BEFORE THE PUBLIC SERVICE COMMISSION OF WYOMING

 

IN THE MATTER OF THE AMENDED APPLICATION OF MONTANA-DAKOTA UTILITIES CO., A DIVISION OF MDU RESOURCES GROUP, INC., FOR A GENERAL RATE INCREASE FOR ITS WYOMING ELECTRIC UTILITY SERVICE RATES OF $5,053,756 PER ANNUM

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Docket No. 20004-81-ER-09

(Record No. 12259)

 

APPEARANCES

 

For the Applicant, Montana-Dakota Utilities Co. (MDU or the Company):

BRUCE S. ASAY of Associated Legal Group, Cheyenne, Wyoming.

 

For the Intervenor, Office of the Consumer Advocate (OCA):

IVAN H. WILLIAMS, Senior Counsel, Cheyenne, Wyoming.

 

MEMBERS OF THE PUBLIC APPEARING PRO SE

 

STEVE MAIER, Chairman of the Sheridan County Commission

BILL BRADSHAW, Chairman of the Sheridan School District Board of Directors

CRAIG DOUGHERTY, District Superintendent, Sheridan School District

DAVE KINSKEY, Mayor, City of Sheridan

BILL BENSEL, Sheridan, Wyoming

MARYANN BURTON, Trustee of the Sheridan School District No. 2

ED JOHLMAN, CFO, Sheridan Memorial Hospital

LES ENGELTER, AARP, Sheridan, Wyoming

BOB ORRELL, Trustee, Sheridan Public Library

JILL MORRISON, Powder River Basin Research Council

DAVID KANE, Sheridan County Stock Growers

ROB FORISTER, Facilities Manager, Sheridan Memorial Hospital

MIKE NIKE, Sheridan County Commissioner,

and numerous other MDU customers

 

HEARD BEFORE

 

Chairman ALAN B. MINIER

Deputy Chairman STEVE OXLEY

Commissioner KATHLEEN A. LEWIS

 

STEVE MINK, Assistant Secretary, and DAVID J. LUCERO, Attorney Supervisor

Presiding pursuant to a Special Order of the Commission

 

MEMORANDUM OPINION, FINDINGS AND FINAL ORDER

(Issued May 26, 2010)

 

This matter is before the Wyoming Public Service Commission (Commission) upon the amended application of MDU for authority to increase its Wyoming electric utility service rates in the amount of $5,053,756 per annum, on the intervention of the OCA and the comments and representations of the members of the public appearing pro se herein.  The Commission, having reviewed the original application and attached exhibits, the amended application and attached exhibits, the evidence of record, the Stipulation and Agreement (Stipulation), its files regarding MDU, applicable Wyoming utility law, and being otherwise fully advised in the premises, hereby FINDS AND CONCLUDES:

 

Findings of Fact: Parties and Procedure

 

            1.         On August 14, 2009, MDU filed its original application, together with pre-filed testimony and exhibits and revised tariff sheets, requesting authority to increase its retail electric utility service rates in Wyoming by $6,198,501 per year, or an overall average increase of 30.7%.  MDU stated the proposed rate increase was necessary to recover its 25% ownership interest investment in the Wygen III generating unit (Wygen III or the Plant).  MDU noted it received a Certificate of Public Convenience and Necessity (CPCN) to participate in the Wygen III coal-fired electric generating unit in Docket No. 20004-72-EA-08.  The certificate authority made no determinations regarding any ratemaking issues associated with MDU’s participation in the generating unit.  The Company stated that Wygen III was expected to be completed and ready for commercial operation in the second quarter of 2010.  MDU stated its investment in Wygen III secures a reliable long-term supply source for a portion of the electric requirements for the Company’s Sheridan System.  MDU stated that it currently purchases its energy and capacity requirements for its Wyoming electric customers through a purchased power contract with Black Hills Power, Inc. (Black Hills).  MDU stated that, when the purchased power contract expires in 2016, its customers will become exposed to uncertain and potentially volatile wholesale power costs.  Participation in WYGEN III will help protect its customers from future wholesale market volatility.

 

            2.         MDU stated that its net rate base would increase by approximately $62 million upon completion of Wygen III, reflecting the Company’s 25% ownership interest in the Plant, together with increased operation and maintenance (O&M) expenses associated with the Wygen III facility, but net of a reduction in purchased power costs under its current full requirements contract with Black Hills.  The Company estimated the rate impact in Wyoming would be approximately $6,198,501 annually or an overall average increase of 30.7% based on a 2008 pro forma test year.  The test year in this case consisted of the 12 month period ending December 31, 2008.  MDU stated that its existing rates were unjust, unreasonable, and not compensatory, and therefore should be increased as requested to allow the Company to earn an adequate return on its investment in Wygen III.

 

            3.         MDU proposed to recover the requested revenue increase from its various customer classes in the following amounts and percentages:

 

Class

Increase

Percentage Change

Residential

$2,968,001

26.1%

Small General Service

$1,552,124

41.3%

Irrigation Service

$70,255

26.9%

Large General Service

$1,579,743

34.5%

Lighting

$28,378

16.7%

Overall Increase

$6,198,501

30.7%

 

4.         With its application, MDU filed the prepared direct testimony of David L. Goodin, J. Stephen Gaske, Darcy J. Neigum, Garrett Senger, Rita A. Mulkern, and Tamie A. Aberle, together with supporting exhibits, studies, and other documentation for the case.

 

5.         On August 17, 2009, the Commission issued its Suspension Order suspending the Company’s rates in this case for investigation and further action for the initial six-month period provided in W.S. § 37-3-106(c), which commences after the 30-day notice term provided in subsection (b) thereof.

 

6.         On August 25, 2009, the Commission issued its Notice of Application, providing for an intervention, comment and protest deadline of September 25, 2009.  The Notice of Application was published once a week for two consecutive weeks in the Sheridan Press and a public service announcement was aired five times a week for two weeks on KROE-AM in Sheridan.

 

7.         The OCA filed its Notice of Intervention on August 25, 2009, and requested the application be set for public hearing.  No other formal -- and timely -- intervention petitions were filed.

 

8.         On September 24, 2009, MDU customers filed with the Commission a petition bearing numerous customer signatures, opposing the proposed rate increase and requesting a public hearing be held in the Sheridan area. Throughout the course of these proceedings, numerous MDU customers filed comments opposing the general rate increase or the proposed increase to the Irrigation class.  Some of the customer comments also requested that a public hearing be held in Sheridan.  Copies of all customer comments and requests for a public hearing were provided to MDU and OCA.

 

9.         On October 15, 2009, the Commission issued its Notice of Setting Scheduling Conference which set a scheduling conference for November 4, 2009, in the Commission’s hearing room in Cheyenne, Wyoming.

 

10.       On October 20, 2009, the Commission issued its Special Order Authorizing One Commissioner and/or Hearing Examiner to Conduct Public Hearing.

 

            11.       The duly noticed scheduling conference was held on November 4, 2009.  Bruce S. Asay, local counsel for MDU, participated in person.  Rita Mulkern and Tamie Aberle for MDU participated by telephone.  Ivan Williams, counsel for the OCA, and David Lucero, Steve Mink and Marci Norby, of the Commission Staff, participated in person.

 

            12.       On November 5, 2009, the Commission issued its Scheduling Conference Order (Scheduling Order) which established a procedural schedule agreed to by the parties at the scheduling conference, including a public hearing commencing on February 23, 2010, in the Commission’s hearing room in Cheyenne, Wyoming.

 

13.       The Commission issued its Procedural Notice and Order Setting Public Hearing on November 10, 2009 (Procedural Order).  It set a public hearing to commence on February 23, 2010, in the Commission’s hearing room in Cheyenne, and provided for the filing of written public comments by February 23, 2010.  It was published once per week for two consecutive weeks in the Sheridan Press and a public service announcement was aired five times a week for two weeks on KROE-AM in Sheridan.

 

14.       To accommodate the requests of MDU customers for a Sheridan public hearing, the Commission issued its Procedural Notice and Order Setting Public Comment Hearing on December 9, 2009, setting a public comment hearing to commence on February 10, 2010, at the Sheridan Public Library.  It was published once per week for two consecutive weeks in the Sheridan Press and a public service announcement was aired five times a week for two weeks on KROE-AM in Sheridan.

 

15.       On December 30, 2009, Dave Kinskey, Mayor of the City of Sheridan (the City), filed a letter offering the Sheridan City Council Chambers as a location for the February 10, 2010, public comment hearing as it is equipped with a camera system which allows for live broadcast, recording and rebroadcasting on the City’s local government channel.  He stated there was a tremendous amount of interest in MDU’s proposed rate increase and it would be beneficial to the public to be able to broadcast the hearing.  On January 4, 2010, via electronic mail, the parties were advised that the location of the public comment hearing had changed and would now be held in the Sheridan City Council Chambers.

 

16.       On January 14, 2010, MDU filed its supplement to application (Amended Application) together with appendices, exhibits and statements, which had the effect of amending the Company’s original application.  MDU stated that, after a review of the applicable federal authority, it believed it was entitled to take certain bonus depreciation deductions for Wygen III.  The Amended Application was filed to reflect bonus depreciation deductions associated with Wygen III expenditures that reduced the revenue increase found in the Company’s original application from $6,198,501 per annum (30.7 % overall) to $5,053,756 per annum (25.1% overall).

 

            17.       The amended rate increase was proposed to be recovered from the various customer classes by the following amounts and percentages:

 

Class

Increase

Percentage Change

Residential

$2,414,230

21.2%

Small General Service

$1,296,410

34.5%

Irrigation Service

$55,496

21.2%

Large General Service

$1,263,787

27.6%

Lighting

$23,833

14.0%

Overall Increase

$5,053,756

25.1%

 

18.       On January 19, 2010, OCA pre-filed the direct testimonies and respective exhibits of Denise Kay Parrish, Amy J. Zamora and Kimber M. Wichmann.

 

19.       On January 21, 2010, the Commission issued its Amended Procedural Notice and Order Setting Public Hearings (Amended Procedural Order).  The Amended Procedural Order gave notice that the Company’s original application had been amended and the amount of the proposed revenue increase and the recovery of the proposed increase from the various customer classes had also been revised.  Further, the notice provided that the February 10, 2010, public comment hearing to be held at the Sheridan Public Library had been relocated to Sheridan Community College.  The Amended Procedural Order also provided additional notice of the public hearing already scheduled to commence on February 23, 2010, in the Commission’s hearing room in Cheyenne.  It was published once per week for two consecutive weeks in the Sheridan Press and a public service announcement was aired five times a week for two weeks on KROE-AM in Sheridan.  A display ad announcing the Sheridan public comment hearing was also published in the Sheridan Press on February 4 and 8, 2010.  Copies of the Amended Procedural Order were also sent to customers who submitted comments or requests for hearing in this matter.

 

20.       On January 20, 2010, the City filed, via facsimile, a Petition for the City of Sheridan for Leave to Intervene Out-of Time (Late-Filed Petition) stating, inter alia, that it did not have adequate notice of MDU’s application.  The City requested that it be allowed to intervene out-of-time and respond to MDU’s application, via pre-filed testimony.  A signed hard copy of the Late-Filed Petition was filed on January 21, 2010.  The City filed a First Amended Petition of the City of Sheridan for Leave to Intervene Out-of-Time via facsimile, on January 22, 2010, and a signed hard copy of the First Amended Petition on January 25, 2010.  The First Amended Petition was signed by the City’s counsel, Robert P. Warburton of Sheehan, Sheehan & Stelzner, P.A., a licensed Wyoming attorney.

 

21.       On January 25, 2010, MDU filed the Supplemental Testimony of Witnesses Rita A. Mulkern and Tamie A. Aberle, in support of the amended application.

 

22.       On January 27, 2010, MDU filed its Objection of Montana-Dakota Utilities Co. To the Petition of City of Sheridan, Wyoming to Intervene (Objection).  The City’s First Amended Petition and MDU’s Objection came before the Commission for consideration pursuant to due notice at its open meeting of January 27, 2010.  Based on the arguments of the parties and its finding that the City had not shown good cause for the failure to timely request intervention, the Commission denied the City’s intervention request by Order Denying Intervention issued on February 23, 2010.  The Commission strongly encouraged City representatives to participate in this proceeding through the presentation of oral comments at the public hearings in this matter or by providing written comments as provided for in Commission Rule Section 103 (g).

 

23.       On February 5, 2010, MDU filed its Electric Division Depreciation Study and its Common Plant Depreciation Study, both as of December 31, 2008, and depreciation testimony of Rita A. Mulkern.

 

24.       On February 9, 2010, MDU filed the rebuttal testimony of Dr. J. Stephen Gaske, Rita A. Mulkern and Tamie A. Aberle.

 

25.       On February 10, 2010, and pursuant to due public notice, a public comment hearing was held in Sheridan.  MDU and OCA witnesses provided brief summaries of their respective positions and members of the public were invited to offer comments.  Numerous customers offered their comments during this public comment hearing.

 

26.       Pursuant to the Scheduling Conference Order issued on November 5, 2009, the Commission held a pre-hearing conference on February 12, 2010, in the Commission’s hearing room in Cheyenne, Wyoming.  On that day, [i] OCA filed its Updated Summary of Contentions, Designation of Exhibits and Summary of Remaining Issues; and MDU also filed its Scheduling Conference Memo For Montana-Dakota Utilities Co., A Division of MDU Resources Group, Inc.  The Commission issued a Prehearing Conference Order on February 19, 2010.

 

27.       On February 16, 2010, MDU filed its List of Exhibits and Summary of Contentions.

 

28.       On February 17, 2010, OCA filed its Amended Designation of Exhibits.  Transcripts of the February 10, 2010, public comment hearing were also received in the Commission’s office on February 17, 2010.

