Commission
Appellants-Intervenor and Statutory Cause No. 44370 & 44371
Party below, The Honorable James D. Atterholt,
Chairman; The Honorable Carolene
R. Mays; The Honorable David E.
Ziegner, Commissioners
v.
Northern Indiana Public Service
Company, et al.,
Appellees-Petitioner and Parties below.
Barnes, Judge.
Case Summary
[1] In this consolidated appeal, the Indiana Office of Utility Consumer Counselor
(“OUCC”) and the NIPSCO Industrial Group (“Industrial Group”) appeal the
decision of the Indiana Utility Regulatory Commission (“Commission”)
regarding two petitions filed by Northern Indiana Public Service Company
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(“NIPSCO”) to establish increased rates under a new statute, Indiana Code
Chapter 8-1-39. We affirm in part, reverse in part, and remand.1
Issues
[2] The Industrial Group raises three issues, which we consolidate and restate as:
I. whether the Commission erred by allowing
NIPSCO to specifically identify the proposed
projects for only the first year of the seven-year
plan and by establishing a presumption that the
proposed projects for years two through seven
of the plan were eligible for special ratemaking
treatment; and
II. whether the Commission erred by approving
costs allegedly in excess of a statutory cap on
aggregate increases.
[3] The OUCC raises two issues, which we restate as:
III. whether the Commission erred by allowing
NIPSCO to continue rate recovery of retired
equipment while also recovering for
replacement assets; and
IV. whether the Commission erred by approving
NIPSCO’s proposed rate allocation
methodology.
1
We held oral argument on this matter on February 26, 2015. We commend counsel for their presentations.
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Facts
[4] NIPSCO is a public electric and gas utility that services over 457,000 customers
in northern Indiana. The OUCC is the statutory representative of the public
before the Commission. See Ind. Code § 8-1-1-5(c). The Industrial Group is a
group of some of NIPSCO’s largest industrial customers.
[5] Traditionally, a utility’s rates charged to customers are adjusted through
periodic rate cases, which are expensive, time consuming, and sometimes result
in large, sudden rate hikes for customers. NIPSCO’s last rate case was finalized
in December 2011. There, the Commission issued an order in Cause No. 43969
and approved a settlement regarding NIPSCO’s proposed general rate increase.
See In Re Petition of NIPSCO to Modify its Rates, Cause No. 43969, 2011 WL
6837714 (Ind. U.R.C. Dec. 21, 2011).
[6] Another way to set rates is through “tracker” proceedings, which allow smaller
increases for specific projects and costs between general rate case proceedings.
The General Assembly has authorized several trackers, including a fuel charge
tracker, see Ind. Code § 8-1-2-42(d), a tracker for qualified pollution control
projects under construction, see Ind. Code § 8-1-2-6.8, a tracker for federally
mandated costs, see Ind. Code § 8-1-8.4-7, and a tracker for clean energy
projects, see Ind. Code §§ 8-1-8.8-11 and 8-1-8.8-12. In 2013, the General
Assembly enacted Indiana Code Chapter 8-1-39, which allows a utility to
petition for a tracker for certain proposed new or replacement electric or gas
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transmission, distribution, or storage projects. The new statute is referred to as
the “TDSIC” statute.
[7] In July 2013, NIPSCO filed two petitions with the Commission under the new
TDSIC statute. In Cause No. 44370, NIPSCO sought approval of a seven-year
plan pursuant to Indiana Code Section 8-1-39-10. The plan included over $1
billion in improvements and replacements to NIPSCO’s transmission and
distribution systems. In Cause No. 44371, NIPSCO sought approval of the rate
increases associated with the seven-year plan. The two petitions were treated as
companion cases. The parties prefiled evidentiary submissions, and an
evidentiary hearing was held in November 2013.
[8] On February 17, 2014, the Commission issued its final orders. In Cause No.
44370, the Commission substantially approved NIPSCO’s seven-year plan.
However, the Commission found that NIPSCO had provided sufficient detail of
the plan for only the first of the seven years. For years two through seven, the
Commission established a “presumption of eligibility” and required NIPSCO to
annually update the plan through an informal process. Industrial Group’s App.
pp. 25-26.
[9] In Cause No. 44371, the Commission also substantially approved NIPSCO’s
proposed rate increases. The Commission approved NIPSCO’s adjustments to
the customer class revenue allocation factors based on firm/non-firm load and
distribution/transmission considerations. The Commission rejected the
OUCC’s argument that NIPSCO should be required to reduce its return and
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depreciation so that it was not recovering on both replaced assets and the new
replacement assets. Finally, the Commission rejected the Industrial Group’s
interpretation of the two-percent cap found in Indiana Code Section 8-1-39-14.
[10] The OUCC filed a petition to reconsider in Cause No. 44371. The OUCC
argued that “the recoverable TDSIC costs should be adjusted to reflect the
removal of any return and depreciation expenses embedded in base rates that
are associated with original transmission and distribution investments that will
be retired as a result of new TDSIC investments.” Id. at 34. The OUCC also
argued that “NIPSCO’s request to apply adjusted customer class allocation
factors should be denied and they should be required to apply the customer
class revenue allocators from the Commission’s Order in Cause No. 43969.”
