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.
 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 (“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
 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.
 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.
 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.
 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).
 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 transmission, distribution, or storage projects. The new statute is referred to as the “TDSIC” statute.
 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.
 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.
 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 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.
 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.
 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 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.
 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 Cop., 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.
 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 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.
 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 is clear and unambiguous on its face; rather, we will give such a statute its apparent and obvious meaning. Id.
I. Plan Sufficiency
 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.
 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.
 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 not acknowledge that unforeseen events and changes in circumstances do occur and may require changes to the 7–Year Plan.
Id. at 22.
 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.
 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.
 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.”
 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 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.
 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. 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.
 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.
II. Statutory Cap
 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.
 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.
 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:
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.
 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 Association argues that the Industrial Group's interpretation would “cripple the TDSIC statute.” Indiana Energy Association's Br. p. 3.
 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
 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.
 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 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.
 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 double recovery is not in the public interest or consistent with fundamental ratemaking principles.
The statutory definition of eligible improvements at Ind.Code § 8–139–2 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.
 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, 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. § 8–139–13.
 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.”
 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 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.
 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 exceeds the return on investment currently included in its base rates and charges for the original catalyst layer.” Id.
 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.
 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.
 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 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
 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.
 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 transfer of electric energy through a retail delivery system to smaller-scale industrial, commercial, and residential customers. See id.
 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.
 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 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.
 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, 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.
 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 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.
 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.
 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.
 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 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.
 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.
 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.
 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.
 The statute, however, did not require an adjustment for transmission versus distribution considerations. The adjustment of the allocation factors to account 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.
 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 factors based on transmission and distribution considerations. part, reverse in part, and remand.
 Affirmed in part, reversed in part, and remanded.
1. We held oral argument on this matter on February 26, 2015. We commend counsel for their presentations.
MAY, J., and PYLE, J., concur.