 

29.       A public hearing in this matter was held on February 23-25, 2010, in Cheyenne.  MDU and OCA appeared and participated in the hearing.  MDU presented its case through six witnesses, David L. Goodin, Dr. John Stephen Gaske, Garrett Senger, Darcy Neigum, Rita Mulkern and Tamie Aberle.  OCA presented its case through three witnesses, Denise Kay Parrish, Amy J. Zamora and Kimber Wichmann.  Public comments were provided by MDU’s customers.

 

30.       On March 3, 2010, MDU filed its Late-Filed Exhibit Nos. 157 and 158.  Exhibit No. 157 provides support for the Company’s calculation of the allowance for funds used during construction (AFUDC) as of December 31, 2009, shown on MDU Exhibit No. 139.  Exhibit No. 158 supports MDU’s share of the Shared Assets, Ground Lease and Administrative Fee shown on MDU Exhibit No. 139.

 

31.       On March 5, 2010, MDU filed the Stipulation, the affidavit of David L. Goodin, and the testimony of Rita A. Mulkern and Tamie A. Aberle in support of the Stipulation; and OCA filed Amy J. Zamora’s testimony in support of the Stipulation.  In the Stipulation, MDU and OCA agreed, inter alia, to an increase in the Company’s Wyoming jurisdictional retail electric service revenues in the amount of $3,253,726 per annum, effective for service rendered on and after May 1, 2010, with the increase to be phased in over a three-year period.

 

32.       The Commission issued its second Suspension Order on March 9, 2010, suspending the Company’s rate increase request for the final three-month period provided for in W.S. § 37-3-106(c).  Also on this date, the Commission issued its Procedural Notice and Order Reopening Record and Setting Additional Public Hearing.  It set an additional public hearing to commence on March 22, 2010, in Cheyenne. At this additional public hearing, the Commission expressed its intent to receive into the record [i] the Stipulation, [ii] the testimony and exhibits of MDU and OCA in support of the Stipulation, and [iii] further public comment.  The Procedural Order was published on March 13 and 17, 2010, in the Sheridan Press and a public service announcement was aired five times on KROE-AM in Sheridan during the week of March 14-21, 2010.

 

33.       On March 12, 2010, MDU filed its Late-Filed Exhibit No. 159 which provides the detailed class of service study and work papers underlying MDU Exhibit No. 130.  On March 15, 2010, the OCA and MDU filed their Joint Responses to Stipulation Data Requests.

 

34.       On March 16, 2010, OCA filed Exhibit AJZ-1 as referenced in the Stipulation Testimony of Amy J. Zamora on Behalf of the Wyoming Office of Consumer Advocate,

 

35.       On March 16, 2010, transcripts of the hearings held on February 23-25, 2010, were received in the Commission’s offices.  Parties were notified on March 17, 2010, via electronic mail, that the transcripts were received and post hearing briefs were due on or before April 7, 2010.

 

36.       On March 22, 2010, the Commission held an additional public hearing in Cheyenne, reopening the record for purposes of receiving the Stipulation and the testimony and exhibits of the parties in support thereof.  MDU offered the testimony of its witnesses, Rita Mulkern and Tamie Aberle.  OCA offered the testimony of Amy J. Zamora.

 

37.       On April 7, 2010, MDU and OCA filed their Combined Post-Hearing Brief.

 

38.       On April 8, 2010, transcripts of the hearing held March 22, 2010, were received in the Commission’s offices.  Parties were notified on April 8, 2010, via electronic mail, that public deliberations would be held on April 14, 2010, in the Commission’s hearing room.

 

39.       Pursuant to W.S. § 16-4-403, the Commission held public deliberations on April 14, 2010, rejecting the Stipulation and the rate increase reflected therein, approving inter alia, a general rate increase of $2,651,565 per annum and directing the preparation of an Order consistent with its deliberations.

 

40.       As directed by the Commission at deliberations, MDU submitted on April 23, 2010, its compliance tariff sheets consistent with the deliberations of the Commission.  The tariff sheets were approved at the Commission’s open meeting of April 27, 2010, to be effective for service rendered on and after May 1, 2010.

 

Findings of Fact:  Party Positions

 

Summary of MDU’s evidence

 

41.       Mr. David Goodin, President and CEO of MDU, provided a summary of his prefiled testimony (MDU Exhibit No. 100) in support of the Company’s amended application.  He discussed the amended application and provided a policy statement and justification for MDU’s rate increase request.  Goodin testified that the requested general rate increase of $5,053,746, or 25.1% in the Company’s Wyoming electric rates is based on a 2008 test year adjusted for known and measurable changes.  Goodin stated MDU was requesting a rate increase to recover its investment in Wygen III explaining the Plant secures a reliable supply source for a portion of MDU’s electric requirements.  Goodin explained that the overall rate increase and revenue requirement will reflect customer class percentage rate changes as follows:

 

Class

Percentage Change

Residential Rates Schedules 10 and 18

21.2%

Small General Service

34.5%

Irrigation Service

21.2%

Large General Service

27.6%

Municipal; Lighting

14.0%

Overall Increase

25.1%

 

(Tr., pp. 140-141.)

 

42.       Goodin stated MDU currently purchases its energy and capacity requirements through purchased power agreements (PPAs).  MDU’s current full requirements contract with Black Hills, which commenced on January 1, 2007, was filed in Docket No. 20004-65-EP-06 (Sub 65).  This full requirements contract expires December 31, 2016, and contains an option for MDU to purchase up to 25 megawatts from Black Hills’ Wygen III generating unit.  Goodin stated that MDU exercised that option and purchased a 25% ownership interest in the Plant to serve its Wyoming electric service customers.  MDU also filed an application for a Certificate of Public Convenience and Necessity (CPCN) in Docket No. 20004-72-EA-08 (Sub 72) for participation in Wygen III, which has an expected in service date of April 1, 2010.  Goodin testified that, upon completion of the Plant, the Company’s net rate base will increase by approximately $62 million to reflect its 25% interest ownership together with the increased O&M expenses associated with the facility, offset in part by a net reduction in power purchase costs under the current full requirements contract with Black Hills.  He stated that MDU’s participation in the Plant will help protect its ratepayers from the volatile energy market by providing a cost-effective resource and bring diversity to the Company’s resource mix by including Company-owned generation with power supply purchases, rather than being totally dependent on PPAs.  He discussed how the electric resource modeling process used in the CPCN application took into account possible carbon legislation (cap and trade), carbon costs and pollution considerations.  The Company’s electric resource analysis demonstrated that a combination of Wygen III, demand side management (DSM) and supplemental purchased power would provide an adequate, reliable and economic electric supply.  Goodin also discussed MDU’s efforts to employ technological advances to streamline its business practices and its utility integration efforts to become more efficient and save money.  He testified to the benefits and risks to the Company in owning a partial interest in the Plant.  He also discussed how the Company’s ownership and investment of monies increases the risk to ratepayers and the reasons the Company took on the increased risk as a result of its investment in Wygen III.  (Tr. pp. 141-144, 150-151, 153-159; MDU Exhibit No. 100, pp. 10-12.)

 

43.       Dr. John Stephen Gaske, Senior Vice President of Concentric Energy Advisors, provided a summary of his prefiled testimony including attached supporting exhibits.  (MDU Exhibits 101-102.)  Gaske’s testimony addressed his analyses in support of his suggested cost of common equity capital of 12.75% for MDU’s Wyoming electric utility operations.  Gaske stated he calculated the cost of common equity capital based on Discounted Cash Flow (DCF) analyses of a proxy company group with risks similar to those of MDU’s Wyoming electric operations.  He stated the purpose of the DCF analysis is to find the discount rate or the cost of capital that is implicit in the stock price of any given utility and reflects what investors expect to receive from their investment in the future.  He stated the DCF analysis is a straightforward approach for estimating the cost of capital.  Gaske testified he conducted two different DCF analyses: [i] a basic DCF analysis that relies on investment analysts’ estimates for the growth rate; and [ii] a two-step growth rate estimation model that combines investment analysts’ growth rates with forecasts of the earnings retention growth rates of companies.  He also performed Risk Premium and Alternative Equity Investment analyses in establishing benchmarks for a reasonable rate of return.  Gaske argued that the results of his DCF analyses must be adjusted by a flotation factor to account for issuance costs for new common equity capital.  He used a flotation adjustment factor of 3.7% which he based upon the average cost of a representative sample of flotation costs incurred by electric companies for 81 new common stock issuances during the period 2000-2009.  Gaske stated he used a group of 13 proxy companies that have similar risks to those of MDU’s Wyoming electric utility operations.  He discussed his belief that the OCA’s proxy companies were less comparable to MDU than his proxy companies, stating it was more important to have companies as comparable as possible than it is to have a larger group of companies as proposed by OCA.  Gaske discussed his 13 proxy companies stating, inter alia, he chose companies that [i] have at least 85% of their invested assets dedicated to electric utility operations; [ii] derive at least 25% of their generation from coal-fired plants; and [iii] have investment grade bond rating, [iv] paid dividends and [v] have published growth rate estimates provided by investment analysis services.   He acknowledged that a true proxy company does not exist.  (Tr., pp. 168-171, 175-176, 188-191; MDU Exhibit No. 101, pp. 3, 9, 16.)

 

44.       Gaske testified that, in a DCF analysis, the dividend yield portion of the equation is simple to calculate but the future growth rate component is more difficult to estimate.  His basic DCF analysis, which relied solely on investment analysts’ forecasts for determining the growth rate component, resulted in a median cost of equity of 12.73%, an average cost of 12.91%, and a proposed return of 12.95%.  Gaske testified that his two-step DCF growth rate estimation analysis, which ascribes two-thirds weight to investment analysts’ forecasts and one-third weight to Value Line’s retention growth rates for his proxy companies, resulted in a median cost of capital of 11.56% with an average for the group of 12.1% and a 12.62% return.  He stated it was his opinion, given the slightly above average risk of MDU’s Wyoming electric operations, that the required rate of return on common equity for MDU’s Wyoming electric operations is approximately 12.75%.  He discussed how the rate of return for MDU’s Sheridan system affects the overall Company and he acknowledged that the 12.75% rate of return is higher than normal.  Gaske explained that with the stock market down, investors require a higher rate of return because they perceive more risks in investments.  Gaske stated the decrease in stock prices in the market increased his current DCF analysis results versus what the result would have been two years ago.  (Tr., pp. 172-178, 186-187, 192-195.)  He discussed the different risks faced by utilities and investors, the additional risk to a company of having coal-generated resources in its portfolio, and the differences in the risk associated with having an ownership interest in Wygen III and entering into PPAs.  He stated that with PPAs more risk falls on the ratepayers and with an investment in its own plant, a company assumes more of the risk than would the ratepayers.  (Tr., pp. 179-182, 188-191, 194-203, 206-212.)

 

45.       During cross examination and in his rebuttal testimony (MDU Exhibit No. 135), Gaske criticized OCA witness Kimber Wichmann’s proxy company selection and screening criteria, to include what he termed her failure to limit her proxy group to coal-fired generation assets, and her exclusion of companies with bond ratings above MDU’s, while including companies with bond ratings below MDU, and her use of comparable companies with electric operating revenue of 70% or more, whereas his threshold was 85% of electric revenues.  Further, he disagreed with her application of the constant growth and two-stage DCF models, her use of the Capital Asset Pricing Model as a method of estimating the cost of common equity capital, and her use of a partial flotation cost adjustment.   (Tr., pp. 179-186; MDU Exhibit No. 135, pp. 4-5, 29-39, 53-54.)

 

46.       Gaske also offered a summary of his rebuttal testimony (MDU Exhibit No. 135) responding to OCA witness Denise Parrish’s proposal to levelize the cost of the returns on Wygen III over the OCA’s recommended expected 50-year depreciable life of the Plant, in contrast to traditional ratemaking wherein the return is earned on the net value of the Company’s rate base each year.  He stated the OCA’s proposal would deny MDU an opportunity to earn a fair return on its investment in Wygen III.  He stated, under OCA’s proposal, common equity investors would be allowed to only earn a 3.20% return on Wygen III during the first year as compared to the higher returns on equity (ROE) he and Wichmann propose.  He argued that ratepayers would be denied the opportunity to earn a fair rate of return on the Wygen III investment until twenty years in the future.  He stated that OCA’s proposal does not provide: [i] a rate of return sufficient to assure the financial integrity of the Company, [ii] sufficient revenue to cover the financial costs of the utility, or [iii] a return comparable to similar investments of like risk.  He stated OCA’s proposal deprives common equity investors of approximately $8.7 million in present value dollars that would otherwise be available to them under a normal rate of return on rate base calculation.  Regarding levelization and cash flow, Gaske stated Parrish did not look at what effect levelization would have on the equity holders; she only looked at the overall rate of return.  Gaske stated his calculation illustrated that levelization would cover the debt service but would substantially cut the equity return.  (Tr., pp. 719-720, 729-731; MDU Exhibit No. 135, pp. 2-3, 6-8, 12.)

 

47.       Gaske stated that Parrish’s levelized proposal incorrectly assumes investors will be reimbursed for the cost of their capital 50 years from now.  Gaske stated that, during the proposed 50-year levelization period, much of the equipment will be replaced or refurbished because the levelization period exceeds the life of many of the assets.  Further, the overall rate of return of 8.45% utilized in her levelization proposal is too low in comparison to the Company’s proposed overall rate of return.  He stated Parrish failed to recognize that interest on the debt must be paid before the equity investors receive any return.  He stated that, under the OCA’s proposal, most of the overall return dollars available in the early years will be paid as interest to the debt holder and more equity returns will be pushed out to the later years and will not provide full compensation for the time value of their deferred investment.  Gaske stated that, for the equity holders to actually stay whole under Parrish’s levelized overall rate of return of 8.45%, the bondholders would have to agree to defer their receipt of interest.  He discussed further complications that would need to be considered when considering a levelized approached.  (Tr., pp. 719-720, 737-742; MDU Exhibit No. 135, pp. 4.)

