STATE OF INDIANA
INDIANA UTILITY REGULATORY COMMISSION
VERIFIED PETITION OF SOUTHERN INDIANA GAS AND ELECTRIC COMPANY d/b/a VECTREN ENERGY DELIVERY OF INDIANA, INC., FOR APPROVAL OF PETITIONER’S 7-YEAR ELECTRIC TDSIC PLAN FOR ELIGIBLE TRANSMISSION, DISTRIBUTION AND STORAGE SYSTEM IMPROVEMENTS, PURSUANT TO IND. CODE §8-1-39-10(A), FOR AUTHORITY TO DEFER COSTS FOR FUTURE RECOVERY, AND APPROVING INCLUSION OF VECTREN SOUTH’S TDSIC PLAN PROJECTS IN ITS RATE BASE IN ITS NEXT GENERAL RATE PROCEEDING PURSUANT TO IND. CODE § 8-1-2-23.
	)
)
)
)
)
)
)
)
)
)
)
)
)	

CAUSE NO. 44910

APPROVED:

ORDER OF THE COMMISSION

Presiding Officers:
David E. Ziegner, Commissioner
David E. Veleta, Senior Administrative Law Judge

	On February 23, 2017, Southern Indiana Gas and Electric Company d/b/a Vectren Energy Delivery of Indiana, Inc. (“Vectren South” or “Petitioner”) filed its Verified Petition (“Petition”) with the Indiana Utility Regulatory Commission (“Commission”) for approval of Petitioner’s seven-year plan for eligible transmission, distribution and storage system improvements (the TDSIC Plan”), pursuant to Ind. Code § 8-1-39-l0(a). 

	On February 23, 2017, Vectren South also filed its testimony and attachments constituting its Case-In-Chief.  Petitions to intervene were filed on February 24, 2017 by Citizens Action Coalition of Indiana, Inc. (“CAC”) and Valley Watch, Inc. (“Valley Watch”) (collectively, “CAC/Valley Watch” or “Joint Intervenors”), on March 2, 2017 by the Vectren Industrial Group on behalf of two companies (“Industrial Group”), and on April 24, 2017 by the City of Evansville.  Each petition to intervene was granted by the Presiding Officers.

	On March 24, 2017, the Industrial Group filed its Motion to Strike Attachment JKL-1 to Petitioner’s Exhibit No. 1 and Associated Testimony (“Motion to Strike”).  On March 31, 2017, the Indiana Office of the Utility Consumer Counselor (“OUCC”) filed its Notice of Joinder in Support of the Industrial Group’s Motion.  Also on March 31, 2017, Vectren South filed its Response to Motion to Strike Attachment JKL-1 and Supporting Testimony.  The Industrial Group filed its Reply in Support of the Motion to Strike on April 7, 2017.

	On April 18, 2017 the OUCC filed a request for public field hearing.  The OUCC’s request was granted and a field hearing was held on May 2, 2017 at 6:00 p.m. in the auditorium of the Academy for Innovative Studies-Diamond Campus, 2319 Stringtown Road, Evansville, Indiana.   Vectren South, the OUCC, and CAC/Valley Watch participated. Members of the general public spoke at the field hearing.

	On May 18, 2017, Vectren South, the OUCC, and the Industrial Group (the “Settling Parties”) filed the Stipulation and Settlement Agreement among Vectren South, the Vectren Industrial Group and Indiana Office of Utility Consumer Counselor (the “Settlement Agreement”).  Vectren South and the OUCC also filed testimony in support of the Settlement Agreement on May 18, 2017.

	On June 2, 2017, CAC/Valley Watch filed its case-in-chief as well as a Motion for Administrative Notice of certain materials.  Vectren South filed its rebuttal testimony along with a Partial Objection to Citizens Action Coalition of Indiana, Inc. and Valley Watch's Motion for Administrative Notice on June 12, 2017.  On June 19, CAC/Valley Watch filed the Reply of Joint Intervenors in Support of Motion for Administrative Notice of Comments on Vectren's IRP.

	A public evidentiary hearing was conducted in this Cause on 9:30 a.m. on June 29, 2017 in Room 222 of the PNC Center, 101 West Washington Street, Indianapolis, Indiana.  Vectren South, the OUCC, the Industrial Group, CAC/Valley Watch and the City of Evansville appeared at and participated in the hearing.  At the hearing, the prefiled evidence of Vectren South, the OUCC and CAC were admitted into the record without objection. The Industrial Group’s Motion to Strike was withdrawn.  Vectren South withdrew its opposition to the CAC's request for administrative notice based on the CAC’s agreement administrative notice could be taken of Vectren South’s responsive documents.  Consequently, the Commission took administrative notice of the documents presented by the CAC and Vectren South.  No members of the general public appeared or participated in the hearing.

	Based upon the applicable law and evidence presented herein, the Commission now finds:

1.	Legal Notice and Commission Jurisdiction.  

Due, legal and timely notice of the filing of the hearing in this Cause was given as required by law.  Vectren South is a public utility as that term is defined in Ind. Code §§ 8-1-2-1(a) and 8-1-39-4. Under Ind. Code § 8-1-39-10, the Commission has jurisdiction over a public utility’s request for approval of a seven-year plan for eligible transmission, distribution, and storage improvements. Under Ind. Code § 8-1-39-9, the Commission has jurisdiction over a public utility's request to recover eligible transmission, distribution, and storage system costs through a periodic rate adjustment. Therefore, the Commission has jurisdiction over Vectren South and the subject matter of this proceeding.

2.	Petitioner’s Characteristics.  

	Vectren South is a public utility incorporated under the laws of the State of Indiana. It has authority to engage in and is engaged in rendering electric service and natural gas distribution service within Indiana. Vectren South owns, operates, manages, and controls, among other things, plant, property, equipment, and facilities that are used and useful for the production, storage, transmission, distribution, and furnishing of electric utility service to approximately 144,000 customers and natural gas utility service to approximately 111,000 customers in southwestern Indiana.  Petitioner is a wholly-owned subsidiary of Vectren Utility Holdings, Inc. (“VUHI”), which is a wholly-owned subsidiary of Vectren Corporation (“Vectren”).  Vectren is a holding company whose stock is publicly traded and listed on the New York Stock Exchange. VUHI also owns all of the common stock of Indiana Gas Company, Inc. d/b/a Vectren Energy Delivery of Indiana, Inc. (“Vectren North”) and Vectren Energy Delivery of Ohio, Inc. (“VEDO”).  

3.	Relief Requested

	Vectren South requests approval of its proposed TDSIC Plan under Ind. Code § 8-1-39-10, as agreed upon in the Settlement Agreement.  Specifically, Vectren South requests that the Commission: 

	(a) 	approve, as “eligible transmission, distribution, and storage system improvements” within the meaning of Ind. Code § 8-1-39-1 et seq. (the “TDSIC Statute”), the projects and programs designated in the TDSIC Plan, as updated pursuant to the Settlement Agreement; 

	(b) 	find the project cost estimates presented in the updated TDSIC Plan reflect the best estimates of Vectren South’s TDSIC Plan costs;  

	(c) 	determine that the public convenience and necessity require or will require the eligible improvements included in the TDSIC Plan;  

	(d) 	determine that the estimated costs of the eligible improvements included in the TDSIC Plan are justified by incremental benefits attributable to the plan; 

	(e) 	approve the TDSIC Plan as reasonable and designate the eligible transmission, distribution and storage system improvements included in the plan, including the substitute projects, as eligible for Transmission, Distribution and Storage System Improvement Charge treatment in accordance with Ind. Code § 8-1-39-10; 

	(f) 	authorize deferral of 100% of the depreciation associated with Vectren South’s Advanced Metering Infrastructure (“AMI”) project for recovery in a subsequent Vectren South retail base rate case;  

	(g) 	approve recovery of the deferred depreciation associated with the AMI project over a 10-year period without carrying costs in Vectren South’s subsequent retail base rate case;  

	(h) 	approve deferral of debt-related post-in-service carrying costs associated with the AMI project at a debt rate of 4.77% in an amount not to exceed $12 million for recovery in a subsequent Vectren South retail base rate case;  

	(i)	approve a cap of the investment of AMI eligible for deferral of $39 million. 

	(j) 	approve the ratemaking and accounting proposals contained in the Settlement Agreement for recovery of 80% of up to $446.5 million TDSIC Plan costs, and deferral with carrying costs of 20% of the TDSIC Plan costs for recovery in a subsequent Vectren South retail base rate case;  

	(k) 	approve the agreed-upon methodology for recovering TDSIC costs, as well as the other terms in the Settlement Agreement relating to future ratemaking treatment; 

	(l) 	approve Vectren South’s proposed process for updating the TDSIC Plan in future annual proceedings consistent with the Settlement Agreement; and 

	(m) 	approve Appendix K, the Transmission, Distribution, and Storage System Improvement Charge (the “TDSIC”) along with the other miscellaneous tariff change.

	4.	Petitioner’s Case-in-Chief Evidence.  

		A.  	Direct Testimony of Jon K. Luttrell  

	Jon K. Luttrell, Senior Vice President, Utility Operations of Vectren and President of its subsidiary VUHI, explained, at a high level, why the TDSIC Plan, in his opinion, is necessary to ensure Vectren South can continue providing safe, resilient and reliable service to its customers and summarized the modernization made possible by the TDSIC Plan.  Mr. Luttrell testified that the TDSIC Plan is designed to achieve the goals and objective of Senate Enrolled Act 560 by carefully studying system and asset performance and subsequently identifying the projects that most promote reliability, resiliency, and safety while ensuring service and reliability benefits to customers.  To that end, Mr. Luttrell stated that, in his opinion, each program makes its own unique contribution to safety, resilience and reliability.

	Mr. Luttrell testified that the primary benefits customers will receive from the TDSIC Plan are enhanced reliability, resiliency and safety.  Mr. Luttrell further testified that the TDSIC Plan represents an opportunity to stay ahead of aging facilities and make modernization investments that benefit customers. In Mr. Luttrell’s opinion, under a traditional ratemaking approach, Vectren South would be challenged to allocate this level of capital without the beneficial timing that Senate Enrolled Act 560 provides with timely investment cost recovery.  

	Mr. Luttrell noted that Vectren South commissioned a study by the Indiana Business Research Center, Kelley School of Business, Indiana University to evaluate the economic benefits resulting from the TDSIC Plan.  Mr. Luttrell testified that, despite his lack of personal knowledge of direct involvement with the study, the study concluded the economic effects of Petitioner’s TDSIC investment are “expected to generate an average of more than $91.4 million per year in total economic output” in the Vectren South service area and “support an estimated 770 jobs over the next seven years” – with the total economic impact to the Vectren South service area over the seven year period being $640 million. See, Petitioner’s Exhibit No. 1, Attachment JKL-1.   

		B.  	Direct Testimony of Lynnae K. Wilson  

	Lynnae K. Wilson, Vice President of Energy Delivery for VUHI, sponsored and described the TDSIC Plan.  The TDSIC Plan was attached to Ms. Wilson’s testimony as Petitioner’s Exhibit No. 2, Attachment LKW-1, and included a list of the programs and projects to be completed as well as cost estimates for each.  Ms. Wilson testified that the TDSIC Plan focuses on system investments that enhance system reliability, reduce system risk, improve customer experience, and optimize the electric grid to accept new technology.  Ms. Wilson stated that the improvements in the TDSIC Plan initially were identified by Petitioner’s trained group of employees who serve as subject matter experts (“SMEs”) in Engineering, Field Operations, and System Operations.  Following an internal review of the potential programs and projects the SMEs identified, Ms. Wilson testified that Vectren South partnered with Black & Veatch Management Consulting LLC (“B&V”) to review internal assessments and prioritizations and identify additional programs and projects.  Ms. Wilson testified that the potential programs were subjected to a screening process to validate that they met the requirements of Senate Enrolled Act 560.

	Ms. Wilson stated that, in her opinion, flexibility is an essential component of the TDSIC Plan. Ms. Wilson stated that projects may shift to different years as Vectren South assesses risks and reprioritizes investments and system needs.  Particularly in the later years of the TDSIC Plan, Ms. Wilson stated that Vectren South may decide to delay a project beyond the seven-year period of the TDSIC Plan and replace it with another project from its list of potential substitution projects designated in the TDSIC Plan.  Ms. Wilson testified that the projects on the substitute project list were subjected to the same engineering and estimation process as the projects in the TDSIC Plan.

	Ms. Wilson testified that each project and each program completed in Vectren South’s TDSIC Plan will bring customers enhanced system reliability, safety, resilience, and modernization.  Ms. Wilson testified that the TDSIC Plan directly enhances system reliability and system resilience, public safety and employee safety and overall quality of service for Vectren South customers.  Ms. Wilson offered her opinion that the TDSIC Plan also ensures that Vectren South’s electric infrastructure continues to perform in the safe, efficient and reliable manner that our customers rely upon.  

		C.  	Direct Testimony of William D. Williams  

	William D. Williams, Associate Vice President in the Asset Management Practice of B&V, summarized the methodology used by B&V to develop a risk-based model of Vectren South’s transmission and distribution assets and described the results and conclusions of that “Risk Model,” stating that the Risk Model analyzes the consequence of failure and likelihood of failure of various assets and uses this information to calculate risk for each of the assets.  Mr. William stated that the Risk Model was used to develop a prioritized list of projects, based on the risk score, replacement cost, and other resource constraints, of all the assets evaluated by the model. Mr. Williams testified that by highlighting the highest risk assets on Vectren South’s system with the Risk Model, the Vectren South team was able to develop asset specific TDSIC Plan projects, which consist of all types of assets, and utilize the results of the Risk Model to optimize project selection to ensure that assets representing the highest risk to the system are included in the TDSIC Plan.

	Mr. Williams testified that the B&V and Vectren South team were able to use the Risk Analysis to determine that the proposed TDSIC Plan would reduce the total T&D system risk by 40% over the seven years of the study period as compared to allowing the assets to “run to failure.” Mr. Williams stated that this result is driven by significant substation and circuit risk reduction, which represents a 46% and 19% reduction in potential asset failures, respectively.  Mr. Williams stated that, in his opinion, (i) the TDSIC Plan is an optimized plan that prioritizes investment for eligible transmission and distribution improvements using risk reduction as a primary objective, while minimizing TDSIC recovery costs; and (ii) by implementing the plan, total T&D system asset risk is significantly reduced, providing incremental benefits to Vectren South’s system and customers in terms of improved service reliability.

		D.  	Direct Testimony of Daniel C. Bugher, Sr.  

	Daniel C. Bugher, Sr., Vice President of Customer Experience for VUHI, described Vectren South’s AMI project, and gave an overview of AMI and how he believes it will benefit Vectren South customers and modernize the electric system.  Mr. Bugher testified as to the benefits that AMI will bring to various areas of Vectren South’s business, including metering, system billing, field meter services, customer call center, revenue management, revenue protection, load research, outage management, energy conservation/demand side management, distribution engineering and strategic planning.  Mr. Bugher testified how these benefits will inure to customers and how the AMI system will help improve the reliability of Vectren South’s electric distribution system, as well as improve customer engagement, operation efficiency and energy management.  Mr. Bugher described how, in his opinion, AMI will further the public convenience and necessity  by enabling Vectren South to improve quality of customer bills, improve customer access to their specific energy detail, improve timeliness and accuracy in addressing power outages, improve cost of performance for meter reading, as well as improve safety in performing outage work, among other benefits.  

