state of indiana indiana utility regulatory …€¦ · earthjustice 48 wall street, 15th floor new...
TRANSCRIPT
STATE OF INDIANA INDIANA UTILITY REGULATORY COMMISSION
PETITION OF NORTHERN INDIANA PUBLIC SERVICE COMPANY LLC PURSUANT TO IND. CODE §§ 8-1-2-42.7, 8-1-2-61 AND, IND. CODE § 8-1-2.5-6 FOR (1) AUTHORITY TO MODIFY ITS RATES AND CHARGES FOR ELECTRIC UTILITY SERVICE THROUGH A PHASE IN OF RATES; (2) APPROVAL OF NEW SCHEDULES OF RATES AND CHARGES, GENERAL RULES AND REGULATIONS, AND RIDERS; (3) APPROVAL OF REVISED COMMON AND ELECTRIC DEPRECIATION RATES APPLICABLE TO ITS ELECTRIC PLANT IN SERVICE; (4) APPROVAL OF NECESSARY AND APPROPRIATE ACCOUNTING RELIEF; AND (5) APPROVAL OF A NEW SERVICE STRUCTURE FOR INDUSTRIAL RATES.
) ) ) ) ) ) ) ) ) ) ) ) ) ) ) )
CAUSE NO. 45159
SUBMISSION OF JOINT PROPOSED ORDER BY INTERVENORS
INDIANA COAL COUNCIL, INC., INDIANA COALITION FOR AFFORDABLE AND RELIABLE ELECTRICITY,
AND PEABODY COALSALES, LLC
Intervenors Indiana Coal Council, Inc., Indiana Coalition for Affordable and
Reliable Electricity, and Peabody COALSALES, LLC jointly submit the attached
proposed order.
2
Respectfully submitted,
FROST BROWN TODD LLC By: Robert L. Hartley, #7563-49
Carly J. Tebelman, #34796-49 201 N. Illinois St., Suite 1900 P.O. Box 44961 Indianapolis, IN 46244-0961 317-237-3800 Fax: 317-237-3900 [email protected] [email protected]
3
CERTIFICATE OF SERVICE
Service of the foregoing was made on August 27, 2019 by electronic
transmission to:
NIPSCO Claudia J. Earls NiSource Corporate Services - Legal 150 West Market Street, Suite 600 Indianapolis, Indiana 46204 [email protected] Nicholas K. Kile BARNES & THORNBURG LLP 11 South Meridian Street Indianapolis, Indiana 46204 [email protected] Michael Hooper Erin E. Whitehead Northern Ind. Public Service Co. LLC 150 West Market Street, Suite 600 Indianapolis, Indiana 46204 [email protected] [email protected]
CITIZENS ACTION COALITION Jennifer A. Washburn Margo L. Tucker CITIZENS ACTION COALITION 1915 West 18th Street, Suite C Indianapolis, Indiana 46202 [email protected] [email protected] Raghu Murthy, Atty. No. 6633-95-Ta EARTHJUSTICE 48 Wall Street, 15th Floor New York, Ny 10005 [email protected] Cassandra Mccrae, Atty. No. 6607-95-Ta EARTHJUSTICE 1617 John F. Kennedy Blvd., Suite 1130 Philadelphia, Pa 19103 [email protected] Thomas Cmar EARTHJUSTICE 1101 Lake Street, Suite 405B Oak Park, IL 60301 [email protected]
INDIANA MUNICIPAL UTILITY GROUP Robert M. Glennon Robert Glennon & Assoc., P.C. 3697 N. Co. Rd. 500 E Danville, Indiana 46122 [email protected]
UNITED STEELWORKERS Anthony Alfano 1301 Texas St., 2"d Floor Gary, IN 46402 [email protected]
4
BOARD OF COMMISSIONERS OF LAPORTE COUNTY Shaw R. Friedman Friedman & Associates, P.C. 705 Lincolnway LaPorte, IN 46350 (219) 326-1264 [email protected] Keith L. Beall Beall & Beall 13238 Snow Owl Dr., Ste. A Carmel, IN 46033 (317) 810-9357 [email protected]
SIERRA CLUB Kathryn A. Watson Cantrell Strenski & Mehringer, LLP 150 West Market Street, Suite 800 Indianapolis, Indiana 46204 [email protected] Casey Roberts 1536 Wynkoop Street, Suite 312 Denver CO, 80202 [email protected] Tony Mendoza 2101 Webster St., 13th Floor Oakland, CA 94612 [email protected]
US STEEL Nikki G. Shoultz Kristina Kern Wheeler Jeffery A. Earl Bose McKinney & Evans LLP 111 Monument Circle, Suite 2700 Indianapolis, Indiana 46204 [email protected] [email protected] [email protected]
NIPSCO INDUSTRIAL GROUP Bette J. Dodd Todd A. Richardson Joseph P. Rompala Lewis & Kappes, P.C. One American Square, Suite 2500 Indianapolis, Indiana 46282 [email protected] [email protected] [email protected]
NLMK INDIANA Anne E. Becker Lewis & Kappes, P.C. One American Square, Suite 2500 Indianapolis, Indiana 46282 [email protected] James W. Brew Stone Mattheis Xenopoulos & Brew 1025 Thomas Jefferson St., NW, 9th Floor, West, Tower, Washington, DC 20007 [email protected]
WALMART Eric E. Kinder Spilman Thomas & Battle, PLLC 300 Kanawha Boulevard, East P.O. Box 273 Charleston, West Virginia 25321 [email protected] Barry A. Naum Spilman Thomas & Battle, PLLC 1100 Bent Creek Boulevard, Suite 101 Mechanicsburg, Pennsylvania 17050 [email protected]
5
PEABODY COALSALES, LLC Joshua A. Claybourn Chad Sullivan JACKSON KELLY PLLC 221 NW Fifth Street P.O Box 1507 Evansville, Indiana 47706 [email protected] [email protected]
ICARE Meghan E. Griffiths Jennifer A. Ferri Jackson Walker LLP 100 Congress Ave., Suite 1100 Austin, Texas 78701 [email protected] [email protected]
MODERN FORGE INDIANA, LLC Alan M. Hux Taft Stettinius & Hollister, LLP One Indiana Square, Suite 3500 Indianapolis, IN 46204 [email protected]
DENNIS RACKERS Dennis Rackers 275 E. 125th Pl Crown Point, IN 46307 [email protected]
NORTHERN INDIANA COMMUTER TRANSPORTATION DISTRICT James A.L. Buddenbaum Aleasha J. Boling Parr Richey Frandsen Patterson Kruse LLP 251 N. Illinois Street, Suite 1800 Indianapolis, IN 46204 [email protected] [email protected] L. Charles Lukmann, III, Att'y No.: 9903-64 Connor H. Nolan, Att’y No.: 32707-64 Harris Welsh & Lukmann 107 Broadway Chesterton, IN 46304 [email protected] [email protected]
OUCC William Fine Jeffrey M. Reed Randall C. Helmen Office of Utility Consumer Counselor 115 W. Washington Street Suite 1500 South Indianapolis, Indiana 46204 [email protected] [email protected] [email protected] [email protected]
Robert L. Hartley
STATE OF INDIANA INDIANA UTILITY REGULATORY COMMISSION
PETITION OF NORTHERN INDIANA PUBLIC SERVICE COMPANY LLC PURSUANT TO IND. CODE §§ 8-1-2-42.7, 8-1-2-61 AND, IND. CODE § 8-1-2.5-6 FOR (1) AUTHORITY TO MODIFY ITS RATES AND CHARGES FOR ELECTRIC UTILITY SERVICE THROUGH A PHASE IN OF RATES; (2) APPROVAL OF NEW SCHEDULES OF RATES AND CHARGES, GENERAL RULES AND REGULATIONS, AND RIDERS; (3) APPROVAL OF REVISED COMMON AND ELECTRIC DEPRECIATION RATES APPLICABLE TO ITS ELECTRIC PLANT IN SERVICE; (4) APPROVAL OF NECESSARY AND APPROPRIATE ACCOUNTING RELIEF; AND (5) APPROVAL OF A NEW SERVICE STRUCTURE FOR INDUSTRIAL RATES.
) ) ) ) ) ) ) ) ) ) ) ) ) ) )
CAUSE NO. 45159
APPROVED:
ORDER OF THE COMMISSION
Presiding Officers: David E. Ziegner, Commissioner Stefanie N. Krevda, Commissioner Brad J. Pope, Administrative Law Judge
On October 31, 2018, Northern Indiana Public Service Company LLC (“NIPSCO,” “Petitioner,” or “Company”) filed its Verified Petition initiating this matter. On October 31, 2018, Petitioner also filed its case-in-chief, workpapers, administrative notice documents and information required by the Minimum Standard Filing Requirements (“MSFRs”) set forth in 170 IAC 1-5-1.
Petitions to intervene were granted to the following parties, without objection: NIPSCO, Industrial Group, NLMK Indiana, US Steel, CAC, Walmart, NICTD, Sierra Club and the OUCC
Citizens Action Coalition of Indiana, Inc. (“CAC”) Indiana Coal Council, Inc. (“ICC”) Indiana Coalition for Affordable and Reliable Electricity (“ICARE”) Indiana Municipal Utility Group (“IMUG”)1 Board of Commissioners of Laporte County, Indiana (“LaPorte”) Modern Forge Indiana, LLC
1 The companies that comprise IMUG are Town of Highland, Town of Schererville, Town of Munster, Town of
Dyer, Town of Griffith, Town of Winfield, City of East Chicago, and City of Valparaiso.
2
NIPSCO Industrial Group (“Industrial Group”)2 NLMK Indiana (“NLMK”) Northern Indiana Commuter Transportation District (“NICTD”) Peabody COALSALES, LLC (“Peabody”) Dennis Rackers (“Rackers”) Sierra Club Walmart Inc. (“Walmart”) United States Steel Corporation (“US Steel”) United Steel, Paper and Forestry, Rubber, Manufacturing, Energy,
Allied Industrial Service Workers International Union AFL-CIO/CLC and its Locals 12775 and 13796
By docket entry dated November 21, 2018, the Commission established a procedural schedule in this matter.3 On February 13, 2019, the Indiana Office of Utility Consumer Counselor (“OUCC”) and Intervenors filed their respective cases-in-chief. The Commission conducted a public field hearing on March 11, 2019 at Hammond High School Auditorium. At the field hearing, members of the public were afforded an opportunity to make statements to the Commission.
On March 15, 2019, NIPSCO filed its rebuttal testimony and exhibits.
Also on March 15, 2019, Intervenors CAC, ICARE, Sierra Club, NLMK Indiana, and Industrial Group filed cross-answering testimony and exhibits.
On April 9, 2019, the Presiding Officers directed NIPSCO and the OUCC to respond to requests for information, to which NIPSCO and the OUCC responded on April 11, 2019 and April 10, 2019, respectively.
On April 26, 2019, NIPSCO, Industrial Group, NLMK Indiana, US Steel, CAC, Walmart, NICTD, Sierra Club and the OUCC (the “Settling Parties”) filed a Stipulation and Settlement Agreement on Less than all the Issues resolving revenue requirements issues and other miscellaneous issues (the “Revenue Settlement”). On April 30, 2019, the Settling Parties filed a Status Update notifying the Commission that IMUG had joined the Revenue Settlement and provided an additional provision in the Revenue Settlement (Paragraph 11).4 The Settling Parties and IMUG are collectively referred to herein as the “Revenue Settling Parties.”