Id. The Commission did “not find statutory support for the netting of
investment in determining the appropriate investment to be afforded cost
recovery” and declined “to require NIPSCO to adjust TDSIC costs to reflect
the removal of any return and depreciation expenses embedded in base rates
that are associated with original transmission and distribution investments that
will be retired as a result of new TDSIC investments.” Id. at 34-35. As for the
allocation factors, the Commission found that its original order addressed the
issue adequately. Consequently, the Commission denied OUCC’s petition to
reconsider.
[11] The OUCC appealed the Commission’s order in Cause No. 44371, and the
Industrial Group appealed the Commission’s order in Cause No. 44370. We
granted NIPSCO’s motion to consolidate the appeals. In addition to filing an
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appellant’s brief, the Industrial Group also filed an appellee’s brief addressing
the rate allocation issue raised by the OUCC. The Commission and NIPSCO
also filed appellee’s briefs. Finally, we granted the Indiana Energy Association
permission to file an amicus curiae brief.
Analysis
[12] The OUCC and the Industrial Group appeal the Commission’s order regarding
NIPSCO’s TDSIC petitions. The General Assembly created the Commission
primarily as a fact-finding body with the technical expertise to administer the
regulatory scheme devised by the legislature. N. Indiana Pub. Serv. Co. v. U.S.
Steel Corp., 907 N.E.2d 1012, 1015 (Ind. 2009); I.C. § 8-1-1-5. The
Commission’s assignment is to ensure that public utilities provide constant,
reliable, and efficient service to the citizens of Indiana. Id. The Commission
only can exercise power conferred upon it by statute. Id. Its authority also
“includes implicit powers necessary to effectuate the statutory regulatory
scheme.” United States Gypsum, Inc. v. Indiana Gas Co., 735 N.E.2d 790, 795
(Ind. 2000). Any doubts regarding the Commission’s statutory authority must
be resolved against the existence of such authority. U.S. Steel Corp. v. N. Indiana
Pub. Serv. Co., 951 N.E.2d 542, 550 (Ind. Ct. App. 2011), trans. denied.
[13] An order of the Commission is subject to appellate review to determine whether
it is supported by specific findings of fact and by sufficient evidence, as well as
to determine whether the order is contrary to law. United States Gypsum, 735
N.E.2d at 795. On matters within its jurisdiction, the Commission enjoys wide
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discretion. Id. The Commission’s findings and decision will not be lightly
overridden just because we might reach a contrary opinion on the same
evidence. Id. We first review the entire record to determine whether there is
substantial evidence to support the Commission’s findings of basic fact. U.S.
Steel Corp., 951 N.E.2d at 551. Next, we review ultimate facts, or mixed
questions of fact and law, for their reasonableness with the amount of deference
owed depending on whether the issue falls or does not fall within the
Commission’s expertise. Id. Finally, legal propositions are reviewed for their
correctness. Id. More precisely, “an agency action is always subject to review
as contrary to law, but this constitutionally preserved review is limited to
whether the Commission stayed within its jurisdiction and conformed to the
statutory standards and legal principles involved in producing its decision,
ruling, or order.” Id.[14] Many of the issues here involve the interpretation of the new TDSIC statute.
Generally, an agency’s reasonable interpretation of a statute it is charged with
enforcing is entitled to great weight. Id. In statutory construction, our primary
goal is to ascertain and give effect to the intent of the legislature. Id. at 552.
The language of the statute itself is the best evidence of legislative intent, and
we must give all words their plain and ordinary meaning unless otherwise
indicated by statute. Id. Furthermore, we presume that the legislature intended
statutory language to be applied in a logical manner consistent with the statute’s
underlying policies and goals. Id. However, we will not interpret a statute that
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is clear and unambiguous on its face; rather, we will give such a statute its
apparent and obvious meaning. Id.I. Plan Sufficiency
[15] The Industrial Group argues that the Commission erred by allowing NIPSCO
to specifically identify the proposed projects for only the first year of the seven-
year plan. The Industrial Group also argues that the Commission erred by
establishing a presumption that the proposed projects for years two through
seven of the seven-year plan were eligible for special ratemaking treatment.
[16] Indiana Code Section 8-1-39-10(a) requires a utility’s TDSIC petition to contain
a “seven (7) year plan for eligible transmission, distribution, and storage
improvements.” The Commission’s order on the petition must include the
following:
(1) A finding of the best estimate of the cost of the eligible
improvements included in the plan.
(2) A determination whether public convenience and necessity
require or will require the eligible improvements included in the
plan.
(3) A determination whether the estimated costs of the eligible
improvements included in the plan are justified by incremental
benefits attributable to the plan.
I.C. § 8-1-39-10(b). “If the commission determines that the public utility’s
seven (7) year plan is reasonable, the commission shall approve the plan and
designate the eligible transmission, distribution, and storage improvements
included in the plan as eligible for TDSIC treatment.” Id.
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[17] The Commission found that NIPSCO’s seven-year plan included “general
categories of spending, separated primarily by function rather than specific
projects in Years 2 through 7, with the specific projects for Year 1 better
defined.” Industrial Group App. pp. 20-21. Despite the lack of specificity
regarding the projects beyond the first year of the plan, the Commission
approved the plan as follows:
Based upon our review of the evidence of record, and the foregoing
considerations of each component of Ind. Code § 8-1-39-10, we find
that NIPSCO’s 7-Year Electric Plan is reasonable under the conditions
as applied by this Order. . . . We find there is sufficient evidence to
approve the Year 1 projects as eligible for TDSIC treatment.