	Mr. Bugher discussed the deployment of the AMI system stating that it would begin in 2017 with completion planned for summer of 2019.  He further testified regarding the customer engagement process during deployment. He stated that the customer engagement process is designed to provide timely notice to its customers along with the opportunity to learn and ask questions about AMI.  He stated communications will include press releases to targeted deployment areas one to two months in advance, information on Vectren South’s website and through Vectren South’s contact center, and bill messaging on statements, proactive calls and emails, as well as personal communications through door hangers and outbound calls. 
 
		E.  	Direct Testimony of Andrew Lewis Trump  

	Andrew Lewis Trump, Director of Utility Practice for B&V, described Vectren South’s cost and benefit evaluation of the AMI system as well as the results of the evaluation.  Mr. Trump testified that the AMI evaluation was a collaborative process between B&V and Vectren South to uncover how AMI will influence Vectren South’s business. He testified that the methodology for completing the cost benefit evaluation involved organizing the 121 separate cost items into four categories:  1) meters and their installation; 2) AMI communications network; 3) back office information technology applications and operations; and 4) program management.  Mr. Trump testified that costs were estimated over a 20-year period beginning in 2017.  He discussed that costs were further classified in order to ensure that they could be properly described and recognized as part of the TDSIC plan, Vectren South budgets and the cost and benefit evaluation.  The classifications included categories such as “build period”, operating period costs, TDSIC Period costs, and TDSIC Eligible costs among others.  Mr. Trump testified that the TDSIC eligible costs did not include any operation and maintenance expense, and only included costs in years 1 through 7 for distribution plant assets.  IT-related costs were also excluded from the TDSIC costs.  

	Mr. Trump also testified that while Vectren South’s AMI communications network will benefit both electric and gas customers, there are no gas-related costs within the electric TDSIC eligible cost estimate.  He stated that Vectren South applied a 90% cost allocation factor to the electric costs for joint use devices.  

	Mr. Trump testified that the cost estimate for the AMI system includes a contingency of $5.4 million, of which $3.4 million would be recovered through the TDSIC if incurred.  He further testified that the planning, building, testing, commissioning, and operation of the electric AMI system is estimated at $77.7 million over a 20 year period, beginning in 2017.  He stated for the 7-year TDSIC period, the cost is estimated at $51 million, of which $39 million is recoverable through the TDSIC.  Mr. Trump also sponsored attachments describing the alleged benefits opportunities, with the 66 benefit impact areas in Attachment ALT-1.  Attachment ALT-2 describes each of the alleged monetized financial benefits in further detail.  Mr. Trump concluded that the net benefit of AMI exceeds costs by over $70 million over the 20-year evaluation period.

		F.  	Direct Testimony of Steven A. Hoover 

	Steven A. Hoover, Director of Engineering for VUHI, described the methodology Vectren South utilized to develop cost estimates for the projects that make up the TDSIC Plan.  Mr. Hoover stated that Vectren South’s methodology for developing cost estimates was a comprehensive and detailed process utilizing both internal and external subject matter experts.   Mr. Hoover stated that Vectren South’s Engineering team determined all projects in the TDSIC Plan would be estimated consistent with the recommended practices of AACE International (“AACE”), formerly Association for the Advancement of Cost Engineering International.    He testified that projects planned to be completed in the first two years of the TDSIC Plan were designed to a Class 2 criteria and the remaining projects have been designed to AACE Class 4 estimate criteria.  He stated that Class 2 estimates have accuracy ranges of -15% to +20% and Class 4 estimates have accuracy ranges of -30% to +50%.  Mr. Hoover testified that Vectren South engaged the assistance of B&V and two other engineering firms to work with internal resources in the development of Vectren South’s cost estimates.  Mr. Hoover said that Vectren South will incur an estimated $3.7 million in costs with external firms, made up of plan development, engineering/cost estimation, risk model creation, and case support.

	Mr. Hoover testified that estimates for years one and two transmission and substation projects include a 15% contingency placed on the labor and engineering.  Vectren South, in consultation with B&V, determined to establish the labor, subcontract, equipment, and engineering contingency at 40% for transmission and substation projects in years three through seven of the TDSIC Plan.  He stated that estimates for years one and two distribution projects include a 5% contingency placed on the entire estimate to account for potential unknown labor or material factors and that  estimates for years three through seven include a 12-18% contingency based on the type of project.    
	
Mr. Hoover stated that Vectren South has high confidence in the accuracy and completeness of the TDSIC Plan’s project cost estimates.  He testified that Vectren South and B&V both performed a review of the estimates, which indicated the cost estimating process and the estimates are reasonable.  Mr. Hoover stated that, in his opinion, the level of detail used to develop the Vectren South transmission and distribution project cost estimates is consistent with common practice within the industry.

		G.  	Direct Testimony of Scott E. Albertson  

	Scott E. Albertson, Vice President of Regulatory Affairs and Gas Supply for VUHI, described Vectren South’s proposal for the allocation of TDSIC costs as well as its proposed rate design for the recovery of TDSIC costs.  He testified as to his description of Petitioner’s use of transmission and distribution revenue requirements from its last rate case to allocate TDSIC costs in compliance with Ind. Code § 8-1-39-9(a).  Mr. Albertson testified as to Vectren South’s proposal for its TDSIC rate adjustment mechanism, which proposes for the first time by any Indiana electric investor-owned utility to recover the distribution revenue requirement amount via a fixed monthly charge and the transmission revenue requirement through a volumetric (kilowatt hour) charge for Residential Standard and Water Heating and Small General Service customers.  He stated that for the remaining rate schedules, with the exception of Street Lighting and Outdoor Lighting, Vectren proposed to recover both the distribution and transmission revenue requirement amounts via a demand charge.  Vectren also proposed that Street Lighting and Outdoor Lighting customers pay fixed monthly charges as the lights are unmetered.  Mr. Albertson stated his opinion that the proposed TDSIC cost allocation is consistent with cost causation principles so that customers who cause costs to be incurred pay for those costs through their applicable rates.  He testified as to his opinion that Vectren South’s methodology is consistent with the TDSIC statute in that it uses the customer class revenue allocation factors specific to transmission and distribution from Petitioner’s last rate case.  

	Mr. Albertson testified that Vectren South’s TDSIC rate design principles are based on the following proposed objectives:  to allegedly provide accurate price signals to customers based upon the costs attributed to service and to allegedly eliminate or mitigate intra-class subsidies that Vectren says would result from how customers with the same or similar power requirements use energy differently.  Mr. Albertson testified that under Vectren South’s current rate design, most of its fixed costs (about 90%) are recovered through energy charges.  He further stated that Vectren South is proposing a gradual increase in fixed charges over time via the TDSIC, which would result in about 80% of Petitioner’s fixed costs being recovered in an energy charge at the end of the seven-year plan period.  He testified that Vectren’s position is that continuing to recover fixed costs via energy charges would continue to send inaccurate price signals to customers and exacerbate intra-class subsidies.  Mr. Albertson testified that sending the appropriate price signals to customers is part of a framework by which customers can begin to better understand the cost of utility services.

		H.  	Direct Testimony of Russell A. Feingold  

	Russell A. Feingold, Vice President and leader of the Rates & Regulatory Services Practice for B&V, reviewed and provided commentary and background in support of Vectren South’s cost allocation and rate design proposals.  Mr. Feingold found that, in his opinion, Vectren South’s rate design proposal is appropriate for customers billed under two-part rates, which includes residential and small general service customers, to recover Vectren South’s distribution-related TDSIC Plan costs in the fixed monthly charges and to recover the transmission-related TDSIC Plan costs in the variable energy charges.  He testified that, in his opinion, Vectren South achieved a reasonable balance of the underlying cost causative characteristics of its TDSIC Plan costs and the principle of gradualism through the recognition of customer bill impact considerations.

	Mr. Feingold described the changes occurring in the electric utility industry that are driving the need for a re-alignment of fixed costs and fixed cost recovery, including rapid technological change, customer demand for more energy choices, legislative initiatives, economic changes, and new ways in which  customers are utilizing the utility delivery system.  He also testified that the residential class of service has evolved and is becoming less homogenous over time, which under a two-part rate structure can create intra-class subsidies.  He stated that, in his opinion, if subsidies become too great it would become very difficult to eliminate them without resulting in an adverse impact on customers accustomed to receiving them.  Mr. Feingold testified that, in his opinion, since rates are designed based on the cost and load characteristics of the “average customer” in the class, as the load characteristics of customers in a class become more diverse over time, the ability of a two-part rate structure to charge customers on a fair and equitable basis is diminished unless changes are made to the relative levels of the fixed and variable charges in the rate structure.  Mr. Feingold testified that if a portion of an electric utility’s fixed costs are recovered through a variable part of the rate structure, as is true for Vectren South, he believes it can create a mismatch between the costs incurred by the utility and the revenues generated to recover those costs.  He stated that this in turn skews the price signals to customers provided from rates.

	Mr. Feingold testified that Vectren South’s revenue allocation method appropriately reflects the fixed nature and cost causative characteristics of its transmission and distribution costs and that Vectren South’s proposal, in his opinion, recognizes the need to minimize cross-subsidies in its rates while giving consideration to customer bill impacts and rate gradualism.

		I.  	Direct Testimony of J. Cas Swiz  

	J. Cas Swiz, Director, Rates and Regulatory Analysis for VUHI, discussed the accounting relief Vectren South requested related to the TDSIC Plan.   Mr. Swiz stated that, consistent with TDSIC Statute, Vectren South is requesting authority to recover 80% of the eligible TDSIC Plan revenue requirement via a newly established TDSIC mechanism, and authority to defer the remaining 20% of the revenue requirement until a subsequent base rate proceeding.  In addition, Mr. Swiz stated that Vectren South is requesting authority to defer depreciation and post-in-service carrying costs (“PISCC”) on eligible TDSIC Plan projects until inclusion for recovery in the TDSIC mechanism.  Mr. Swiz testified that Vectren South proposes to use a weighted average cost of capital (“WACC”) for the TDSIC based upon the actual capital structure at the end of each respective measurement period in the TDSIC, inclusive of the typical items included in Petitioner’s base rate case capital structure: (1) long-term debt, (2) common equity, (3) customer deposits, (4) cost free capital, including deferred income taxes, and (5) investment tax credits.   Consistent with the TDSIC Statute, Mr. Swiz stated the balances and cost of debt will be based on the actual amounts, and the cost of equity will be set at 10.4%, as approved in Petitioner’s last base rate case Order, i.e., Cause No. 43839 (approved April 27, 2011).

	Mr. Swiz further stated that Vectren South has incurred costs throughout 2016 to assist in the development of the TDSIC Plan and proposes to amortize and recover this deferred balance through the TDSIC over a period of three (3) years.  In addition, Mr. Swiz noted that Vectren South is seeking authority through the establishment of the TDSIC to recover depreciation and property tax expenses associated with TDSIC Plan investments.

	Mr. Swiz also testified about the proposal for the “migration adjustment” reflected in the allocation of TDSIC revenues.  Mr. Swiz stated that in Vectren South’s last rate case, Rate HLF consisted of two (2) customers.  As of 2017, one of those customers has invested in a customer-owned cogeneration facility, reducing the load required from Vectren South to serve its facilities and has requested non-firm backup service from Vectren South.  Mr. Swiz stated that to avoid the remaining Rate HLF customer paying the fully allocated share of Rate HLF costs, Vectren South has modified the allocation percentages by migrating this customer from Rate HLF to Rate LP at the amount included in the rate case.  

	Finally, Mr. Swiz testified that Vectren South proposes to file its TDSIC petitions and cases in chief every six months, specifically on August 1 and February 1 of each year, with new TDSIC rates and charges becoming effective for the six month periods beginning November 1 and May 1, respectively.  Mr. Swiz explained that this proposed schedule is designed to avoid conflicts with Vectren South’s and Vectren North’s Gas TDSIC filings, which are filed April 1 and October 1 of each year, for the benefit of the Commission, the OUCC, and other potential parties to the proceedings, including Petitioner.  

	5.	The Settlement Agreement.  

Prior to the OUCC and Intervenors filing their respective cases-in-chief, the Settling Parties filed the Settlement Agreement with less than all the parties.  The Settlement Agreement proposes a resolution to all disputes, claims and issues arising from the Commission proceeding regarding Vectren South’s TDSIC, as between the Settling Parties.  The following summarizes the terms of the Settlement Agreement proposed to the Commission:

		A. 	Overall Scope of TDSIC Plan 

	Vectren South agreed to limit recovery through the TDSIC ratemaking treatment of its direct and indirect capital costs actually expended upon its TDSIC Plan to $446.5 million over the seven-year TDSIC period (exclusive of TDSIC Plan development costs) – a reduction in capital costs of approximately $67.5 million from its originally-filed TDSIC Plan.  The agreed-upon TDSIC Plan revises the filed TDSIC Plan proposal in the following manner:  

(a) the AMI program ($39.0 million in the originally-filed Plan) would not be included in the TDSIC Plan, although Vectren South stated its intention to continue with its planned AMI deployment; 

(b) the Advanced Distribution Management System program ($8.2 million in the originally-filed Plan) would not be included in the TDSIC Plan; 

(c) the Geomagnetic Disturbance Protection program ($1.2 million in the originally-filed Plan) would not be included in the TDSIC Plan; 

(d) the Mobile Asset Data Collection program ($1.1 million in the originally-filed TDSIC Plan) would not be included in the TDSIC Plan; 

(e) the Substation Physical Security Upgrades program ($2.9 million in the originally-filed TDSIC Plan) would not be included in the TDSIC Plan; 

(f) project contingency factors would not exceed 15% for years 1-3 of the TDSIC Plan (i.e., 2017 through 2019) and 25% for years 4-7 of the TDSIC Plan (i.e., 2020 through 2023); 

(g) the capital cost of projects included in the TDSIC Plan would be allocated Engineering and Supervision (E&S) costs and Administrative and General (A&G) costs expense on a combined basis not to exceed 18% of the direct capital cost; 

(h) the cost of removal associated with projects in the TDSIC Plan would not be included as part of the projects’ net capital investment balance eligible for a return recoverable in the TDSIC mechanism; 

(i) some projects would be moved from substitution projects—as identified in the Filed TDSIC Plan proposal—to projects planned to be completed during the seven-year period of the TDSIC Plan and the number of substitution projects was reduced.  

The Settling Parties agreed in their proposed Settlement with less than all the parties to a TDSIC Plan which would include designated substitution projects, which Vectren South may construct and the costs of which it my recover through the TDSIC rates and charges provided that performance of any such substitution projects would not cause Vectren South to exceed the capital spending caps noted below.  The planned substitution projects that would be eligible to be moved into the TDSIC Plan would be limited to a capital cost of $67 million.

The Settling Parties agreed in their proposed Settlement with less than all the parties that Vectren South provided sufficient project detail and program descriptions and sufficient cost estimates for the projects included in the TDSIC Plan.  The Settling Parties also agreed in their proposed Settlement that the costs of the TDSIC Plan are justified by the benefits of the plan.  

However, it is important to note the following caveats included in the Settling Parties’ testimony submissions.  OUCC Witness Rutter testified:

Q:  In general, does the OUCC support TDSIC cost recovery through fixed charges?  
A:  No. The OUCC contends that, among other reasons, fixed charge increases provide inefficient pricing signals, and limit the ability of customers to control their own bills.  The OUCC does not generally support changes to rate design in expedited tracker proceedings, contending that rate cases are a more appropriate venue for such changes, based on evidence that shows how a utility’s costs are incurred.  