2 The companies that comprise the Industrial Group are Accurate Castings, Inc., Arcelor Mittal USA, BP
Products North America, Inc., Cargill, Inc., Enbridge Energy, Praxair, Inc., and USG Corporation. 3 The procedural schedule was modified by Docket Entries dated January 29, 2019, April 11, 2019, April 24,
2019, May 1, 2019, May 10, 2019, and May 31, 2019. 4 IMUG filed a Formal Notice of Indiana Municipal Utility Group Joinder in Amended Partial Settlement
Agreement on May 15, 2019.
3
On May 17, 2019 NIPSCO, OUCC and Industrial Group filed testimony and exhibits in support of the Revenue Settlement, and Sierra Club filed a Notice of Support for the Revenue Settlement.
On May 17, 2019, NIPSCO, Industrial Group, NLMK Indiana, and US Steel (the “Rate 831 Settling Parties”) filed a Stipulation and Settlement Agreement on Rate 831 Implementation (the “Rate 831 Settlement”).5 Also on May 17, 2019, NIPSCO, Industrial Group, and US Steele filed testimony and exhibits supporting the Rate 831 Settlement.
On June 7, 2019, ICC, ICARE, and LaPorte filed testimony and exhibits in opposition to the Revenue Settlement. ICC and ICARE also filed motions for administrative notice, which were granted by Docket Entries dated June 20, 2019.
On June 17, 2019, OUCC and CAC filed testimony and exhibits in opposition to the Rate 831 Settlement, and Sierra Club joined in the OUCC’s and CAC’s responsive testimony.
On June 20, 2019, NIPSCO filed testimony and exhibits in reply to Revenue Settlement responsive testimony.
On June 27, 2019, NIPSCO filed testimony and exhibits in reply to Rate 831 Settlement responsive testimony.
On July 17, 2019, the Presiding Officers directed Walmart and LaPorte to respond to requests for information, to which Walmart and LaPorte responded on July 17, 2019.
On July 16, 2019, Rackers filed a Motion for Administrative Notice. NIPSCO filed its objection to the Motion on July 17, 2019. Rackers filed his reply to NIPSCO’s objection on July 22, 2019. The Commission denied the motion by Docket Entry dated August 1, 2019.
On July 24, 2019, Rackers filed a Second Motion for Administrative Notice. NIPSCO filed its objection to the Motion on July 24, 2019. The Commission denied the motion by Docket Entry dated August 1, 2019.
Pursuant to notice given and published as required by law, the Commission conducted an evidentiary hearing in Room 222 beginning at 9:30 a.m. on July 25, 2019 and continuing through August 5, 2019. All parties presented their evidence and offered their witnesses for cross-examination.
5 The Rate 831 Settling Parties filed a revision to the Rate 831 Settlement on June 7, 2019.
4
The Commission, based upon the applicable law and evidence presented, now finds:
1. Notice and Jurisdiction.Notice of the filing of the Petition in this Cause was given and published by NIPSCO as required by law. Notice was given by NIPSCO to its customers summarizing the nature and extent of the proposed changes in its rates and charges for electric service. Notices of the public hearings in this Cause were given and published as required by law. NIPSCO is a public utility as defined in Ind. Code § 8-1-2-1. NIPSCO is also an energy utility as defined in Ind. Code § 8-1-2.5-2 and provides “retail energy service” as that term is defined by Ind. Code § 8-1-2.5-3. NIPSCO is also a utility within the meaning of Ind. Code § 8-1-2-42.7(c). NIPSCO is also subject to the jurisdiction of the Federal Energy Regulatory Commission (“FERC”). Pursuant to Ind. Code §§ 8-1-2-42 and 42.7, the Commission has jurisdiction over NIPSCO’s rates and charges for utility service. Therefore, the Commission has jurisdiction over NIPSCO and the subject matter of this proceeding.
2. Petitioner’s Characteristics.NIPSCO is a public utility with its principal office and place of business at 801 East 86th Avenue, Merrillville, Indiana and provides gas and electric service (“NIPSCO Electric”) in Indiana. NIPSCO is authorized by the Commission to provide electric utility service to the public in all or part of Benton, Carroll, DeKalb, Elkhart, Fulton, Jasper, Kosciusko, LaGrange, Lake, LaPorte, Marshall, Newton, Noble, Porter, Pulaski, Saint Joseph, Starke, Steuben, Warren and White Counties in northern Indiana.
3. Existing Rates.NIPSCO’s current electric basic rates and charges were approved in the Commission’s July 18, 2016 Order in Cause No. 44688 (the “44688 Rate Case Order”), wherein the Commission approved a Stipulation and Settlement Agreement between NIPSCO and the majority of the intervenors (the “44688 Rate Case”).6 Those new basic rates and charges went into effect on September 29, 2016. The 44688 Rate Case Order approved, among other items, an increase in NIPSCO’s basic rates and charges. In addition, on May 1, 2018, NIPSCO’s basic rates were modified to reflect the reduction in the federal income tax rate from 35 percent to 21 percent as approved in the Tax Cut and Jobs Act of 2017 (“TCJA”) pursuant to the Commission’s January 3, 2018 Order in Cause No. 45032.7
NIPSCO’s petition initiating Cause No. 44688 was filed with the Commission on October 1, 2015. Therefore, in accordance with Ind. Code § 8-1-2-42(a), more than fifteen months have passed since the filing date of NIPSCO’s most recent request for a general increase in its basic rates and charges.
6 The Stipulation and Settlement Agreement was entered into as of the 19th day of February, 2016, by and
between NIPSCO, the OUCC, IMUG, Industrial Group, NLMK, US Steel and United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, AFL-CIO/CLC.
7 The Commission approved NIPSCO’s 30-Day Filing No. 50167 on April 25, 2018.
5
4. Relief Requested.NIPSCO’s Petition requests approval of the following:
A. Electric Service Tariff and Standard Contract.NIPSCO seeks approval of changes to its basic rates and charges for electric utility service that will provide NIPSCO with the opportunity to earn a fair return on the fair value of its property. NIPSCO seeks approval of changes to its Electric Service Tariff, including the elimination of Riders 772 and 775, changing the series number of its rate schedules to Series 800, and miscellaneous changes to its General Rules and Regulations and Standard Contract, as proposed in its evidence to be presented in this proceeding. The overall structure of NIPSCO’s tariffs remains the same for residential and commercial customers (except for a proposed increase in fixed recovery by increasing customer charges), but NIPSCO is proposing a new service structure for its industrial customers currently taking service under Rates 732, 733, and 734.
(b) NIPSCO requests that the Commission approve NIPSCO’s proposal for a new industrial service structure as an alternative regulatory plan pursuant to Ind. Code § 8-1-2.5-6. To the extent any other proposals of NIPSCO herein may require alternative regulation, NIPSCO requests that they be approved as an alternative regulatory plan. NIPSCO elects to become subject to the provisions of Ind. Code § 8-1-2.5-6 for purposes of any such proposals herein. NIPSCO requests that its proposed industrial service structure be found to be in the public interest pursuant to Ind. Code § 8-1-2.5-6.
B. Depreciation Rates.
NIPSCO seeks approval to revise its depreciation accrual rates.
C. Previously approved Environmental Compliance Projects and Federally Mandated Compliance Projects Depreciation Rates.
NIPSCO has been recognizing for ratemaking purposes the cost of previously approved qualified pollution control property, clean coal technology, and clean energy projects (collectively “Environmental Compliance Projects”) and Federally Mandated Compliance Projects and associated operating expense through its ECRM and FMCA. NIPSCO proposes to reflect in its basic rates and charges the capital costs and operating expenses associated with Environmental Compliance Projects and Federally Mandated Compliance Projects previously approved by the Commission in Cause Nos. 42150, 44012, 44311, 44340, 44872 and 44889 that were or are projected to be completed and in service at the end of the forward test year (December 31, 2019) and that are currently being recovered through the ECRM and FMCA. Since all of the Environmental Compliance Projects are or will be in-service and thus rolled into rate base in this case, NIPSCO is proposing to discontinue the ECRM. When new tariff sheets are filed based upon the final order in this proceeding, NIPSCO proposes to adjust, as applicable, its then current FMCA
6
adjustment factors to reflect the removal of the in-service plant and related expenses as of the same effective date, and modify its allocation factors consistent with the Commission’s final order, subject to any necessary variance reconciliations in the ongoing FMCA proceedings.
D. Accounting Relief.
As explained in NIPSCO’s case-in-chief, NIPSCO seeks accounting authority to defer, as a regulatory asset, discounts offered to certain customers under its Economic Development Rider (“EDR”) for recovery in a future rate case; authority to defer, as a regulatory liability, an amount equal to 100% of (1) annual off-system sales (“OSS”) margins net of expenses and (2) back up and maintenance demand margins, both for pass back through the RTO Tracker; and authority to defer the remaining net book value of coal generation assets as a regulatory asset within rate base after the assets are retired.
E. DSM.
NIPSCO proposes to exclude from its basic rates and charges all costs associated with its demand-side management (“DSM”) program. In addition, NIPSCO has adjusted its usage determinants for energy efficiency measures installed through December 31, 2017, consistent with Evaluation, Measurement and Verification. NIPSCO has also adjusted its usage upward for energy efficiency measures installed between January 1, 2018 and December 31, 2019. NIPSCO proposes to reset lost margins in its DSM tracker filing upon new, effective base rates in this proceeding to eliminate lost margins attributable to all energy efficiency measures installed prior to December 31, 2017. Ultimately, NIPSCO is seeking a neutral transition to lost margin recovery between the filing of this rate case and the operation of its DSM tracker filing.
F. RTO Tracker and OSS Margin Sharing.
NIPSCO proposes to update Rider 771 – Adjustments of Charges for Regional Transmission Organization to (i) remove Midcontinent Independent System Operator, Inc. (“MISO”) charges and credits and collect 100% of MISO charges that are not included in the FAC through the RTO; (ii) remove positive or negative OSS margins currently included in base rates and flow back 100% of any margins net of expenses through the RTO; (iii) remove all back-up and maintenance margins currently included in base rates and pass back 100% of such margins net of expenses through the RTO Tracker; and change the allocation methodology.
G. Environmental Cost Recovery Mechanism.
NIPSCO proposes to discontinue its Rider 772 – Adjustment of Charges for Environmental Cost Recovery Mechanism and Appendix D – Environmental Cost Recovery Mechanism Factor (the “ECR Mechanism”).
7
H. Regulatory Assets.
NIPSCO proposes to recover through its revenue requirement certain costs NIPSCO has deferred in accordance with the Commission’s orders identified in NIPSCO’s case-in-chief.
I. Prepaid Pension Asset.
NIPSCO’s pension plan is currently in a net prepaid pension asset position, which is the net of the related pension obligation and regulatory asset in accordance with governing accounting standards. This prepaid pension asset reduces the pension cost that would otherwise be reflected in the revenue requirement and preserves the integrity of the pension fund. NIPSCO proposes that its rates reflect this asset as part of its capital structure.
5. Test Year and Rate Base Cutoff.NIPSCO proposed a forward-looking test period using projected data as authorized by Ind. Code § 8-1-2-42.7(d)(1). In the docket entry setting the procedural schedule, the Commission found that the test year for determining NIPSCO’s projected operating revenues, expenses and operating income shall be the 12-month period ending December 31, 2019 (the “2019 Forward Test Year” or “Forward Test Year”). The historic base period shall be the 12-month period ending December 31, 2017 (the “2017 Historic Base Period” or “Historic Base Period”). The rate base cutoff shall reflect used and useful property at the end of the 2019 Forward Test Year.
[Below ICC, Peabody, and ICARE provide proposed summaries of the testimony of only their witnesses. They assume other parties will provide proposed summaries of the testimony of their witnesses. If ICC, Peabody, or ICARE take issue the proposed summaries of any other witnesses, they will raise them by exception filing.]