 

48.       Gaske noted Parrish’s proposal does not recognize or account for the significant increase in business and regulatory risks that would be caused by OCA’s recommendations.  He stated that the Company’s auditor advised him that OCA’s proposal would not qualify for SFAS 71 treatment in the recording of a regulatory asset.  He stated MDU’s auditor advised him that you can defer an expense item but you cannot record deferrals for revenue items.  (Tr., pp. 732-734.)

 

49.       Mr. Darcy Neigum, MDU Systems Operations and Planning Manager, [i] provided a summary of his prefiled testimony (MDU Exhibit No. 103) which offered an overview of Wygen III, [ii] discussed the Company’s March 2008 Integrated Resource Plan (IRP) filed as part of its CPCN application in the Sub 72 proceeding, and [iii] described how Wygen III worked in conjunction with the current Black Hills’ PPAs.  He stated the Plant was expected to be fully commercial and operational on or around April 1, 2010.  He discussed the three main areas the IRP encompassed: [i] a load forecasting update; [ii] a Demand Side Management update; and, [iii] a supply-side update which included a market analysis of the estimated energy market.  Neigum also discussed MDU’s long-term coal supply agreement with Wyodak Resources for Wygen III, its terms and how the coal would be transported from the Wyodak Mine to Wygen III.  He discussed the benefits of the Plant, stating they occur over the long term and include, inter alia, protection for Wyoming rate payers from wholesale market volatility.  He stated participation in Wygen III provides MDU with ownership of a stable and cost-effective resource, brings diversity to its resource mix, and provides a more stable power supply to the customers’ benefit.  Neigum testified that, in conjunction with MDU’s 25% ownership in Wygen III, the Company executed an amendment to its full requirements PPA with Black Hills to service its Sheridan load.  The amended PPA runs through December 16, 2016.  He stated MDU will be required to use its ownership share of the Wygen III output or rely on replacement power to serve the Sheridan load.  Neigum further explained that, following the commercial operation of Wygen III, the PPA will supply all needed resources above those provided by the Company’s share of the Plant up to 74 MW.  (Tr., pp. 219-224, 226-228, 241, 266-268, 278-280.)

 

50.       Neigum discussed differences in Wygen III construction costs (and the reasons therefor)  between those presented in the Sub 72 certification proceeding and those presented in this matter.  He testified that MDU’s current updated estimate for the total project cost, with the projected AFUDC and remaining capital expenditures for 2010, is $63,354,500 as of December 31, 2009.  (MDU Exhibit No. 139.)  He discussed the changes to O&M expenses, and administrative and general expenses (A&G) associated with Wygen III as estimated in Sub 72 and as presented in this case, stating the O&M costs in this case are based on Wygen II costs.  Neigum also discussed MDU’s ability to oversee the ongoing Wygen III O&M and A&G expenses. He discussed the administrative costs Black Hills charges the Company stating there were two types of costs: [i] directly assigned costs, and [ii] administrative costs.  He further stated coal prices related to fuel costs for Wygen III had also decreased from the last update and were projected at $11.70 per ton for the year 2010.  Neigum also testified he believed a 40-year depreciable life for Wygen III was reasonable.  He noted that the coal supply agreement for Wygen III is for 50 years.  He stated it was hard to predict how long a plant could operate given the technologies used to build it and how it has been run.  Neigum noted that MDU has several coal resources that have operated for 50 years.  Finally, Neigum described the costs kVARS impose on the Company’s system.  (Tr., pp. 226-239, 245, 253-255, 263, 280-283; MDU Exhibit No. 103, pp. 8-9.)

 

51.       Mr. Garrett Senger, MDU’s Vice President-Controller and Chief Accounting Officer, provided a summary of his prefiled direct testimony (MDU Exhibit No. 104), in support of the Company’s calculation of the overall cost of capital, capital structure, debt and preferred equity cost.  He also discussed Statements A, B and F, attached to the Application. (MDU Exhibits 105, 106 and 107.)  Statement A is the balance sheet for MDU as of December 31 for the calendar years ended 2007 and 2008, and accompanying notes to the financial statements.  Statement B reports the income statement for the 12 months ended December 31, 2008, and March 31, 2009.  Statement F shows the utility’s capital structure at December 31, 2008, and a pro forma capital structure for 2009, as well as the associated costs of debt, preferred stock, and Gaske’s proposed common equity cost.  Senger testified that the pro forma capital structure and the associated costs serve as the basis for the overall requested rate of return of 9.62%, which is comprised of:

 

Component

Percentage

Cost

Weighted cost

Long-term Debt

44.959%

6.793%

3.054%

Average Short-term Debt

2.771%

3.773%

0.105%

Preferred Stock

2.5%

4.594%

0.115%

Common Equity

49.77%

12.75%

6.346%

TOTAL

100.00%

 

9.62%

 

He also discussed the pro forma capital structure and the differences between the pro forma and the per books capital structures as of December 31, 2008.  (Tr., pp. 287-291.)

 

52.       Senger also addressed the Company’s calculation of the AFUDC related to Wygen III, stating it was calculated pursuant to the prescribed FERC Uniform System of Accounts formula which is comprised of two components: [i] borrowed funds used during construction and, [ii] other funds used during construction comprised of debt and equity.  He stated that MDU applies AFUDC to construction projects that are greater than 60 days in length.  Senger also discussed how the AFUDC was calculated for 2010, stating the AFUDC will be accrued until the Plant is in service.  He referenced MDU Exhibit No. 139 which showed AFUDC in the amount of $1.8 million for 2010.  (Tr., pp. 457-462.)

 

53.       Ms. Rita A. Mulkern, MDU’s Regulatory Analysis Manager, provided a summary of her prefiled direct and supplemental testimony, including attached supporting exhibits.  (MDU Exhibits No. 108 and 126.)  Mulkern’s testimony addressed [i] the Company’s revenue requirement and per books cost of service for the 12 months ending December 31, 2008, [ii] the pro forma cost of service reflecting known and measurable adjustments that would occur by December 31, 2009, including the Company’s 25 MW investment in Wygen III, and [iii] the calculation of MDU’s revenue deficiency.  She also sponsored Statements C-E and G-L.  (MDU Exhibits 109-117.)  She noted the pro forma cost of service is summarized in Statement L with the supporting detail contained in Statements C-K.  Statement L shows the calculation of the revenue deficiency based on the overall rate of return of 9.62% from Statement F, page 1, as supported by Gaske and Senger.  She stated the pro forma adjustments to the income statement, Adjustments 1-31, pertain to revenue, expense items and rate base, with Adjustments A-K pertaining to rate base items.  Adjustments relating to Wygen III included: an accumulated reserve for depreciation, accumulated deferred income taxes, fuel and purchased power, O&M, depreciation expense, and other taxes, including income taxes, that are listed separately in the statements.  (MDU Exhibit No. 108, pp. 4-14.)  Mulkern’s testimony also addressed the Company’s current power supply cost adjustment (PSCA) tariff given MDU’s ownership of Wygen III for a portion of its electric requirements.  She stated that MDU’s PSCA tariff is an annual adjustment that specifies the procedure to use to adjust rates for fuel and purchased power and amortization of the power supply balancing account.  Mulkern stated that, with the addition of Wygen III into MDU’s power supply mix, the Company will still be purchasing capacity and energy from Black Hills pursuant to its PPA.  The capacity and energy available from Wygen III will displace a portion of the energy and capacity from the Black Hills PPA.  She stated MDU would also incur fuel expense for the coal supply required for its portion of Wygen III.  Mulkern testified the current PSCA tariff language provides for the inclusion of fuel, purchased energy and capacity and any ancillary services. Mulkern expressed her belief that the addition of Wygen III could be accommodated within the existing tariff language and no changes to the tariff are needed.  Mulkern noted the Company was proposing to change the calculation of the PSCA to accommodate the differences in customer class allocations and to clarify the language on the calculation of the PSCA.  Mulkern testified that MDU was also proposing to add language to provide the detail of the calculation used to determine the monthly over- or under-recovered amounts placed in the balancing account.  (Tr., pp. 294-296; MDU Exhibit No. 108, pp. 15-18.)

 

54.       Mulkern also summarized her supplemental testimony revising MDU’s revenue requirement to reflect its proposed bonus tax depreciation adjustment.  She testified an accelerated/bonus depreciation deduction was available for federal income tax purposes for certain 2009 qualifying property additions.  She stated the deduction was created in February 2008 as part of the Economic Stimulus Act of 2008 which allows for an accelerated tax deduction equal to 50% of the cost of new qualifying property purchased and placed in service in 2008.  The bonus depreciation provisions were extended in 2009 under the American Recovery and Reinvestment Act to new qualifying assets acquired and placed in service in 2009.  She explained the bonus depreciation accelerates the amount of tax depreciation available thereby affecting current income taxes, deferred income taxes and accumulated deferred income taxes found in rate base.  She stated that it does not affect the value of Wygen III or any of its associated expenses.  Mulkern testified the revised additional revenue requirement, taking into account the bonus depreciation adjustment, is $5,053,903 or $1,144,369 less than the initial requested amount.  (Tr., p. 298.)  Mulkern testified that at the time MDU filed this rate case, it was not certain if its investment in Wygen III would qualify for the bonus depreciation.  However, after research and review of the requirements, Mulkern stated the Company now believes it satisfies the requirements; and the 2009 expenditures for Wygen III should be eligible for the bonus tax depreciation.  She stated the Company intends to take the bonus depreciation in its 2009 taxes.  If MDU is not eligible for the bonus depreciation, the IRS will review the Company’s taxes and advise it that it is not eligible.  Mulkern stated an IRS review will not take place for three or four years but the Company stands by its determination to take the bonus depreciation.  (Tr., pp. 297-300, MDU Exhibit No. 126, pp. 3-4.)

 

55.       Mulkern also addressed the Company’s February 5, 2010, filing of an electric division Depreciation Study and Common Plant Depreciation Study, both as of December 31, 2008.  The studies set forth the new depreciation rates for electric and common plant.  They were filed in compliance with the Commission’s Order in the Company’s last general rate case (Docket No. 20004-75-ER-08 (Sub 75)) which directed the Company to file a depreciation study with its next rate case.  She testified the effect of the proposed revised depreciation rates results in a decrease in the overall revenue requirement of $220,358 from the January 14, 2010, amended filing, resulting in a decrease in the Company’s proposed revised revenue increase of $5,053,903 to $4,833,545.  (Tr., p. 298; MDU Exhibit No. 142, pp. 2-3.)

 

56.       Mulkern testified on rebuttal and in cross-examination on her adjustment seeking recovery of $1,683 for institutional advertising expenses from customers rather than shareholders, arguing it was appropriate because customers benefit from this form of advertising.  She noted the Company serves small communities in which it is important for MDU to be involved and to demonstrate its support, all of which benefits its customers.  She disagreed with OCA’s proposed disallowance of this expense, stating it should be recoverable, and the Commission has the authority to consider recovery on a case by case basis.  She also addressed the general inflation adjustment and the reasons MDU applied it to various expense categories.  She stated the inflation adjustment is applied to smaller dollar amounts and is an aggregate adjustment to expenses using the Consumer Price Index (CPI) as the inflation factor.  The CPI used by the Company is a three-year historical average.  Regarding the Company’s depreciation expense adjustment, she stated the Company used an annual depreciation expense on the plant additions but utilized a six month period in developing the deferred taxes, including tax depreciation, associated deferred taxes and the rate base deduction for accumulated deferred income taxes.  Mulkern testified that MDU used six months of depreciation expense for plant additions because they come into service throughout the year.  (Tr., pp. 301-306, 743, 753.)

 

57.       Mulkern explained why MDU’s proposed three-year amortization period for regulatory commission expense was reasonable, stating three years allows time to recover the cost from customers before the time the company may need to file another rate case.  She stated this time frame will help avoid the situation where customers are paying the expenses associated with the current case and the cost of a previous case.  Mulkern argued that, should rate case expenses be extended beyond the three years proposed by the Company, it would be appropriate to include the unamortized rate case expense balance in rate base to compensate the Company for the time value of money in delaying recovery of its expenses incurred in 2009.  Mulkern also addressed the tariff changes MDU was proposing for its PSCA.  (Appendix B to the amended application.)  She stated that, under the PSCA Rate 50 tariff, the Company proposes to have three separate classes; it currently has one class applicable to all its customers.   The three classes would be: [i] Primary Service for customers taking service under Rates 20 and 39; [ii] Secondary Service for customers taking service under Rates 10, 20, 24, 25 and 39; and [iii] Controlled Rates 11 and 22.  MDU proposed to establish a base cost of fuel and purchased power for each of these classes in a general rate case.  Then, as part of its monthly accounting, MDU would calculate the over-or-under recovery for each class separately.  (Tr., pp. 312-316, 743.)

 

58.       On rebuttal, (MDU Exhibits No. 138 and 139), Mulkern addressed certain adjustments proposed by OCA witness Zamora.  She stated MDU objected to Zamora removing the $3,499 expense relating to transmission expenses.  She stated that Zamora eliminated this expense as it related to a one-time occurrence.  Mulkern stated that this particular activity might be non-recurring as reflected in the transmission account, but she explained that it is not a non-recurring expense and that the expense itself, or the dollars associated with it, were not incremental.  Mulkern disagreed with OCA’s calculation of tax depreciation on plant additions because Zamora used a full year of book depreciation in her calculation rather than the half year used by MDU.  Mulkern stated, when calculating book depreciation in the calculation of tax depreciation, the book depreciation portion is based on the actual depreciation expense on those plant additions and is neither a normalized expense nor a theoretical depreciation expense.  Regarding the calculation of investment in the Plant, she stated that an update of this investment cost had been provided (MDU Exhibit No. 139), with updated amounts for coal expense and O&M expenses (MDU Exhibits 155 and 156) which are more current than the amounts utilized by OCA.  She stated the Company agreed that these most recent updates should be utilized and would match the update of the Wygen III Plant value included in her Rebuttal Testimony.  (Tr., pp. 743-748, 760-762.)