Vectren Witness Feingold said:  

As I note from my review of the settlement testimony of OUCC Witness Rutter, the OUCC has reserved the right to address rate design issues related to the use of fixed monthly charges in future utility proceedings before the Commission.  The rebuttal testimony I present in this Cause presents Vectren South’s response to a Joint Intervenor witness and it includes arguments that Vectren South believes to be valid and appropriate, but that should not be interpreted as a policy position held by any of the Settling Parties other than Vectren South.

Petitioner’s Exhibit 14, p. 3, lines 4-9.  Vectren Witness Albertson similarly said: 

As indicated in the settlement testimony of OUCC Witness Rutter, the OUCC has reserved the right to debate fixed charge recovery issues in future proceedings.  Further, I expect the OUCC may not agree with many of the arguments Vectren South believes are reasonable justifications for recovering a portion of TDSIC costs via fixed charges…The testimony I present below represents Vectren South’s response to Joint Intervenor witnesses, including arguments Vectren South believes to be valid and appropriate, but that should not be interpreted as a policy position held by any of the Settling Parties other than Vectren South. 

Petitioner’s Exhibit 13, p. 2, line 29—p. 3, line 8.

		B. 	Recovery of TDSIC Costs 

	Pursuant to Ind. Code ch. 8-1-39, eighty percent (80%) of approved capital expenditures and TDSIC costs will be recovered through the TDSIC rate adjustment mechanism and twenty percent (20%) will be authorized to be deferred for subsequent recovery in Vectren South’s next base rate case.  As the 20% deferral already includes income taxes, Vectren South will not include a gross-up for income taxes on this deferred balance at the time of the next base rate case.  

		C. 	Plan Flexibility 

	The Settling Parties agreed Vectren South should be authorized to implement components of the TDSIC Plan in good faith up to the $446.5 million cap over a seven-year period, but should have flexibility to adjust the Plan as circumstances dictate, such as system changes, reliability issues, or reasonable and prudent cost changes.  The Settling Parties agreed to cap the capital investment in each year of the TDSIC Plan as proposed in the chart below, subject to a 5% tolerance for each year of the TDSIC Plan:

Year	Cap	
2017	$38,153,000	
2018	$53,925,000	
2019	$64,723,000	
2020	$68,098,000	
2021	$77,535,000	
2022	$80,838,000	
2023	$63,236,000	

		D. 	TDSIC Tracker Filings 

	The Settling Parties agreed the first tracker filing will occur on August 1, 2017 to establish TDSIC rates and charges to be implemented with the first billing cycle starting November 1, 2017, or as soon thereafter as is practicable.  This first tracker filing will be based on TDSIC Plan costs and investments as of April 30, 2017.  The second tracker filing will be made on or about February 1, 2018, with rates to be effective with the first billing cycle of May 1, 2018.  The petition filed on February 1 will be based on capital investments and expenses through the period ended October 31. Subsequent tracker filings will occur semi-annually each August and February thereafter.

		E.	AMI 
	
	In consideration for Vectren South’s agreement to remove AMI project capital from the TDSIC Plan, the Settling Parties agreed Vectren South may retain any savings associated with the AMI project until the time of its next base rate case. The Settling Parties further agreed to allow Vectren South to defer, without carrying costs, 100% of the depreciation costs associated with the AMI project. The Settling Parties also agreed to defer post-in-service carrying costs, up to a maximum of $12 million, associated with the AMI project for recovery in Vectren South’s next base rate case. To calculate the carrying costs on the AMI project, Vectren South will use the debt only post-in-service carrying cost rate of 4.77% until $12 million is reached after which no additional post-in-service carrying cost will be deferred.  The total investment eligible for accounting treatment cannot exceed $39 million.

		F.	Customer Programs 

	Vectren South will not offer dynamic or time of use price options as mandatory price options to any of its residential customers for the next seven (7) years.  In addition, Vectren South agreed to make any prepaid service associated with its AMI capabilities optional, unless and until Indiana passes legislation, or the Commission via a rulemaking establishes some form of prepayment option that is mandatory for certain customers.

		G. 	Low-Income Customer Reporting Requirements 

	At the request of the one or more Settling Parties, but no more often than annually, Vectren South agreed to make available in spreadsheet format certain specified data with respect to its customers that receive benefits from the Low Income Home Energy Assistance Program (“LIHEAP”) during the July 1 through June 30 period preceding the request. 

		H. 	Return on Equity  

	The Settling Parties agreed the Return on Equity (“ROE”) included in the WACC for projects in the TDSIC Plan will be 10.4%.

		I.	Other Ratemaking Agreements  

	The Settling Parties reached a number of other agreements regarding future ratemaking:	
			
		(i)	Depreciation and Property Tax Expense. Depreciation expense included for recovery in the TDSIC Plan will reflect an annualized level of expense related to the gross new capital investment as of the cut-off date of the TDSIC filing. Property tax expense included for recovery in the TDSIC will reflect an annualized level of expense related to the gross new capital investment as of the cut-off date of the filing.  Vectren South will net the depreciation expense associated with retired and replaced equipment against the depreciation expense associated with new equipment in the TDSIC Plan.

		(ii)	CWIP Ratemaking Treatment.  Vectren South will recover, through the TDSIC mechanism, financing costs incurred during the construction period attributable to TDSIC Plan eligible capital investments.

		(iii)	TDSIC Plan Development Costs. Vectren South has incurred $3.7 million throughout 2016 to assist in the development of the TDSIC Plan, including asset risk modeling and the development of detailed project estimates.  The Settling Parties agreed Vectren South should amortize and recover this deferred balance through the TDSIC over a period of three (3) years.

		(iv)	Cost Allocation.  The Settling Parties agreed Vectren South should be authorized to allocate TDSIC costs to the rate schedules using allocation percentages based on the “firm load approved in” Vectren South’s most recent retail base rate case order.  In connection with a large customer that was served under Rate HLF at the time of Vectren South’s most recent general rate case but has since installed cogeneration facilities, the Settling Parties recognized the customer has migrated to Rate LP for its remaining firm generation load, with non-firm service provided under Rate BAMP.

(iv)	Rate Design.  The Settling Parties agreed that, in TDSIC-1, for customers served under Rate Schedules RS, B, and SGS, distribution-related costs will be recovered via a per customer charge up to a cap of $0.50 per customer per month.  The cap on the monthly fixed TDSIC charge will grow by $0.50 per customer in each semi-annual filing (e.g., TDSIC-2 would be capped at $1.00 per customer per month), with the overall distribution-related fixed TDSIC charge not to exceed $7.00 per customer per month by the end of the seven year plan period.  Distribution-related TDSIC costs exceeding the applicable cap, and all transmission-related TDSIC costs, will be included in the energy charge (per kWh).  For customers receiving service pursuant to Rate Schedules DGS, MLA, OSS, LP, BAMP and HLF, the entirety of the tracked portion of approved capital expenditures and TDSIC costs will be recovered through demand charges.

		J.	Other

	The Settling Parties agreed any proposals not specifically addressed in the Settlement Agreement are as in Vectren South’s case in chief testimony and exhibits.

	6.	Evidence Supporting Settlement Agreement

		A.	Petitioner’s Evidence in Support of the Settlement Agreement

			1.	Lynnae K. Wilson  

	Vectren South witness Wilson testified that the Settlement Agreement is the product of extended negotiations among the Settling Parties, conducted on an arms’ length basis prior to the deadline by which the OUCC and intervenors were to file their respective cases-in-chief.  Ms. Wilson stated that the Settlement Agreement is intended to resolve all disputes, claims and issues that were or could have been raised among the Settling Parties in Cause No. 44910.  Ms. Wilson noted that all of the parties that were granted authority to participate in this proceeding were invited to the settlement discussions.  Counsel for CAC/Valley Watch participated in the meetings and the Settling Parties made a good faith effort to understand their position.  Vectren South’s counsel communicated with the City of Evansville’s counsel throughout the discussions.  

	Ms. Wilson stated that the Settlement Agreement supports Vectren South’s TDSIC Plan to maintain the reliability of its transmission and distribution (“T&D”) system over the period of 2017-2023.  Ms. Wilson noted that the projects described in Vectren South’s case-in-chief that were carefully studied and engineered remain largely intact with negotiated modifications that provide more certainty regarding the scope and cost of the TDSIC Plan.

	Ms. Wilson sponsored Petitioner’s Exhibit 10, Attachment LKW-S2, an updated list of the projects that constitute Vectren South’s TDSIC Plan. Ms. Wilson stated that the revised TDSIC Plan excludes the projects and programs listed above and includes revised contingency factors and cost allocation factors.  In addition, Ms. Wilson indicated that certain projects Vectren South previously designated as substitution projects were moved to the TDSIC Plan.  The estimated cost of the TDSIC Plan, as revised pursuant to the Settlement Agreement, is approximately $446.5 million.  Vectren South has also agreed to a $446.5 million hard cap on the amount of trackable TDSIC Plan costs.  Ms. Wilson stated that although the TDSIC Plan was reduced in scope, the revised TDSIC Plan will preserve the reliability, resiliency and integrity of the transmission and distribution systems in Vectren South’s service territory and Indiana.  In addition, Ms. Wilson testified that the TDSIC plan will modernize portions of the transmission and distribution systems.  

	Ms. Wilson also discussed the Settling Parties’ agreement that Vectren South be authorized to defer 100% of the depreciation associated with the AMI project for recovery in a subsequent Vectren South retail base rate case, with the amount of AMI project costs subject to deferral capped at $39 million.  Ms. Wilson stated that Vectren South believes AMI is a critical investment in the modernization of the distribution grid.  In Ms. Wilson’s opinion, the Settlement Agreement constitutes a reasonable middle ground whereby AMI is not included in the TDSIC, but the deferral accounting authority will allow Petitioner to go forward with its AMI plan without material earnings erosion.

	Ms. Wilson stated that the updated TDSIC Plan directly enhances system reliability and system resilience, public safety and employee safety and overall quality of service for Vectren South customers.  She testified that it ensures that Vectren South’s electric infrastructure continues to perform in the safe, efficient and reliable manner that our customers rely upon.  Ms. Wilson concluded that the Settlement provides a reasonable balance to the many issues presented in this proceeding. 

			2.	Scott E. Albertson  

	Vectren South witness Albertson testified regarding the cost allocation and rate design components of the Settlement Agreement.  He provided the chart below, setting forth the proposed allocation methodology for the rate schedules of transmission and distribution percentages:

Rate Schedule	Transmission Allocation Percentage	Distribution Allocation Percentage	
RS	42.62%	58.44%	
B	0.13%	1.12%	
SGS	1.82%	4.10%	
DGS/MLA	27.33%	22.53%	
OSS	2.12%	2.32%	
LP	25.33%	10.59%	
HLF	0.65%	0.01%	
SL/OL	0.00%	0.89%	

	Mr. Albertson testified that the rate design for recovery of TDSIC costs was agreed upon by the Settling Parties so that TDSIC costs will be recovered via a demand charge from Rate DGS, Rate MLA, Rate OSS, Rate LP, and Rate HLF.  He stated the proposal to have residential customers and small general service customers (Rates RS, B and SGS) pay a fixed monthly TDSIC charge for distribution-related costs up to a capped fixed charge that will grow by $0.50 per customer in each semi-annual TDSIC filing.  He stated that the distribution-related fixed TDSIC charge would not exceed $7.00 per customer per month in TDSIC-14, and that distribution costs exceeding the applicable fixed charge cap, along with transmission related costs would be included in an energy charge.  Mr. Albertson concluded that the TDSIC rate design agreed to by the Settling Parties results in a smaller percentage of distribution costs recovered via fixed charges than what was proposed in Vectren South’s case-in-chief.

			3.	J. Cas Swiz  

	Vectren South witness Swiz testified regarding aspects of the Settlement Agreement pertaining to capital overheads, cost of removal, AMI, the procedural schedule for Vectren South’s semi-annual TDSIC filings and the estimated customer impact of the Settlement TDSIC Plan.  Mr. Swiz testified that Vectren South included two types of capital overheads in the TDSIC Plan construction costs:  Engineering and Supervision (“E&S”) and Administrative and General (“A&G”).  He stated that the Settling Parties agreed that capital overheads associated with E&S and A&G would be no more than 18% for each TDSIC Plan project.  Mr. Swiz testified regarding the Settling Parties agreement to exclude costs of removal of retiring assets being replaced as part of a TDSIC capital project.  He noted that Vectren South will seek to include the incurred cost of removal as part of net utility plant proposed within rate base in Vectren South’s next general rate case.  Mr. Swiz testified that the Settling Parties agreed to remove Vectren South’s proposed AMI project from the TDSIC Plan.  He stated the Settling Parties proposed to allow the AMI project to be deferred without carrying costs, the depreciation associated with the AMI project and to defer debt related PISCC associated with the AMI project.  He testified that the AMI project investment eligible for deferred accounting agreement would be capped at $39 million and that the deferred depreciation and PISCC balance would be recovered over a period of 10 years without carrying costs in Vectren South’s next electric retail base rate case. He stated that the PISCC rate applied to the AMI project will be Vectren South’s current cost of long-term debt, (4.77%) and that the total amount of deferred debt related to PISCC will not exceed $12 million.  Mr. Swiz also provided Attachment JCS-S1, Schedule 1 which summarizes the estimated rates and charges by Rate Schedule and year-over-year impacts in total over the life of the plan.

		B.	OUCC’s Evidence in Support of the Settlement Agreement

	Edward T. Rutter, Chief Technical Advisor in the OUCC’s Resource Planning and Communications Division testified in support of the Settlement Agreement.  Mr. Rutter stated that while not all parties in this Cause joined in the Settlement Agreement, it is the result of significant compromise among the Settling Parties on the issues presented in this case.  Mr. Rutter stated that when examined in its entirety, the Settlement Agreement is beneficial to ratepayers' interests and should be approved by the Commission as being in the public interest.

	Mr. Rutter stated that there are a number of ratepayer benefits achieved by the Settlement Agreement, including:  (i) reducing the proposed TDSIC Plan's ("Plan") capital costs from $514 million to a cap of $446.5 million, saving ratepayers approximately $67.5 million; (ii) limiting increases to the fixed monthly charge recovery component of the TDSIC to $0.50 per semi-annual filing, mitigating residential ratepayers' fixed-charge obligation to approximately one-half that originally requested; (iii) reducing both contingency percentages and indirect costs, which results in Vectren South being more accountable to hold the line of project "soft" costs; (iv) excluding “cost of removal” of existing, to-be-retired plant as part of the TDSIC-eligible costs; (v) AMI deployment must be undertaken without TDSIC recovery treatment and ratepayers will pay no carrying costs on the deferred depreciation amount; (vi) the migration adjustment portion of the agreement resolves a unique, complicated circumstance that required intense negotiations and creative compromise to address reasonable cost allocations; (vii) data Vectren South agreed to provide with respect to residential customers receiving benefits from the Low Income Home Energy Assistance Program ("LIHEAP") and those that do not will allow the OUCC to better serve these customers' needs going forward; and (viii) Vectren South agreed to make any residential dynamic or time-of-use price products optional.