6. NIPSCO Case-in-Chief.
7. CAC Case-in-Chief
8. ICC Case-in-Chief
A. Emily S. Medine. Emily S. Medine, a Principal in the consulting firm of Energy Ventures Analysis, Inc., testified on behalf of intervenor Indiana Coal Council, Inc.
In her direct testimony Ms. Medine opposed NIPSCO’s proposed acceleration of depreciation for coal generation units because NIPSCO’s 2018 IRP—which NIPSCO claims indicates early retirement of its coal generating units—is too flawed to rely on. Ms. Medine also opposed NIPSCO’s request that the Commission now authorize post-retirement accounting treatment, as well as cost recovery and
8
return. She opined that request remains premature, especially in light of the fact that the report of the 21st Century Energy Policy Development Task Force is not due until December 1, 2020.
Ms. Medine testified that every utility should be required to minimize the costs associated with early retirement of any plant. Ms. Medine noted that for NIPSCO, the stranded costs it might seek to recover from customers upon early retirement of any existing coal plant could be significant and could include sums that NIPSCO only recently requested and received approval to spend.
Ms. Medine opined that NIPSCO should recognize that the longer its coal units remain in service, the lower the rate shock associated with their early retirement will be. In other words, she said, NIPSCO’s efforts should be less focused on resource replacement and more focused on cost-effective strategies to extend life. In the alternative, Ms. Medine opined, NIPSCO should actively be marketing this capacity to third parties. The marketing efforts should be conducted by an independent third party, most likely an investment banker, that has appropriate capabilities and experience. The sales efforts should consider an off-take agreement, i.e., a PPA, that would support a purchase for a limited time.
Ms. Medine testified that NIPSCO’s proposal to allow its largest industrial customers to opt into a new market access tariff and reduce or eliminate paying for generation assets built to serve their firm and interruptible loads will have significant adverse impacts on NIPSCO’s other customers. She said the change in NIPSCO industrial load that could result from such a new tariff was not modeled in NIPSCO’s Integrated Resource Plan (IRP). She said that NIPSCO has invested heavily in generation assets to serve the firm and interruptible loads of those large industrial customers. To the extent those customers are allocated less of the cost of those assets, NIPSCO will seek to recover those stranded costs from other customers (smaller industrial, commercial, and residential). She further opined that NIPSCO’s proposal for retail wheeling for large industrial customers raises statewide policy issues that are inappropriate for resolution in a rate case.
Ms. Medine recommended NIPSCO’s request for a new market access tariff for its largest industrial customers be denied without prejudice so that: (a) NIPSCO can perform truly integrated resource planning in its next IRP and include in its load forecasts for that planning the load changes that would result from its market access tariff proposal; (b) the Commission can include in its Statewide Analysis and annual reporting to the legislature the issues surrounding potential migration of load to market resources in lieu of local utility resources; (c) the issue of stranded cost allocation can be considered from a policy perspective on a statewide basis.
Ms. Medine further suggested that a better way to address cost concerns of large industrial customers without negatively impacting other customers might be to focus on controlling other costs. She pointed to the IURC mandated Key
9
Performance Indicators under Cause 44688 as showing several areas in which there is room for considerable improvement.
Ms. Medine also offered significant critique of NIPSCO’s 2018 IRP. Ms. Medine opined that NIPSCO’s 2018 IRP modeling—from which NIPSCO draws its assumed 2023 and 2028 dates for retirement of all of NIPSCO existing coal generation resources—suffers from numerous fatal flaws, including some of the same flaws as its 2016 modeling. Ms. Medine said a significant flaw is the using of hardwired retirement dates selected by NIPSCO rather than dates optimized by the model. Another flaw is the sequential rather than integrated retirement and replacement modelling and decision making.
Ms. Medine also testified that when performing its separate modeling of retirement decisions, NIPSCO biased the outcome in favor of early retirement by (i) assigning undue certainty its regulatory concerns, and (ii) assuming lower cost replacement portfolios that it has no intention of acquiring. She also testified that NIPSCO expended no effort in seeking to minimize the costs of the early retirement of the Schahfer units,
Ms. Medine also criticized other aspects of NIPSCO’s 2018 IRP on which NIPSCO bases its assumption that the depreciation schedules for its coal fired generation units need to be realigned with assumed 2023 and 2028 retirement dates. Ms. Medine opined that while NIPSCO endeavored to improve its IRP process since its 2016 IRP, the 2018 IRP contains significant problems (some of which the Director commented on in his 2016 report). She identified several claimed flaws in NIPSCO’s 2018 IRP, including: (i) poor construction of the scenarios which she said (a) did not properly evaluate the likely ranges of outcomes the IURC should consider before making any decisions, and (b) unfairly biased outcomes against continued operation of coal generation; (ii) failure to include a proper range of commodity price assumptions, particularly for coal and carbon; (iii) failure to include a proper range of regulatory assumptions; (iv) separating retirement analysis from replacement analysis; (v) not giving proper consideration to an offer to purchase Schahfer units 17 and 18; (vi) lack of consideration of customer rate impacts that will result from the premature retirements of its remaining coal fleet, accelerated depreciation of the remaining costs and the creation of a regulatory asset; and (vii) failure to consider ways to minimize stranded costs, including but not limited to, actively marketing the units for sale to third-parties.
Ms. Medine recommended that in connection with doing a truly integrated resource plan in its next IRP, NIPSCO should, as part of its retirement planning, solicit and meaningfully consider offers from third parties to purchase those assets in order to properly assess the costs of retirement. NIPSCO should not reject without due economic analysis purchase offers that may include proposals for NIPSCO to purchase capacity or energy from those units.
10
Finally, Ms. Medine recommended that NIPSCO be prohibited from including its non-tracked variable operating and maintenance costs in the calculation of its offer prices when bidding its units into the market. Ms. Medine noted that to the extent variable operating costs are not periodically adjusted in trackers, those costs are, by default, embedded in the utility’s base rate revenue requirement. Not periodically adjusting variable operating costs in trackers would thus incent utilities to control them. However, allowing utilities to include those costs when computing MISO offer prices—and thus increase their MISO offer price—may perversely incent utilities to control variable operating costs, not by the normal means of competitively sourcing materials and avoiding wasteful practices, but rather by reducing the amount generation. Ms. Medine also noted that coal units operate most efficiently, i.e., have lower (better) heat rates, when their capacity factors are higher. Higher MISO offer prices that depress unit dispatch would suppress coal burn resulting in higher (poorer) heat rates. In addition, such an approach to operations increases wear and tear on the units increasing other operating and maintenance costs as well.
9. ICARE Case-in-Chief
A. Charles S. Griffey. Charles S. Griffey, a consultant providing services to the electric and natural gas industries, testified regarding NIPSCO’s decision to retire the Schahfer coal units in 2023 and the Michigan City 12 coal unit in 2028 and the reasonableness of its related rate request for accelerated depreciation. He explained that NIPSCO’s integrated resource plan (“IRP”) does not support its decision to retire the Schahfer and Michigan City coal units in 2023 and 2028, respectively. Mr. Griffey also addressed significant flaws, errors, and omissions in the IRP and explained that the IRP does not demonstrate that early retirement of the coal fleet is prudent or economical for ratepayers. He testified that NIPSCO has not demonstrated that the related rate relief it seeks in this proceeding is just and reasonable, and that early retirement of NIPSCO’s coal fleet will have significant negative cost impacts for ratepayers.
Mr. Griffey’s direct testimony focused on what NIPSCO has labeled Retirement Portfolios 1,4, 5, and 6 and its preferred Replacement Portfolio F. Portfolio 1 is NIPSCO’s portfolio in which all of the coal units operate through the end of their planned service lives. Portfolio 4 retires Schahfer 17/18 in 2023 in favor of purchase power agreements (“PPAs”) from NIPSCO’s request for proposals (“RFP”), and Schahfer 14/15 in 2028 and Michigan City 12 in 2035 in favor of generic solar resources. Portfolio 5 differs from Portfolio 4 by retiring Schahfer 14/15 in 2023 and replacing it with RFP resources. Portfolio 6 differs from Portfolio 5 by replacing Michigan City 12 in 2028 with generic solar resources. Finally, Portfolio F—NIPSCO’s preferred portfolio—differs from Portfolio 6 by inserting NIPSCO ownership of renewables in lieu of relying entirely on the optimized PPAs chosen in Portfolio 6.
11
Mr. Griffey described the flawed two-step process used in the IRP. NIPSCO’s evaluations of the coal unit retirement decision and the subsequent replacement decision were conducted separately, with no cost comparison between the two decisions. NIPSCO uses this separate two-step process to arrive at its preferred plan (Portfolio F). First, NIPSCO evaluates the operation of the coal plants with certain retirement dates against optimized portfolios based on aggregated offers from its recent RFP. Based on this comparison, NIPSCO claims that it is cheaper to acquire the optimized new renewable resources (i.e., Portfolio 6) compared to any of the other portfolios where the coal plants might operate for longer. NIPSCO thereby concludes that the Schahfer coal units should be retired in 2023 and Michigan City 12 in 2028 and holds out to the Commission that the Portfolio 6 result (the entire coal fleet retires by 2028) is better for customers.
Mr. Griffey explained that NIPSCO then switches to comparing different portfolios in step 2 of the IRP analysis. In this step, NIPSCO takes it as a given that the coal units will be retired in the specified years. NIPSCO then discards the optimized portfolio that was purportedly cheaper than the continued coal operation cases, and evaluates six other portfolios with different sets of new resource and market purchases (the “Replacement” portfolios). NIPSCO discards the optimized Portfolio 6 because it appears NIPSCO has no intention of acquiring that particular set of resources, which was entirely made up of PPAs. Instead, NIPSCO selects Portfolio F from among the non-optimized replacement portfolios, which Mr. Griffey testified is NPV $420 million more expensive than Portfolio 6 due almost solely to NIPSCO owning renewable resources rather than purchasing those resources. Mr. Griffey notes that Portfolio F is made up of a significant amount of NIPSCO-owned renewable resources, which are more profitable for the utility and its investors than renewable PPAs. Mr. Griffey stated that NIPSCO’s own analysis shows that using owned solar and wind resources in Portfolio F is more expensive than either entering into the PPAs (Portfolio 6) or operating Michigan City 12 through 2035 instead of 2028 (Portfolio 5).
Mr. Griffey explained that NIPSCO’s own figures, before other necessary adjustments, show that its Preferred Portfolio F is more expensive than Portfolio 5, in which Michigan City 12 operates through 2035 in all scenarios and across NIPSCO’s cost certainty and cost risk metrics. He explained that the values from NIPSCO’s IRP dramatically understate the cost of the replacement renewable resources and overstate the cost of continuing to operate the coal plants. Notwithstanding, NIPSCO’s own analysis—unadjusted for any errors—shows that, in every scenario, the portfolio wherein Michigan City 12 operates until 2035 is economically preferable to the Preferred Portfolio F that NIPSCO recommends by hundreds of millions of dollars.
Mr. Griffey also testified that beginning in 2020, NIPSCO’s preferred Portfolio F is more costly on an annual basis than Portfolio 5. This means an election of Portfolio F over Portfolio 5 would result in annual rate increases
12
significantly greater than the amount NIPSCO is requesting in this case. Mr. Griffey stated that Portfolio 5 is better than Portfolio F along NIPSCO’s Cost Certainty and Cost Risk metrics.