 

59.       In opposition to OCA’s proposed revisions to the PSCA, Mulkern testified she believed the current tariff language conforms to Commission Rules 249 and 250.  She stated that the language in Rules 249 and 250 does not preclude recovery of fuel associated with a generation unit and they do not address what is prohibited.  Regarding the use of a dead band, Mulkern stated the Company did not agree with Zamora’s recommendation to use a base fuel cost with a dead band and a sharing over/under the dead band.  She explained that the components of MDU’s PSCA include a contract that was filed with and approved by FERC and this Commission, which contains an escalation factor.  She stated it was not appropriate at this time to determine whether the escalation factor is recoverable.  The PSCA also includes a transmission component, which is a FERC-regulated tariff with a regulated rate.  She stated it was not appropriate to establish a dead band that would preclude recovery of that amount.  Mulkern further stated the coal contract (Statement R) includes a price for coal that is not negotiated but is a rate filed with and approved by the South Dakota Commission.  Mulkern stated that, because the PSCA contains rates that are established or regulated, it would not be appropriate to establish a dead band that would preclude recovery of the costs.  (Tr., pp. 748-754.)

 

60.       Tamie A. Aberle, MDU’s Pricing and Tariff Manager, provided a summary of her prefiled testimony and attached exhibits (MDU Exhibits No. 108, 119-125, 130-134), in support of the Company’s rate design and the embedded class cost of service study.  She discussed the results of the class cost of service study and the proposed design of rates to recover the revenue requirement calculated by Mulkern in her direct and supplemental testimony.  Aberle stated the cost allocations in the study are based on cost causation with direct assignments made where possible, with remaining costs being allocated primarily on customer-related, demand-related and energy-related factors, depending on the nature of the cost.  She said the class cost of service study is consistent with studies MDU has performed in the past.  She stated her proposed rates are intended to recover additional revenues in the amount of $5,053,756 per annum, as proposed in the Company’s amended application.  She testified the results of the class cost of service study indicated that the classes are providing returns on the investment necessary to provide service to each of the rate classes.  However, every rate schedule is producing a pro forma return below the overall rate of return.  MDU is proposing to increase each rate class in an amount necessary to bring each of these classes’ revenue responsibility up to the overall rate of return, with the exception of the private lighting class, which the Company proposes not to change.  MDU proposes to allocate the $15,264 decrease in revenues which would otherwise accrue to this class to all other classes.  (Tr., pp. 324-325; MDU Exhibit No. 118, pp. 4-10.)

 

61.       Aberle further stated that, in addition to the rate of return by class, the embedded cost of service study (MDU Exhibit No. No. 130) provided the cost for customer demand and energy-related costs for all classes.  She stated the increase in the customer component proposed in this case moves rates toward or to embedded costs as directed by the Commission in the last rate case proceeding.  Demand charges for service under the Small General and Large General Service schedules are being adjusted to reflect movement towards recovery of costs as identified in the class cost of service study.  The energy rate for each schedule reflects the residual of the revenues required to be collected from each rate schedule after deducting the revenues proposed to be collected from base rates and demand charges.  She stated MDU has not proposed any change in rate classes or rate designs in this case.  Aberle stated that although the Company filed an inverted block residential rate design as directed by the Commission in its last rate case, the Company prefers to maintain its current rate structure of a monthly base rate and a flat energy charge.  However, she stated she would not be averse to implementing an inverted block rate design provided the base rate is set at a minimum level of $25.00 per month.  She stated that, unless the Commission adopts the Company’s proposed revenue increase proposal, the Company will have to run its cost of service model and its rate design proposals again to determine the appropriate rates for each rate schedule.  (Tr., pp. 325-326, 777; MDU Exhibit No. 118, pp. 11-17.)

 

62.       Aberle’s direct testimony and exhibits addressed the Company’s Irrigation Service – Rate 25, proposal.  She stated the rate design retains a base rate and time differentiated demand charge as adopted in the last rate case.  The Company is proposing to recover the revenue increase allocated to this rate class by increasing the base rate from $25.00 to $50.00 per month; with no change in the on-peak demand charge of $9.50 per kW or the off-peak demand charge of $3.00 per kW.  The remainder of the increase would be recovered through the energy charge.  MDU proposed to continue the current peak period of Noon to 8:00 p.m..  (MDU Exhibit No. 118, pp. 15-16.)  On cross-examination, Aberle stated that Irrigators who operate on a 24 hour/seven day schedule contribute to the peak because they are poor load factor customers who typically operate four to five months a year.  She also discussed the effects of having a shorter peak demand period, stating a shorter peak period would only move the peak to the next hour.  She noted the majority of irrigator kWh were billed off peak with approximately 54% of the kWs billed off peak and 46% of the kWs billed on peak.  She discussed the demand charge for the Irrigation customers, how it works, and the Company’s efforts to work with customers to establish an alternative to the mandatory time-of-day schedule to help customers move off peak.  She also described the Company’s alternative irrigation rate proposal that she offered in her rebuttal testimony (MDU Exhibit No. 140), which included an optional time-of-day irrigation schedule that would provide an incentive to irrigation customers to move load off-peak, in addition to the standard schedule that includes a non-time differentiated flat demand charge.  The standard irrigation rate would include a demand charge of $6.25 for the monthly peak demand regardless of the time the peak demand is established.  The optional time-of-day schedule would include the current on-peak charge of $9.50 per kW and the off-peak charge of $3.00 per kW.  She assured the Commission that an irrigation customer taking service during the on-peak period and off-peak period and would not pay a rate of $12.50 per kW but would be billed for each period separately at the applicable $9.50 or $3.00 per kW rate.  (Tr., pp. 329, 354, 360, 362-365, 770; MDU Exhibit No. 140, p. 4.)  However, an irrigator taking energy during both on-peak and off-peak hours would pay both demand charges, or a total of $12.50 per kW for all hours during the month.  (Tr., pp. 385-387.)

 

63.       Aberle also addressed MDU’s inclusion in its revenue requirement of approximately $55,000 a year for kVar penalties.  Aberle stated the Company believes that a $2.50 per kVar penalty [i] provides an incentive to customers to make a change to their equipment to avoid supplying kVars to the system; [ii] is sufficient to cover the identified potential impacts to the system; and [iii] will provide a revenue stream to cover capacitors and the losses and the other costs associated with kVars being introduced into the system.  (Tr., pp. 345-347, 374.)

 

64.       In her rebuttal testimony, Aberle offered an alternative to Zamora’s recommendation to use separate demand and energy rates for purchased power and fuel recovered under a tracking mechanism in the PSCA.  MDU Exhibit No. No. 141 illustrated her alternative proposal that the demand costs associated with the PSCA be moved to the cost of service component of each rate with only the prospective changes in demand under the contract being billed through an energy charge in the PSCA.  Aberle suggested the demand component included in the purchased power agreement is relatively stable; and therefore, prospective changes in demand-related costs under the PSCA mechanism should be minimal.  (Tr., pp. 778-783; MDU Exhibit No. 140, pp. 4-5.)

 

            65.       Aberle’s rebuttal testimony addressed certain rate design-related proposals made by OCA witness Zamora. (MDU Exhibit No. 140.)  She discussed Zamora’s proposal to introduce a $4.00 per kW charge for the first ten kW billed under the Small General Service Rate 20, Secondary Service, and a $4.50 per kW for the first ten kW billed under Small General Service, Primary Rate 20, schedule.  She stated these changes would result in a significant change to a large group of very small use customers taking service under Small General Service Rate 20.  The current rate design for the Rate 20 Class provides the first ten kW at no charge with a demand charge being imposed on all kW over ten kW.  She stated OCA’s proposal would require the purchase and installation of approximately 17,000 demand meters at a cost of approximately $484,500.  She recommended the current rate structure be maintained.  (Tr., p. 764, MDU Exhibit No. 140, p. 3.)

 

Summary of OCA’s Evidence

 

66.       Ms. Kimber Wichmann, Rate Analyst for the OCA, provided a summary of her prefiled direct testimony, including attached supporting exhibits, which addressed OCA’s position on the appropriate ROE, cost of debt, and capital structure that should be used in the computation of MDU’s overall rate of return.  (OCA Exhibits 201-208.)  Wichmann testified her analyses supported a ROE for MDU’s Wyoming electric utility operations of 10.4%, resulting in an overall rate of return for the Company of 8.45%.  In performing her analyses, she identified a group of twenty-two proxy companies from publicly available financial data which were comparable to MDU’s regulated electric utility operations.  She stated the filters used in selecting her comparable companies were that they should have [i] a Baa rating as MDU’s issuer rating was Baa1, [ii] at least 70% of revenues from regulated electric operations, and [iii] had to pay dividends in 2009.  All but one of Gaske’s 13 comparable companies were included in her group of comparable companies.  Wichmann stated she utilized a constant growth rate DCF model, a non-constant growth DCF model and a capital asset pricing model (CAPM) in conducting her ROE analyses.  She stated the two DCF models provide an estimate of cost of equity capital by examining expected dividends and market prices, but the non-constant growth DCF analysis provides a more realistic estimate of future growth.  She stated that she used the CAPM not as a primary model but as an objective measure of risk for regulated electric utilities with the same investment as MDU, in comparison to other securities available to investors.  (Tr., pp. 473-475, 483,507-510; OCA Exhibit No. 201, pp. 6-8.)

 

67.       Wichmann testified she and Gaske used similar information sources in performing their respective analyses and in their selection of comparable companies but differed in their application of the information, including their calculation of flotation costs and size adjustments.  She stated that, although she supported a flotation cost adjustment, she utilized a conventional flotation cost calculation, which assumes that flotation costs are incurred only when new stock is sold and not when earnings are retained.  Under the conventional calculation the flotation adjustment is applied only to the dividend yield of the DCF calculation and not to the growth component.  She stated her use of MDU’s actual flotation factor of 3.50%, which was lower than an industry average of 3.70% used by Gaske, was appropriate as it was a known factor, and customers should only have to pay the actual cost.  As to utilizing a size adjustment as advocated by Gaske, she rejected such an adjustment on the basis that MDU’s utility operations do not share the same risk as a small business in a free market, given MDU’s status as a regulated monopoly with certain mechanisms such as the PSCA tariff which mitigates the risk of cost recovery.  Wichmann identified other areas of disagreement with Gaske’s ROE analyses, including his averaging of stock prices in his DCF models, his use of an “unconventional” growth adjustment in his DCF analysis, resulting in an overestimated cost of capital, and the results of his Risk Premium analysis, which fail to support or legitimize the results of his DCF analyses.  (Tr., pp. 475-476, 517; OCA Exhibit No. 201, pp. 14-15, 31-34.)

 

            68.       Wichmann concluded that her ROE analyses supported a range of reasonableness of 9.05% to 10.93%, with a midpoint of 9.9%.  After considering the macroeconomic environment, financial and business risks, growth forecasts and MDU’s ability to recover many of its costs through regulatory and tariff provisions she recommended a conservative ROE of 10.4% as providing a reasonable balancing of shareholder’s interests with the customer’s interests, although she acknowledged that any ROE number falling within her range would be supported by her analysis.  Using the Company’s pro forma capital structure for 2009, its calculated costs of long-term debt (6.79%), short-term debt (3.77%), preferred stock (4.59%), and OCA’s recommended cost of common equity (10.4%), Wichmann recommended an overall rate of return of 8.45%:

 

Component

Percentage

Cost

Weighted cost

long-term debt

44.959%

6.79%

3.05%

average short-term debt

2.771%

3.77%

0.104%

preferred stock

2.5%

4.59%

0.115%

common equity

49.77%

10.4%

5.18%

TOTAL

100.00%

 

8.45%

 

(Tr., pp. 475-477, 521-522; OCA Exhibit No. 201, pp. 23-29, 36; OCA Exhibit No. 208.)

 

69.       Ms. Denise Kay Parrish, OCA’s Deputy Administrator, provided a summary of her prefiled direct testimony, including attached supporting exhibits (OCA Exhibits 216-218), in support of OCA’s proposal to levelize the cost of the return on MDU’s 25% ownership interest in the Wygen III generation Plant over the expected depreciable life of the Plant.  Parrish stated the concept behind her levelization proposal was to assure that all generations of MDU’s Wyoming electric customers benefiting from the Wygen III Plant pay their proportional share of the return MDU is entitled to earn on its share of the Plant.  Through this levelization approach, the impact of adding the Wygen III Plant to rate base would lessened during the initial years the rates are in effect.  Levelization would address generational inequities existing today under more traditional methods of front-loaded return on new plant placed in rate base, wherein early generation customers benefiting from the plant pay more return than later generation customers.  She stated the total value that MDU would earn over the depreciable life of the Plant is summed; with the total value being divided by the expected Plant life to arrive at an equal dollar amount of return to be recovered from customers during each year of the Plant’s operating life.  She stated her proposal in addition to not disadvantaging generations of customers is also intended to not disadvantage investors over the life of the Plant by making sure they receive the same amount of return over the life of the Plant by using present value calculations. (Tr., pp. 622-623; OCA Exhibit No. 216, pp. 3-4, 8.)

 

70.       Parrish described the calculation of her levelization proposal (OCA Exhibits 217 and 218), stating she developed a rate base for the Plant based on the 50-year depreciable life that OCA was recommending for Wygen III; but she acknowledged she had not updated her gross Plant numbers as brought up to date by MDU.  Based on her calculations, the Company, on behalf of its investors, would have to receive $2.8 million each year for fifty years.  Parrish stated that, for purposes of her calculation, she assumed that investors should have the opportunity to receive the same total present value amount that they would receive under current regulatory practices.  She testified that, over the 50-year life cycle of the Plant, investors would receive the same dollar value in return that they would receive over the life of the Plant using the more traditional front-loaded method.  Her analysis further showed the total amount of return collected by MDU would be approximately $55 million more under her levelized approach as compared to the amount that would need to be collected using a nominal levelized return.  She justified this result as being fair because customers will be deferring some of the higher payments to a later time period when the funds they pay will have a lesser value than if they were paying the higher and more traditional cost today.  She stated her levelized approach assumes the Company would continue to receive the $2.8 million over the life of the Plant, without modification, even if there were subsequent rate case filings submitted over the course of the 50-year period.  (Tr., pp. 624-631; OCA Exhibit No. 216, pp. 8-20.)