	Mr. Rutter stated that he personally reviewed and analyzed Vectren South's development of work order-level cost estimates for each of its 825 planned and 556 “substitute” programs/projects within its originally proposed TDSIC Plan as identified in the direct testimonies and workpapers of Vectren's witnesses.  Mr. Rutter stated that his review helped the OUCC conclude Vectren's estimates, as modified by the Agreement, can be considered "best" estimates.  In addition, Mr. Rutter indicated that the OUCC retained Mr. Howard Sobel, P.E. to review each of the proposed projects from an engineering perspective, to evaluate their overall reasonableness and to assist with a determination as to which projects could reasonably be considered part of Vectren South's transmission and distribution “system” as required by Ind. Code§ 8-1-39-2 and as that term has been interpreted by the Commission.  Mr. Rutter also testified that the OUCC’s collective analysis of the migration adjustment issue, cost of equity issues, and numerous accounting and ratemaking issues helped shape the conclusion that, when considered in its entirety, the Settlement Agreement meets the statutory requirements, benefits ratepayers, serves the public interest, and is reasonable.

	Mr. Rutter explained how the terms of the Settlement Agreement describe the reduction to the cost of Vectren South’s 7-Year Plan, by detailing the $446.5 million cap, which is a $67.5 million reduction to the costs eligible for recovery. He stated that the Agreement provides for a specified allocation of the $67.5 million reduction over specific years of the Plan. Mr. Rutter testified that while the costs associated with Vectren South’s 7-Year Plan cannot exceed $446.5 million, the Settling Parties agreed Vectren South has the ability to deviate above each annual cost recovery cap by no more than 5% in a rolling historical three-year period.

	Mr. Rutter described the flexibility of the scope of Vectren South’s 7-Year Plan by stating that the Settling Parties agreed to reduce the size of the “substitute project” pool from approximately $250 million to $67 million, representing about 15% of the $446.5 million total Plan cap. Mr. Rutter testified that this size is comparable to the relative ratio between the overall Plan and the pool of alternate projects approved by the Commission in Cause No. 44720, the Duke Energy Indiana 7-Year Plan proceeding. He explained that in the event a given project, in whole or in part, is rescheduled to a different year, the annual cost recovery caps for the affected years will be adjusted by that project’s whole or partial approved cost estimate to reflect the change. Mr. Rutter testified that the Settling Parties agreed Vectren South would provide certain documentation to justify cost variances in excess of agreed thresholds, and that the non-Vectren South Settling Parties retain the ability to challenge any costs that exceed the approved estimates. 

	Mr. Rutter testified that the Agreement reflects Vectren South’s fixed monthly charge for distribution-related TDSIC costs will not exceed $7.00, as compared to its as-filed request for a fixed charge in excess of $13.50 per month. He explained that, in general, the OUCC does not support TDSIC cost recovery through fixed charges and that the OUCC contends fixed charge increases provide inefficient pricing signals, and limit the ability of customers to control their own bills. He stated that the OUCC does not generally support changes to rate design in expedited tracker proceedings, contending that rate cases are a more appropriate venue for such changes, based on evidence that shows how a utility's costs are incurred. Mr. Rutter testified that, given its reservations, the OUCC agreed to increase Vectren South’s fixed monthly charge for distribution-related TDSIC costs because, as it must with every issue in the context of negotiating a settlement, the OUCC weighed its litigation risks against the broader benefits achieved by the Agreement and determined the Agreement yielded sufficient ratepayer protections and reductions to Vectren South’s as-filed request to warrant agreement to some modification to Vecten South’s fixed monthly charge. Mr. Rutter clarified that the OUCC’s agreement in this instance should not be construed as an endorsement of fixed charge recovery for TDSIC costs in any future case, or a departure from its position taken in past cases opposing increases to fixed charges.

	Mr. Rutter concluded that the Settlement Agreement reflects a balancing of interests among all the Settling Parties.  Mr. Rutter stated that given the benefits provided to ratepayers as outlined in the Settlement Agreement and discussed above, the OUCC, as the statutory representative of all ratepayers, believes the Settlement Agreement is in the public interest, is supported by sufficient evidence, and should be approved.

	7.	Joint Intervenors’ Evidence in Opposition to the Settlement Agreement

		A.	Karl R. Rábago
	
	CAC witness Karl R. Rábago, principal of Rábago Energy LLC, recommended that the Commission not approve Petitioner’s proposal to recover distribution-related costs through fixed, non-bypassable customer charges for residential customers, and direct that any such approved costs be recovered through a volumetric distribution charge.  Mr. Rábago further recommended the Commission order Petitioner to evaluate:  (i) the impacts of changes in rates on energy consumption—demand elasticity—among each of its rate classes and major subclasses (e.g., residential customers, single-family home owners, apartment renters, low income customers, elderly customers, etc.); (ii) the impacts of a wide range of alternative residential rate design
approaches on customer usage; and (iii) its low use and low-income customer base so that it can evaluate future rate and service impacts on these customers.

	Mr. Rábago stated that there is no economic authority that supports the assertion that the nature or label of a cost as either “fixed” or “variable” should govern the design of the price for the service related to that cost.  Therefore, in Mr. Rábago’s opinion, Petitioner has failed to establish that its proposed rates, either in the original petition or in the proposed Settlement Agreement, are just and reasonable.  Mr. Rábago stated that utilities and regulators throughout the country have typically allocated a large proportion of fixed costs to volumetric rate elements for residential and small commercial customers and provided an Attachment to his testimony (KRR-43).  

	Mr. Rábago testified that residential and small commercial customers have only limited options for changing their demand independently of their energy use, and this is especially true of renters; so volumetric energy rates are the best rate design option for sending price signals for both energy and demand cost causation on a going-forward basis.  Accordingly, Mr. Rábago recommended that the prudently incurred distribution-related TDSIC costs that Petitioner proposes to allocate to fixed customer charges should be allocated to volumetric rate elements unless and until Petitioner demonstrates the reasonableness of its proposed rate design in light of the potential adverse impacts.  Some of the adverse impacts Mr. Rábago identified include:  (i) forcing low use customers to pay for costs they do not create; and (ii)  forcing customers to pay for costs that they offset through self-investment in efficiency and other distributed energy resources.

	Mr. Rábago testified that economic efficiency and equity are not advanced when rate design mimics cost structure.  To that end, Mr. Rábago stated that he has never found any article, text, treatise, or other reputable source to support the notion that rate design must mimic cost structure in order to achieve or advance economic efficiency.

	Mr. Rábago also attached several discovery responses from Vectren South to his testimony:
•	Vectren Response to JIs’ Data Request 3.27/4.27 (JI Exhibit 1, Attachment KRR-30) showed how the Company has no cost of service data for types of residential customers.
•	Vectren Response to JIs’ Data Request 3.29/4.29 (JI Exhibit 1, Attachment KRR-32) showed that the Company offers no real evidence to back its economic efficiency assertions.
•	Vectren Response to JIs’ Data Request 3.30/4.30 (JI Exhibit 1, Attachment KRR-33) states the Company’s admission that fixed costs are impacted by usage level.
•	Vectren Response to JIs’ Data Request 3.34/4.34 (JI Exhibit 1, Attachment KRR-44) ignores the request or shows that the Company does not know the customer count per bin.
•	Vectren Response to JIs’ Data Request 5.12 (JI Exhibit 1, Attachment KRR-39) demonstrates that the Company has no cost of service study for distributed generation customers.
•	Vectren Response to JIs’ Data Request 5.13 (JI Exhibit 1, Attachment KRR-40) directly contradicts Vectren Response to Joint Intervenors’ Data Request 3.14/4/14 (Attachment KRR-6), wherein the Company says that short term is seven (7) years.
•	Vectren Response to JIs’ Data Request 5.15 (JI Exhibit 1, Attachment KRR-14) shows that the Borenstein paper is the ONLY authority that the Company cites to support the proposition that “economic efficiency is improved when fixed charges are used to recover fixed costs because the energy charges are moved closer to marginal cost by doing so.”
•	Vectren Response to JIs’ Data Request 3.3/4.3  (JI Exhibit 1, Attachment KRR-16) states how the Company has no analysis showing cost causation principles require fixed charges for fixed costs.
•	Vectren Response to JIs’ Data Request 3.4/4.4  (JI Exhibit 1, Attachment KRR-17) states that Vectren Witness Albertson does not opine whether rate design improves economic efficiency, only that fixed charges are necessary to keep customers from thinking they can change sunk fixed costs (and ignore future fixed costs).
•	Vectren Response to JIs’ Data Request 3.5/4.5  (JI Exhibit 1, Attachment KRR-9) states that Vectren Witness  Albertson claims that subsidies arise simply by paying something other than the average rate.
•	Vectren Response to JIs’ Data Request 3.7/4.7(c) (JI Exhibit 1, Attachment KRR-12) states that Vectren has no idea how rates impact customer usage.
•	Vectren Response to JIs’ Data Request 3.10/4.10  (JI Exhibit 1, Attachment KRR-21) states, “Yes, it is the Company’s position that, once distribution investments are made, changes in energy consumption do not impact the cost of service for that customer.”
•	Vectren Response to JIs’ Data Request 3.12/4.12 (JI Exhibit 1, Attachment KRR-23) states, “It is the position of the Company that high users, interpreted to mean residential customers with high energy consumption relative to the average residential customer, do not impose higher fixed costs.”
•	Vectren Response to JIs’ Data Request 3.13/4.13 (JI Exhibit 1, Attachment KRR-24) asked:  “Please see Petitioner’s Exhibit No. 7 (Albertson Direct) at p. 8, lines 16- 25. Please confirm whether it is the Company’s position that customer reductions in energy use and demand can never reduce fixed cost investment requirements. If the Company holds the position that customer reductions in energy use and demand can reduce future fixed cost investment requirements, please explain how this effect should be more efficiently reflected in rate design.”  Vectren objected and did not respond stating, “Petitioner objects to the foregoing Data Requests on the grounds that it is vague and ambiguous, overly broad and requests that Petitioner make speculations regarding events that might or might not occur over an undefined period of time.”
•	Vectren Response to JIs’ Data Request 3.15/4.15 (JI Exhibit 1, Attachment KRR-25) noted that Vectren has not even quantified the supposed cross subsidy.
•	Vectren Response to JIs’ Data Request 3.16/4.16 (JI Exhibit 1, Attachment KRR-26) shows that Vectren has no actual cost data – just the assumption that subsidy arises when usage is anything except the average.
•	Vectren Response to JIs’ Data Request 3.18/4.18  (JI Exhibit 1, Attachment KRR-28) shows that the Company does not even have bill frequency data by level of use.

		B.	Kerwin L. Olson

	Kerwin L. Olson, the Executive Director for CAC testified that Joint Intervenors proposed that the Commission:  (i) reject the agreed upon increased fixed customer charge proposal; (ii) make it clear to Petitioner and other utilities that proposals this significant as it relates to rate design should only be considered in the context of a full base rate case; (iii) require that if Petitioner chooses to propose  offering prepaid service, voluntary or otherwise, Petitioner must seek that approval within a formal docketed proceeding; (iv) modify the language of the Settlement Agreement regarding low-income reporting to state the data will be provided “at least annually” rather than “no more than annually;” (v) require Petitioner to report general residential customer data in addition to the low-income customer data; and (vi) require Petitioner to report the customer data directly to the Commission and that the data be made publicly available to all interested stakeholders.  

	Mr. Olson stated that a rate design proposal this significant can only be fairly and fully considered in the context of a full base rate case.  Otherwise, Mr. Olson stated that Joint Intervenors would effectively have to engage in every utility filing to protect their rights and interests on this issue.  With respect to CAC/Valley Watch’s recommendations regarding low-income customer reporting, Mr. Olson state that payment problems are not limited to low-income households. Mr. Olson also stated that reporting of this data is critical to establishing the affordability of utility service for Hoosiers. Mr. Olson testified “[t]his crucial information should not be held hostage by restrictive terms which limit the acquisition of the information to only those parties who entered into the non-unanimous settlement with the Company in this proceeding.”

	While Mr. Olson stated that he believes the Settlement Agreement implies that Petitioner intends to offer prepaid service in its service territory, which in his view is problematic.  Mr. Olson noted that consumer advocates, most notably low-income advocates, have serious concerns with prepaid services. Mr. Olson stated that should the Commission approve this term, the Commission should require and state with absolute certainty that if Petitioner chooses to propose offering prepaid service, it must seek that approval within a formal docketed proceeding. Mr. Olson also recommended the Commission review the current administrative rules related to billing, disconnects and other  related areas and update those rules to protect consumers from the many capabilities AMI offers, most notably the capability of remote disconnections and potential prepaid offerings. Mr. Olson suggested the Commission utilize the guidance and recommendations provided by the NCLC report entitled “Rethinking Prepaid Utility Service, Customers at Risk” as well as the NASUCA resolution entitled “Rethinking Prepaid Utility Service, Customers at Risk” as templates for establishing rules related to Petitioner, or any other regulated utility.

 	8.	Petitioner’s Rebuttal Evidence 
		
		A.	Rebuttal Testimony of Scott E. Albertson

	Petitioner’s witness Albertson testified that CAC/Valley Watch witness Rábago has highly sensationalized the impact of Petitioner’s proposal by disregarding the fact that the fixed TDSIC charge, whether as proposed by Vectren South or as provided for in the Settlement Agreement, will increase gradually over a period of seven years.  Mr. Albertson stated that the fixed monthly charge will increase by not more than $1 each year, or less than a 10% increase per year in the total fixed charge (TDSIC plus base rates).  Mr. Albertson stated that at the end of the 7-year TDSIC period, Petitioner’s fixed charges under the Settlement will have increased by a maximum of $7, resulting in an overall fixed charge that is consistent with prior Commission orders and at a similar level as many utilities’ existing fixed charges.

	Mr. Albertson stated that he reviewed the utility data provided by Witness Rábago in his Attachment KRR-43 and found:  (i) 27% of the utilities have received approval of a fixed monthly charge in the $14 to $21 range (within $3-4 per month of the $18 agreed to in the Settlement Agreement); (ii) of the 43 litigated cases, 22 resulted in a fixed charge increase of 20% or more – the highest of which was a 96% increase; (iii) many of the utilities listed have approved electric decoupling mechanisms; and (iv) the exhibit accurately reflects that the Commission recently approved 55% and 27% increases in the fixed charge for Indianapolis Power and Light Company (“IPL”) and NIPSCO, respectively. 

	Mr. Albertson testified that in a decision issued April 5, 2017, the Indiana Court of Appeals affirmed the Commission’s decision in the IPL case finding that a gradual increase to the fixed charge from $11 per month to $17 per month was reasonable.  Mr. Albertson stated that the IPL Order and Court decision capture two main points:  (i) cost recovery alignment with cost causation (fixed cost recovery in fixed charges) results in efficient price signals, especially when considering distribution-related costs; and (ii) a phased-in approach to increases in fixed charges (gradualism) helps temper rate shock.   Mr. Albertson stated that Vectren South’s rate design, as agreed to in the Settlement Agreement, would result in a maximum $7 increase to the fixed charge over a period of 7 years ($1 increase per year), and, when adding the TDSIC costs to Petitioner’s last cost of service study, 85% of Vectren South’s total fixed costs at year 7 will still be recovered in a volumetric charge.

