Court of Appeals of Indiana | Opinion 93A02-1403-EX-158 |April 8, 2015 Page 1 of 31

ATTORNEYS FOR APPELLANT,

NIPSCO INDUSTRIAL GROUP

Todd A. Richardson

Bette J. Dodd

Jennifer W. Terry

Joseph P. Rompala

Lewis & Kappes, P.C.

Indianapolis, Indiana

ATTORNEYS FOR APPELLANT,

INDIANA OFFICE OF UTILITY 

CONSUMER COUNSELOR

A. David Stippler

Randall C. Helman

Lorraine Hitz-Bradley

Jeffrey Reed

Indianapolis, Indiana

ATTORNEYS FOR AMICUS CURIAE,

INDIANA ENERGY ASSOCIATION

Wayne C. Turner

Patrick Z. Ziepolt

Bingham Greenebaum Doll, LLP

Indianapolis, Indiana

ATTORNEYS FOR APPELLEE,

INDIANA UTILITY REGULATORY 

COMMISSION

David Lee Steiner

Deputy Attorney General

Office of the Indiana Attorney General

Indianapolis, Indiana

Beth Krogel Roads

Andrew J. Wells

Indiana Utility Regulatory Commission

Indianapolis, Indiana

ATTORNEYS FOR NORTHERN 

INDIANA PUBLIC SERVICE 

COMPANY

Brian J. Paul

Kay E. Pashos

Kelly S. Earls

Ice Miller, LLP

Indianapolis, Indiana

Claudia J. Earls

Erin Casper Borissov

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 2 of 31

I N T H E

COURT OF APPEALS OF INDIANA

NIPSCO Industrial Group, and,

Indiana Office of Utility 

Consumer Counselor,

Appellants-Intervenor and Statutory 

Party below,

v.

Northern Indiana Public Service 

Company, et al.,

Appellees-Petitioner and Parties below.

April 8, 2015

Court of Appeals Cause No.

93A02-1403-EX-158

Appeal from the Indiana Utility 

Regulatory Commission

Cause No. 44370 & 44371

The Honorable James D. Atterholt, 

Chairman; The Honorable Carolene 

R. Mays; The Honorable David E. 

Ziegner, Commissioners

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 sevenyear 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 sevenyear 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, 
Court of Appeals of Indiana | Opinion 93A02-1403-EX-158 |April 8, 2015 Page 20 of 31

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 nonfirm 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.