 

71.       In Gaske’s rebuttal, he argued that her levelization proposal requires future commissions to be bound by the determinations of this Commission regarding this issue over the 50-year period.  Parrish responded, acknowledging that, although one commission cannot bind future commissions, it was her experience that this Commission and prior commissions have been reasonable and have not backed out of prior commitments.  She further expressed her disagreement with Gaske’s argument that recording the deferral as a regulatory asset would only be acceptable if MDU’s customers entered into a 50-year contract to ensure the Company’s recovery of its Wygen III investment.  Parrish testified that, although her levelization approach would affect cash flow streams for the Company differently than more traditional approaches, because levelization would result in less cash being collected during the earlier years with more cash becoming available in later years, she believed OCA’s approach did not violate the standards set out in the Hope and Bluefield cases, as was argued by Gaske, because the levelization proposal provides OCA’s recommended overall rate of return of 8.45% over the life of the Plant.  She stated the Hope and Bluefield cases do not require that regulatory commissions provide specific cash flow streams on a specific schedule.  Finally, Parrish stated that, although she did not believe OCA’s proposal created more risk for MDU, she provided several options for consideration to mitigate the regulatory risk that might be attributed to the adoption of her levelization proposal.  (Tr., pp. 631-635, 637; OCA Exhibit No. 216, pp.  21-24.)

 

72.       Parrish expressed OCA’s concerns over possible Commission approval of MDU’s latest depreciation studies, which were filed very shortly before the commencement of the hearings in this matter, stating that OCA had only a limited opportunity to review the studies and had many unanswered questions, including: [i] the need to review the Company’s rationale for significant differences between present and proposed depreciation rates for various accounts; [ii] issues regarding interim retirement rates; and [iii] other aspects of the depreciation studies that require further review.  She recommended the depreciation studies be considered in more detail in a separate docket or in the next rate case.  Parrish testified it was reasonable to accept MDU’s depreciation adjustment as identified in Mulkern’s depreciation testimony (MDU Exhibit No. 142, pp. 2-3), which results in decreasing the Company’s revenue increase request by $220,358. (Tr., pp. 639-646, 679-680.)

 

73.       Ms. Amy Zamora, Senior Rate Analyst for the OCA, provided a summary of her prefiled direct testimony, including attached supporting exhibits.  (OCA Exhibits 209-215.)  Zamora’s testimony provided background for the Company’s application, including its entry into a new all requirements purchased power contract with Black Hills Power in 2006, which provided MDU with the option, which it exercised, to purchase 25% of Wygen III.  She stated MDU will be obligated to pay 25% of the investment cost of the Plant, O&M costs, the costs associated with 25% of the coal needed to fuel the Plant, and certain administrative expenses to Black Hills Power as the Plant operator.  Zamora also addressed her review of the Company’s revenue requirement, the class cost of service study and rate design, which were incorporated in the OCA revenue requirement recommendation, proposed rate spread and proposed rate design.  Zamora stated she reviewed the per books amounts contained in the Company 2008 test year and the Company’s pro forma adjustments, whereupon she made her own adjustments to the Company’s results to normalize and annualize the test year numbers to remove prior period expenses, one-time expenses, expenses that did not need to be incurred in providing utility service, and expenses that were not known and measureable.  She further stated that she separated her adjustments between non-Wygen III-related expenses and Plant, and only Wygen III-related expenses and Plant.  Her separation of Wygen III-related expenses and investment costs from the rest of the revenue requirement was done to accommodate Parrish’s proposed levelized return proposal for the Wygen III Plant.  (Tr., p. 528: OCA Exhibit No. 209, pp. 3-6.)

 

            74.       OCA Exhibit No. 211 sets forth OCA’s non-Wygen III-related adjustments to revenues, purchased power and fuel costs, O&M expenses, depreciation expense, Taxes Other Than Income, deferred income taxes and current income taxes.  Zamora’s revenue adjustment was comprised of an MDU-provided correction to the pro forma usage and revenue calculations for Large General Service Class Rate 39, which increases pro-forma revenues by $18,726.  In all, OCA made six adjustments to O&M expenses, including increasing the purchased power expense by $18,714, to reflect the correction in the Rate 39 usage calculation, and increasing expenses by $6,782,183 to remove the MDU calculated Wygen III-related purchased power and fuel costs, for a net expense increase adjustment of $6,801,897.  She stated the changes are included in the Wygen III-related adjustments.  An adjustment was made to remove Wygen III-related O&M expenses of $2,681,907, which would be included in the Wygen III adjustments.  Zamora made an additional adjustment to remove institutional advertising and industry dues expenses of $2,413 on the basis these expenses need not be incurred in providing service.  Zamora supported her adjustment by stating institutional advertising should be shareholder funded.  Recovery of these expenses has been denied by the Commission in past cases, and are here precluded from rate recovery under OCA’s interpretation of Commission Rule Section 248.  OCA proposed to amortize regulatory commission (rate case) expense over a ten year period to reflect the historical length of time between past Company general rate filings, as opposed to the three years proposed by the Company.  OCA also proposed an O&M expense reduction of $6,551 to remove MDU’s general inflation adjustment for other miscellaneous expense items.  Zamora testified that adjusting these other expenses by a blanket percentage, based upon the consumer price index, is not a known and measurable adjustment, and has been disallowed by the Commission in cases involving other utilities.  Finally, OCA removed certain one-time expenses occurring in the test period, prior period adjustments, and costs recovered through the Company’s Load Management Program resulting, after a correction to OCA’s computations, in an O&M expense reduction of $30,994.  (Tr., pp. 528-532, 561, 584-585, 589; OCA Exhibit No. 209, pp. 6-8.)

 

            75.       Zamora discussed her removal of MDU’s calculation of Wygen III-related depreciation expense of $1,744,988, saying it would be offset by inclusion in her Wygen III adjustments.  Regarding the Company’s filing of its most recent depreciation studies that had the effect of reducing depreciation expense, she stated OCA accepted the adjustment in this case but requested additional time to allow a more thorough review of the studies and the proposed depreciation rates in the context of a future proceeding.  Regarding her adjustments for Taxes Other Than Income Taxes, she annualized franchise and gross revenue taxes by applying OCA’s adjusted revenues to the appropriate tax factors, and removed MDU’s pro forma ad valorem taxes related to Wygen III stating they would be added in later as part of her Wygen III adjustments, for a net decrease of $100,327.  Zamora also proposed an annualized adjustment to deferred income taxes for all other plant by using a full year of book depreciation for all assets regardless of when they went into service, as opposed to the Company’s use of one-half year’s depreciation.  She supported this adjustment by stating use of one-half year’s depreciation is inappropriate as it would not reflect a normal year of depreciation for ratemaking purposes, and it does not match the full year of depreciation used for depreciation expense.  This adjustment also recognizes MDU’s applying of the IRS-authorized 50% bonus depreciation rate and the accumulated depreciation rate toward plant additions placed in service in 2009 or for expenditures incurred in 2009.  She removed the calculated deferred income taxes for Wygen III which resulted in a decrease of $817,322, for a net reduction for these two adjustments of $822,626.  She proposed an interest synchronization adjustment of $1,534 to synchronize interest expense with OCA’s calculated rate base, excluding Wygen III.  She also removed interest expense for the Wygen III rate base.  The net effect of these two adjustments amounted to a $1,947,215 decrease in interest expense.  Based upon the above-described adjustments, as corrected, MDU’s adjusted operating income is reduced by $2,103,062.  (Tr., pp. 532-534; OCA Exhibit No. 209, pp. 10-12.)

 

            76.       Zamora also proposed adjustments to the Company’s rate base (OCA Exhibit No. 213) which included the removal of Wygen III costs related to the investment, accumulated depreciation and accumulated deferred income taxes and updates to accumulated deferred income taxes for all other investments, resulting in a total revised rate base, without Wygen III, of $18,902,960.  Zamora stated that with OCA’s revised adjusted test year return of approximately $1.6 million, the resulting rate of return without Wygen III is 8.587%, which exceeds OCA’s recommended overall rate of return of 8.45%, resulting in the need for a revenue decrease.  (Tr., pp. 538-539.)

 

            77.       Zamora testified to OCA’s adjustments related to and including Wygen III, for purchased power and fuel, O&M expenses, Taxes Other Than Income and deferred income taxes.  Regarding purchased power and fuel costs, she stated OCA’s adjustment for decreases in energy capacity and transmission costs were the same as MDU’s adjustment, but she adjusted fuel costs by $1,902,225 based on the gross tonnage of coal estimated by Black Hills Power to be used in Wygen III.  She stated she used a more current estimate of gross tonnage provided by Black Hills Power in its currently pending rate case, which resulted in a net adjustment decrease of approximately $6.9 million dollars in purchased power and fuel expenses.  In addition, she made adjustments to Wygen III-related O&M expenses, and to Wygen III-related depreciation expense.  Zamora stated her gross Plant cost as reflected in her prefiled testimony was $61.7 million, but acknowledged that MDU had provided an updated gross Plant cost on rebuttal, which she wished to verify prior to accepting it.  She also adopted a depreciation expense adjustment to reflect a 50 year Plant life, testifying that it is appropriate, reasonable and consistent with depreciable lives used by other utilities for similar generating plants.  Zamora made additional adjustments to Wygen III-related ad valorem taxes to reflect the most current 2009 mill levy, and the use of a full year of depreciation for deferred income taxes.  She stated the tax depreciation for Wygen III had been adjusted to reflect the use of the special 50% bonus depreciation rate.  She stated that she had included certain costs that were not incurred in 2009 in calculating tax depreciation which might require further revision.  (Tr., pp. 539-541, 557, 596; OCA Exhibit No. 209, pp. 12.)

 

            78.       Zamora testified that her calculation for the Wygen III only portion of the revenue requirement is based on OCA’s levelized return at present value for Wygen III of $2,825,952.  The decrease in expenses of $1,871,213 per OCA’s adjustments, when subtracted from the $2,825,952 recommended return for Wygen III results in the need for additional revenue of $954,739.  Adjusting this amount by the federal income tax factor results in the need for additional revenues for Wygen III of $1,485,693.  OCA’s total recommended additional revenue requirement, taking into consideration OCA’s recommended decrease in revenues without Wygen III of approximately $40,000, when combined with the revenue requirement for Wygen III, results in a total revenue increase of approximately $1.45 million or 7.852%.  (Tr., p. 542; OCA Exhibit No. 209, p. 18.)

 

            79.       Zamora provided testimony regarding MDU’s class cost of service study, stating she found it to be reasonable, with the methodologies and allocations being comparable to other studies that have been accepted by the Commission.  She utilized MDU’s cost of service study in performing two model runs for each piece of her revenue requirement and then added the results of the two runs for the revenue requirement without Wygen III and with the Wygen III-only revenue requirement to determine total costs to serve each customer class.  (OCA Exhibit No. 214.)  Zamora stated that after allocation of OCA’s proposed additional revenue increase, each rate class will be providing the same percentage increase on each piece of the revenue requirement, i.e., non-Wygen III and Wygen III-only, with the effective rate of return for each class being slightly different and ranging from 5.857% to 7.564%.  In doing so, OCA moved each class toward (but not to) recovery of its full cost of service-based revenue responsibility, with all classes receiving an increase except the Private Lighting Class which is currently exceeding its cost of service, and therefore will see a 36.9% decrease.  (Tr., pp. 545-546: OCA Exhibit No. 209, pp. 19-23.)

 

            80.       Zamora addressed OCA’s proposed rate designs for the various customer classes, stating she utilized the Company’s class cost of service model in developing her rate design recommendations, the results of which are set out in OCA Exhibit No. 215.  She described her rate design proposals for the various customer classes.  (OCA Exhibit No. 209, pp. 26-30.)  She proposed an inverted block energy charge for Schedule 10, Residential Class, with a monthly customer charge of $25.50.  OCA’s initial proposed rate design for Schedule 20, Small General Service, included demand rates for all customers in the class; but she discovered that customers in the class using less than 10 kW did not have demand meters, and stated her rate design would not work for the entire class because demand could not be measured for the entire class.  Therefore, she withdrew her recommendation of a demand charge for Rate 20 customers using less than 10 kW.  Zamora stated the Schedule 25, Irrigation Class, is the only class whose rate components are not recovering their respective full costs.  She testified the cost of service study supports a monthly charge of $105.64; but, to avoid rate shock, she proposed a monthly charge of only $50.00, which is about twice the current monthly charge.  In addition, OCA is proposing a reduction in the on-peak demand rate of $9.50 per kW to $8.30 per kW, with the off-peak rate remaining at $3.00, which will bring this rate element to cost of service.  Regarding Aberle’s proposal on rebuttal of offering a time-of-use rate and a non-time-of-use rate to irrigation customers, Zamora deemed it a reasonable alternative.  She acknowledged that, [i] if the revenue increase ultimately approved differs from that proposed by OCA, the rate design will have to be revised, and  [ii] if the amount of the increase is significant, it might impact her proposal to move to cost based rates.  (Tr., pp. 547-549, 552-553, 556 & 611; OCA Exhibit No. 209, pp. 26, 29-30.)