	Mr. Albertson similarly testified that the Commission and Court of Appeals had approved a monthly customer charge increase for NIPSCO of $3, from $11 per month to $14 per month.  Mr. Albertson noted that as stated in the discussion and findings of the NIPSCO Order, “Mr. Rábago was the only witness in opposition to the proposed settlement agreement increase to the customer charge.”   The Commission’s Order states that it disagrees with Witness Rábago and found “that the increase in the monthly customer charge from $11 to $14 for residential customers…is cost-based based upon the evidence presented, consistent with gradualism, and is reasonable and should be approved.”  

	Mr. Albertson also stated that in Cause Nos. 44429/44430, Vectren South and Vectren North’s gas TDSIC proceedings, the Commission authorized both Vectren South and Vectren North to implement a fixed TDSIC charge applicable to residential customers. This fixed TDSIC charge recovers both distribution-related and transmission-related costs.  Mr. Albertson stated that while Petitioner is financially indifferent to how the approved TDSIC revenue requirement amount is collected from customers, recovery of all TDSIC costs through a volumetric rate would only serve to exacerbate the intra-class subsidies that exist today.
	
	Mr. Albertson further stated that at the end of the 7-year period, 85% of Vectren South’s fixed costs will remain in a volumetric (or variable) energy charge, along with all defined variable costs. In addition, he testified that Petitioner is not modifying base rates in this proceeding; therefore, any investments in energy efficiency or distributed generation that were cost-effective prior to the filing of this TDSIC will remain cost-effective.

		B.	Rebuttal Testimony of Russell A. Feingold

	Petitioner’s witness Feingold testified that the numerous criticisms made by Mr. Rábago of Petitioner’s rate design proposal for its residential class are factually incorrect, misleading, or misplaced relative to the underlying economic concepts and utility ratemaking methods supporting the structure of Petitioner’s rate design proposals.  Accordingly, Mr. Feingold recommended that the Commission should approve the rate design agreed upon in the Settlement Agreement because it achieves a reasonable balance between cost causation principles and the impact of its rate design method on customers’ electric bills.

	Mr. Feingold stated that the argument being made by witness Rábago is essentially that one can deviate from just and reasonable rates to solve a host of issues, such as:  low-use and low-income customer impacts, energy efficiency investments and Distributed Generation (“DG”) investments. Mr. Feingold testified that witness Rábago’s argument falls apart because cost-based rates provide the most meaningful rationale for rate design.  Mr. Feingold noted that one obvious problem with Mr. Rábago’s stated desire to protect low income customers by recovering all TDSIC costs in Petitioner’s kWh charges is the unavoidable consequences of this rate design on high use, low income customers who must now subsidize not only other low income customers but also vacant premises, high income/low use customers, and separately metered barns and other outside structures. Mr. Feingold testified that volumetric two-part rates cannot result in just and reasonable cost recovery, unless the class is nearly perfectly homogeneous – which is not the case for Petitioner’s residential class as Mr. Feingold demonstrated in his direct testimony. 

	Mr. Feingold testified that he disputed Mr. Rábago’s claims that the Company’s proposed increase in fixed charges means that the incentive to either invest in efficiency and the payback associated with energy savings are reduced. Mr. Feingold stated that increases in kWh energy charges still occur under Petitioner’s rate design proposal.  Mr. Feingold also argued against Mr. Rábago’s claims that Petitioner’s proposal to “lock demand-related fixed costs into a per-customer charge” means that residential customers have no financial incentive under proposed default rates to reduce their demand. Mr. Feingold stated Vectren South is not proposing to lock demand-related distribution costs into the fixed monthly charge. Mr. Feingold stated that the portion of demand costs in Petitioner’s existing rates for distribution, transmission and production are not impacted by its rate design proposal in this proceeding.

	Mr. Feingold stated that he believes Petitioner’s distribution-related TDSIC costs include customer-related costs that should be recovered in a fixed monthly charge.  Mr. Feingold testified that Dr. James Suelflow indicates in his treatise, “Public Utility Accounting: Theory and Practice” that costs are more closely related to customers the closer one approaches the ultimate customer. Mr. Feingold also cited a number of other sources that he said demonstrate that the recognition of customer-related costs is neither new nor novel, but has been established for over 100 years.  For instance, Mr. Feingold testified that in his widely utilized text, The Regulation of Public Utilities, Dr. Charles F. Phillips, Jr. states that, “customer costs vary with the number of customers. These costs include a portion of the distribution system, local connection facilities, metering equipment, billing and accounting. Customer costs, moreover, are independent of consumption.”  Mr. Feingold said it is only through the use of fixed charges to recover fixed costs that the matching principle of aligning a utility’s costs and rates (revenues) is satisfied.

		C.	Rebuttal Testimony of Daniel C. Bugher, Sr.

	Petitioner’s witness Bugher responded to CAC/Valley Watch’s criticisms regarding prepaid services and the low-income customer data Petitioner has agreed to provide the other Settling Parties.  Mr. Bugher stated that while AMI capability is not required to offer prepaid services, it can facilitate prepaid utility service because AMI meters have the capability to capture and report energy usage multiple times per day and compare the actual usage to the prepaid amount.  Mr. Bugher stated that Vectren South is not requesting approval of a prepaid service option as part of this Cause and CAC/Valley Watch witness Olson’s belief that the terms of the Settlement Agreement imply Vectren South intends to offer voluntary prepaid service in its service territory is wrong. Nonetheless, Mr. Bugher stated that Vectren South does not agree to the condition that a formally docketed proceeding must be utilized to offer prepaid electric service of any type. As a practical matter, Mr. Bugher testified that it is likely that any approval would arise in a formally docketed proceeding where Vectren South is seeking revisions to its tariff. However, Mr. Bugher stated it is also possible that a Commission rulemaking—of the type CAC Witness Olson recommends—might develop a framework for prepaid service that eliminates the need for approval in a formally docketed proceeding. Accordingly, Mr. Bugher stated that it is premature to now determine that the only avenue for approving a prepaid electric service option is through a docketed proceeding.

	With respect to the customer reporting requirements set forth in the Settlement Agreement, Mr. Bugher stated that Vectren South stands behind the commitments made in the Settlement Agreement, but it does not agree to expand those commitments in the manner sought by the CAC. Mr. Bugher testified that CAC was invited to participate in the settlement discussions and did participate, but agreement could not be reached on terms acceptable to the CAC.  Mr. Bugher stated that from Vectren South’s perspective, it is willing to provide the data if it is useful, but Petitioner does not want to commit to pulling the data every year even if the other parties do not find it useful. Mr. Bugher further testified that Vectren South does not collect data about its customers’ incomes, leaving no mechanism for the additional data that CAC/Valley Watch is requesting to be utilized to evaluate the impact on low-income customers who are not receiving LIHEAP.

		D.	Stipulation of Additional Evidence in the Record

	In lieu of cross-examination of its witnesses, Vectren South agreed to the admission of the following discovery responses to Joint Intervenors:

•	Vectren Response to JIs’ Data Request 1.5 (JI CX 1) shows that the Company lacks the basic data about low income customers necessary to even know whether its rate design is regressive.
•	Vectren Response to JIs’ Data Request 2.3 (JI CX 2) does not address the impact of the changed rates on energy efficiency – and did not examine the potential effects.  Rather, it only says that there will still be a lot of volumetric charges at the end of the planned TDSIC period.
•	Vectren Response to JIs’ Data Request 2.4 (JI CX 2) states, “Vectren South has not performed any studies or collected data regarding customer payback expectations or willingness to invest in energy efficiency measures for residential and small commercial customers.”
•	Vectren Response to JIs’ Data Request 2.5 (JI CX 2) states, “While Vectren South has not performed any studies on the elasticity of demand of its residential and small commercial customers specifically, in support of Vectren South’s most recent Integrated Resource Plan, Itron submitted a Long-Term Energy and Demand Forecast. As shown in the attached excerpt from that forecast, Itron used a residential and commercial price elasticity of -0.10 as an input to that forecast (see CAC Attachment DR 2.5).”
•	Vectren Response to JIs’ Data Request 2.6 (JI CX 2) shows that Vectren only has very high level data on distributed generation.
•	Vectren Response to JIs’ Data Request 2.8 (JI CX 2) shows how Vectren claims no revenue loss due to distributed generation.
•	Vectren Response to JIs’ Data Request 2.10 (JI CX 2) states, “Vectren has made no projections of the effects of the increase in fixed customer charges on customer willingness to invest in energy efficiency or distributed generation.”
•	Vectren Response to JIs’ Data Request 2.11 (JI CX 2) states, “A PV value analysis has no bearing on the distribution and storage system improvements contemplated under the 7-year TDSIC.”
•	Vectren Response to JIs’ Data Request 3.20/4.20 (JI CX 3) contains no statement of the Company’s overall goal in rate design.
•	Vectren Response to JIs’ Data Request 3.23/4.23 (JI CX 3) shows that the Company has no income data on its customers.
•	Vectren Response to JIs’ Data Request 6.4 (JI CX 4) shows that Vectren does not have the data on cost, but are still proposing to set identical fixed charges equal for every customer.
•	Vectren Response to JIs’ Data Request 7.1 (JI CX 5) shows that Vectren has no consideration to segmenting residential customer class in spite of stated recline in homogeneity.
•	Vectren Response to JIs’ Data Request 7.10 (JI CX 5) demonstrates an attempt by the Company to shift burden of just and reasonable rates to the Commission.

9.	Discussion and Findings.  

	A.	Consideration of Settlement Agreements

When reviewing a settlement agreement, the Commission must consider whether the settlement serves the interest of the public. Ind. Code § 8-1-2-24 (2008).  This is because what begins as “a contract between private parties takes on public interest ramifications once the Commission approves it.”  Northern Ind. Pub. Serv. Co. v. U.S. Steel Corp., 907 N.E.2d 1012, 1017 (Ind. 2009); U.S. Gypsum, Inc. v. Ind. Gas Co., 735 N.E.2d 790, 803 (Ind. 2000), quoting Citizens Action Coalition v. PSI Energy, Inc., 664 N.E.2d 401, 406 (Ind. Ct. App. 1996).  Thus, the Commission “may not accept a settlement merely because the private parties are satisfied; rather [the Commission] must consider whether the public interest will be served by accepting the settlement.” Citizens Action Coalition v. PSI Energy, 664 N.E.2d 401, 406 (Ind. Ct. App. 1996).   

“[T]he Commission indeed has broad authority to supervise settlement agreements . . . and to be proactive in protecting the public interest.” N. Indiana Pub. Serv. Co. v. Indiana Office of Util. Consumer Counselor, 826 N.E.2d 112, 119 (Ind. Ct. App. 2005).  See Citizens Action Coalition v. NIPSCO, 796 N.E.2d 1264, 1267–68 (Ind. Ct. App. 2003), trans. denied.  This broad authority provides the Commission with more discretion than to merely approve or reject a settlement in total.  In re Access Charge Reform & Universal Serv. Reform, 40785-S1, 2001 WL 797973 (Mar. 19, 2001).  More specifically, “the Commission undoubtedly has the authority to modify or condition a settlement presented to it to serve the public interest prior to approving it,” even when the settling parties explicitly request that the settlement be approved or rejected without modification.  Id.  This means that “[t]he Commission acts well within its authority when it modifies a contested settlement so that the contested terms will be consistent with Commission precedent or policy.  If [petitioner] does not want to accept the settlement with the modifications that the Commission found were necessary to insure that the settlement was consistent with the public interest then [it] can reject the modified settlement and litigate the issues.”  In re Access Charge Reform & Universal Serv. Reform, 40785-S1, 2001 WL 797973 (Mar. 19, 2001), quoting Eastern Shore Natural Gas Co., 43 F.E.R.C. P 61, 489, at 62, 212 (1988).

The Commission’s own procedural rules require that settlements be supported by probative evidence. 170 IAC 1-1.1-17(d). Thus, the Commission must determine whether the evidence in this Cause sufficiently supports the conclusions that the Settlement Agreement is reasonable, just and consistent with the purpose of Ind. Code § 8-1-2-4, and that such agreement serves the public interest. See Indiana Michigan Power Co., Cause No. 43306, Final Order, pp. 45-46 (March 4, 2009).

Participation by the Office of Utility Consumer Counselor in a settlement agreement does not require the Commission to presume a settlement to be in the public interest.    Citizens Action Coal. of Indiana, Inc. v. PSI Energy, Inc., 664 N.E.2d 401, 405 (Ind. Ct. App. 1996); Nextel W. Corp. v. Indiana Util. Regulatory Comm’n, 831 N.E.2d 134, 156 (Ind. Ct. App. 2005).  The OUCC is mandated by statute to “have charge of the interests of the ratepayers and consumers of the utility.”  Ind. Code § 8–1–1.1–5.1(e). Accordingly, the OUCC holds the statutory ability to “appear on behalf of ratepayers, consumers, and the public in ... hearings before the [C]ommission.” Ind. Code § 8–1–1.1–4.1(a).  But, this statutory role of the OUCC does not change the statutory responsibility of the Commission with respect to proposed settlements.  As the Court of Appeals has stated, “Although we recognize the strong public policy favoring settlement agreements, we reject the notion that the commission must accept an agreement endorsed by the OUCC without determining whether the public interest will be served by the agreement.”  CAC, 664 N.E.2d at 405.    

	We will address each of the issues raised by the CAC in our discussion below.  However, initially, we must consider whether the proposed TDSIC Plan meets the requirements of Ind. Code § 8-1-39-10.

III.		APPLICABLE STATUTORY FRAMEWORK 

Any change to a charge, as required by Ind. Code § 8-1-2-4, “shall be reasonable and just, and every unjust or unreasonable charge for such service is prohibited and declared unlawful.”  Ind. Code § 8-1-2-68 also requires that:

Whenever, upon an investigation, the commission shall find any rates, tolls, charges, schedules, or joint rate or rates to be unjust, unreasonable, insufficient, or unjustly discriminatory, or to be preferential or otherwise in violation of any of the provisions of this chapter, the commission shall determine and by order fix just and reasonable rates, tolls, charges, schedules, or joint rates to be imposed, observed, and followed in the future in lieu of those found to be unjust, unreasonable, insufficient, or unjustly discriminatory or preferential or otherwise in violation of any of the provisions of this chapter.

Ind. Code § 8-1-2-25 further notes the Commission’s “right and power to make such other and further changes in rates, charges and regulations as the commission may ascertain and determine to be necessary and reasonable.”  

Finally, the Commission created a framework to comply with the Utility Powerplant Construction Act (Ind. Code 8-1-8.5) and the National Energy Policy Act of 1992 (16 U.S.C. 2621 and 16 U.S.C. 2622 effective October 24, 1992, P.L.102-486 Stat. 2795) as found at 170 IAC 4-8-3, which states in part:  

The regulatory framework attempts to eliminate or offset regulatory or financial bias against DSM, or in favor of a supply-side resource, a utility might encounter in procuring least-cost resources. The commission, where appropriate, will review and evaluate the existence and extent of regulatory or financial bias.  
 
16 U.S.C. 2621(d)(17)(A)(ii) encourages state regulators of utilities, like the Commission, to consider setting rates to “promote energy efficient investments,” and 16 U.S.C. 2621(d)(17)(B)(iii)–(B)(iv) encourages authorities similar to the Commission to both consider including energy efficiency as one of the goals of ratemaking, and to consider “adopting rate designs that encourage energy efficiency.” Finally, The Commission’s IRP Rule also contemplates “An evaluation of the utility’s DSM programs designed to defer or eliminate investment in a transmission or distribution facility including their impacts on the utility’s transmission and distribution system for the first ten (10) years of the planning period.” 	170 IAC 4-7-8(b)(7).  All of these policy considerations are relevant to the Commission’s review of Vectren’s rate design proposal.”  