Mr. Griffey also testified that NIPSCO’s analysis shows higher costs for the Schahfer units, but when accounting and adjusting for the other flaws in its IRP, it is likely more economic to operate Schahfer 14/15 past 2023 and possible that it will be more economic to operate Schahfer 17/18 past 2023 as well. Thus, he testified, the reasonable and appropriate choice is to not retire Michigan City 12 and defer the decision on retirement of the Schahfer units until NIPSCO’s next IRP.
Mr. Griffey’s testimony described how this two-step process is designed to benefit NIPSCO. He explained that, NIPSCO gets recovery of its sunk costs and maintains its earnings power into the future by making its plant retirement decision based on comparing Portfolios 5 and 6, but then acquiring resources based on the more expensive Preferred Portfolio F, which is effectively a “bait and switch.” Mr. Griffey stated that, on its IRP analysis, in ten years, NIPSCO’s rate base and earnings would be 5 times as large in its “switch” Preferred Portfolio F as in Portfolio 5 where Michigan City operates until 2035, and approximately twice as large as in the “bait” Portfolio 6.
Mr. Griffey further testified that NIPSCO did not properly evaluate the timing of coal unit retirements. He noted that NIPSCO evaluated only 3 possible retirement dates (2023, 2028, and 2035) across its four IRP scenarios. He testified that, based on NIPSCO’s last depreciation study Michigan City would have been retired in 2031 and on average the Schahfer coal units would have retired in 2035. Mr. Griffey stated that NIPSCO’s use of only these three dates was not an optimal or reasonable approach to evaluating retirement dates for the units, given the uncertainties in environmental regulations described in Mr. Nasi’s testimony and the uncertainties in pricing of carbon dioxide emissions described in Ms. Medine’s testimony.
Mr. Griffey indicated that the problem with NIPSCO’s approach is that the utility ignores that it has the flexibility to respond to changing circumstances with its currently owned generation. For example, he explained, NIPSCO accepts as a certainty that it will have to spend $1.2 billion on environmental capital expenditures to keep Schahfer 17 and 18 operating past 2023, but based on Mr. Nasi’s and Ms. Medine’s testimony there is no basis for that certainty as to either amount or timing. NIPSCO also constructed 3 out of 4 of its future scenarios assuming a 2026 imposition of prices or taxes on CO2 emissions, but there is no certainty about that assumption. Mr. Griffey testified that NIPSCO assumes that the capital expenditures necessary to keep Schahfer 14 and 15 operating in the future will be 50%-75% higher and that fixed operations and maintenance (“O&M”) expense and will also be significantly higher than the level experienced from 2013-2018, but operation in the next several years may prove that incorrect. Mr.
13
Griffey’s direct testimony indicated that, in short, NIPSCO’s analysis does not value the flexibility provided by continuing to run the Schahfer coal units for a period of time after 2023 if allowed by environmental regulations.
In his direct testimony, Mr. Griffey also explained that much of the NPV difference between portfolios is based on a cost comparison of generic solar units that replace the coal units in either 2028 or 2035 to solar bids from the RFP based on today’s costs. He also stated that NIPSCO artificially inflates the cost of retiring Schahfer 14/15 in 2028 by NPV $375 million because it uses different pricing assumptions for the solar capacity that replaces the coal units across the different portfolios depending on the retirement date. For the portfolios where a coal unit retires in 2023, the Schahfer 14/15 coal units are replaced by a solar resource that is priced based on the best bids from the recent RFP. In contrast, for the resource portfolios where coal units are replaced after 2023, NIPSCO’s replacement resource does not use the cost from the RFP bids, but instead uses a higher cost assumption for a generic solar resource. Mr. Griffey explained that this arbitrary use of a higher solar cost assumption in the later years weighs in favor of early plant retirements.
Mr. Griffey stated that some utility executives believe that solar costs will continue to decrease, and that there is value to waiting for that decrease to happen. NIPSCO’s IRP does not assume that solar costs will decrease in nominal or real terms from the RFP prices, much less decrease sufficiently to overcome the reduction in ITC. This, Mr. Griffey explained, is yet another case where NIPSCO stacks the deck against continued coal unit operation and undervalues the flexibility to wait and see if technology advances.
Mr. Griffey stated that NIPSCO could have fixed this problem by updating its replacement generic solar resource costs to reflect a starting point based on actual market conditions using its cost from the RFP, and then accounted for technological improvements if it wished to do so. He testified that NIPSCO’s failure to update these values amounts to approximately NPV $375 million in the case of moving the retirement date of Schahfer 14/15 from 2023 to 2028.
Mr. Griffey also testified that NIPSCO overstates the capacity value for Indiana wind resources. It uses an estimate that the UCAP (ELCC) of wind resources is approximately 15% of the installed capacity of those resources. He testified that this is consistent with the average across the MISO system in 2017 of 15.2%, but the assigned UCAP for wind varies across the zones in the MISO system based on how likely the wind resource is to operate during MISO’s peak demand hours. Mr. Griffey stated that, compared with the 15.2% average ELCC for MISO, wind in Indiana received significantly less than the 15% used in NIPSCO’s IRP. This means that the IRP understates the cost of wind resources. Mr. Griffey testified that, at the capacity price level assumed by NIPSCO in its IRP, NIPSCO is understating the cost of wind resources in Portfolio F by about $2 million annually in constant dollars, or about NPV $20 million. He further testified that if one
14
instead assumed that over time capacity would have to be priced at the cost of new entry of $84/kw-year, the understatement of wind resource ELCC and UCAP would be NPV $68 million.
Mr. Griffey further testified that NIPSCO has excluded from its evaluation certain costs it should reasonably expect to be incurred in connection with the replacement renewable resources. He stated that NIPSCO has excluded from consideration the cost of congestion and/or the costs of transmission to alleviate congestion, and it has not included any estimate of higher ancillary service costs from portfolios that rely primarily on renewable resources or any projected degradation in output for its owned wind generation. Mr. Griffey also testified that NIPSCO has not evaluated whether it can actually use all of the production tax credits (“PTCs”) and investment tax credits (“ITCs”) generated by a decision to move to a largely renewable portfolio including owned renewable generation, and instead assumes it can use tax equity financing without any apparent loss of tax efficiency. He stated that if NIPSCO cannot use all of the tax credits, or if there is leakage to outside investors in tax equity financing, then the costs of the renewable portfolios will be higher than it has estimated.
Mr. Griffey also testified that NIPSCO has included speculative environmental regulation costs as certain expenditures for the continued operation of the coal plants. He stated that NIPSCO has included approximately $1.1 billion in capital costs as being required for continued operation of Schahfer 17/18, $220 million for Schahfer 14/15, and $54 million for Michigan City. NIPSCO has also included the equivalent of a continually escalating carbon tax in three out of four scenarios beginning in 2026, which adds hundreds of millions in cost on the coal units in each of those scenarios. Mr. Griffey testified that, based on the testimonies of Mr. Nasi and Ms. Medine, there is no certainty that most of these costs must be incurred in order to keep the coal units operating past 2023. The fact that NIPSCO treats these costs as certain essentially preordains the outcome of the IRP for the Schahfer units. Mr. Griffey explained that if the CO2 cost assumption is excluded for the years 2028-2035, that would put Portfolio 5 on par with Portfolio 6. Further, Portfolio 5 is even better than preferred Portfolio F by an additional $105 million in the “Base and Booming Economy” cases and $266 million in the “Aggressive Environmental” case used in NIPSCO’s IRP.
Mr. Griffey testified that NIPSCO has also inflated maintenance capital expenditures associated with operating the coal units by failing to reflect recent renegotiations from coal and transportation suppliers. He also testified that NIPSCO has substantially increased the ongoing fixed O&M and maintenance capital expenditures for the coal units relative to the 2013-2018 average for each plant. He stated that NIPSCO actually decreases assumed annual maintenance capital expenditures by nearly 1/4 from the average of the most recent six years in the cases it prefers, i.e., retire the Schahfer coal units in 2023. But in the cases where the units keep operating, NIPSCO increases the assumed maintenance
15
capital expenditures by anywhere from 50% to 75%. The NPV impact of these assumptions relative to the six-year average is substantial. Mr. Griffey testified that for Schahfer 14/15, the case where the units run until 2028 would be cheaper than the preferred case where they retire in 2023, and for the 2035 operation case it would also be cheaper. For Schahfer 17/18 it would similarly be cheaper to operate until 2035.
Mr. Griffey further testified that NIPSCO has made similar assumptions for fixed operating and maintenance costs. For Michigan City, the average fixed O&M cost was $41/kw-year from 2013-2017. Allocating general administrative, engineering, fuel and environmental support costs of $7/kw-year leads to a five-year historical average of $48/kw-year. In the IRP, however, NIPSCO increases the fixed O&M assumption significantly above the five-year historical average. This leads to an unjustified increase in costs of the operation of Michigan City 12 from 2029-2035. For Schahfer 14/15, NIPSCO similarly assumed that fixed O&M would increase on a constant dollar basis by a large percentage above the historical average, likewise resulting in a large increase in NPV for operation through 2028.
Mr. Griffey also testified regarding the impact of inflated fuel prices on the IRP. NIPSCO did not use its recently renegotiated fuel prices in its IRP. Since lower fuel prices can change the dispatch of the units, the Aurora model would have to be re-dispatched to accurately calculate the decrease in costs associated with lower fuel costs. The impacts reported below are therefore minimums. If NIPSCO had used current prices as a baseline and then escalated those prices as before, without redispatch it would have significantly lowered both the cost of operating Michigan City 12 through 2035 in lieu of 2028 and the cost of operating Schahfer 14/15 through 2028 in lieu of 2023.
Mr. Griffey testified that it is not possible to quantify the impact of all the flaws he identified in the IRP, but that he did aggregate the impact of the flaws that he could quantify. He testified that it is always more economic to operate Michigan City 12 through 2035 compared to NIPSCO’s preferred portfolio, even without adjustments, and there are no cases where it makes sense to declare a retirement date of 2028 for Michigan City in any scenario or under NIPSCO’s cost certainty or cost risk metrics.
Mr. Griffey stated that NIPSCO did not make a serious effort to gauge the optimal retirement date for Schahfer 17/18. Only one portfolio was evaluated with operating those units past 2023, and that portfolio simply cannot be compared to any other scenario because of the differences in demand-side management assumptions. Further, NIPSCO assumed such high costs for meeting environmental regulations that either do not exist (NOx requirement) or are very uncertain (effluent limitation guideline (“ELG”) and other costs) that it preordained a decision to retire these two units as soon as possible.
16
Mr. Griffey also testified that NIPSCO’s proposed changes in its tariffs that would allow its five largest industrial customers to access the market for most of their power needs could significantly decrease NIPSCO’s need for capacity and energy from resources that it controls, which may change the results of the IRP. He explained that the portfolios are all constructed and dispatched based on a defined amount of needed capacity and energy, and purchases/sales to the market are used to balance each portfolio based on that defined need. Mr. Griffey stated that if future needs are expected to decrease, it makes little sense to analyze long-term commitments based on ignoring that expected decrease.
Mr. Griffey testified that it is premature for the Commission to determine whether NIPSCO should receive a return on the regulatory asset if it is approved, or what the level of return should be, and recommended that the Commission postpone any determination regarding rate recovery for the associated plant retirement decisions until after NIPSCO’s next IRP.
10. IMUG Case-in-Chief
11. LaPorte Case-in-Chief
12. Industrial Group Case-in-Chief
13. NLMK Case-in-Chief
14. NICTD Case-in-Chief
15. Peabody Case-in-Chief
A. Michael J. Nasi. Michael J. Nasi provided testimony on behalf of Peabody regarding certain environmental regulatory assumptions underlying NIPSCO’s cost assumptions for compliance with environmental regulations. Mr. Nasi explained that the environmental regulatory assumptions on which NIPSCO so heavily relies in its proposal to retire Michigan City Unit 12 and Schahfer Units 14, 15, 17, and 18 are deeply flawed or, at best, premature.