However, we are concerned that the project specific detail of Years 2
through 7 does not rise to the same level of confidence. Thus, in the
context of our 7-Year Plan approval we will presume the categories of
spending identified in the 7-Year Electric Plan for Years 2 through 7
are eligible for TDSIC treatment. Because we expect these eligible
project categories will become better defined in terms of specificity as
their respective investment year comes of age, this presumption of
eligibility will be assigned to specific projects in the annual updating
process as further described below.
Id. at 25. The Commission then established an informal bi-annual update to the
plan and anticipated that NIPSCO would provide details on specific projects,
similar to what it provided for Year 1. The Commission found that “this
process will reasonably balance the needs of NIPSCO for investment recovery
confidence and customers for prudent investment assurance.” Id. at 26. The
Commission noted:
Clearly, a 7-Year Plan for any public utility must necessarily include
some level of flexibility to address changing circumstances. It would
not be reasonable for a public utility to submit a 7-Year Plan that does
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not acknowledge that unforeseen events and changes in circumstances
do occur and may require changes to the 7-Year Plan.
Id. at 22.
[18] On appeal, the Industrial Group argues that the statutes require the
improvements to be “designated” in the plan and that the Commission did not
have enough information to determine whether the plan was “reasonable” or to
determine a “best estimate of the cost” of the improvements. See I.C. § 8-1-39-
10(b). The Commission argues that approval of the plan was a matter within its
expertise and discretion. NIPSCO contends that the plan is reasonable because
the Commission found NIPSCO had an “overarching goal,” included a
“defined roadmap,” and had a “reasonably detailed overview of what types of
projects need to be undertaken.” NIPSCO’s Appellee’s Br. pp. 29-30.
[19] NIPSCO’s seven-year plan included cost estimates for projected direct capital
expenses, which included estimates for both transmission and distribution
projects, and projected indirect capital expenditures. The plan also provided
detailed information on the improvements for the first year of the plan.
Specifically, for 2014 only, NIPSCO provided details on the type of
improvement, reason for the improvement, the project title and location, and a
project cost for each category. However, detailed information on the projects
was not provided for years two through seven of the plan. For the remaining
years, NIPSCO only provided “expected annual total spends for major project
categories.” Tr. p. 624.
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[20] NIPSCO argues that another exhibit, TAD-R1, is part of the plan. TAD-R1 is
a list of all of NIPSCO’s major transmission and distribution assets and that
TAD-R1 identifies the name of each asset to be replaced, the cost of each asset
to be replaced, and the year in which the asset is to be replaced. However,
NIPSCO’s argument conflicts with the Commission’s finding regarding the
plan. See Industrial Group App. p. 25 (“[W]e are concerned that the project
specific detail of Years 2 through 7 does not rise to the same level of
confidence.”). NIPSCO also did not identify TAD-R1 as part of the “plan.” In
fact, in the verified rebuttal testimony of Timothy Dehring, NIPSCO’s senior
vice president of transmission and engineering, he acknowledged the OUCC’s
concerns with the plan’s lack of detail, noted that TAD-R1 was provided during
discovery to address the OUCC’s concerns, and stated that the OUCC “makes
a valid recommendation that in the future this type of information should be
provided with the 7-Year Electric Plan.” Tr. p. 589. Consequently, we
conclude that TAD-R1 was not part of the “plan.”
[21] We further conclude that the plan provided to the Commission simply did not
contain enough detail for the Commission to determine whether NIPSCO’s
plan for years two through seven was “reasonable” or to determine a “best
estimate of the cost” of the improvements. I.C. § 8-1-39-10(b). We
acknowledge the arguments on appeal that a utility needs some flexibility to
deal with changing conditions. Clearly, NIPSCO requires some flexibility in
completing the seven-year plan because some equipment may need to be
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replaced earlier or later than initially planned. Even the OUCC acknowledged
that some flexibility is required, and its representative testified:
The OUCC appreciates that over the course of 7 years project priorities
will likely change. Unforeseen events will occur and assets may fail
sooner than anticipated. . . . The OUCC does not object to this
shifting as long as the utility (NIPSCO) is transparent with the
[Commission], OUCC and Intervenors regarding the reasons for the
shift. . . . NIPSCO should not be locked into a specific set of projects
today that in the future would not provide the greatest benefit to the
T&D system and its users. Conversely, the OUCC does not believe
the Statute permits NIPSCO to make wholesale substitutions of
projects as it sees fit.
Tr. pp. 842-43. The OUCC proposed that NIPSCO submit an updated plan
annually “concurrent with its Fall TDSIC tracker filing” and that the parties
would have the opportunity to contest the revised plans. Id. at 843. We believe
that the legislature anticipated the necessity of flexibility when it enacted the
updating process of Indiana Code Section 8-1-39-9. The updating process does
not, however, relieve the utility of providing an initial seven-year plan that
meets the statutory requirements. Allowing for flexibility in a plan is not the
same thing as not having a plan at all. We conclude that the Commission erred
by approving NIPSCO’s seven-year plan given its lack of detail regarding the
projects for years two through seven.
[22] The Industrial Group also takes issue with the Commission establishing a
presumption of eligibility for years two through seven. The Commission found
that, even though NIPSCO provided insufficient detail of the plan for years two
through seven, a presumption of eligibility would be established that the
projects would be eligible for TDSIC treatment. See Industrial Group’s App. p.