		B.	Approval of the TDSIC Plan under Ind. Code § 8-1-39-10

	Indiana Code § 8-1-39-10(a) permits a public utility to petition the Commission for approval of the public utility’s seven-year plan for eligible transmission, distribution, and storage system improvements.  Indiana Code § 8-1-39-2 defines “eligible transmission, distribution, and storage system improvements” as new or replacement electric or gas transmission, distribution, or storage utility projects that: 

	(1) a public utility undertakes for purposes of safety, reliability, system modernization, or economic development, including the extension of gas service to rural areas;

	(2) were not included in the public utility’s rate base in its most recent general rate case; and

	(3) either were:

(A) designated in the public utility’s seven (7) year plan and approved by the commission under section 10 of this chapter as eligible for TDSIC treatment; or 

(B) approved as a targeted economic development project under section 11 of this chapter.

	Indiana Code §  8-1-39-l0(b) states that after notice and a hearing, and not more than 210 days after the petition is filed for approval of a public utility’s seven-year plan, the Commission shall issue an order that includes the following:

	(1) A finding of the best estimate of the cost of the eligible improvements included in the plan.

	(2) A determination that the public convenience and necessity require or will require the eligible improvements included in the plan.

	(3) A determination whether the estimated costs of the eligible improvements included in the plan are justified by incremental benefits attributable to the plan.

Further, “[i]f the commission determines that the public utility’s seven (7) year plan is reasonable, the commission shall approve the plan and designate the eligible transmission, distribution, and storage improvements included in the plan as eligible for the TDSIC treatment.”   Id.	
	
	1.	Content of Vectren South’s TDSIC Plan and Project Eligibility under Ind. Code §§ 8-1-39-10(a) and 8-1-39-2  

	The initial question we must answer is whether the agreed-upon TDSIC Plan is a plan as required by Section 10(a).  The Settling Parties request approval of a TDSIC Plan that includes an estimated $446.5 million of capital improvement projects over calendar years 2017 through 2023. The TDSIC Plan presented in this proceeding as Petitioner’s Exhibit No. 10, Attachment LKW-S2, provides a detailed and defined roadmap for how Vectren South intends to achieve its objectives of maintaining safe, reliable service for Vectren South Customers.  Petitioner’s Exhibit No. 10, Attachment LKW-S2 contains a detailed description of each of the projects to be completed and when.  It also contains a detailed description of the agreed-upon substitution projects.

	Vectren Witness Luttrell sponsored Petitioner’s Exhibit 1, Attachment JKL-1, which claims to report on a study of alleged “economic development benefits” of the TDSIC Plan.  However, the Commission will provide this study and the associated testimony at p. 8, lines 18-29, with no weight as “economic development benefits” are not germane to the issues in this case.  

	The evidence of record establishes that Vectren South reviewed all of its transmission and distribution (“T&D”) assets to develop its TDSIC Plan and determine that the projects contained therein were “eligible transmission, distribution, and storage system improvements” as defined in Ind. Code § 8-1-39-2.  Vectren South witness Wilson testified that Vectren South employees who serve as SMEs in Engineering, Field Operations, and System Operations identified and prioritized potential programs and individual projects to meet the following identified goals:  (i) enhance customer experience and prepare for customers’ energy future; (ii) maintain and enhance system reliability; and (iii) manage utility assets as good stewards of Vectren South’s portion of the electric system.   (Pet. Exh. 2 at 6.)  

	Vectren South also partnered with B&V to subject the projects and programs to a screening process and validate that they met the eligibility criteria in the TDSIC statute of being new or replacement transmission, distribution, or storage utility projects for defined purposes such as safety, reliability, system modernization, or economic development.  (Id.)  B&V also analyzed the current risk of Vectren South’s T&D system and determined that the proposed TDSIC Plan would reduce system risk by 40% over the seven-year period as compared to allowing the assets to “run to failure.”  (Pet. Exh. 3 at 11.)

	The projects also were thoroughly reviewed by the OUCC.  OUCC witness Rutter testified that the OUCC retained Mr. Howard Sobel, P.E. “to review each of the proposed projects from an engineering perspective, to evaluate their overall reasonableness and to assist with a determination as to which projects could reasonably be considered part of Vectren South’s T&D ‘system’ as required by Ind. Code§ 8-1-39-2 and as that term has been interpreted by the Commission in its Orders in Cause Nos. 44526 (Duke Energy, May 8, 2015), and 44542 (Indiana Michigan Power, May 8, 2015).”  (Public’s Exh. 1-S at 5.)  No party suggested that the projects included in the TDSIC Plan offered into evidence as Petitioner’s Exhibit No. 10, Attachment LKW-S2 were not eligible improvements under Ind. Code § 8-1-39-2.

	Based upon the uncontroverted evidence of record, we find that the record supports that each of the projects included in the TDSIC Plan are to be undertaken for purposes of safety, reliability and/or system modernization. Accordingly, we find that the projects identified in the TDSIC Plan provided as Petitioner’s Exhibit No. 10, Attachment LKW-S2, including the substitution projects, are “eligible transmission, distribution, and storage system improvements” within the meaning of Ind. Code § 8-1-39-2.   We further find that Vectren South’s TDSIC Plan provides a detailed overview of the types of projects that need to be undertaken, and why these types of projects are necessary.  

	2.	Best Estimate of Cost of Eligible Improvements under Ind. Code §  8-1-39-l0(b)(1)  

	Indiana Code § 8-1-39-10(b)(1) requires that an order approving a utility's 7-Year Plan include a finding of the best estimate of the cost of the eligible improvements included in the plan. While we have encouraged utilities to improve the level of accuracy and completeness of their cost estimates prior to seeking Commission pre-approval for a project, we also have recognized that the circumstances of a project may dictate the appropriate range of accuracy. See Northern Indiana Public Service Company, Cause No. 44012 at 18 (IURC December 28, 2011). The framework of this proceeding was established by the TDSIC Statute that requires a public utility seeking approval to submit a plan for seven years of eligible improvement capital investment. It is reasonable that a 7-Year Plan for any public utility should include some level of flexibility to address changing circumstances.

	Again, the uncontested evidence of record supports the conclusion that Vectren South’s estimating techniques and cost estimates summarized in Petitioner’s Exhibit No. 10, Attachment LKW-S2 are reasonable and appropriate and represent the best estimates of the costs of the 7-Year Electric Plan.  Specifically, this conclusion is supported by Petitioner’s direct testimony, the Settlement Agreement and evidence provided in support of that agreement.  

	Petitioner’s witness Hoover provided extensive testimony explaining the process for developing the cost estimates for each category of projects.  (Pet. Exh. 6.)  Mr. Hoover noted that Vectren South leveraged the expertise of three different external engineering firms in developing cost estimates for some distribution projects and the more complex transmission and substation projects.  (Id. at 6.)  OUCC witness Rutter testified that he “personally reviewed and analyzed Vectren South’s development of work order-level cost estimates for each of its 825 planned and 556 ‘substitute’ programs/projects” within the TDSIC Plan.  Mr. Rutter stated that based on his review of the TDSIC Plan projects and substitute projects, he “helped the OUCC conclude Vectren [South]’s estimates, as modified by the Settlement [Agreement], can be considered ‘best’ estimates.”

	Mr. Rutter also noted that “[w]hile Vectren South provided sufficient cost estimate support for the $514 million in projects and programs proposed to be included in its TDSIC Plan, for purposes of settlement, the Settling Parties agreed that the total cost of the Plan will be capped at $446.5 million, representing a reduction of $67.5 million eligible for TDSIC cost recovery.”  The Settling Parties’ agreement to cap TDSIC Plan spending provides an additional level of protection for customers.

	We accordingly find that Vectren South has supported the TDSIC Plan with appropriate and reasonable cost estimates that constitute best estimates of the costs associated with the TDSIC Plan.

			3. 	Public convenience and necessity require or will require the eligible improvements included in the plan as required under Ind. Code § 8-1-39-l0(b)(2)	

	Vectren South has a statutory obligation to provide adequate retail service in its assigned electric service area pursuant to Ind. Code§ 8-1-2-4.  Petitioner provided substantial evidence that completion of the projects in the TDSIC will serve the public convenience and necessity by ensuring that Vectren South continues to meet this statutory obligation.  

	Vectren South witness Luttrell testified that while Vectren South’s T&D systems have been reliable, additional investment is necessary to maintain the reliability Petitioner’s customers have come to expect.  (Pet. Exh. 1 at 9.)  Mr. Luttrell noted that Vectren South’s assets continue to age and require investments to maintain reliability.  (Id. at 6-8.)  The TDSIC Plan represents an opportunity to stay ahead of aging facilities and make modernization investments that benefit customers, which Vectren South testifies would have been a challenge under a traditional ratemaking approach.  

	Vectren South witness Wilson similarly testified that the projects set forth in the TDSIC Plan ensure Vectren South’s electric infrastructure continues to perform in the safe, efficient and reliable manner that customers rely upon.  (Pet. Exh. 2 at 14-15.)  Vectren South and B&V used a risk-based planning approach to evaluate capital investments and ensure that the TDSIC Plan addresses the most critical aging assets on Petitioner’s system.  (See, Pet. Exh. 3, Attachment WDW-1).  B&V concluded the “TDSIC Plan is an optimized plan that prioritizes investment for eligible transmission and distribution improvements using risk reduction as a primary objective, while minimizing TDSIC recovery costs.”  (Pet. Exh. 3 at 13.)  

	No party contended the TDSIC Plan was inconsistent with the public convenience and necessity.  OUCC witness Rutter testified that Vectren South provided sufficient support for a finding that the public convenience and necessity require (or will require) the eligible improvements outlined in Vectren South's proposed TDSIC Plan as required by Ind. Code§ 8-l-39-10(b)(2).

	We find based on the uncontested evidence of record that Vectren South has sufficiently supported that the investments described in its TDSIC Plan are reasonably necessary for it to continue to provide adequate retail service to customers in its assigned electric service area. Therefore, based upon the evidence presented in this proceeding, we find that the public convenience and necessity require or will require the eligible improvements included in the TDSIC Plan.

			4. 	Incremental Benefits Attributable to the TDSIC Plan pursuant to Ind. Code §  8-1-39-l0(b)(3).

	The evidence of record shows that Vectren South has a large number of aging assets on its electric T&D system. The evidence supports Vectren South’s position that these assets need to be replaced.  Vectren South’s TDSIC Plan puts forth a plan to address these replacements.  

	B&V conducted a quantitative risk assessment of these assets, which took into account both likelihood of failure and consequence of failure.  Based on the risk analysis, B&V determined that the proposed TDSIC Plan would reduce the total T&D system risk by 40% over seven years of the study period as compared to allowing the assets to “run to failure.”  (See, Pet. Exh. 3 at 11.)  B&V further determined that the TDSIC Plan requires a lower overall capital investment total than allowing the assets to “run to failure.”  (Id.)  Accordingly, B&V concluded that by implementing the TDSIC Plan, total T&D system asset risk is significantly reduced, providing incremental benefits to Vectren South’s system and customers in terms of improved service reliability.  (Id. at 13.)  

	OUCC witness Rutter testified that Vectren South provided sufficient support for a finding that the estimated costs of the eligible improvements included in the plan are justified by incremental benefits attributable to the Plan as required by Ind. Code§ 8-l-39-10(b)(3).  No party presented contrary evidence.  

	Accordingly, we find there is sufficient evidence to support our finding that replacing aging infrastructure will enhance the safety, resiliency and reliability of Petitioner’s system. We further find Vectren South has provided sufficient evidence that the estimated costs of the eligible improvements included in the TDSIC Plan are justified by the reasonably expected incremental benefits attributable to the TDSIC Plan. 

			5.	Approval of the TDSIC Plan under Ind. Code § 8-1-39-10
	
	Pursuant to Ind. Code § 8-1-39-10, if the Commission finds a seven-year plan to be reasonable, the plan shall be approved and the projects shall be designated as eligible for TDSIC treatment.  Based upon our review of the evidence of record, and the foregoing consideration of each component of Ind. Code § 8-1-39-10, we find Vectren South’s TDSIC Plan is reasonable. The TDSIC Plan submitted in this proceeding as Petitioner’s Exhibit No. 10, Attachment LKW-S2 contains individual improvement level detail sufficient to allow the Commission to reasonably identify what projects will be completed and when. NIPSCO Indus. Grp. v. Northern Ind. Pub. Serv. Co., 31 N.E.3d 8, 8 (Ind. Ct. App. 2015), see also Indiana Michigan Power Company, Cause No. 44542, 2015 WL 2250624, at *11 (IURC 5/8/15).  

	We further note a number of provisions in the Settlement Agreement that underscore the reasonableness of the TDSIC Plan.   The Settlement Agreement reduces the TDSIC Plan by $67.5 million and provides for a hard cap on recoverable costs in the TDSIC. Vectren South also agreed to remove from the TDSIC Plan costs associated with the Advanced Distribution Management System, Geomagnetic Disturbance Protection, Mobile Asset Data Collection and Substation Physical Security Upgrades programs.  In addition, the Settling Parties agreed the size of the “substitute project” pool would be reduced from approximately $250 million to $67 million.  Each of the foregoing agreements provides additional certainty to customers.  As a further protection to customers, the Settlement Agreement establishes annual caps on recoverable capital expenditures in each plan year, subject to an agreed degree of flexibility. 

	Based upon our review of the evidence presented and our discussion above, we find that Vectren South’s TDSIC Plan is reasonable. We also find that Vectren South has provided sufficient evidence that its cost estimates are best estimates, that public convenience and necessity require or will require the eligible improvements in the TDSIC Plan, and that the benefits of the TDSIC Plan justify its costs. Therefore, we find the TDSIC Plan is reasonable, and that the eligible transmission, distribution and storage system improvements included in the TDSIC Plan, including the substitute projects, are eligible for Transmission, Distribution and Storage System Improvement Charge treatment in accordance with Ind. Code § 8-1-39-1 et seq.

		C. 	Approval of the TDSIC Mechanism under Ind. Code § 8-1-39-9

	Vectren South requests approval of a proposed TDSIC mechanism and accompanying changes to its electric service tariff, which will allow for timely recovery of 80% of eligible and approved capital expenditures and TDSIC costs under Ind. Code § 8-1-39-9, which provides in part:

	(a)  Subject to subsection (c), a public utility that provides electric or gas utility service may file with the commission rate schedules establishing a TDSIC that will allow the periodic automatic adjustment of the public utility's basic rates and charges to provide for timely recovery of eighty percent (80%) of approved capital expenditures and TDSIC costs. The petition must:

	(1) use the customer class revenue allocation factor based on firm load approved in the public utility's most recent retail base rate case order;

	(2) include the public utility’s seven (7) year plan for eligible transmission, distribution, and storage system improvements; and

	(3) identify projected effects of the plan described in subdivision (2) on retail rates and charges.

*	*	*
	(b) A public utility that recovers capital expenditures and TDSIC costs under subsection (a) shall defer the remaining twenty percent (20%) of approved capital expenditures and TDSIC costs, including depreciation, allowance for funds used during construction, and post in service carrying costs, and shall recover those capital expenditures and TDSIC costs as part of the next general rate case that the public utility files with the commission.