 

            81.       Zamora described OCA’s proposed revisions to the Company’s current PSCA to reflect its change in status from a purchaser of all its power requirements to, in part, a self-generator.  It is OCA’s position that as a self-generator of a portion of its power requirements, the provisions of Commission Rule Sections 249 and 250, which currently apply to MDU, will no longer be applicable.  She testified that these rule provisions have not been interpreted in a manner which would allow a self-generator to accumulate its production costs and pass them on to customers.  Recovery of these production costs is typically addressed in computing base rates.  Her proposed tariff language to revise the PSCA is similar to the language used by Cheyenne Light, Fuel and Power Company, which she recommended as an appropriate starting point for PSCA revision.  OCA proposed a deadband of $290,000, based on a proportion of kWh sales, to assure that some portion of the system power cost changes are borne by the Company’s shareholders rather than placing all the risk and reward of changing system power costs on ratepayers.  In addition, ratepayers would only receive 95% of the cost changes that fall outside the deadband.  Zamora testified this approach will incent the Company to make operational decisions for the benefit of customers.  She also recommended further tariff language changes to the PSCA.  She advocated changing the term “Base Rate” in each rate schedule to “Basic Service Charge” to reduce confusion.  She noted the “Energy Charge” reference in the rates in the tariffs is actually comprised of two components, and argued they should be separately identified by the base purchased power and fuel cost rate component and the energy rate component, to arrive at the “Energy Charge” in an effort to provide more transparency in demonstrating how the energy charge in the PSCA is calculated.  (Tr., p. 550; OCA Exhibit No. 209, pp. 32-34, 37-38.)

 

Summary of Parties’ Testimony on Stipulation

 

82.       The Commission reopened the record at its hearing of March 22, 2010, to receive into the record the Stipulation (MDU/OCA Joint Exhibits No. 1 and 2) and the parties’ testimony and exhibits in support of the Stipulation.  Mr. Bruce S. Asay, MDU counsel, offered certain late-filed exhibits in addition to the exhibits to the Stipulation.  The offered late-filed exhibits included: [i] Exhibit No. 157, an explanation of the Company’s AFUDC calculations; [ii] Exhibit No. 158, a document identified as the shared assets administrative fee and ground lease; and [iii] Exhibit No. 159, the detailed class cost of service study and work papers.  Provided in support of the Stipulation were Goodin’s affidavit (MDU Exhibit No. 60); Mulkern prefiled testimony (MDU Exhibit No. 161) and Aberle’s prefiled testimony and exhibits (MDU Exhibit No. 162).

 

83.      Mulkern summarized her testimony, stating the Stipulation represents the parties’ efforts to arrive at negotiated agreements regarding various adjustments initially advocated in the parties’ respective direct and rebuttal cases.  She stated the Company believed the Stipulation is in the public interest and should be approved.  Mulkern summarized the various terms and conditions of the Stipulation including an identification of the various stipulated adjustments, which result in a stipulated increase in MDU’s revenue requirement of $3,253,726 per annum.  The Stipulation provides, inter alia, for the implementation of the stipulated revenue increase over a three-year phase-in period.  Mulkern testified the phase-in approach addresses the concerns expressed by many MDU customers at the Sheridan public comment hearing that the immediate implementation of the 25% revenue increase was excessive, caused rate shock, and precluded customers’ ability to budget for such a large increase.  In the phase-in plan, a Year 1, increase of $1.8 million or 8.9% would be implemented on May 1, 2010.  The remaining $1.4 million or 6.6% would be implemented in Year 2 on May 1, 2011, and would also include a separate surcharge of $0.0029 per kWh which would be amortized over a two-year period or until the remaining deferred amount, including interest, is amortized to zero.  She stated the interest component is based on the overall stipulated return of 8.68%, explaining the 8.68% was not really an interest rate but rather the rate of return or a carrying charge.  Adding together the deferred amount and the surcharge, the Year 2 total increase would be $2,261,726 or 10.3%.  She acknowledged the overall increase of 10.3% in Year 2 was on top of the 8.9% increase in Year 1, essentially resulting in an increase of 20.1%.  She stated customers will experience an increase in the first and second year; but there would be no change in rates in the third year.  In the fourth year, customers would see a decrease in rates due to the elimination of the surcharge.  She agreed customers would still be paying the 20.1% increase in Year 3 because of the amortization of the amount deferred in the first year.  She also acknowledged the stipulated increase would be 16.1% if it were implemented in its entirety this year rather than being phased in as proposed in the Stipulation.  (Transcript of March 22, 2010, Stipulation Comment Hearing, hereinafter Stipulation Comment Tr., pp. 16-17, 19, 36-39, 41-44; MDU/OCA Joint Exhibit No. 1, pp. 5-6.)

 

            84.       Mulkern stated that to address irrigation customers’ concerns, MDU will bifurcate the Rate 25 irrigation rate into two rate schedules; [i] the optional time-of-day irrigation rate; or, if preferable, [ii] a more traditional non-time differentiated rate with a flat demand and energy charge.  The optional time-of-day tariff will utilize an on-peak period of 3:00 p.m. to 7:00 p.m.  She stated the Stipulation also includes a revised PSCA Rate 50 which includes a sharing of costs symmetrically above and below the base cost of power supply of 90% to the customer and 10% to the Company.  She also stated the parties had agreed to a negotiated 45-year depreciated life for Wygen III.  (Stipulation Comment Tr., pp. 17, 24, 29.)

 

            85.       Ms. Tamie Aberle provided a summary of her prefiled testimony and exhibits in support of the Stipulation.  (MDU Exhibit No. 162)  She testified that the stipulated increase of $3,253,726 was allocated to each of the rate classes based on the results of the embedded class cost of service study.  (Exhibit No. TAA-1 to MDU Exhibit No. 162.)  Regarding the phase-in of the rate increase, Aberle stated the Years 1 and 2 increases were allocated to each rate class based on the revenue requirement for each particular class as derived from the embedded class cost of service study.  The surcharge needed to collect the deferred portion of the revenue increase was spread to all customer classes based on energy usage.  She stated the revenue increase was allocated so each class would produce the overall rate of return of 8.68%.  Going forward with those revenues, she agreed, would produce a rate of return for all classes of 8.68%.  (Exhibit No. TAA-2 to MDU Exhibit No. 162.)  She acknowledged that, depending on the customer’s usage, the surcharge could affect a Rate 39 large service customer differently than a residential customer.  She discussed the $0.00290 per kWh surcharge, stating under the proposed Stipulation, the residential class would experience an increase of approximately $3.95 per month in Year 1 and $7.70 per month in Year 2.  (Stipulation Comment Tr., pp. 61-62, 69-71, 82-88.)

 

86.       Aberle stated the Stipulation will result in changes to Small General Service Rate 20 in that it had been split into separate schedules for demand and non-demand metered customers.  She discussed the irrigation service rate, stating the schedule was bifurcated into Rate 25, non-time differentiated rate, and Rate 26, for customers who choose the option of using time-differentiated service.  Aberle testified that irrigation customers can choose a new rate schedule at the beginning of their irrigation season but prior to any usage for that season.  Under the Stipulation, the irrigation tariff provides that customers may choose a rate schedule through May of 2010.  Aberle stated the Company does not want irrigation customers to change rate schedules during the season because of the additional administrative burden and the need to reprogram meters.  She said MDU would probably inform its irrigation customers of this change and the options available to them by sending a letter to its customers.  Under the Stipulation, the negotiated time-of-use irrigation peak period is from 3:00 p.m. to 7:00 p.m. Aberle acknowledged the evidence presented in this case demonstrated the peak periods fall between 4:00 p.m. and 6:00 p.m. with the majority occurring at 5:00 p.m.  (MDU Exhibit No. 122.)  She also discussed costs to serve irrigation customers and how the demand charge was calculated.  The Stipulation proposes a demand charge of $6.25 per kW for non-time-of-use irrigators.  (Stipulation Comment Tr., pp. 62-69, 75-77, 79-82, 89-97.)

 

87.       Zamora provided a summary of her prefiled testimony and exhibits  in support of the Stipulation. (OCA Exhibits No. 219, 220, and 221.)   Zamora’s testimony explained how the Stipulation resolved the  issues identified in OCA’s direct case regarding revenue requirement, rate design and tariff issues, and why she believed approval of the Stipulation was in the public interest.  She stated [i] the parties had stipulated to an ROE of 10.9%, resulting in an overall rate of return of 8.68%; and [ii] the Company adopted OCA’s adjustments, or agreed to revise OCA’s adjustments with updated information.  The Stipulation further provides for an increase in revenues of $3,253,726 per annum to be effective May 1, 2010, to be phased-in over a three year period (an explanation of the phase-in increases is found in the Stipulation at ¶¶ 16-20).  She stated the phase-in approach was intended to address the concern expressed by MDU’s customers at the Sheridan public comment hearing over the significant size of the proposed rate increase and would give customers an opportunity during the first year of implementation to plan and budget for the additional increase to occur in the second year.  She also addressed the proposed interest on the deferred amount of 8.68%, which was based on the overall stipulated rate of return.  She found them appropriate and reasonable.

 

88.       Zamora stated other significant issues in the Stipulation included, but were not limited to, a stipulated depreciation life of forty-five years for Wygen III, and rate design issues for residential, small general service and irrigation customers.  She also testified that the Stipulation provides for a revised Rate 50 Schedule applicable to the PSCA that provides for a deadband or sharing mechanism based on a 90/10 ratio, wherein MDU would recover 90% of its purchased power and fuel costs above the base rate costs and will return 90% of purchased power and fuel costs below the base rate costs.  (Tr., pp. 103-105, 115-116, 137; OCA Exhibit No. 219, pp. 3-4, 7.)

 

Findings of Fact: Public Comments

 

89.       The Commission heard numerous comments from MDU ratepayers at the February 10, 2010, hearing in Sheridan.  City and county officials and representatives from the Sheridan County School District and Board of Directors, Sheridan Memorial Hospital, Sheridan County Public Library, AARP, Powder River Basin Resource Council and the Sheridan County Stock Growers expressed concerns that the amount of the increase would negatively impact their respective budgets and would result in the loss of jobs and programs.  Numerous MDU residential customers opposed the proposed rate increase because of current economic conditions, inflation and the financial burden it would place on ratepayers.  Ratepayers generally questioned [i] the magnitude of the proposed increase, [ii] the effect it will have on their electricity bills, [iii] the prudency of MDU’s investment in Wygen III, [iv] the proposed ROE, and [v] the depreciable life of the Plant.

 

90.       Mr. Bill Bensel, Chairman of the Wyoming Water Development Commission and an MDU irrigation and residential customer, provided comments generally opposing the irrigation demand charge and rate structure changes for the Irrigation class, stating the peak hours needed to be adjusted to allow irrigators to irrigate their fields consistent with state water laws.  Bensel also discussed the prudency of MDU’s investment in Wygen III and offered several alternatives for MDU and the Commission to consider when seeking to meet future electricity demands.  He discussed the difficulty irrigators will face when trying to shut down their systems to avoid watering during peak times, and he questioned whether the proposed increases will cause irrigators to discontinue doing business because they no longer can afford to irrigate their lands.  Bensel expressed concern that MDU’s proposed peak hours were not compatible with state water laws or the way irrigation is managed and used and could result in a loss of the irrigators’ water and water rights.  He stated that the demand rate option of a $6.25 per kW demand charge would not be a workable alternative.  Bensel also explained that flood irrigation has become less common in the Sheridan area, so most irrigators pump constantly.  (Tr., pp. 63-67, 438-456.)

 

91.       The Commission wishes to express its gratitude to the Sheridan ratepayers for their participation in the public comment hearing.  The Commission was impressed with the high level of rate payer participation and the thoughtful quality of their comments and questions.  The public raised a substantial number of issues which are worthy of comment; and we will address these issues to help MDU’s customers better understand the regulatory process and the decisions of this Commission.  Some of the questions posed by MDU’s customers and the answers are as follows:

 

                        a.         Question.         When and why did MDU decide to purchase a 25% share in Wygen III Plant?  Why did MDU not consider wind as an alternative?  Has MDU lost the flexibility of competitive bidding for supply contracts?

 

                        Answer.           MDU had an option which expired December 31, 2008, to purchase a portion of the Wygen III facility.  Because the Company was faced with the expiration of favorable long-term supply contracts in 2016, it was concerned that long-term supply and demand trends would make Sheridan ratepayers vulnerable to wholesale market volatility, including unstable prices and sharp price increases.  Its analysis showed that the best option for protecting Sheridan ratepayers was to purchase a share in Wygen III.  Black Hills had a proven record of being able to construct similar plants on time and on or under budget.

 

MDU did not specifically consider wind as an alternative.  However, the Commission is aware that wind is generally more expensive.  Although costs are coming down as the technology matures, wind is somewhat expensive; and it is, by its nature, an intermittent resource.  Complete reliance on wind power poses considerable service and economic risks to a utility with a relatively small service population.  Wind integration cost is discussed in a Black and Veatch paper found under the Hot Topics section of the Commission’s web site at http://psc.state.wy.us.  Interested persons should also review the Western Wind and Solar Integration Study prepared for the National Renewable Energy Laboratory in Golden, Colorado.  It may also be found under Hot Topics/Wind Integration on the PSC’s web site.

 

                        b.         Question.         Has the economic downturn lowered the cost of equity capital?

 

                                    Answer.           In general, this appears to be the case.  However, the cost of equity capital for a public utility must be considered in comparison to similar companies.  Both parties submitted evidence on this question, and the Commission decided on a return on equity capital less than that originally proposed by either party.  However, the Commission is not free to ignore established legal standards (found in statute, Wyoming and federal Supreme Court cases) which address the type of evidence the Commission must consider in reaching conclusions on capital costs.

 

                        c.         Question.         Could the Commission require MDU to rely entirely on debt, with no equity?