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25 (“[W]e will presume the categories of spending identified in the 7-Year
Electric Plan for Years 2 through 7 are eligible for TDSIC treatment. . . . [T]his
presumption of eligibility will be assigned to specific projects in the annual
updating process . . . .”). The Industrial Group points out that we have held
that the Commission may not create legal presumptions. See S. Indiana Gas &
Elec. Co. v. Indiana Farm Gas Prod. Co., 540 N.E.2d 621, 625 (Ind. Ct. App.
1989), vacated on reh’g on other grounds, 549 N.E.2d 1063 (Ind. Ct. App. 1990),
trans. denied. The Industrial Group also asserts that, by creating a presumption
of eligibility, the Commission has shifted the burden from NIPSCO to
intervening parties to demonstrate that the proposed projects are eligible for
TDSIC treatment. NIPSCO counters that the presumption is permissible
because the Commission was exercising its expertise and inherent authority and
the presumption “balanced the relationship between NIPSCO and its
customers.” NIPSCO’s Appellee’s Br. p. 41. The Commission argues that it
did not shift the burden of proof and did not establish a rebuttable presumption.
[23] We conclude that the Commission’s order did establish a presumption of
eligibility regarding the undefined projects for years two through seven. There
does not appear to be any statutory support for establishing such a presumption.
We agree with the Industrial Group that such a presumption inappropriately
shifts the burden of showing a project’s eligibility for TDSIC treatment from
NIPSCO to other intervening parties. On remand, the Commission may not
establish such a presumption.
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II. Statutory Cap
[24] The Industrial Group also argues that the Commission erred by approving costs
in excess of a statutory cap on aggregate increases. Because this issue and the
issues raised by the OUCC are likely to be relevant on remand, we will address
them.
[25] Indiana Code Section 8-1-39-14 provides:
(a) The commission may not approve a TDSIC that would result
in an average aggregate increase in a public utility’s total retail
revenues of more than two percent (2%) in a twelve (12) month
period. For purposes of this subsection, a public utility’s total
retail revenues do not include TDSIC revenues associated with
a targeted economic development project.
(b) If a public utility incurs TDSIC costs under the public utility’s
seven (7) year capital expenditure plan that exceed the
percentage increase in a TDSIC approved by the commission,
the public utility shall defer recovery of the TDSIC costs as set
forth in section 9(b) of this chapter.
[26] Before the Commission, the Industrial Group argued that, under the statute,
NIPSCO was limited to a two-percent increase over the course of the seven-
year plan. The Commission disagreed and found:
NIPSCO and the Industrial Group have presented two different
interpretations of Ind. Code § 8-1-39-14. NIPSCO’s calculation
compares the increase in TDSIC revenue in a given year with the total
retail revenues for the past 12 months whereas the Industrial Group
compares the total TDSIC revenue in a given year with the total retail
revenues for the base 12 months. Since this is a case of first
impression, we must interpret and apply this statutory language for the
first time based on the express language of the statute and the general
rules of statutory interpretation.
Section 14(a) states as follows:
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The commission may not approve a TDSIC that would
result in an average aggregate increase in a public utility’s
total retail revenues of more than two percent (2%) in a
twelve (12) month period. For purposes of this
subsection, a public utility’s total retail revenues do not
include TDSIC revenues associated with a target
economic development project.
Based on the unambiguous language of Section 14, we find that
NIPSCO’s proposed calculation that compares the increase in TDSIC
revenue in a given year with the total retail revenues for the past 12
months is consistent with the TDSIC statute. Under the Industrial
Group’s interpretation, a utility would be capped at an amount of
TDSIC revenue that would have the effect of being a cumulative 2%
increase. However, the average aggregate increase language of the
statute allows a utility to increase its TDSIC revenues by 2% a year, on
a year over year basis. Thus, we find that NIPSCO’s proposed
calculation is consistent with Section 14 and should be approved.
OUCC App. p. 29.
[27] On appeal, the Industrial Group argues that the statute is ambiguous regarding
the two-percent cap. According to the Industrial Group, the “aggregate”
increase over the entire seven-year plan cannot exceed two percent. NIPSCO
asserts that the statute is unambiguous. According to NIPSCO, the Industrial
Group is ignoring the “twelve (12) month period” language in the statute.
NIPSCO argues that the statute allows a two-percent increase every twelve
months based on the prior twelve months’ total retail revenues. The
Commission agreed with NIPSCO and argues that its interpretation was
reasonable and that the statute is unambiguous. The Commission points out,
“If the Legislature intended to apply the 2% cap to the entirety of a seven-year
plan, why would it specifically confine the 2% increase to a twelve-month
period?” Commission’s Appellee’s Br. p. 20. Additionally, the Indiana Energy
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Association argues that the Industrial Group’s interpretation would “cripple the
TDSIC statute.” Indiana Energy Association’s Br. p. 3.
[28] The statute does not allow “an average aggregate increase in a public utility’s
total retail revenues of more than two percent (2%) in a twelve (12) month
period.” I.C. § 8-1-39-14(a). The plain language of the statute allows an
average two-percent increase in a twelve month period, not during the entire
seven-year plan. We must give the statute its apparent and obvious meaning.
U.S. Steel Corp., 951 N.E.2d at 551. The Commission did not err in interpreting
the two-percent cap of Indiana Code Section 8-1-39-14(a).