	As further discussed below, we find Petitioner has met the requirements for approval of a TDSIC mechanism set forth in Ind. Code § 8-1-39-9.  

			1.	Allocation of TDSIC Costs

	The Settling Parties request that the Commission authorize Vectren South to allocate TDSIC costs to the rate schedules in each TDSIC tracker filing using allocation percentages set forth in the Settlement Agreement, which in turn, are based on the “firm load approved in” Vectren South’s “most recent retail base rate case order,” i.e., Cause No. 43839 (IURC Order April 27, 2011).  The allocation factors set forth in the Settlement Agreement reflect that following the issuance of the Order in Cause No. 43839, Vectren South lost a substantial amount of the “firm load” previously served under Rate HLF due to a large customer investing in a customer-owned cogeneration facility.  (Pet. Exh. 9 at 16.)  The customer now receives “non-firm back up service” under Rate BAMP, along with service under Rate LP for its remaining firm auxiliary service.  (Id.)  In recognition that a substantial amount of firm load in Rate HLF shifted to Rate LP because a large customer changed rate classes, the Settling Parties adjusted the allocation percentages approved in Cause No. 43839 by migrating the customer from Rate HLF to Rate LP.  (Id.)      

	No party opposed this adjustment.  Moreover, the plain language of Ind. Code § 8-1-39-9(a)(1) requires that TDSIC customer class revenue allocation factors be based on “firm load.”  As such, the adjustment made by the Settling Parties is consistent with the statute in that it recognizes that a significant portion of the load on which the allocation factor for Rate HLF was based in Petitioner’s most recent retail base rate case order is “non-firm.”  Allocating TDSIC costs based on “firm load” that no longer exists would produce an illogical result and unduly burden the remaining customer in Rate HLF.  Accordingly, we find the allocations factors set forth in the Settlement Agreement are consistent with Ind. Code § 8-1-39-9(a)(1) and should be approved.

			2.	Rate Design

Under the Settlement Agreement, all of Petitioner’s TDSIC costs would be recovered through demand charges from commercial and industrial customers receiving service under Rates DGS, MLA, OSS, LP and HLF.  The Settlement proposes that distribution-related TDSIC costs be recovered through a combination of a fixed customer charge and a per kWh energy charge from residential and small commercial customers receiving service under  Rate RS – Residential Service; Rate B – Water Heating Service; and Rate SGS – Small General Service.  As proposed by the Settling Parties, customers would pay a fixed monthly TDSIC charge per customer up to a maximum or capped fixed charge in each semi-annual TDSIC proceeding.  The cap on the monthly fixed TDSIC charge will grow by $0.50 per customer in each semi-annual TDSIC filing.  The distribution-related fixed TDSIC charge will not exceed $7.00 per customer per month in TDSIC-14.  Distribution-related TDSIC costs exceeding the applicable fixed charge cap, along with all transmission-related TDSIC costs, would be included in an increased energy charge applicable to residential and small commercial customers.

	Petitioner originally had proposed to recover all of its TDSIC costs through customer charge, resulting in a fixed TDSIC charge in excess of $13.50 per month by the final year of the Plan.  (See, Public’s Exh. 1-S at 6.)   OUCC Witness Rutter noted that while the OUCC generally does not support TDSIC cost recovery through fixed charges, believes fixed charges provide inefficient price signals, and prefers rate cases as a more appropriate venue for such changes, the OUCC weighed its litigation risks against the broader benefits achieved by the Agreement and determined the Agreement yielded sufficient ratepayer protections.  Petitioner’s witness Albertson testified that as “a result of the Settlement, the increases in the fixed portion of the customer’s bill will be even more gradual over the period of the TDSIC Plan.”  (Pet. Exh. 11 at 4.)  

	CAC/Valley Watch witnesses Rábago and Olson opposed the terms of the Settlement Agreement relating to the recovery of distribution-related TDSIC costs through a combination of a fixed customer charge and per kWh energy charge, recommending instead that costs be recovered just through the per kWh energy charge as is typical practice for tracker cost recovery.  Mr. Rábago testified that recovering distribution-related costs through an increase to fixed customer charges “is at odds with long-established principles of regulatory ratemaking.”  Specifically, Mr. Rábago  suggested that Petitioner’s proposed rate design:  “fails under Indiana Code § 8-1-2-4, which requires that any ‘charge made by any public utility for any service rendered or to be  rendered either directly or in connection therewith shall be reasonable and just.’” (JI Exh. 1 at 5.)  Mr. Rábago further contends the increase in fixed charges “eliminates any price signal for residential customers.”   (Id.)  .  

	In Re Indianapolis Power & Light Co (“IPL 2016 Rate Order”), we approved increases in IPL’s customer charges from $6.70 to $11.25 (for less than 325 kWh/month) and $11.00 to $17.00 (for greater than 325 kWh/month).  In the IPL 2016 Rate Order, we noted the increase in the customer charge was a “move toward a more fixed and variable rate design consistent with traditional cost causation principles [sic],” while being “demonstrably short of SFV rates.”  The Court of Appeals affirmed the IPL 2016 Rate Order in Citizens Action Coalition of Indiana, Inc. v. Indianapolis Power & Light Company, 74 N.E.3d 554, 555 (Ind. Ct. App. 2017).  The Court of Appeals rejected CAC’s arguments alleging an adverse impact on conservation efforts and a disproportionate impact on low-income customers. 

	Subsequent to issuing the IPL 2016 Rate Order, we approved a settlement in NIPSCO’s base rate case (“NIPSCO 2016 Rate Order”) which increased the monthly customer charge from $11.00 to $14.00 for NIPSCO’s residential customers.  In approving the customer charge increase included in the settlement in that case, we again noted “the increase to the customer charge was a move toward a more fixed variable design consistent with traditional cost causation principles, while being demonstrably short of straight fixed variable rates.” (NIPSCO 2016 Rate Order at 88).  Again, CAC appealed the Order and challenged the increase in fixed monthly charges, but the Court of Appeals affirmed the approval of the NIPSCO settlement in all respects.  See Citizens Action Coalition v. Northern Indiana Public Service Co., 2017 WL 1399850 (Ind. App. 2017).

	We note that Petitioner argued that we rely on our decisions made in the Vectren South and Vectren North’s recent gas TDSIC proceedings, where we authorized both Vectren South and Vectren North to implement a fixed TDSIC charge applicable to residential customers.  We held that:  

Petitioners have not proposed a modification to the design of their base rates and the customer facilities charge is not being adjusted. Rather, Petitioners’ proposal simply addresses the rate design for cost recovery of the Compliance and TDSIC Projects. 

(slip op. at 23.)  

Although we have made these prior rulings, we reconsider and change our position on the issue of fixed charge recovery, especially as it relates to the appropriate venue in which to bring such proposals.  First, we are convinced by the testimony put forth by CAC and the OUCC that rate cases, not expedited tracker proceedings, are the only appropriate venues to consider rate design issues, where decisions are “based on evidence that shows how a utility’s costs are incurred.”  Public’s Exhibit No. 1-S, pp. 6-7. A proposal this significant as it relates to rate design can only be fairly and fully considered in the context of a full base rate case.  Such a dramatic change in fundamental rate design is beyond the scope of this proceeding, and to grant the rate design proposal in this proceeding would constitute a denial of due process to a wide range of stakeholders and interested parties who would not expect this proceeding to be used for such a purpose.  We are concerned about starting a trend wherein interested stakeholders would effectively feel the need to engage in every utility filing to advocate their positions on this issue as they would have no other way of ensuring that matters that belong within the scope of one proceeding are not decided in another.  Accordingly, we change our prior position and refuse to even allow fixed customer charge proposals to be presented in expedited tracker proceedings such as this.  If Vectren would like to put forth such a proposal, it may do so in a general rate case.  Any such approved costs herein shall be recovered through a volumetric distribution charge.

Secondly, we find that the Company proposes to increase fixed customer charges by 64% to recover distribution-related TDSIC plan costs without coherent or logical explanation that would establish a result that is just and reasonable, thus failing to meet the requirements of Indiana Code § 8-1-2-4.   Vectren Response to JIs’ Data Request 7.10 (JI CX 5) even demonstrates an attempt by the Company to shift the burden of just and reasonable rates to the Commission, while Vectren Response to JIs’ Data Request 3.20/4.20 (JI CX 3) shows a lack of an overall goal in the rate design presented.   Rather, the Company asserts that the proposed rate design is motivated by two key objectives: allocating costs according to cost causation, and avoiding increases in subsidies in rates. Petitioner’s Exhibit 7 at 4. Yet, the justifications put forth by the Company for this rate design proposal, even as modified by the Settlement, are either flawed or unsubstantiated in the record.  

The Company views all fixed costs associated with distribution-related investments as sunk costs to be assigned to a per-customer charge, and therefore to be unaffected by variation in customer demand. We agree with CAC Witness Rábago that this confusion of “sunk” and “fixed” costs ignores the impact that customer demand has on fixed costs going forward. The Company proposal to treat all fixed distribution-related costs as sunk costs eliminates any price signal for residential customers—sending them the very wrong economic message that there is nothing they can or need to do to help keep future fixed costs from rising.  

The Company implies that its proposed collection of distribution-related TDSIC costs as fixed customer charges reflects the principle of “cost causation,” but does not further explain how cost-causation leads to the rate design recommendation of recovering the costs in a fixed per-customer charge.  In fact, 
•	Vectren Response to JIs’ Data Request 5.9 and 5.10 (JI Exhibit 1, Attachments KRR-3 and -4) notes how the Company did not evaluate or estimate the impacts that its proposed rates would have on the level or pattern of customer usage. 
•	Vectren Response to JIs’ Data Request 5.11 (JI Exhibit 1, Attachment KRR-5) notes how the Company did not consider the impact of changes in marginal demand on future distribution related costs.  
•	Vectren Response to JIs’ Data Request 7.1 (JI CX 5) shows that Vectren has no consideration to segmenting residential customer class in spite of stated recline in homogeneity.  
•	Vectren Response to JIs’ Data Request 6.4 (JI CX 4) shows that Vectren does not have the data on cost, yet it still proposes to set identical fixed charges equal for every customer. 
•	Vectren Response to JIs’ Data Request 5.8(b) (JI Exhibit 1, Attachment KRR-3) shows how the Company is extremely inconsistent and unclear on its price signal motivations and refuses to address how it anticipates customers will respond to its proposed rate design.  
•	While the Company asserts that all charges for the distribution system-related components of its TDSIC plan should be recovered with per-customer charges because those component costs are fixed in nature (Petitioner Exhibit 7 at 9), the Company proposes to collect all transmission system-related costs in its TDSIC plan through a volumetric charge (Petitioner Exhibit 7 at 9) and also proposes volumetric charges that do not vary with time or location. (Petitioner Exhibit 9, Attachment JCS-2).
•	Vectren did not evaluate any alternative rate designs to its current proposal. (JI Exhibit 1, Attachments KRR-5-7). 
These all weigh against Vectren’s proposal as modified by the Settlement. 

In addition, the Company has not adequately considered the potential regressive impacts of its rate design proposal.  Vectren Response to CAC Data Request 1.5 (JI CX 1) demonstrates that the Company lacks the basic data about low income customers necessary to even know whether its rate design is regressive.  The Company proposes in its petition, and in the proposed Settlement, electric service rates for residential customers that are economically inefficient, unjustly discriminatory, and unreasonable, and that will impair customer choice and the economics of energy efficiency and distributed generation.  Yet, the Company has not considered the adverse impacts of its rate design proposal on the economics of energy efficiency, demand response, distributed generation, and other products and services that could enhance the overall economic efficiency of and strengthen the economy and electric system in Indiana.  Vectren Response to JIs’ Data Request 2.3 (JI CX 2) demonstrates that the Company does not address the impact of the changed rates on energy efficiency – and did not examine the potential effects; rather, the Company only says that there will still be a lot of volumetric charges at the end of the planned TDSIC period.  Even more telling is Vectren Response to JIs’ Data Request 2.4 (JI CX 2) which says “Vectren South has not performed any studies or collected data regarding customer payback expectations or willingness to invest in energy efficiency measures for residential and small commercial customers” and Vectren Response to JIs’ Data Request 2.8 (JI CX 2) shows that Vectren does not even claim any revenue loss due to distributed generation.  See also Public’s Exhibit No. 1-S at 6 (“The OUCC contends that, among other reasons, fixed charge increases provide inefficient pricing signals, and limit the ability of customers to control their own bills.”)  

Together, with the concern that this is the inappropriate venue for such a proposal, the Commission rejects this Settlement term to recover these costs through a fixed customer charge.  A fixed customer charge is not the only mechanism for recovering fixed costs.  We agree with CAC Witness Rábago that the use of volumetric rates to carry fixed costs do not present a financial integrity risk to the utility that should be remedied with higher fixed charges.  There is no statistical likelihood or evidence presented in this record of any real risk to the Company’s financial integrity due to some customers using less energy than the utility had forecast in the interval between rate cases. The adverse impact on low use, low-income, and fixed income elderly customers, as well as upon the economics of efficient use of energy, outweighs any hypothetical risk to the Company’s earnings. It should be noted that any revenue variances could more reasonably be addressed through better forecasting, more frequent rate cases, and, in times of market transformation, through the use of future test years.  Properly designed rates reflect properly allocated costs and send signals for efficient consumption in the future.  Sunk fixed costs, the focus of the Company’s concern in its customer charge proposal, can be reflected in either the fixed charge or a volumetric charge. An efficient price signal relating to future fixed costs can only be communicated with a volumetric charge. That is why a volumetric charge is the optimal rate design in this case for demand-related distribution fixed costs. The Company is so ordered to recover any costs approved herein for residential and small commercial customers through a volumetric charge.  

	Finally, we agree with Witness Rábago that more information is needed about the impacts of changes in rates on energy consumption—demand elasticity—among each of the Company’s rate classes and major subclasses; the impacts of a wide range of alternative residential rate design approaches on customer usage, on the economics of energy efficiency and demand response, on the economics of distributed generation, and on other potential services; and its low use and low-income customer base so that it can evaluate future rate and service impacts on these customers.  Vectren is hereby ordered to conduct such a study in collaboration with the other parties in this case, as well as with assigned Commission staff, in order to inform future rate designs and rate design proposals that the Company may put forth.  

			3.	Additional TDSIC Ratemaking Terms

	The Settlement Agreement addresses a range of ratemaking issues relevant to the semi-annual TDSIC tracker filings provided for under Ind. Code § 8-1-39-9 and Petitioner’s next base rate case.  These terms include a confirmation of Petitioner’s authority to: (i) apply CWIP ratemaking treatment to all eligible investments under the TDSIC Plan through the TDSIC; (ii) continue the statutory 80%/20% recovery and deferral of approved TDSIC costs through Appendix K, the Transmission, Distribution and Storage System Improvement Charge; (iii) adjust its authorized net operating income to reflect any approved earnings associated with the TDSIC for purposes of Ind. Code § 8-1-2-42(d)(3) pursuant to Ind. Code§ 8-1-39-13(b); and (iv) amortize and recover the $3.7 million incurred to assist in the development of the TDSIC Plan through the TDSIC tracker over a period of three (3) years commencing in TDSIC-1.
	