Mr. Nasi testified that NIPSCO made assumptions about which scenarios to run and included in these scenarios regulatory timelines relating to both the Coal Combustion Residual (“CCR”) Rule and the Effluent Limit Guidelines (“ELGs”) that were too short given currently available extension options and EPA-announced plans to significantly reform both of those rules for the express purpose of mitigating their impacts on coal-fired power plants.
Regarding ELGs, Mr. Nasi described why NIPSCO overestimates costs given the current postponement of certain compliance dates under the ELG and the fact that EPA has announced plans to significantly revise the existing ELG by December 2019, at which time there will be additional regulatory clarity essential to
17
evaluating and selecting retirement or retrofit scenarios. Given the several months more of uncertainty, Mr. Nasi concluded it is unreasonable to make a retirement decision at this time based upon an estimate of ELG compliance costs, which very likely could be overstated.
Regarding CCRs, Mr. Nasi noted that NIPSCO asserts there will be over $226 million in CCR Rule compliance costs from 2018 to 2024 if Michigan City Unit 12 and Schahfer Units 14, 15, 17, and 18 continue operating. But Mr. Nasi testified that this estimated value is unjustified for numerous independent reasons. First, NIPSCO failed to provide specific evidence justifying the values included in its IRP or its discovery responses. Second, the state of the CCR Rule is currently in fluctuation, as the EPA is expected to announce changes in “Phase 2” of the rule in late 2019 or early 2020. Given the significant changes that could be made, Mr. Nasi believes it is unreasonable to make a retirement decision at this time based upon overly conservative predictions about the need to close surface impoundments or CCR Rule compliance cost estimates, which very likely could prove to be too high. Third, NIPSCO has inappropriately included reference to CCR-related costs that will be incurred regardless of the retirement decision, which renders them irrelevant to an evaluation of the prudence of the retirement decision and the resulting request for accelerated depreciation.
Mr. Nasi also testified that NIPSCO’s cost assumptions were too high. He explained that NIPSCO’s various capital expenditure assumptions, as well as operation and maintenance (“O&M”) cost assumptions, regarding the continued operation of the aforementioned power generating units are either not backed up by specifics or simply too high. In addition to unjustified expenditures assumed to be necessitated by the CCR Rule, the ELG Rule, and updates to the Cross State Air Pollution Rule (“CSAPR”), Mr. Nasi testified that NIPSCO incorrectly assumes the continued burden of O&M expenses associated with the Mercury and Air Toxics Standards (“MATS”) Rule that could be mitigated moving forward—something that NIPSCO is failing to support despite EPA’s regulatory invitation to do so.
Mr. Nasi states that although NIPSCO understandably installed MATS compliance equipment initially, it is inappropriate for NIPSCO to continue assuming they will incur long-term MATS O&M costs for these electric power generating units. There is a strong possibility that EPA will withdraw MATS entirely or drastically alter the rule as to reduce the ongoing O&M cost burden. Therefore, NIPSCO's assumption to build these high O&M costs into its IRP is unreasonable. Additionally, NIPSCO’s prudence should be questioned given its lack of support for EPA’s current opportunity to withdraw MATS and eliminate the costs that EPA has concluded are unreasonable.
Regarding CSAPR compliance cost assumptions, Mr. Nasi notes that NIPSCO claims that it is required to spend $448 million in SCR technology for Schahfer 17/18 to comply with existing CSAPR regulations, another cost that was
18
built in to their IRP. But Mr. Nasi testifies that NIPSCO failed to provide adequate justification for choosing Selective Catalytic Reduction (“SCR”) technology over the much less costly alternative Selective Non-Catalytic Reduction (“SNCR”) technology. He argues there is no basis in the record to justify NIPSCO’s assumption that SCR technology was required.
Mr. Nasi concludes that, in light of the magnitude of costs involved and the fact that ongoing regulatory reforms could significantly reduce those costs, it is premature to move forward with retirement of NIPSCO’s units and a related increase of rates as proposed in this case at this time. Once these units are retired he believes it becomes an irreversible decision. He notes that by waiting until ongoing regulatory reforms are better understood, NIPSCO, the Commission, and all stakeholders will have a better understanding of the regulatory costs faced by NIPSCO and, therefore, the advisability of their current proposal. Moreover, even if NIPSCO’s regulatory assumptions could be justified, Mr. Nasi testified that their inclusion of costs they would incur whether or not these power plants are retired provides an additional basis to reject the current request to gain approval of the accelerated depreciation resulting from early retirement.
16. Sierra Club Case-in-Chief
17. Walmart Case-in-Chief
18. US Steel Case-in-Chief
19. OUCC Case-in-Chief
20. ICC Cross-Answering Testimony
A. Phillip Graeter. Mr. Phillip Graeter, a Manager in the consulting firm of Energy Ventures Analysis, Inc. offered cross-answering testimony on behalf of intervenor Indiana Coal Council, Inc., in response to the testimony of Mr. Avi Allison filed on behalf of Intervenor Sierra Club.
Mr. Graeter testified that in considering the calculation of savings from accelerated retirement of NIPSCO coal fired generation, Mr. Avi does not take into account the cost of lost jobs. Mr. Graeter performed a “Job Impact Study of the Accelerated Retirements of NIPSCO’s R.M. Schahfer and Michigan City Power Plants,” a copy of which was attached to Mr. Graeter’s testimony as Attachment PG-2.
Mr. Graeter testified that his study shows that the accelerated retirements of the R.M. Schahfer and Michigan City power plants will have serious negative impacts on the local communities, while NIPSCO’s plan to replace these power plants will do little to soften these impacts.
19
Mr. Graeter testified that according to NIPSCO’s recent presentation at the public advisory meeting in October 2018, 276 direct plant jobs would be lost if the Schahfer plant were to close in 2023 (151 at units 14/15 and 125 at units 17/18). An additional 150 plant jobs would be lost if Michigan City 12 also closed in 2028, putting the total number of direct jobs at risk to 426. Mr. Graeter calculated that due to the acceleration of these power plant retirements, almost 5,500 job-years would be lost. Additionally, he testified, the average annual salary for power plant employees in the state of Indiana is more than double the amount of the average Indiana employee, and losing such a significant amount of a well-compensated workforce will have trickle-down effects felt throughout the county and state economy.
Mr. Graeter testified that in addition to the 426 well-compensated direct plant jobs that are at risk by the accelerated retirements of R.M. Schahfer and Michigan City 12, there is also a risk of loss of many indirect and induced jobs, such as indirect jobs supplying goods and services to the power plant or jobs that are directly dependent on the output of the power plant, like coal mining jobs at the coal-supplying mine in the Illinois Basin, and employees at Georgia Pacific’s gypsum plant in Wheatfield, IN, which uses fly ash produced at the R.M. Schahfer plant to produce gypsum. Mr. Graeter also referred to the potential loss of induced jobs are created by the spending of income from direct and indirect jobs, such as local retail stores at which plant employees to spend disposable income.
Mr. Graeter testified that according to his study, 552 local indirect and induced jobs are at risk should R.M. Schahfer retire at the end of 2023, while 300 such jobs are at risk when Michigan City retires at the end of 2028. He noted that his study excluded coal mining jobs, since they would not be considered “local”, despite the proximity to the Illinois coal basin, one of the main sources of coal for the R.M. Schahfer plant. Mr. Graeter testified that including the indirect and induced jobs at risk due to the accelerated retirements of the two power plants, the total number of job-years lost due to the accelerated retirements at R.M. Schahfer and Michigan City increases significantly, to more than 16,400 job-years would be lost to the state and local economies.
Mr. Graeter testified that the location of the power plants is also important. Both Jasper County (the county R.M. Schahfer is located in) and LaPorte County (the county Michigan City is located in) have higher unemployment rates than the rest of the state. After exceeding 10% at the height of the great recession of 2008, unemployment rates in Indiana as a whole, as well as Jasper and LaPorte counties, have dropped significantly, reaching 10-year lows in 2018. Nevertheless, unemployment in Jasper and LaPorte counties are more than 15% and 29% higher than the average unemployment rate in Indiana, respectively.
Mr. Graeter testified that losing the jobs associated with both power plants could have dramatic impacts on the local workforce. For example, when adding the
20
276 plant jobs from R.M. Schahfer to the unemployment number from December 2018 for Jasper County, the unemployment rate would increase by over 40%, from 3.96% to 5.62%. When including the indirect and induced job losses, the unemployment rate would more than double to almost 9%, a level not seen in Jasper County since 2011. Similar effects would be observed in LaPorte County, where the unemployment rate would increase by 7% and 21% when including plant jobs and plant jobs + indirect and induced jobs in the latest unemployment numbers from the U.S. Bureau of Labor Statistics.
Mr. Graeter also noted that as a direct result of the significant job losses and the accelerated plant closures, local and state economies will likely lose a substantial amount of tax revenue, including property taxes NIPSCO currently pays to both the LaPorte and Jasper County governments. Mr. Graeter noted that according to NIPSCO’s recent presentation in October 2018, NIPSCO is the largest property taxpayer in Jasper County where R.M. Schahfer is located while being one of the top three property taxpayers in LaPorte County, where Michigan City is located. According to information presented by NIPSCO in its 2016 IRP, the tax revenue to Jasper County attributable to the property taxes paid for R.M. Schahfer is substantial. For example, in 2014, almost three-quarters of the township tax was attributable to the R.M. Schahfer property tax NIPSCO paid.
Mr. Graeter testified that as part of the retirement analysis presented in NIPSCO’s 2018 IRP, NIPSCO attempted to quantify the likely impact to local economies due to the accelerated loss of property tax revenue from the R.M. Schahfer and Michigan City power plants. According to the 2018 IRP, accelerating the retirements of R.M. Schahfer and Michigan City would result in a loss of $74 million, or 29% over the preferred scenario presented in the 2016 IRP. However, Mr. Graeter noted, that $74 million only includes the property taxes lost to local economies. It does not include the economic losses to local and state economies, due to the loss in personal income taxes and sales taxes on goods and services as a direct result of the jobs lost.
Mr. Graeter also testified that NIPSCO’s plan to replace R.M. Schahfer and Michigan City with mostly renewable resources will do very little to the local economies in LaPorte and Jasper Counties. He noted that according to the 2018 IRP, NIPSCO plans to replace the retiring coal capacity primarily with solar, wind, and energy efficiency. In fact, solar and solar + storage account for 78% of expected cumulative capacity additions (on a UCAP basis) at the end of 2028. However, he said, the vast majority of jobs created are temporary or not located within the communities where the jobs related to the power plant closures are lost.
Mr. Graeter cited the U.S. Department of Energy’s 2017 U.S. Energy and Employment Report, for the fact that more than 80% of all jobs in the U.S. solar industry are associated with manufacturing or importing solar panels and parts, and construction and installation, while less than 1% is associated with actually
21
operating and maintaining the solar generating facilities once installed. He further testified that with only 2.8 gigawatts of domestic solar PV manufacturing capacity at the end of 2017, the vast majority of solar panels and equipment is being imported from overseas, mainly from Asian countries such as Malaysia, Vietnam, and the Philippines while domestic solar manufacturing is concentrated in just a few states: Washington, California, Mississippi, Michigan, Ohio, and Georgia, with no manufacturing facilities in the state of Indiana. Accordingly, Mr. Graeter said, increased solar build-out will most likely create more jobs overseas or out-of-state than locally where other jobs would be lost.