III. Retired Assets
[29] The OUCC argues that the Commission erred by allowing NIPSCO to
continue rate recovery of retired equipment while also recovering for
replacement assets. According to the OUCC, under the rate increases proposed
by NIPSCO, NIPSCO will continue recovering on assets no longer in use until
the next general rate case, which could result “in utility rate payers paying
millions of dollars for up to seven years for assets no longer providing them any
service.” OUCC’s Reply Br. p. 10. The OUCC asserts that NIPSCO will
receive a double recovery, i.e., a return on the new assets at the same time as it
is receiving a return on the old, replaced asset.
[30] This argument has two facets—the calculation of NIPSCO’s “return on” the
investments and depreciation. In general, “the end purpose of the function of
the Commission is to establish a rate sufficient to meet the operating expenses
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of the company plus a fair return which will compensate the investors.”
Citizens Energy Coal., Inc. v. Indiana & Michigan Elec. Co., 396 N.E.2d 441, 445
(Ind. Ct. App. 1979). “Utility’s revenues, minus expenses, constitute the return
on investments.” Id. (emphasis added). On the other hand, depreciation
accounts for a reduction in value of an asset as it ages; depreciation is
sometimes called “return of” the investment. OUCC’s Reply Br. p. 10. The
OUCC does not “oppose NIPSCO collecting any remaining amounts for
undepreciated plant, but advocated for adjustments to the TDSIC to prevent
NIPSCO from earning a ‘return on’ an investment that was no longer in
service.” OUCC’s Appellant’s Br. p. 25 n.8.
[31] The OUCC challenged NIPSCO’s proposed rate increase for the TDSIC
improvements based on this issue. The Commission allowed NIPSCO to
recover for TDSIC projects without subtracting for returns or depreciation
already being recovered for the assets being replaced. Specifically, the
Commission found:
The OUCC recommended that NIPSCO should only be permitted to
recover the incremental capital, depreciation and operating and
maintenance costs of replacement TDSIC projects because ratepayers
are already paying for the replaced assets in basic rates. Similarly,
U.S. Steel recommended NIPSCO should be required to produce
adjustments in its updated 7-Year Electric Plan and in the calculation
of the periodic TDSIC trackers to account for and eliminate the
recovery of costs and depreciation associated with the early retirement
and replacement of assets replaced and recovered in the TDSIC
charges. U.S. Steel argued that by recovering carrying costs and
depreciation expense for assets that are retired early and replaced
through the 7-Year Electric Plan, NIPSCO will be recovering for assets
that are no longer used and useful. U.S. Steel argued to allow such
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double recovery is not in the public interest or consistent with
fundamental ratemaking principles.
The statutory definition of eligible improvements at Ind. Code § 8-1-
39-2 authorizes recovery of investment for replacement projects and
the definition of pretax return at Ind. Code § 8-1-39-3 provides that
revenues should provide for such investments, notably without
suggesting any deduction or netting of the replaced asset. Further,
TDSIC costs as defined at Ind. Code § 8-1-39-7 includes this
unadjusted pretax return. While acknowledging that Ind. Code § 8-1-
39-13(a) allows the Commission to consider other information in
setting the appropriate pretax return, we read this section to be
addressing the weighted cost of capital rate rather than the investment
amount so as to reconcile the statutory language of Sections 13 and 3.
Accordingly, we do not find statutory support for the netting of
investment in determining the appropriate investment to be afforded
cost recovery. In addition, the TDSIC statute requires a general rate
case before the expiration of the utility’s 7-year plan which provides a
built in mechanism to update the net investment of the utility. Thus,
we decline to require NIPSCO to recognize the replaced asset
investment cost already embedded in base rates because Ind. Code ch.
8-1-39 does not support it outside of the required rate case.
OUCC App. pp. 26-27.
[32] The Commission found that the TDSIC statutes do not specifically address this
issue, and we agree. The TDSIC statute allows a utility to recover, through
“the periodic automatic adjustment of the public utility’s basic rates and
charges,” eighty percent of “approved capital expenditures and TDSIC costs.”
I.C. § 8-1-39-9(a). Recovery of the remaining twenty percent of approved
capital expenditures and TDSIC costs is deferred to the next general rate case
filed by the utility. I.C. § 8-1-39-9(b). Although TDSIC costs are defined by the
statutes, the statutes do not mention depreciation or return on the replaced
equipment. See I.C. § 8-1-39-7 (defining TDSIC costs, including pretax returns,
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among other things); I.C. § 8-1-39-3 (defining pretax returns). The statute does,
however, allow the Commission to consider “[o]ther information that the
commission determines is necessary” in calculating pretax returns. I.C. § 8-1-
39-13.
[33] Despite the lack of a specific statute addressing the OUCC’s concern here, the
OUCC argues that Indiana Code Section 8-1-2-6(a) requires the Commission to
“value all property of every public utility actually used and useful for the
convenience of the public at its fair value.” (Emphasis added). The OUCC
argues that the Commission allowed NIPSCO to continue recovering a return
on assets that will be replaced through the TDSIC proceeding and will no
longer be “used and useful.”