	The Settling Parties also agreed depreciation expense included for recovery in the TDSIC Plan will reflect an annualized level of expense related to the gross new capital investment as of the cut-off date of the TDSIC filing.  As the investment is placed in service, it will be classified in the appropriate FERC Plant Account, and depreciated using the depreciation rate approved for the Plant Account.  Similarly, the Settling Parties agreed property tax expense included for recovery in the TDSIC will reflect an annualized level of expense related to the gross new capital investment in service as of the cut-off date of the filing.  Vectren South agreed to net the depreciation expense associated with retired and replaced equipment against the depreciation expense associated with new equipment in the TDSIC Plan.

	The Settling Parties further agreed that the ROE included in the WACC for the TDSIC mechanism will be 10.4%, consistent with Vectren South’s most recent base rate case.  This Settlement Agreement notes that this agreement recognizes that (1) Vectren South will continue to net the original cost of retired assets from the depreciable base used to determine its incremental recoverable depreciation expense, and (2) Vectren South will not accrue carrying costs on the amount deferred representing 20% of the TDSIC plan revenue requirement.  

	No party opposed any of the foregoing terms.  We find that the agreed terms regarding ratemaking issues set forth in the Settlement Agreement are consistent with Ind. Code § 8-1-39-9(a)(1) and should be approved

		D. 	Additional Terms of the Settlement Agreement

	The following is a description of some of the significant provisions of the Settlement Agreement, which further support the determination that it is reasonable and in the public interest as discussed below.

			1.	Timing of TDSIC Tracker Filings			

	The Settlement Agreement addresses the cadence for future TDSIC tracker proceedings under Ind. Code §8-1-39-9. With the exception of the first tracker filing, these proceedings would be undertaken consistent with the statutory 90-day cycle contemplated by Ind. Code§ 8-1-39-12(a).  The first tracker filing associated with the TDSIC Plan will occur on August 1, 2017 to establish TDSIC rates and charges to be implemented with the first billing cycle starting November 1, 2017 or as soon thereafter as is practicable.  In order to make this feasible, Vectren South has agreed to waive the statutory deadline for an Order in this initial filing and modify the procedural schedule to ensure stakeholders’ testimony is due four weeks after the Commission issues an Order approving this Settlement Agreement.  The timing of the remaining tracker filings was determined after giving consideration to the general schedules of the Settling Parties and the Commission. Based on the foregoing, we find the Settling Parties’ agreement with respect to TDSIC tracker filings to be reasonable and in the public interest.

			2.	Flexibility within the TDSIC Plan

	The Settling Parties recognized that circumstances including system changes, reliability issues, or reasonable and prudent cost changes may dictate that the projects undertaken within the TDSIC Plan be subject to change or re-prioritization, and the Settlement Agreement provides that the dollars associated with a specific project can be moved between Plan years, in whole or in part, subject to certain limitations set forth in the Settlement Agreement. The Settlement Agreement also includes designated planned substitution projects, which Vectren South may construct and the costs of which it may recover through the TDSIC rates and charges. The planned substitution projects that are eligible to be moved into the TDSIC Plan are limited to a capital cost of $67 million in accordance with the agreement of the Settling Parties.  Originally, Petitioner had proposed a $250 million substitute project pool.  

	Each year in its August tracker filing, Vectren South will provide a detailed list of projects that will be completed during the upcoming year, with best estimate of project costs.  In addition, Vectren South will provide the actual completed costs of the projects completed in the prior year and updated projected cost estimates of the projects in the following years. For projects with actual or projected costs higher than the costs previously approved, Vectren South will provide justification in the form of written variance explanations.  The Settling Parties retain the right to challenge any costs that exceed approved estimates in accordance with Ind. Code§ 8-l-39-9(f).  

	The flexibility terms agreed upon by the Settling Parties ensure that Petitioner is not locked into a schedule for a specific set of projects today that in the future would not provide the greatest benefit to the T&D system and its users. At the same time, the foregoing terms do not allow Petitioner to make wholesale substitutions of projects without regard to the contents of the approved plan.  Accordingly, we find the Settlement Agreement provides an appropriate level of flexibility consistent with the TDSIC Statute, our prior orders and opinions of the Court of Appeals.  

			4.	Potential Future Rate Offerings

	In the Settlement Agreement, Vectren South agreed it would not offer dynamic or time-of-use price options as mandatory price options to any of its residential customers for the next seven (7) years.  In addition, Vectren South agreed to make any prepaid service associated with its AMI capabilities optional, unless and until Indiana passes legislation, or the Commission via a rulemaking establishes some form of prepayment option that is mandatory for certain customers.  

	CAC/Valley Watch witness Olson testified that the foregoing settlement term “strongly implies that, due to the planned deployment of AMI, the Company intends to offer prepaid service in its service territory.”  (JI Exh. 2 at 7.)  Accordingly, Mr. Olson asked the Commission to:
1)	Review the current administrative rules related to billing, disconnects and other related areas and update those rules to protect consumers from the many capabilities AMI offers, most notably the capability of remote disconnections and potential prepaid offerings; and  
2)	Utilize the guidance and recommendations provided by the NCLC report entitled “Rethinking Prepaid Utility Service, Customers at Risk” as well as the NASUCA resolution entitled “Rethinking Prepaid Utility Service, Customers at Risk” as templates for establishing rules related to the Company, or any other regulated utility, should they propose prepaid service offerings. 
Mr. Olson also recommended that should the Commission approve this term within the settlement, “the Commission should require and state with absolute certainty that if the Company chooses to propose offering prepaid service, voluntary or otherwise, the Company must seek that approval within a formal docketed proceeding which affords the public and any affected and interested stakeholders the opportunity to comment and participate fully.”

	We agree with Mr. Olson’s proposals and see the value in the Commission conducting a comprehensive review of a changing landscape, as admitted by Vectren, in the utility world of technology and offerings.  First, we note our continued support for the current Commission rules which prohibit prepaid offerings to the extent they imply the automatic disconnection of service when the meter runs out of funds.  Second, we have serious concerns with prepaid services and agree that it is a significant diversion from standard offer credit-based services and can deprive customers of critical consumer protections intended to keep households connected to what, everyone agrees, is an essential human service.  Although we are approving this term within the Settlement, the Commission is requiring that if the Company chooses to propose offering prepaid service, voluntary or otherwise, the Company must seek that approval within a formal docketed proceeding which affords the public and any affected and interested stakeholders the opportunity to comment and participate fully.  In addition, the Commission, with this Order, is opening a docket to review the changing landscape in the world of AMI and correlating offerings to examine the issues identified in the reports and resolutions highlighted in CAC Witness Olson’s testimony. 

	

			5.	Low-Income Reporting Requirements
	
	At the request of the one or more Settling Parties, but no more than annually, Vectren South agreed to make available certain data with respect to its customers that receive benefits from the Low Income Home Energy Assistance Program (“LIHEAP”).  CAC/Valley Watch witness Olson recommended that the Commission modify the Settling Parties’ agreement to:  (i) state “at least annually” rather than “no more than annually”; (ii) require that Petitioner report general residential customer data in addition to the low-income customer data; and (iii) require that the Company report the data directly to the Commission and that the Company make the data publicly available to all interested stakeholders.

	With respect to Vectren’s commitment to provide the data “no more than annually,” Petitioner’s witness Bugher testified that Vectren South is not concerned with providing the data annually and has specifically agreed that the Settling Parties may request the data annually.  However, Mr. Bugher stated that from Vectren South’s perspective, “we are willing to provide the data if it is useful, but we do not want to commit to pulling the data every year even if the other parties do not find it useful.”  (Pet. Exh. 15 at 5.)  Mr. Bugher also stated that providing the data required under the Settlement Agreement for all of its residential customers would be problematic because Vectren South does not collect data about its customers’ incomes, leaving no mechanism for this data to be utilized to evaluate the impact on low-income customers who are not receiving LIHEAP.  (Id. at 6.) 

We agree with CAC/Valley Watch on this matter.  We are pleased that the Settling Parties have come to an agreement which highlights this important issue.  But, Vectren’s rationale for its disagreement with the CAC on these issues is unconvincing.  CAC simply requested a modification to the Settlement term as it relates to reporting to:  (i) state “at least annually” rather than “no more than annually”; (ii) require that Petitioner report general residential customer data in addition to the low-income customer data; and (iii) require that the Company report the data directly to the Commission and that the Company make the data publicly available to all interested stakeholders.  We find CAC’s proposed modification to the Settlement on this matter to be in the public interest and a reasonable request. 

Regular reporting of indicators of payment problems should be required to assess on an ongoing basis the state of home energy security among Vectren’s residential customers, and to evaluate the effectiveness of programs and policies intended to protect that security. Further, such data reporting is needed to assess the effectiveness of the credit and collection policies and practices of the Company, with an eye toward improving such practices when appropriate. Implementing a regular data collection and reporting protocol, in light of sweeping changes underway in energy and utility industry technology and economics – changes that have profound bearing on the energy security of the Company’s most vulnerable customers– is particularly relevant and timely. 

Under Ind. Code § 8-1-2-26, the Commission may require the making of reports, including “other items, whether of a nature similar to those hereinbefore enumerated or otherwise, as the commission may prescribe, in order to show completely and in detail the entire operation of the public utility in furnishing the unit of its product or service for the public.”  Indiana’s regulators, policy-makers, consumers, and utility decision-makers are faced with difficult questions regarding the effectiveness of programs and policies designed to ensure regular payment for utility service while recognizing the essential nature of that service.  Questions regarding appropriate expenditure for energy efficiency and payment assistance, the effectiveness of existing regulatory consumer protections and credit and collection practices can only be answered through data-driven analysis of trends in customer arrearages, service terminations and related indicators of the magnitude of utility payment troubles.  Without timely trend data, it is not possible to appropriately respond to the payment troubles increasingly being experienced within the low-income population.  

 The evidence of record shows that Vectren is the only entity that has the data on these matters.  It would be difficult for outside entities to understand the effectiveness of credit and collection practices and policies of Vectren without this data.   It would be difficult for outsiders to understand the state of home energy security among Vectren’s residential customers without this data, or the appropriate amount of expenditures required to help low income customers with energy efficiency programs and payment assistance without this data. 

Furthermore, both general residential and low income residential customer data is now being reported by three other investor-owned electric utilities to the public on an annual basis.  See the Settlement Agreement approved in Cause Nos. 43114 IGCC 15, the Performance Metric Report filed in Cause No. 44576/4460, and the Performance Metric Report filed in Cause No. 44688.  Consistency is an important consideration for the Commission here. 

Thus, the Commission hereby modifies this Settlement term to: (i) state “at least annually” rather than “no more than annually”; (ii) require that Petitioner report general residential customer data in addition to the low-income customer data; and (iii) require that the Company report the data directly to the Commission and that the Company make the data publicly available to all interested stakeholders.  

	
	10.	Conclusion Regarding Settlement Agreement

	For all of the foregoing reasons, we find the Settlement Agreement is reasonable, supported by the evidence of record and in the public interest and should be approved as modified herein.  As discussed above, the TDSIC Plan is supported not only in the Settlement of the Settling Parties, but also by a substantial and uncontested evidentiary record. We note that the Settlement Agreement resolves a number of previously contested issues in a manner consistent with the TDSIC Statute, opinions of the Indiana Court of Appeals and previous Orders of the Commission. In so doing, the Settlement provides clarity and predictability with respect to future TDSIC tracker filings in a manner that is consistent with the public interest and administrative efficiency.

	The Settlement provides both the Settling Parties and the Commission with a clearly defined structure for the consideration of TDSIC tracker proceedings based on the TDSIC Plan, including agreements on ratemaking and the timing and frequency for those filings. It is evident from the terms of the Settlement that there were compromises undertaken by the Settling Parties as to cost recovery caps, the appropriate amount of distribution-related TDSIC costs to be recovered through the fixed charge, reporting obligations, and the provision of flexibility in the implementation of the projects. We find that the compromises, except as it relates to the fixed charge recovery proposal which is modified herein, embodied in the Settlement are consistent with the applicable statutory provisions and are reasonable and in the public interest.

	 11.	Effect of Settlement Agreements 

With regard to future citation of the Settlement Agreement, we find the agreement and our approval thereof (as modified herein) should be treated in a manner consistent with our finding in Richmond Power & Light, Cause No. 40434 (approved March 19, 1997) and the terms of the agreement regarding its non-precedential effect. The Settlement Agreement shall not constitute an admission or a waiver of any position that any of the Parties may take with respect to any or all of the items and issues resolved therein in any future regulatory or other proceedings, except to the extent necessary to enforce its terms.

	12.	Confidentiality 

	Vectren South filed a motion for protection of confidential and proprietary information on February 23, 2017. In the motion and supporting affidavit, Vectren South demonstrated a need for confidential treatment for the detailed work cost estimates for prospective T&D projects and detailed cost estimates for Vectren South’s Advanced Metering Infrastructure Project. On March 8, 2017, the Presiding Officers made preliminary determinations that such information should be subject to confidential procedures. We find that all such information, including similar information filed in support of the Settlement Agreement, is confidential pursuant to Ind. Code § 5-14-3-4 and Ind. Code § 24-2-3-2, is exempt from public access and disclosure by Indiana law, and shall be held confidential and protected from public access and disclosure by the Commission.  However, we note that Vectren South must file this information publicly as soon as the detailed work cost estimates no longer meet the threshold for confidential protection by the Commission. 

IT IS THEREFORE ORDERED BY THE INDIANA UTILITY REGULATORY COMMISSION that:  

1.	The Settlement Agreement is hereby approved subject to the modifications herein.

2.	The projects contained in Vectren South’s revised TDSIC Plan provided as Petitioner’s Exhibit No. 10, Attachment LKW-S2, including the substitution projects, are “eligible transmission, distribution, and storage system improvements” within the meaning of Indiana Code § 8-1-39-2.

3.	Vectren South is authorized to implement Appendix K, the Transmission, Distribution and Storage System Improvement Charge, as well as implement the other tariff changes described by Petitioner’s witness Swiz pursuant to Ind. Code § 8-1-39-9(a) to effectuate the timely recovery of 80% of up to $446.5 million of eligible and approved capital expenditures and TDSIC costs.

4. 	Vectren South is authorized to defer 20% of eligible and approved capital expenditures and TDSIC costs under Ind. Code§ 8-1-39-9(b) and Vectren South is hereby authorized to recover the deferred capital expenditures and TDSIC costs as part of Vectren South’s next general rate case.

5.	Vectren South shall allocate the cost associated with the TDSIC Plan in the manner described in the Settlement Agreement subject to the modifications herein in that no portion of the costs will be recovered through a fixed monthly charge. 

	7.	Vectren South is authorized to adjust its authorized net operating income to reflect any approved earnings associated with the TDSIC for purposes of Ind. Code § 8-1-2-42(d)(3) pursuant to Ind. Code§ 8-1-39-13(b).

	8.	The proposed process for updating the 7-Year Plan and filing future TDSIC adjustment proceedings is approved. Vectren South shall file its first TDSIC tracker proceeding on August 1, 2017.

	9.	The information filed by Vectren South in this Cause pursuant to its Motion for Protective Order is deemed confidential pursuant to Indiana Code § 5-14-3-4 and Indiana Code § 24-2-3-2, is exempt from public access and disclosure by Indiana law, and shall be held confidential and protected from public access and disclosure by the Commission.

10.	This Order shall be effective on and after the date of its approval.

ATTERHOLT, FREEMAN, HUSTON, WEBER AND ZIEGNER CONCUR:

APPROVED:

I hereby certify that the above is a true
and correct copy of the Order as approved.

							
Mary M. Becerra
Secretary to the Commission