Mr. Graeter also cited the 2017 DOE Energy and Employment Report, which found that more than one-third of jobs in the solar industry are in construction and installation. Mr. Graeter noted therefore, that while the installation of solar panels may be done by local companies and local installation crews, these jobs are temporary, by definition. Further Mr. Graeter testified that with no guarantee that the solar facilities are being built in the same general location as the retiring plants, the large amount of installation and construction jobs might not bring any economic benefits to Jasper and LaPorte Counties.
21. ICARE Cross-Answering Testimony
A. Charles S. Griffey. Mr. Griffey’s cross-answering testimony rebutted several of the conclusions reached by Mr. Avi Allison in his testimony on behalf of Sierra Club. He testified that, contrary to Mr. Allison’s assertion, the potential loss of industrial firm load would not make NIPSCO’s coal units less viable relative to NIPSCO’s preferred plan from its IRP. He testified that maintaining flexibility about when to retire the coal plants and deferring burdensome new PPAs or renewables ownership is likely to have great value. He noted that no one, including NIPSCO, knows what the level of industrial load will be on the NIPSCO system in five years.
Mr. Griffey testified that in NIPSCO’s IRP Retirement Portfolio 6, the total must take from PPAs is 8.3 million MWh per year for twenty years. He explained that, at the approximately $30/MWh - $40/MWh cost NIPSCO assumed in Retirement Portfolio 6, NIPSCO customers would become committed to incurring an annual cost of $250 million – $330 million for renewable energy.
He further explained that, in NIPSCO’s class cost of service study, the annual firm energy is 12.1 million MWh, of which approximately 3.3 million MWh are from industrial customers. Thus, if a large amount of industrial energy use leaves the system because of NIPSCO’s proposed large industrial rate restructuring, NIPSCO is proposing to purchase renewable energy every year for the next twenty years equal to nearly 100% of its current non-industrial usage.
22
Mr. Griffey testified that this means NIPSCO will be taking a large amount of price risk, and it would change the IRP results in three out of the four scenarios and the stochastics for those three scenarios. He explained that NIPSCO’s IRP results do not show that lower industrial usage results in the coal units becoming less economic. He stated that, in fact, with a lower load forecast the coal units become more economic, and the renewables become less economic. He further testified that lower industrial load and energy favors the coal-to-gas conversions of Schahfer 17 and/or 18, instead of the long-term commitment to renewable generation.
Mr. Griffey testified that NIPSCO should rerun its IRP to properly evaluate the likelihood that its five largest industrial customers will leave the system. He stated that without this information, NIPSCO has failed to demonstrate the early retirement of its coal fleet is prudent and the related rate request for accelerated depreciation is just and reasonable.
Mr. Griffey further rebutted Mr. Allison’s claim that the retirement of all of NIPSCO’s coal plants will save $4 billion. He testified that these savings are illusory, in part, because NIPSCO only made assumptions and ran the Aurora model for twenty years, yet it made thirty year NPV calculations. It did so—ostensibly to account for “end effects”—by simply assuming for the last ten years of its NPV period that year twenty costs (escalated only for inflation) would prevail for the remaining ten years. Mr. Griffey testified that NIPSCO should have used a twenty-year planning period for its NPV calculation because twenty years is more closely aligned with the PPA term and service life of the replacement renewable resources. He also noted that the price of PPAs or replacement generation in years 21-30 is mere guesswork at this time. He further explained that NIPSCO made unreasonable assumptions about the price of PPAs in the last ten years of the NPV period.
Mr. Griffey testified that by enlarging its NPV calculations to thirty years, and doing so in a short-cut manner, NIPSCO unfairly biased the results in its Base Case in favor of its Preferred Portfolio by anywhere from approximately $100 million to nearly $1 billion. In the Challenged Economy case it biased the results in favor of its Preferred Portfolio by as much as almost $680 million in one instance.
Mr. Griffey also noted that the facts in NIPSCO’s requests for PPA approval demonstrate (i) the UCAP to be expected from the wind resources is close to what he showed in his direct testimony, rather than the ~15% UCAP NIPSCO assumed in its IRP, and (ii) other costs, such as congestion, should have been included in the IRP modeling. He states that the resulting extra cost of capacity would likely drive the modeling to prefer different resources, including possibly later retirement dates for some of the coal units, and assuredly the gas-to-coal conversion of Schahfer 17/18.
23
22. Industrial Group Cross-Answering Testimony
23. NLMK Cross-Answering Testimony
24. Sierra Club Cross-Answering Testimony
25. US Steel Cross-Answering Testimony
26. NIPSCO Rebuttal
27. NIPSCO Settlement Testimony
28. CAC Settlement Testimony
29. ICC Settlement Testimony
A. Emily S. Medine. Ms. Medine opposed that part of the Revenue Settlement that would have the Commission approve now, years in advance of any actual retirements, the accounting treatment and amortized recovery of undepreciated costs that NIPSCO will receive when and if it decides to retire any existing coal generation resource. For three reasons, she recommended that at the present time Commission deny approval of accounting treatment and amortized recovery that NIPSCO would receive if and when it retires any existing coal generation resources, and require NIPSCO to seek that relief at or near the time of actual retirement. First, the Indiana General Assembly has recently enacted legislation that creates a task force to study and report on the Commission’s regulation of changes in utilities’ generation portfolio. Second, that relief is unnecessary at this time. Third, the premise for that relief is that NIPSCO will retire its Schahfer coal units in 2023 and its remaining Michigan City coal unit in 2028. But NIPSCO’s preference for such retirements is based on a flawed IRP that appears designed to produce that outcome.
Ms. Medine noted that current Indiana law requires Commission approval for new resources, but not for retirement of existing resources. However, once an asset is retired it is no longer used and useful in rendering service to customers. So, if a utility has undepreciated costs it wants to recover and earn a return on until recovered, the utility must get appropriate accounting and recovery relief from the Commission. No one can know what the Task Force recommendations will be or what legislation might result. The law could change before 2023 or 2028 to require Commission approval to retire existing generation assets and/or to specify the allowed recovery of any undepreciated costs after retirement.
Ms. Medine testified that the Commission should decide about recovery of undepreciated costs at or near the time of retirement in accordance with the law then in effect. The Commission should not undermine the legislature’s authority or
24
the Commission’s own future decision-making by authorizing recovery of undepreciated costs years in advance of any actual retirement.
Ms. Medine further testified that other than NIPSCO’s convenience and preference for certainty, nothing requires a decision now about recovery of undepreciated costs that may exist in 2023 or 2025 or 2028 or any other years away date. NIPSCO is free to plan for retirement on any date it chooses, and conduct its operations, as well as make its maintenance and capital expenditures accordingly. And NIPSCO is free to change its plan and act accordingly. Indeed, in the meantime there may be changes in circumstances (environmental or other regulations, commodity prices, NIPSCO’s expected future load profile, technology, energy markets, capacity prices, etc.). Ms. Medine opined that at or near the time when it is actually going to retire a resource is the appropriate time for NIPSCO to seek and for the Commission to grant accounting and recovery treatment for undepreciated costs as allowed by the law then in place and as reasonable, necessary, and proper under then existing circumstances.
In support of her position that NIPSCO’s 2018 IRP is too deeply flawed to justify its use in making any specific resource decisions including whether any existing resource should be retired at any particular date and whether any new resource (owned or not) should be acquired, Ms. Medine incorporated her prefiled direct testimony in this cause, and her prefiled direct testimony in Causes 45194, 45195, and 45196, as well as her comments regarding NIPSCO’s 2018 IRP Cause 45160. As further support she referred to the direct testimony and cross-answering testimony of Mr. Charles S. Griffey in this cause, his prefiled direct testimony Causes 45194, 45195, and 45196. Ms. Medine further testified that the main flaws that make NIPSCO’s 2018 IRP unreliable as a basis for specific resource decisions are:
NIPSCO began its IRP analysis using a future load forecast that assumed its present industrial load. In the middle of its IRP process NIPSCO began discussing with its largest industrial customer a major change in its large industrial tariffs that would allow these customers to access the MISO market for most of their energy needs. Instead of adjusting its load forecast to account for that material change in circumstances, NIPSCO inexplicably decided to complete its IRP using a load forecast that had become outdated by its decision to seek approval for that major change in its large industrial tariffs.
NIPSCO created various retirement portfolios in which assumed different future amounts of coal generation for different lengths of time, ranging from 65 percent coal through 2035 (Retirement Portfolio 1) to no coal as of 2023. But in each instance NIPSCO restrained its models’ ability to select MISO capacity purchases to only 50 MW to replace whatever coal was eliminated, and forced the models to select hypothetical replacement
25
portfolios that NIPSCO had no intention to acquire as actual replacements. NIPSCO then locked-in its decision to retire its entire coal portfolio on the basis of that inadequate analysis.
In deciding to retire its entire coal portfolio NIPSCO assumed onerous environmental requirements would persist, that CO2 would become taxed in the near future, and that NIPSCO would incur unprecedented future maintenance expenses. NIPSCO gave no consideration to grid resilience benefits of coal units, no consideration to the possibility for deferral of environmental compliance requirements, and only considered the possibility of CO2 not being taxed in connection what assumed high coal prices.
NIPSCO calculated the economics of the alternatives using a 30-year Net Present Value calculation as opposed to the standard 20-year analysis the other utilities, including NIPSCO in 2016 use. NIPSCO’s preferred plan was only more economic if the 30-year analysis was used. While NIPSCO’s justification was to capture end effects, NIPSCO did not even model 30 years. Instead of actually running its models for 30 years, NIPSCO stopped the models at 20 years and then extrapolated for 10 more years. This allowed NIPSCO to disfavor its three short-term portfolios that had no owned assets by assuming that at the end of 15-year PPAs they would be replaced by lower load-factor, expensive owned generic solar resources. In contrast NIPSCO could favor its preferred long-term replacement portfolios by assuming that their 20-year PPAs would not need replacement, but would simply continue in effect at extrapolated values until the end of the 30-year calculation period. It was only the “savings” in the last 10 years, when of course the forecast is most uncertain, that catapulted the Preferred Portfolio to least cost.
NIPSCO’s four future scenarios were designed to disfavor continued operation of its existing coal units. NIPSCO assumed early carbon taxes in three of the scenarios, and in the fourth it assumed high coal prices in a down economy.
Ms. Medine also testified about changes that should be made in NIPSCO’s future IRP modeling:
The Commission should direct NIPSCO to perform a truly integrated planning by using the replacement portfolios it is actually considering in its analysis of whether or not to retire existing resources.
If the Commission approves Rate 831, it should direct NIPSCO to develop and use a load forecast that accounts for any possible resulting change in load both in the initial five years of 831 contracts and in later years.
26
When NIPSCO makes assumptions that are major drivers of future costs, it should not model only the assumptions that favor its desired outcome. It should also model what the outcome would be if an assumption is wrong, and in doing so it should not change other material assumptions to drive toward a desired outcome. For example, if NIPSCO wants to assume future carbon taxes, that is fine, but it needs to model no carbon tax futures without tweaking other major assumptions (such as assuming higher coal prices and a poor economy) that have the effect of countering the lack of carbon taxes.
If NIPSCO wants to look more than 20 years into the future to “capture end effects,” then it should run its models longer, instead of artificially extrapolating the 20th year for 10 more years. And, if NIPSCO deems it necessary to capture end effects, it should not play favorites by only capturing the end effects of early acquired owned resources, while ignoring the end-effects of owned resources it assumes must be acquired later in the modeling period to replace short-term resources that expire before the end of the modeling period.