[34] NIPSCO argues that the “used and useful” principle applies only to
determining whether the cost of new investments should be passed onto
consumers. NIPSCO’s Appellee’s Br. p. 70. In support of this argument,
NIPSCO relies on Citizens Action Coal. of Indiana, Inc. v. N. Indiana Pub. Serv. Co.,
485 N.E.2d 610 (Ind. 1985), cert. denied, where NIPSCO sought to recover costs
for a cancelled nuclear power plant. Our supreme court did not allow NIPSCO
to recover the costs of a project that was never used and useful. However, our
supreme court differentiated that situation from the “long-adhered to
administrative interpretation of allowing amortization of abandoned plants, i.e.
plants that were ‘used and useful’ property and then retired from service.”
Citizens Action Coal., 485 N.E.2d at 616. The court noted: “Allowance of
amortization of cancelled plants would encourage uneconomical or
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unproductive ventures; whereas, allowance for amortization of abandoned or
retired plants encourages utilities to remove obsolete plants and property from
the ratebase. This treatment also benefits consumers because obsolete and
inefficient property is removed from the ratebase.” Id.
[35] The OUCC argues that the language from Citizens Action Coal. of Indiana is dicta
and that more recent Commission orders have reached contrary results. The
OUCC notes that, in other contexts, the Commission has refused to allow a
utility to earn such a double recovery even where the statutes do not directly
address the issue. The OUCC cites the Commission’s determination in In Re
Petition of NIPSCO, Cause No. 42150 ECR 21, 2013 WL 5740184 (Ind. U.R.C.
Oct. 16, 2013), where NIPSCO sought to replace pollution control equipment.
The Commission allowed NIPSCO to recover “a return of its investment” on
the original and replacement catalyst layers. OUCC Appellant’s Addendum p.
13. However, the Commission noted that “should we grant full recovery of
NIPSCO’s return on its investment in the replacement layer when it already
receives a return on its investment in the original layer through its base rates
and charges, then until its next base rate case, NIPSCO would receive a return
on investment for two catalyst layers, while only one layer is in service.” Id.The Commission concluded that NIPSCO would “be allowed to seek recovery
of its full depreciation expense (return of investment) for the replacement
layer,” but it would “only be allowed to seek recovery of the incremental
amount of the return on its investment for the replacement catalyst layer that
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exceeds the return on investment currently included in its base rates and charges
for the original catalyst layer.” Id.[36] The OUCC also cites In Re Indiana-American Water Co., Inc., Cause No. 42351
DSIC-1 (Ind. U.R.C. Feb. 27, 2003). There, the Commission was considering a
water utility’s petition under the Distribution System Improvement Charge
(“DSIC”) statute and refused to allow a water utility to earn both a return on a
replaced asset and a return on the replacement asset. The Commission held:
Petitioner’s rate base is based on the fair value of its assets. When any
asset with a positive fair value is retired that will reduce the utility’s
fair value rate base. Thus, if retirements are ignored and a utility is
allowed to earn a return on new plant through a DSIC and on the
retired asset through its return on the fair value rate base determination
from the utility’s last rate case.
Id. at 32.
[37] NIPSCO responds that the Commission is not bound by its prior rulings and
that the rulings concern different statutes. According to NIPSCO, if the
Commission adopted the OUCC’s “netting” proposal, “NIPSCO’s common
equity holders would not only lose their return on common equity, they would
be required to pay NIPSCO’s long-term debt.” NIPSCO’s Appellee’s Br. p. 73.
[38] Under the TDSIC statutes, the Commission “may consider . . . [o]ther
information that the commission determines is necessary” in calculating pretax
returns. I.C. § 8-1-39-13 (emphasis added). The Commission could, under this
statute, address the OUCC’s concern; the Commission, however, is not required
to do so. We give “great deference” to the Commission’s rate-making
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methodology. Office of Util. Consumer Counselor v. Citizens Tel. Corp., 681 N.E.2d
252, 255 (Ind. Ct. App. 1997). This subject is “within the Commission’s special
competence,” and “courts should give it greater deference.” Duke Energy
Indiana, Inc. v. Office of Util. Consumer Counselor, 983 N.E.2d 160, 170 (Ind. Ct.
App. 2012). Although we have significant concerns over the allegedly
inconsistent treatment of this subject by the Commission, in light of the
deference owed to the Commission, we cannot say that its methodology is
erroneous given the lack of specificity in the statutes regarding this calculation.
IV. Rate Allocation Factors
[39] The OUCC next argues that the Commission erred in calculating the rate
allocation factors to be applied here. NIPSCO charges different rates to
different customer classes based on the cost to serve each customer class. For
example, Rates 610, 611, and 612 govern residential customers, while Rates
632, 633, and 634 govern industrial customers. Some customers receive “firm
load,” which is basically the amount of electricity that is guaranteed by the
utility; while some customers also receive “non-firm load” (also known as
“interruptible load”), which is electrical service that can be interrupted. See
NIPSCO’s Appellee’s Br. p. 9.