 

                                    Answer.           When a utility’s capital structure is out of balance, i.e., when it relies too heavily on debt, the Commission may order the use of a hypothetical capital structure for ratemaking purposes and has done so in the past.  As a utility approaches a 100% debt capital structure, it becomes much riskier for itself and bondholders.  If all of its financing is done with fixed obligations (bonds), it must pay for all of its financing on a regular basis in fixed amounts.  This increases the chance of default and bondholders would rightly demand higher and higher returns on their investments, to the point at which small companies might become so risky that they could be denied access to capital markets.  Similarly, a 100% common equity capital structure would lessen the ability of a utility to raise needed money through issuance of more common stock.  Potential stockholders would be buying a heavily diluted portion of the company.  Issuance costs would rise and perhaps stock would remain unsold.  A balanced capital structure gives the utility the ability to access capital markets on generally reasonable terms.  Given our statutory charge under Wyoming law that rates may not be unfair, discriminatory, unjust, unreasonable or unremunerative, ordering reliance on 100% debt would be contrary to law.

 

                        d.         Question.         Could the Commission require 60-year depreciation on the Plant?

 

                                    Answer.           The Commission theoretically could, but doing so would not be supported by the evidence of record in this case.  Such action outside of the record would be arbitrary on its face under the Wyoming Administrative Procedure Act and subject to being overturned on appeal.

 

                        e.         Question.         Could the Commission authorize a return on equity in the mid-single digits?

 

                                    Answer.           It could do so if the evidence of record supported it.  However, such a decision would not be supported by the evidence in this case and or requirements of law (including the United States Supreme Court cases discussed below).  As in ¶ 93d above, if the Commission were to act arbitrarily, its decision could be set aside after judicial review.

 

                        f.          Question.         Is the return on equity based on good comparables?

 

                                    Answer.           As the case is decided, yes.

 

                        g.         Question.         Can the irrigation rate be adjusted?

 

                                    Answer.           The irrigation rate has been adjusted, consistent with the principle that each class of service must bear its own costs.  On the last day of the hearing, devoted principally to the Stipulation, the Commission reviewed details of MDU’s cost of service study as it relates to irrigation service.  The Commission is satisfied with the results of the cost of service study and notes that the new optional irrigation tariff reduces the daily peak hours from an eight-hour window to a two-hour window when the actual MDU system peaks occur.  The Commission also notes that OCA did not question MDU’s cost of service study.

 

                        h.         Question.         Has MDU addressed its own cost structure?

 

                                    Answer.           That issue was more directly addressed in last year’s rate case. Until 2008, MDU’s management had successfully operated under a rate structure which had been in place since 1993.  The Commission believes MDU is competently managed, and there has been no evidence offered to show that MDU has incurred excessive or imprudent costs.  The need for this rate case rests principally on the purchase of a 25% share of Wygen III.

 

                        i.          Question.         Has MDU accounted for the savings it will realize by not having to purchase all of its power?

 

                                    Answer.           Yes.  The purchased power costs are decreased in this case to account for the power generated by the Wygen III Plant.

 

                        j.          Question.         Why are we guaranteeing MDU a return on equity when the healthiest companies in the nation are losing money and private citizens’ investments and businesses do not have guaranteed returns?

 

                                    Answer.           The Commission does not guarantee MDU a return on its equity.  It only gives MDU an opportunity to earn a return on equity, and in doing so, sets a maximum allowable return.  Utilities commonly fail to earn the authorized rate of return. We have to determine a fair rate of return as noted above.  Also see the Hope and Bluefield cases discussed below.  They are the standard for utility regulators throughout the United States.

 

                        k.         Question.         Can MDU do better with demand side management?

 

                                    Answer.           The Commission will address this question in another docket, already in progress.  The Commission notes that the cost of demand side management measures are typically passed on to ratepayers as a surcharge, which means that benefits of proposed measures must be thoughtfully scrutinized and tested to see whether they provide real value for consumers.

 

                        l.          Question.         Are the ratepayers bearing the risk of MDU’s investment in Wygen III?

 

                                    Answer.           There are different forms of risk.  However, as we understand the original question, we believe the answer is that ratepayers are not guaranteeing a return to MDU or otherwise limiting MDU’s own risks in a manner uncommon for utilities in Wyoming or elsewhere in the United States.  In this regard, we note that under Wyoming law, public utilities like MDU are granted exclusive service territories, and so are insulated from competitive risk.  Also, it is important to understand that, in areas of the country where utilities are free to compete, lower prices do not always result.

 

                        m.        Question.         How does MDU compare with Rocky Mountain Power, which was reported to be asking for a 3% decrease in its power costs?

 

                                    Answer.           The newspaper accounts were a bit misleading since they addressed only the portion of Rocky Mountain rates which were driven by purchased power and fuel costs.  Its overall rates have been rising.  Rocky Mountain has advised the Commission that it intends to file rate cases on a yearly basis for the near future.

                       

For the past four years, Rocky Mountain Power normally has had two proceedings a year, one to increase general rates, and one to pass on power costs.  In this year’s general rate case proceeding, Rocky Mountain Power requested a rate increase of $70 million per annum.  Rocky Mountain Power and the parties in those two cases have proposed a combined settlement that would cut this increase in half.

 

Rocky Mountain Power’s plans for the coming ten years call for $10 billion of new investment a substantial portion of which is driven by environmental standards and new transmission to serve its customers.  Rate increases every year are likely, in addition to whatever proceedings there may be to adjust power costs.  MDU does not have similar plans.

 

                        n.         Question.         Did MDU responsibly forecast its need for the next ten years before it decided to invest in Wygen III?

 

                                    Answer.           Yes.

 

                        o.         Question.         Should MDU have been directed to discuss its investment decision with the customers before it went ahead?

 

                                    Answer.           The Commission considered MDU’s decision to become involved with Wygen III in a public hearing for a proposed certificate of public convenience and necessity.  That proceeding, which forecast a rate increase of 17%, drew far less attention than the Company’s eventual proposal to increase rates by nearly double that amount.  We note that the Stipulation here proposed an increase of 16.1%, and the Commission approved an increase that was even smaller.  The Commission is charged with regulating utilities, not managing them.  We cannot require the public to pay active attention to a Company decision, even one which may have long term effects; and such discussions would be outside of the record of this case.  That is, the Commission could not use such meetings in making its decision here.

 

Legal Standards Applicable in This Case

 

92.       W.S. § 37-3-101 states:

 

All rates shall be just and reasonable, and all unjust and unreasonable rates are prohibited.  A rate shall no be considered unjust or unreasonable on the basis that it is innovative in form or in substance, that it takes into consideration competitive marketplace elements or that it provides for incentives to a public utility.  * * * The commission may determine that rates for the same service may vary depending on cost, the competitive marketplace, the need for universally available and affordable service, the need for contribution to the joint and common costs of the public utility, volume and other discounts, and other reasonable business practices. * * *

 

            93.       The Commission has broad powers to inquire into the facts surrounding the determination of rates.  They include W.S. § 37-2-119, which articulates the “used and useful” test and allows wide latitude in the Commission’s investigation of rate-related matters.  It states, in part:

 

In conducting any investigation pursuant to the provisions of this act the commission may investigate, consider and determine such matters as the cost or value, or both, of the property and business of any public utility, used and useful for the convenience of the public, and all matters affecting or influencing such cost or value, the operating statistics for any public utility both as to revenues and expenses and as to the physical features of operation…

 

            94.       W.S. § 37-2-120 requires the Commission to afford due process in its cases, stating, in part:

 

No order, however, shall be made by the commission which requires the change of any rate or service, facility or service regulation except as otherwise specifically provided, unless or until all parties are afforded an opportunity for a hearing in accordance with the Wyoming Administrative Procedure Act.

 

            95.       W.S. § 37-2-121 gives the Commission latitude to determine the actual rates to be charged by a utility, stating, in part:

 

            If upon hearing and investigation, any rate shall be found by the commission to be inadequate or unremunerative, or to be unjust, or unreasonable, or unjustly discriminatory, or unduly preferential or otherwise in any respect in violation of any provision of this act, the commission may fix and order substituted therefore such rate as it shall determine to be just and reasonable and in compliance with the provisions of this act.

 

            96.       W.S. § 37-2-122(a) reinforces the Commission’s ability to exercise its sound informed discretion in rate making cases.  It states:

 

In determining what are just and reasonable rates the commission may take into consideration availability or reliability of service, depreciation of plant, technological obsolescence of equipment, expense of operation, physical and other values of the plant, system, business and properties of the public utility whose rates are under consideration.

 

            97.       W.S. § 37-2-122(b) gives similar necessary latitude to the Commission regarding utility services, stating:

 

If, upon hearing and investigation, any service or service regulation of any public utility shall be found by the commission to be unjustly discriminatory or unduly preferential, or any service or facility shall be found to be inadequate or unsafe, or any service regulation shall be found to be unjust or unreasonable, or any service, facility or service regulation shall be found otherwise in any respect to be in violation of any provisions of this act, the commission may prescribe and order substituted therefore such service, facility or service regulation, as it shall determine to be adequate and safe, or just and reasonable, as the case may be and otherwise in compliance with the provisions of this act, including any provisions concerning the availability or reliability of service. It shall be the duty of the public utility to comply with and conform to such determination and order of the commission.

 

            98.       At W.S. § 16-3-107, the Wyoming Administrative Procedure Act sets parameters for due process in Commission cases, including the giving of reasonable notice.  In accord are W.S. §§ 37-2-201, 37-2-202, and 37-3-106.  See also, Sections 106 and 115 of the Commission’s Rules.

 

            99.       Read in pari materia, these statutes articulate the basic mechanism of the public interest standard which the Commission is to follow in its decisions.  The public interest must come first in the Commission’s decisions, as the Wyoming Supreme Court has stated; and the desires of the utility are secondary to it.  Mountain Fuel Supply Company v. Public Service Comm’n, 662 P.2d 878 (Wyo. 1983).  Construing W.S. § 37-3-101, which requires rates to be reasonable, the Court in Mountain Fuel, supra, at 883, commented:

 

This court cannot usurp the legislative functions delegated to the PSC in setting appropriate rates, but will defer to the agency discretion so long as the results are fair, reasonable, uniform and not unduly discriminatory.

 

Later, 662 P.2d at 885, the Court in Mountain Fuel observed:

 

We agree that if the end result complies with the ‘just and reasonable’ standard announced in the statute, the methodology used by the PSC is not a concern of this court, but is a matter encompassed within the prerogatives of the PSC.

 

100.     In accord are Great Western Sugar Co. v. Wyo. Public Service Comm’n and MDU, 624 P.2d 1184 (Wyo. 1981); and Union Tel. Co. v. Public Service Comm’n, 821 P.2d 550 (Wyo. 1991), wherein the Supreme Court stated, 821 P.2d at 563, that it “…has recognized that discretion is vested in the PSC in establishing rate-making methodology so long as the result reached is reasonable.”

 

            101.     Consistent with the discretion given to the Commission in examining cases and reaching a just result, there are no precise bases in Wyoming law to guide the Commission in determining a utility’s rate of return.  Therefore, the Commission must apply its informed judgment to all of the evidence in the case.  In this work, we are guided by the earnings and capital attraction standards of Bluefield Water Works & Improvement Co. v. Public Service Commission of West Virginia, 262 U. S. 679 (1923); and Federal Power Comm’n v. Hope Natural Gas Co., 320 U. S. 391 (1944); accepted in Wyoming in In re Northern Utilities, 70 Wyo. 275, 249 P.2d 769 (Wyo. 1952).  Taken together, these cases stand for the principle that a public utility is entitled to rates which will permit it a reasonable opportunity to earn a return on its investment properly reflecting the risk of the business and which will reasonably preserve the financial soundness of the company and allow it to raise the capital needed to provide service in the public interest.  Having said that, we also acknowledge that the measurement of the required level of return is not a matter of simple mathematics but is a matter requiring judgment and the employment of discretion.  The United States Supreme Court, in Hope, supra, noted that a “just and reasonable end result” is the desired outcome and that it is the end reached, rather than the method employed in achieving it, that should control.

 

            102.     Under Section 119, Settlements, of the Commission’s Rules, “…informal disposition may be made of any hearing by stipulation, agreed settlement, consent order or default upon approval of the Commission.”

 

            103.     In Willadsen v. Christopulos, 1987 WY 5, 731 P.2d 1181, (Wyo. 1987) the Wyoming Supreme Court discussed the standard of proof to be used in Wyoming administrative hearings.  Construing Wyoming Statutes (W.S. §§ 41-3-911(b) and 41-3-911(c)), neither of which names the standard to be applied in matters coming before the State Board of Control, the Supreme Court stated, 1987 WY 5 at ¶13, with regard to W.S. § 41-3-911(c):

 

Under that statutory section and the applicable provisions of the Wyoming Administrative Procedure Act, the standard applicable to an adjudicatory hearing before the Board of Control, unless otherwise stated, is the "preponderance of the evidence" standard customarily used in civil cases. Amerada Hess Pipeline Corporation v. Alaska Public Utilities Commission, Alaska, 711 P.2d 1170, 1179 n. 14 (1986); Intermountain Health Care, Inc. v. Board of County Commissioners of Blaine County, Idaho, 107 Idaho 248, 688 P.2d 260, 263 (1984), quoting E. Cleary, McCormick on Evidence § 357 (3d ed. 1984).

 

Later, the Court emphasized the necessity of applying this standard, 1987 WY 5 at ¶14, saying:

 

Because the Board of Control failed to apply the preponderance of the evidence standard and instead applied the substantial evidence test applicable to appellate review of an agency decision, we find that petitioners were denied due process.

 

Although one of the statutes on which we rely in this case, W.S. § 37-1-121, specifies the substantial evidence standard, the other sections do not.  We must therefore agree with the Court in Willadsen, that the correct standard to apply to this case is the higher preponderance of the evidence standard.  We would be remiss in even colorably denying due process in this case and will not do so.

 

Additional Findings of Fact

 

104.     Many of the particular facts necessary to the decision of this case have been stated above and will not be restated here.