NIPSCO’s future scenario design must include some reasonable future scenarios in which its preferred outcome is not always the winner.
NIPSCO should not design its potential portfolios to fit into some arbitrary score card analysis. Rather, NIPSCO should strive to identify reasonable potential portfolios that can be stress tested against a variety of reasonable future scenarios. The Commission should expect that contrary to NIPSCO’s 2018 results, the mix of winning and losing portfolios will be different across different future scenarios.
Ms. Medine also noted that while the settlement addresses certain tracker vs. base rates issues, it does not, but should, address an important issue concerning NIPSCO over-pricing its coal unit energy into the MISO market by including costs that are not variable to ratepayers because they are not tracked, but rather are fixed to ratepayers because their recovery is embedded in base rates. Ms. Medine testified that it appears NIPSCO is not doing everything it can to improve the competitiveness of its existing generation resources as long as they are in use. Rather, she contended, NIPSCO is diminishing the competitiveness of those units in the MISO market by over-pricing the energy from those units, resulting in less dispatch and causing lower capacity factors. She noted that NIPSCO admits it no longer attempts to run these units as base load generation. Ms. Medine testified that coal unit performance is tied to capacity factor. The higher the capacity factor, the better the efficiency, the lower the cost. The lower the capacity factor, the lower the efficiency, the greater the wear and tear on the units, and the higher the operating and maintenance costs. Ms. Medine testified that there continues to be significant coal capacity on the lower part of the MISO cost curve. She noted that
27
Michigan City and Schahfer 14/15 are considered to be “mid-merit” indicating there are more efficient units, but these units are still dispatched frequently. Schahfer 17/18 are marginal. She opined that if NIPSCO excluded non-tracked variable operating and maintenance costs from its MISO bid prices the dispatch position of the NIPSCO units would improve.
Ms. Medine further testified that it is well known that coal units operate most efficiently, i.e., have lower (better) heat rates, when their capacity factors are higher. Suppressing coal burn through the offer strategy has resulted in higher (poorer) heat rates. In addition, she said, such an approach to operations increases wear and tear on the units increasing operating and maintenance costs as well. Ms. Medine testified that changes in the electricity market since 2009 have resulted in coal generation being often on the margin, making the bid prices significantly more important. With cost recovery of most variable operating and maintenance costs (other than fuel) in base rates, the utilities are incented to depress coal generation through purchases in the market. This increases the utility’s earnings on the back of ratepayers who are paying higher rates. Ms. Medine testified there are two ways to address this problem. The first is to include the variable costs in a tracker as fuel and purchased power costs are. The second is to leave these costs in base rates but preclude the utilities from including costs recovered in base rates as variable costs in their offer bids. Ms. Medine testified that is reasonable, because from the standpoint of the ultimate payers of those costs (ratepayers) those costs are not variable, because when costs are included in base rates, ratepayers pay those costs regardless of whether a unit runs or not.
30. ICARE Settlement Testimony
A. Charles S. Griffey. Mr. Griffey’s responsive revenue requirement settlement testimony focused on why Commission should reject—at the present time—that part of the Revenue Requirement Settlement that would have the Commission approve automatic regulatory asset treatment for NIPSCO’s coal units years in advance of any actual retirement and pre-ordained amortization for any associated sunk costs.
Mr. Griffey explained that a legislative task force will present findings in 2020 concerning the impacts of changing electric generation portfolios. Therefore, the Commission cannot know today what the statewide policies and governing regulatory statutes will be in 2023 and beyond. Accordingly, he stated, it is premature to preordain in 2019 what accounting treatment and/or amortization treatment NIPSCO should receive if and when it actually retires its coal fleet in or after 2023.
Mr. Griffey testified that NIPSCO made numerous assumptions in its IRP that only appear justified by a desire of the utility to shutter the coal plants with full cost recovery and recapitalize the fleet with renewables. He stated that the
28
design of the scenarios and IRP assumptions all inescapably lead to NIPSCO’s desired end result of coal plant retirement and high capital cost renewables investment. He further stated that NIPSCO relies on very uncertain benefits that in most cases do not accrue until twenty years in the future to justify its preferred portfolio. The future is inherently uncertain, and the farther into the future NIPSCO relies upon to justify overall cost benefits of its preferred portfolio, the less likely the benefits are to appear.
Mr. Griffey testified that if energy prices stay low, it makes no sense to enter into billions of dollars of long-term commitments for renewables today. He stated that if energy prices are moderate and NIPSCO’s assumed environmental conditions do not materialize, it may make sense to maintain the coal plants in operation. Only if the environmental regulations NIPSCO assumes materialize and gas prices are moderate or higher is it likely to make economic sense to adopt NIPSCO’s plan. And, he explains, if that outcome occurs, renewables can be purchased at that time.
Mr. Griffey stated that NIPSCO placed arbitrary limitations on the amount of market purchases that its models could consider as replacement resources. In all of the retirement portfolios across all four scenarios, NIPSCO restrained the market purchases the models were allowed to select at 50 MW every year. In all three of its “short-term” replacement portfolios (A, B, and C) across all four scenarios, NIPSCO restrained the market purchases the models were allowed to select at 400 MW every year. In all three of its “long-term” replacement portfolios (D, E, and “preferred portfolio” F) across all four scenarios, NIPSCO restrained the market purchases the models were allowed to select at 50 MW every year.
Mr. Griffey compared NIPSCO’s IRP to the Vectren South CPCN case, Cause No. 45052, in which the Commission found that Vectren had not fully considered options that would have allowed its coal units to remain in service, failed to comply with recommendations from the past Director’s Report, and failed to update its IRP as a result of significant changes to assumptions. Mr. Griffey explained that NIPSCO’s IRP suffers from these same flaws. He stated that NIPSCO’s IRP ignored options that could allow the coal units to remain in service. NIPSCO assumed the coal units will all need massive environmental capital expenditures, but did not consider the possibility that may not be required. NIPSCO assumed that higher gas and energy prices will only occur when large CO2 taxes are in effect, but failed to consider the possibility of higher gas and energy prices without CO2 taxes. NIPSCO failed to evaluate the option value of maintaining the coal plants in service for several more years while evaluating what future market, environmental and regulatory conditions will be in effect. NIPSCO failed to seriously consider a sale process for the plants. NIPSCO failed to comply with recommendations from the past Director’s Report by not eliminating its two-step process of evaluating retirement and then separately evaluating entirely different portfolios for replacement. NIPSCO has not updated its IRP for significant information, such as
29
the potential loss of load caused by its proposed changes to its industrial market structure and for the fact that the actual wind costs are higher, tax equity contribution lower, and capacity factor lower than what was assumed in its IRP.
Mr. Griffey testified that NIPSCO’s strategic goal is to ensure recovery of its sunk coal and associated environmental investment in the rate case and then build additional investment through owned-renewable resources beginning with the Rosewater Project and expanding to larger owned wind and solar generation. Because that strategy is premised on building higher capital cost resources that depend on savings that largely occur in the out years of NIPSCO’s IRP modeling (which is structured to produce those savings), there is no risk-adjusted expectation of likely benefits for customers. In short, he explained that the costs will be certain and very large, and the benefits are very uncertain, are based on assumptions that are not reflective of the current environment, and are far into the future.
Mr. Griffey further testified that he believes it would be premature to approve in 2019 sunk cost recovery that would begin in 2023 or 2028 without the benefit of the Commission’s report and the legislative task force’s recommendations. Allowing NIPSCO pre-approval for cost recovery in this case could circumvent any recommendations made by the Task Force and acted upon by the General Assembly.
He further testified that approval of the regulatory asset and amortization proposal in this rate case is not necessary to give NIPSCO rates that allow it a reasonable opportunity to earn a reasonable return on its invested capital. Instead, he testified, NIPSCO may seek a regulatory asset and amortization approval at a future date. After the legislature has had an opportunity to act on any Task Force recommendations, and after NIPSCO’s 2021 IRP, if NIPSCO still plans to retire some existing generation resources at the end of 2023, it can file at that time for accounting and amortization treatment as appropriate under then existing law. Mr. Griffey further explained that waiting will allow a direct comparison of the cost of continuing to operate the coal units for several more years compared to the cost of the actual resources NIPSCO will propose to replace them with.
30
31. LaPorte Settlement Testimony
32. Industrial Group Settlement Testimony
33. US Steel Settlement Testimony
34. OUCC Settlement Testimony
35. Commission Discussion
A. Revenue SettlementThe proposed Revenue Settlement was joined into by all parties except intervenors ICC, ICARE, LaPorte, Modern Forge, Peabody, Rackers, and United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial Service Workers International Union AFL-CIO/CLC and its Locals 12775 and 13796.
i. Post-retirement accounting treatmentThe Revenue Settlement proposes that the Commission approve now, post-retirement accounting treatment that would align post-retirement accounting treatment with the proposed depreciation treatment to which the settling parties have agreed. However, the Commission agrees with intervenors ICC, Peabody and ICARE that approval of post-retirement accounting treatment is premature at this time, and therefore not in the public interest. Rather, the public interest requires that Commission exercise its judgment regarding appropriate post-retirement accounting treatment at or near the time of an actual retirement, when the Commission can know the relevant and material facts on which such a judgment should rest.
This deferral of deciding post-retirement accounting treatment is only that—a deferral of the decision. It is not a substantive denial of either post-retirement cost recovery or return, and it should not be interpreted as indicating that, when requested by NIPSCO at an appropriate future time, post-retirement cost recovery or return will be denied.
As explained below, deferring any decision at this time regarding post-retirement accounting treatment is in the public interest for two significant reasons. First, the actual plant retirement dates remain uncertain, so that the facts and circumstances that will exists at retirement—on which the Commission’s judgment concerning appropriate post-retirement accounting treatment should rest—cannot be known. Second, the legislature is presently in the process—through a special task force—of examining, among other things, how major shifts in Indiana’s generation portfolios are impacting the reliability and affordability of power in the state. Accordingly, pre-approval of NIPSCO’s desired post-retirement accounting treatment request years in advance of any actual retirement could preempt any legislative findings and related legislative actions that result for the work of the task force.
31
Actual retirement dates are uncertain and likely several years away.
In seeking an order in this case granting post-retirement cost recovery and return, NIPSCO points to its IRP results as indicating retirement of all four Schahfer units at the end of 2023 and Michigan City 12 at the end of 2028. However, extensive testimony was offered by several parties challenging NIPSCO’s IRP.8 Moreover, NIPSCO concedes that the validity of its IRP results is not an issue for decision in this case, and the outcome of this case will not lock-in actual retirement dates for any of those units.9 NIPSCO acknowledges that its current assessment of the actual useful lives (as opposed to the useful lives for depreciation purposes) may change in the future, and that when the time comes, NIPSCO may retire any or all of those units before or after the dates indicated by its 2018 IRP.10
Anticipating, however, that the actual retirement of some or all of those units will occur before 2032, NIPSCO may have nearly a billion dollars of unrecovered costs remaining on its books. NIPSCO seeks an order in this case determining that whenever, and if, NIPSCO elects to retire any of those units before 2032, NIPSCO may, without further request or order from the Commission, enjoy (i) amortized recovery, through 2032, of its remaining costs (i.e. recovery of), and (ii) a full rate of return on those costs during recovery (i.e. return on).
The parties to the Revenue Settlement ask the Commission to grant NIPSCO that relief now, years in advance of any actual retirements. However, sound public policy does not support our deciding at this time whether to grant such relief. The post-retirement accounting provisions of the Revenue Settlement are premature as it is impossible at this time to know the facts necessary to determine whether what post-retirement accounting treatment will be reasonable and just when a future actual retirement occurs. Moreover, even if the retirement dates indicated in the 2018 IRP do not change, those units are expected to continue to render service for customers for several more years.