[40] Another issue here is whether the customer is a distribution or transmission
customer. Transmission is the transfer of electric energy from its sources of
generation across high-voltage lines to either a local distributor, a substation, or
a large-scale industrial customer. See id. at 77. Distribution involves the
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transfer of electric energy through a retail delivery system to smaller-scale
industrial, commercial, and residential customers. See id.[41] In NIPSCO’s most recent retail base rate case order in December 2011 in Cause
No. 43969, the revenue allocation factors were based on a settlement
agreement, not a typical cost-of-service study. When the parties reached the
settlement in Cause No. 43969, one of the most contentious issues was the rate
allocation. See In Re Petition of NIPSCO to Modify its Rates, Cause No. 43969,
2011 WL 6837714 (Ind. U.R.C. Dec. 21, 2011). Basically, the Order allowed
NIPSCO to move all customers to “firm” rates. Id. (allowing NIPSCO to
“migrat[e] customers from special contracts to firm service”). Industrial
customers were then allowed a credit for interruptible, or “non-firm,” usage
through Rider 675. Id. The Commission noted in Cause No. 43969 that
“revenue allocation and Rider 675 were interrelated and reflected difficult and
painstaking negotiations to reach a balanced outcome and resolution which was
acceptable to the Settling Parties.” Id. The Commission gave “substantial
weight to the Settling Parties’ agreement with respect to revenue allocation.”
Id.[42] The allocation factors are again an issue in this litigation. The TDSIC statute
requires the petition to “use the customer class revenue allocation factor based
on firm load approved in the public utility’s most recent retail base rate case
order.” I.C. § 8-1-39-9(a). Rather than use the allocation factors reached in the
December 2011 settlement agreement, NIPSCO sought to adjust the revenue
allocation factors from the settlement agreement because it claimed that those
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allocation factors: (1) included non-firm load; and (2) included distribution
costs for customers that only used transmission facilities. See Petitioner’s Exh.
DJI-1, Exh. 2, Schedule 4; Tr. pp. 923-24. NIPSCO’s proposed allocation
factors are favorable to large industrial customers and unfavorable to residential
customers. See Tr. p. 1308.
[43] The Commission agreed with NIPSCO and found the following with respect to
the rate allocation factors:
Petitioner is requesting approval to use modified versions of its
customer class revenue allocation factor based on firm load that was
approved as Joint Exhibit C to the settlement agreement approved in
the 43969 Order. Mr. Shambo testified that for transmission costs the
revenue allocation factor should be adjusted for Rider 675 interruptible
credit in order to remove the non-firm portion of revenues from Rates
632 and 634. Mr. Shambo noted that for distribution costs the revenue
allocation factor from Joint Exhibit C should be adjusted to exclude
revenue from Rates 632, 633, and 634, which are transmission and
sub-transmission rates.
OUCC witness Mr. Hand argued that NIPSCO’s request to apply
adjusted customer class allocation factors should be denied and they
should be required to apply the customer class revenue allocators from
the 43969 Order.
The 43969 Order allocated revenue to customer classes based on a
settlement agreement rather than a cost of service study. A cost of
service study would have included separate allocation factors for
distribution and transmission. However, the 43969 Order includes all
costs in one factor. Further, the approved customer class revenue
allocation factors included non-firm load, which was effectively
adjusted out of the revenue allocation in a subsequent ratemaking step.
Ind. Code § 8-1-39-9(a) requires NIPSCO to use the customer class
revenue allocation factor based on firm load developed in the most
recent base rate case. The evidence shows that many of the same
customers currently taking interruptible service under Rider 675 were
interruptible prior to the date the 43969 Order was issued. However,
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the evidence shows that pursuant to the 43969 Order, NIPSCO’s old
interruptible rates were terminated and replaced by the new firm rates
plus an interruptible Rider 675 which established a different method to
designate load as non-firm or interruptible. Thus, in order for the Joint
Exhibit C allocation factors to properly reflect the customer class
revenue allocation factors based on firm load, they must be adjusted to
reasonably reflect non-firm load that was treated as firm under the
construct of the settlement agreement as approved in the 43969 Order.
Based on our review of the TDSIC statute and the evidence in this
Cause, we find that NIPSCO’s proposal that the revenue allocation
factor be adjusted for the Rider 675 interruptible credit in order to
remove the non-firm portion of the revenues from Rates 632 and 634 is
consistent with Ind. Code § 8-1-39-9(a)(1) and should be approved.
Further, NIPSCO’s proposal to exclude Rates 632, 633 and 634 is a
reasonable method to accomplish the alignment of the cost causation
with cost allocation, under the evidence specific conditions presented
in this proceeding together with the 43969 Order, for the purpose of
allocating distribution costs in a manner that comports with Ind. Code
§ 8-1-39-9(a)(1). We find it is appropriate to adjust the 43969 Order
approved Joint Exhibit C allocation factors by removing Rates 632,
633 and 634 from the calculation for purposes of allocating
distribution-related TDSIC costs so that rate classes that do not use the
distribution system are not allocated distribution costs.
OUCC App. pp. 24-25.
[44] On appeal, the OUCC argues that the Commission’s order is erroneous because
it failed to use the allocation factors approved in the last rate case as required by
Indiana Code Section 8-1-39-9(a). The OUCC also argues that it would be bad
public policy to allow the parties to engage in protracted negotiations to
establish the rate allocation factors and then allow NIPSCO to immediately
argue that it is not bound by the settlement. NIPSCO argues that the allocation
factors in the last rate case were established by a settlement agreement, not
through a cost-of-service study, and that, if the allocation factors has been
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established through a cost-of-service study, the large industrial customers would
have been allocated only transmission costs, not distribution costs. NIPSCO
also argues that the statute required it to use allocation factors based on firm
load and that the allocation factors established by the settlement agreement
included non-firm load. Consequently, according to NIPSCO, the allocation
factors had to be adjusted. NIPSCO contends that “[a]ll [it] did was to adjust
these allocation factors to square them with traditional ratemaking principles,
which are based on simple fairness.” NIPSCO’s Appellee’s Br. p. 78.
[45] The Commission also briefly addresses this issue in its Appellee’s Brief. The
Commission only addresses the non-firm adjustment and does not mention the
transmission/distribution adjustment. According to the Commission, the
statute requires only allocation factors based on firm load and it was reasonable
to allow NIPSCO to make the adjustments.
[46] The Industrial Group also filed an appellee’s brief responding to the allocation
factor argument. The Industrial Group supports the allocation factors
advocated by NIPSCO. In its reply brief, the OUCC argues that the evidence
does not support the Commission’s finding that the settlement agreement’s
allocation factors included non-firm load.
[47] At the hearing before the Commission, Frank Shambo, vice president of
regulatory and legislative affairs for NIPSCO, testified that “NIPSCO proposes
that the customer class revenue allocation factor be adjusted for the Rider 675
interruptible credit in order to remove the non-firm portion of revenues from
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Rates 632 and 634.” Tr. pp. 956, 1017. Shambo also testified: “For distribution
TDSIC costs, NIPSCO proposes that the customer class revenue allocation
factor be adjusted to exclude revenues from Rates 632, 633 and 634 which are
transmission and subtransmission service rates.” Id. at 1017; see also id. at 956.
OUCC witness Eric Hand testified that the proposed allocation factors did not
match the factors approved in the settlement agreement and that allowing
NIPSCO to make the proposed adjustments to the allocation factors would
undercut the settlement agreement. Although the OUCC argues that non-firm
load was not included in the settlement agreement’s allocation factors, it seems
clear that non-firm load was included and that a credit was given to the
customers using non-firm load.
[48] In support of its argument, NIPSCO relies on Citizens Action Coalition of Indiana,
Inc. v. NIPSCO, 804 N.E.2d 289 (Ind. Ct. App. 2004). In Citizens Action
Coalition, NIPSCO sought to increase rates to implement pollution control
equipment. A regulation required: “A utility’s jurisdictional revenue
requirement that results from the ratemaking treatment of qualified pollution
control property under construction under this rule shall be allocated among the
utility’s customer classes in accordance with the allocation parameters established by the
commission in the utility’s last general rate case.” 170 IAC 4-6-15 (emphasis added).
Despite the regulation’s requirement that the allocations used in the utility’s last
general rate case be utilized, NIPSCO sought to use an allocation methodology
from a later cost study. The Commission allowed NIPSCO to do so, and on
appeal, we affirmed.
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[49] NIPSCO argued that “the purpose of the rule requiring that allocation among
customer classes be governed by the utility’s last general rate case is to allow
utilities to avoid the necessity of preparing a costly cost of service study every
time they seek authorization for QPCP investments.” Citizens Action Coalition,
804 N.E.2d at 303. “It argue[d] that the rule is not intended to preclude use of
newer and more accurate studies in situations where they have already been
prepared for other reasons.” Id. We concluded that, given the evidence of the
benefits of using the more recent study, the Commission’s decision was not
erroneous. Id. at 304. We noted that “[e]nforcing strict compliance with 170
IAC 4-6-15 by requiring the Commission to use the 1987 study would produce
the illogical result of having NIPSCO allocate costs based on outdated data
when a more recent study is available.” Id. Emphasizing “our preference to
place substance over form,” we could not conclude that the Commission erred
by using the later study rather than the allocations from the last general rate
case. Id.[50] We reach a similar conclusion here. The TDSIC statute requires the use of “the
customer class revenue allocation factor based on firm load approved in the
public utility’s most recent retail base rate case order.” I.C. § 8-1-39-9(a). The
allocation factors from the December 2011 settlement agreement were based on
both firm and non-firm load. Consequently, the adjustment to remove the non-
firm load portion was within the Commission’s discretion and expertise.
[51] The statute, however, did not require an adjustment for transmission versus
distribution considerations. The adjustment of the allocation factors to account
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for differences between transmission and distribution customers would conflict
with the clear language of the statute, which requires the use of the allocation
factors approved in the December 2011 settlement agreement. We recognize
that the Commission has “the technical expertise to administer regulatory
schemes devised by the legislature.” Indiana Office of Util. Consumer Counselor v.
Lincoln Utilities, Inc., 834 N.E.2d 137, 145 (Ind. Ct. App. 2005), trans. denied.
“We also give great deference to the [Commission’s] rate-making
methodology.” Id. However, the Commission’s “authority is limited to that
which is granted to it by statute.” Id. at 142. We conclude that the
Commission exceeded its statutory authority by allowing the adjustment of the
allocation factors based on transmission and distribution considerations.
Conclusion
[52] We conclude that the Commission improperly approved NIPSCO’s seven-year
plan under the TDSIC statute because it lacked detail regarding the proposed
projects for years two through seven. We also conclude that the Commission
improperly established a presumption of eligibility for the projects in years two
through seven. However, we conclude that the Commission properly
interpreted the two-percent cap language in the TDSIC statute, and we give
deference to the Commission’s decision regarding the rate recovery of retired
assets. Finally, we conclude that the Commission was within its discretion to
adjust the rate allocation factors to remove non-firm load; however, the
Commission exceeded its statutory authority when it adjusted the allocation
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factors based on transmission and distribution considerations. We affirm in
part, reverse in part, and remand.
[53] Affirmed in part, reversed in part, and remanded.
May, J., and Pyle, J., concur.
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