Deferring the decision on the regulatory asset is not equivalent to a denial of cost recovery for the remaining book value of the plants. Indeed, the Commission has consistently allowed recovery of remaining costs for abandoned plants once used and useful. The Supreme Court of Indiana has recognized the Commission’s long-standing practice of allowing utilities to amortize their undepreciated investment in abandoned plant. Citizens Action Coalition of Indiana, Inc., et al. v. Northern Indiana Public Service Company, et al., 485 N.E.2d 610 (1985). In that case, Justice DeBruler, speaking for the Court, acknowledged “a long adhered to administrative
8 See, Indiana Coal Council Exhibit 1 (Testimony of Emily S. Medine); Indiana Coalition for Affordable and
Reliable Electricity Exhibits 1, 2, 3, AN-1, AN-2, and AN-3 (Testimony of Charles S. Griffey); Peabody Exhibit 1 (Testimony of Michael J. Nasi).
9 NIPSCO Exhibit 4-S1-R (Testimony of Jennifer S. Shikany), p.2, l.15 – p.3, l.2. 10 Sistovaris Cross, Tr. p.A-62, l.22 – p.A-64, l.10.
32
interpretation of allowing amortization of abandoned plants, i.e. plants that were ‘used and useful’ property and then retired from service.” Id. at 616.
Recent decisions from this Commission support the proposition that the “long adhered to administrative interpretation of allowing amortization of abandoned plants” remains in place today. See, e.g. In Re Duke Energy Indiana, Inc. et al., 2011 WL 6960153, Cause 43986 (Dec. 29, 2011) (“We therefore find that Duke Indiana's request to create a regulatory asset for the remaining net book value of Gallagher Units 1 and 3 is reasonable and should be approved.” ¶11. A. 2); In Re South Haven Sewer Works Inc., 1997 WL 34880736, Cause 40398 (May 28, 1997) (“We conclude that Petitioner's recovery of its abandoned plant should be amortized over a period of five (5) years.” *18); In Re Indianapolis Water Company, 1997 WL 34880925, Cause No. 40526 (January 15, 1997) (“Petitioner should retire its boiler equipment shown in Account 311.01 and amortize the undepreciated balance and removal cost over three years” Ordering ¶3); In Re Indiana-American Water Company, Inc., 983 WL 883539, Cause No. 37182 (December 7, 1983) (“The Petitioner proposes to amortize the premature retirement of the filter of the retired treatment plant over a period of ten years. The Staff accepted the proposed amortization, although it included the amount in operation and maintenance expense. We find that the proposed amortization is not unreasonable and have reflected it in the amount described below as depreciation and amortization.” *4); In Re Southside Utilities, Inc., 1982 WL 969888, Cause No. 36569 (July 12, 1982) (“Upon the evidence as presented the Commission finds that Petitioner's abandoned treatment plant should be amortized over a period of ten years.” *7); In Re Old State Utility Corporation, 1982 WL 970148, Case No. 36470 (March 16, 1982) (“Petitioner should be permitted to amortize the net original cost of its abandoned sewage treatment plant in the amount of $34,816 over a ten year period” *2); In Re Johnson Suburban Utilities, Inc., 981 WL 698357, Cause No. 36296 (August 18, 1981) (“The original cost of the treatment plant and related facilities abandoned by the Petitioner was in the amount of $872,349, and related accumulated depreciation was $154,247, and an estimated salvage value of $150,000 results in net write-off in the amount $568,102 and when amortized over a period of ten years would amount to an annual charge of $56,810, which amount the Commission now finds to be reasonable and proper and will be included in our rate-making determinations herein.” *9); In Re Public Telephone Corporation, 1975 WL 395769, Cause No. 33914 (January 30, 1975) (“Upon such retirement, said equipment will no longer be necessary or desirable in the proper conduct of Petitioner's business and the maintenance of its earnings, and the abandonment of such property should be consented to and approved and Petitioner should amortize the unrecovered cost of such equipment to operating expenses equally over a period of five years following the date of abandonment thereof.” ¶12).
33
NIPSCO contends that not granting, in this case, the requested post-retirement amortization and return will create a risk to NIPSCO of an immediate write-off.11 However, such a risk appears neither genuine nor material at this time. NIPSCO points to FASB Accounting Standard Codification 980-360-35 as the source of that perceived risk.12 Paragraph 35-2 of that standard requires NIPSCO to “determine whether recovery of any allowed cost is likely to be provided.” In making that determination, paragraph 35-3 requires NIPSCO to “consider the past practice and current policies of the applicable regulatory jurisdiction on abandonment situations.” As discussed above, the past practice and current policies of Indiana utility regulation in this regard strongly suggest that a request for post-retirement cost recovery—made when a retirement is imminent or has occurred—will likely be granted. Thus, the past practice and current policies of Indiana utility regulation provide no basis for a present determination—years in advance of any actual retirement—that post-retirement disallowance of costs is probable. See FASB Accounting Standard Codification 980-360-35-3b (“Any disallowance of all or part of the cost of the abandoned plant that is both probable and reasonably estimable shall be recognized as a loss.”). To the contrary past practice and current policies suggest that recovery is probable, while disallowance is unlikely.
In past decisions allowing post-retirement recovery of costs, the Commission has allowed varying amortization periods. For example, in In Re Indianapolis Water Company, 1997 WL 34880925, Cause No. 40526 (January 15, 1997) it allowed a three-year amortization; in In Re Indiana-American Water Company, Inc., 983 WL 883539, Cause No. 37182 (December 7, 1983) the Commission allowed a ten-year amortization. In In Re Public Telephone Corporation, 1975 WL 395769, Cause No. 33914 (January 30, 1975) it allowed a five-year amortization.
The Commission has previously found its determination of the amortization period for abandoned plant “is primarily judgmental.” In Re Southside Utilities, Inc., 1982 WL 969888, *7, Cause No. 36569 (July 12, 1982). In exercising that judgment, the Commission has recognized a need to balance competing considerations. On the one hand, a “shortened amortization period is more costly to the utility's ratepayers insofar as rates are more dramatically increased to recover the loss over a shorter period of time.” Id. On the other hand, the Commission has also considered issues of intergenerational equity among ratepayers. In Re South Haven Sewer Works Inc., 1997 WL 34880736, *18, Cause 40398 (May 28, 1997) (“While a 3-year amortization period would produce rate shock, we must still allow recovery of this amortized expense over an interval sufficiently current so as to require payment from those ratepayers who benefited from this equipment.”)
11 NIPSCO Exhibit 4-S1-R (Testimony of Jennifer S. Shikany), p.7, ll.7-12. 12 See Exhibit ICC CX-1; Shikany Cross, Tr. p.B-8, ll,15-25.
34
A review of past practice regarding post-retirement recovery of costs indicates that requests for such relief are typically made when abandonment or retirement is either imminent or has occurred. Here, NIPSCO has requested that relief long before it even knows when retirements will actually occur, and years before any retirement is presently anticipated. NIPSCO seeks assurance that it will recover the sunk costs. However, NIPSCO has sought that relief too far in advance of any actual retirement for the Commission to exercise its informed judgment concerning the appropriate amortization period for post-retirement recovery of costs. Since the Commission does not know the actual retirement dates, it cannot know the actual amount of the remaining costs. It cannot know what NIPSCO’s rates will be at that time, what rate increases will have recently occurred or may be looming in the near future. It cannot know now the state of the economy at that time or the state of NIPSCO’s business at that time, nor can it know whether the economic conditions and environmental regulations that precipitated NIPSCO’s IRP results will remain in place when, for example, Michigan City is slated to retire nine years from now. In short, given what the Commission cannot know now, it cannot say now that, for example, if one or more units are retired in 2023, amortizing remaining costs over nine years will be reasonable and just at that time, nor can it say now that, if one or more units are retired in 2028, amortizing remaining costs over four years will be reasonable and just at that time. Moreover, the Commission cannot know now whether any future retirement of any unit should be adjudged reasonable and prudent at that time, nor can it determine now that as of the actual retirement NIPSCO will have done everything reasonable and prudent to minimize the remaining costs to be amortized.
The Commission should not preempt the legislature’s review of the reliability on cost impacts of early plant retirements.
The foregoing reasons are ample grounds for the Commission to defer determining appropriate post-retirement accounting treatment until an actual retirement is imminent or has occurred. However, another reason exists to defer deciding now about post-retirement accounting treatment for potential retirements not presently expected to occur until four to nine years in the future. Ind. Code ch. 2-5-45, effective July 1, 2019, creates the 21st Century Energy Policy Development Task Force (“Task Force”) whose remit is to deliver to the Indiana General Assembly and others, by December 1, 2020, its report and recommendations concerning:
(1) Outcomes that must be achieved in order to overcome any identified challenges concerning Indiana's electric generation portfolios, along with a timeline for achieving those outcomes.
(2) Whether existing state policy and statutes enable state regulators to properly consider the statewide impacts of changing electric generation portfolios and, if not, the best approaches to enable state regulators to consider those impacts.
35
(3) How to maintain reliable, resilient, and affordable electric service for all electric utility consumers, while encouraging the adoption and deployment of advanced energy technologies.
In her settlement rebuttal testimony, Ms. Shikany opined that should that Task Force’s report be followed up with material legislative changes to Indiana’s utility regulatory policies and procedures, “there will be plenty of time to reflect legislative changes should they occur.”13 However, when pressed whether the Commission could, in a future order, change relief it grants in this case concerning post-retirement accounting treatment, to reflect any legislative change, Ms. Shikany professed not to know.14
On redirect, Ms. Shikany opined that it would not be fair for a future order to change the relief granted in this case, and it would not be fair for NIPSCO to be denied either post-retirement recovery of its costs or post-retirement return on its unrecovered costs.15 While “fairness” may sometimes enter into regulatory decision making, it is unclear how it applies to post-retirement recovery of cost or return. NIPSCO Witness Rea reminds us that “cost‐of‐service ratemaking is intended to be a substitute for competition. That is, the objective of rate regulation is to produce the same results that would be achieved under the forces of market competition.”16 Fair or not, when companies in competitive markets must retire capital assets that are no longer useful or have become uneconomic, those companies have no expectation post-retirement either of recovering their undepreciated costs or earning a profit on the retired assets. Again, in rejecting this portion of the Revenue Settlement Agreement the Commission is not deciding that NIPSCO will not be allowed post-retirement recovery of costs and return on unrecovered costs. It is rather only deferring for a more appropriate time—namely when an actual retirement is imminent or has occurred—what post-retirement accounting treatment of unrecovered costs will be reasonable and appropriate at that time. There is nothing unfair about requiring NIPSCO to seek such accounting treatment when it becomes appropriate to do so. NIPSCO’s understandable desire for certainty may not be permitted to short circuit the legislature’s present scrutiny of the impacts of early plant retirements on electric reliability and electricity costs in Indiana.
13 NIPSCO Exhibit 4-S1-R (Testimony of Jennifer S. Shikany), p.9, ll.14-16. 14 Shikany Cross, Tr. p.B-21, ll.6-15. 15 Shikany Cross, Tr. p.B-34, l.24-B-35, l.7. 16 NIPSCO Exhibit 15 (Testimony of Vincent V. Rea), p.45, ll.5-7.
36
ii. Other Revenue Settlement provisions[ICC, Peabody and ICARE take no position on other provisions of the Revenue Settlement]
B. Rate 831 Settlement
[ICC, Peabody and ICARE take no position on the Rate 831 Settlement]