 

105.     MDU filed its initial general rate case filing seeking additional revenue relief in the amount of $6,198,501 per annum (30.7% overall increase).  The Company subsequently filed its supplemental or amended application reducing the amount of its requested revenue increase to $5,053,756 per annum (25.1% overall increase) to reflect its accelerated/bonus depreciation deduction adjustment related to Wygen III, as provided for under federal law for certain qualifying property additions.  The Company subsequently filed its updated electric division Depreciation Study and Common Plant Depreciation Study in which it proposed certain revised depreciation rates; the net effect of which is a further decrease in the Company’s revenue request to $4,833,545 per annum.  The OCA offered its testimony through expert witnesses supporting its initial proposed revenue increase of $1,430,794 per annum (7.773% overall).  (OCA Exhibit No. 210.)

 

106.     At the conclusion of the contested portion of the public hearing in which MDU and OCA presented their positions on an appropriate revenue increase, they advised the Commission they were in the process of negotiating a settlement which culminated in the filing of the Stipulation.  An additional public hearing was held in which Company and OCA witnesses provided testimony in support of the Stipulation which provided for a negotiated revenue increase of $3,253,726 per annum based upon a 10.9% return on equity, which when applied to the Company’s proposed capital structure results in an 8.68% overall return on rate base.  Generally, the Stipulation provided for a three year phase-in of the revenue increase including interest on the amount of the increase deferred in the first year of the phase-in.  Other major provisions in the Stipulation included depreciation expense and other depreciation-related calculations based on a negotiated 45 year Wygen III depreciation life, the offering of Rate 25 and Rate 26 irrigation schedules, the filing of a rate case within five years of the date of the order in this case, and a revision to the Power Supply Cost Adjustment tariff mechanism to provide for a sharing mechanism as advocated by the OCA.  (MDU/OCA Joint Exhibit No. 1.)

 

107.     Based upon the preponderance of the evidence offered in this proceeding, the Commission finds that the Stipulation, although offering certain reasonable terms and conditions, must be rejected for the reasons set forth below.  Further, the Commission finds the evidence of record supports additional rate relief for MDU in the amount of $2,651,565 per annum (13.1% overall), as supported by the Commission findings below.

 

The Stipulation

 

            108.     Witnesses Mulkern and Zamora testified that one of the major benefits of the Stipulation was the proposal to phase-in the stipulated revenue increase over a three-year period, offered to mitigate rate shock concerns expressed by MDU’s customers at the public comment hearing in contemplation of the 25% increase proposed.  The phase-in approach was justified as a mechanism which would provide customers with the ability, during the first year of the phase-in, to plan and budget for the additional increase which would come in the second year and continue through the third year.  Zamora acknowledged OCA had made concessions to the Company in the Stipulation regarding the return on equity and the Wygen III depreciation rate to obtain the phase-in provision.  She also expressed her belief that the phase-in provision was an integral part of the Stipulation and that if the Commission had concerns and rejected the phase-in provision it should reject the Stipulation. (Stipulation Comment Tr., pp. 142, 152.)

 

109.     The Stipulation specifies 8.68%, the overall rate of return agreed to by the parties, as the interest rate for the deferred portion of the phased-in rate increase.  The Commission finds this proposed interest rate  on the deferred portion of the revenue increase to be excessive.  If this rate reflects the time value of money, the Commission finds it highly unlikely that, if the Company needed to borrow money in the interim, it would have to pay an interest rate of 8.68%, given current economic and financial conditions.  Below, the Commission will discuss its determination of an appropriate return on equity for this Company which will decrease the overall rate of return on rate base.

 

110.     The phase-in proposal was ostensibly offered to mitigate the rate shock to come from implementation of the full revenue increase in 2010, by implementing a $1.8 million (8.93%) increase in the first year, and a $1,453,726 increase in the second year (6.6%) and continuing into the third year. (MDU/OCA Joint Exhibit No. 1, ¶¶ 16-17.)  On closer inspection of the proposed phase-in and its associated interest on deferred revenues, it is clear that, in exchange for the transitory illusion of less rate shock in the first year of implementation, the net result is that customers will pay more overall than if the phase-in were not allowed.  Zamora acknowledged this fact.  (Stipulation Comment Tr., pp. 123-124.)  Rather than ameliorating rate shock in the first year, the phase-in has the effect of continuing the rate shock effect for at least two years.  Mulkern acknowledged on cross-examination that, in Year Two and Three of the phase-in, and taking into account the interest on the unamortized balance, customers would experience an increase of approximately 20.1%, (in comparison to current revenue levels), as opposed to the 16.1% increase they would realize in the first year if the Stipulation’s revenue increase were put into effect with no phase-in.  Only in Year Four would the increase decline to 16.1%.  (Stipulation Comment Tr., pp. 42-43.)  The phase-in proposal will also cause customers to experience rate instability as rates would be adjusted in Years One, Two and Four (and remaining high in Year 3).  This will contribute to unnecessary customer confusion and may serve little purpose than to remind customers that rates continue to increase in subsequent years as a lingering effect of approval of the Stipulation.  The Commission finds the provisions regarding the handling of possible under-recoveries or over-recoveries of the deferred balance at the end of the two-year amortization period, as referenced in ¶ 19 of the Stipulation, is unclear and leaves unresolved the appropriate rate treatment for an over-recovered balance.  Based upon the findings set forth herein, the Stipulation provides no tangible rate relief benefits to customers, is not in the public interest and must be rejected.  Simply put, the ratepayers will pay more if the phase-in is accepted, and it should not be.  We further reject the notion, expressed at ¶ 25 of the Stipulation, that MDU should bind itself to file another rate case in five years.  MDU is capable of deciding when it wants to file for additional rate increases without an arbitrary deadline, just as the Commission is fully capable of ordering MDU to file another case should we determine the need has arisen.

 

OCA’S Levelization Proposal

 

            111.     OCA witness Parrish offered a proposal to levelize or equalize the cost of the return on MDU’s 25% Wygen III ownership interest over the expected depreciable life of the facility, as a mechanism to make all generations of MDU customers pay the same proportional share of return MDU is entitled to earn on its portion of the Plant.  The levelization proposal would lessen the rate impact of adding Wygen III to rate base during the initial years of its inclusion.  Utilizing a fifty-year depreciable life for Wygen III, and a discount rate for the present value of 8.45% (OCA’s recommended overall return on rate base) over the life of the Plant, levelization results in a return to the Company’s investors of $2.8 million each year over the fifty-year life of the Plant.  Parrish further testified that her levelization proposal assumes no change in the $2.8 million return to investors, regardless of future MDU general rate case filings.  It also does not account for the costs of any additions to or repairs of the Plant during its useful life. Traditional depreciation methods would front load the return on the new Plant, resulting in early customers paying more than later generation customers, as the value of the Plant is depreciated over time.  (Tr., pp. 626, 630-631.)

 

            112.     Parrish acknowledged this is the first case in which she has offered a levelization proposal and she was unaware of any prior Commission decision which addressed or approved a similar proposal.  (Tr., p. 650.)  She conceded that there is some uncertainty surrounding her proposal and that, over the first year of the Plant’s operation, the return on the Plant would be less than 8.45%.  (Tr., pp. 651, 657.)  She further conceded the inherent unevenness in the plan:  during the first ten years, customers would pay a lower return, with the return paid in later years being greater.  She acknowledged implementing an 8.45% return over the fifty-year period could be problematic if certain events occurred, such as [i] debt and equity costs increasing into double digits which would make the discount rate insufficient in the marketplace, or [ii] the Company being unable to attract capital in the event the market did not accept her methodology.  (Tr., p. 686.)  Further Parrish noted in her summary testimony that the result of her levelization approach would be that MDU will collect about $55 million more from customers than it would if a nominal levelized return were used.  (OCA Exhibit No. 216, p. 15.)

 

            113.     The Commission finds, based upon its review of Parrish’s testimony and Gaske’s rebuttal testimony in which he expressed a number of concerns regarding OCA’s levelization proposal, that the proposal relies on too many assumptions to be approved.  For example, to implement OCA’s proposal, which is premised on a return of 8.45%, set at a time of historically low interest rates, we would be required to assume that this return will be reasonable over the 50-year life of Wygen III (an asset which was estimated by Parrish to quadruple the size of MDU’s Wyoming electric rate base).  The proposal may impose unreasonable constraints on future commissions who may feel compelled to maintain the fixed return level in the face of market conditions which may suggest otherwise.  It could jeopardize the Company’s ability to attract capital in the market place under such circumstances.  It would have the effect of shifting part of the recovery of the return on Wygen III from the current generation of customers to later generations who will incur additional significant costs (approximately $55 million under the OCA’s proposal).  In addition, as noted by Gaske, the return earned during the initial year of Wygen III’s inclusion in rate base and in subsequent years, under the levelization proposal, may be insufficient to provide a reasonable return to common equity investors, as interest on debt must first be paid to bondholders.  (Tr., p. 737-739.)  In all, in return for lower, and possibly inadequate initial returns on the Wygen III investment, in contemplation of $55 million of additional costs to be imposed on ratepayers over the years, accepting that we are in a time of low inflation and that it might not remain so over the 50-year life of the Plant, acknowledging that it is not only bad public policy but also not possible to attempt to bind future commissions, either actually or morally, to a decision made today, and understanding that adopting the plan could make it difficult for MDU to raise needed capital in the future, we find that OCA’s levelization proposal must be rejected as being unreasonable and contrary to the public interest.  This finding is supported by the preponderance of the evidence of record in this case.

 

Overall Cost of Capital and Return on Common Equity

 

            114.     MDU witness Senger offered [i] the pro forma MDU capital structure as projected for the twelve month period ending December 31, 2009; [ii] the pro forma costs of long and short term debt; [iii] the costs of preferred stock, as projected through 2009; and [iv] the recommended cost of equity capital of 12.75% as determined by Gaske.  (MDU Exhibit No. 107.)  Using these figures to derive weighted average costs, the Company recommended an overall rate of return of 9.62%.  OCA witness Wichmann adopted the Company’s proposed pro forma capital structure and associated weighted costs of long and short term debt, and preferred stock.  (OCA Exhibit No. 208.)  She applied her recommended cost of equity capital of 10.4% to the pro forma capital structure and weighted costs of debt and preferred stock in arriving at her recommended overall rate of return of 8.45%.  The uncontroverted testimony supports the use of the Company’s pro forma capital structure and pro forma cost of debt and preferred stock, and we will do so in calculation of the authorized overall rate of return below.

 

Component

Percentage

Cost

Weighted cost

long-term debt

44.959%

6.79%

3.05%

average short-term debt

2.771%

3.77%

0.104%

preferred stock

2.5%

4.59%

0.115%

common equity

49.77%

10.4%

5.18%

TOTAL

100.00%

 

8.45%

 

            115.     MDU witness Gaske and OCA witness Wichmann provided their respective testimony and analyses in support of their calculations of a reasonable cost of common equity capital for MDU’s Wyoming electric utility operations as summarized, supra.  Both Gaske and Wichmann selected their respective group of comparable companies utilizing similar information sources and certain criteria or filters they believed would provide a sampling of companies that would reasonably serve as proxies for MDU’s Wyoming electric operations.  We note that twelve of Gaske’s thirteen comparable companies were included in Wichmann’s group of twenty two proxy companies.  Both Gaske and Wichmann relied on several different DCF analyses as their primary methodologies in arriving at their recommended returns on common equity.  Wichmann’s ROE analyses resulted in a range of reasonableness of 9.05% to 10.93%.  She recommended a ROE of 10.4%.  In contrast, Gaske utilized the results of his two DCF analyses in arriving at a range of reasonableness of 11.56% to 12.95% and concluded that because of MDU’s slightly above average risks a ROE of 12.75% was appropriate.  (Tr., p. 174.)

 

            116.     The Commission finds Wichmann’s testimony and analyses presented in calculating a range of reasonableness for MDU’s ROE to be the most thoroughgoing, persuasive, and supported by the preponderance of the evidence.  Gaske’s explanation of his criteria in selecting his comparable companies, and notably his use of companies with at least 25% of generation from coal-fired plants, unreasonably narrows the group of comparable companies, making the results of his analyses vulnerable to manipulation.  He assigned additional risk to the Company because of its use of coal-fired generation in meeting a portion of its supply requirements, which he contrasted to its prior total dependence on purchased power contracts and the associated market volatility in serving its load requirements.  This, on its face, appears to conflict with the Company’s underlying rationale for purchasing a 25% interest in Wygen III, i.e., the mitigation of wholesale market volatility and its associated higher risks.  The Commission is not persuaded by Gaske’s argument that current economic conditions and the decline in the stock market have resulted in investors requiring a higher rate of return as they perceive more risk in common stock investments.  (Tr., pp. 193-194.)[1]  In contrast, Wichmann’s determination of an appropriate ROE took into consideration the results of her DCF analyses and an identification and analysis of macroeconomic, financial and business risks facing MDU’s regulated utility operations. (OCA Exhibit No. 201, pp. 23-28.)  Taking these factors into account and recognizing [i] the narrowing of credit spreads between Aaa and Baa rated company securities and 30-year Treasury bond yields in 2009 (which suggests reduced risk and lower premium expectations by investors),  and [ii] the regulatory paradigm in which MDU operates (which allows a significant portion of its costs to be recovered under tariffs, including the PSCA mechanism), Wichmann concluded the risks to MDU’s Wyoming utility operations are average in comparison to other utilities, with the business risk being low to average.  (Tr., p. 521.)

 

            117.     Although Wichmann recommended a ROE of 10.4%, the midpoint of her range of reasonableness is 9.9%.  Chairman Minier asked  her, given his concerns that the fed fund rate has been low for an extended period of time and the investment climate has been poor, whether it was unreasonable to consider a 9.9% ROE as being appropriate.  She stated that any point within her range of reasonableness of 9.05% to 10.93% would be supported by her analysis.  (Tr., p. 522.)  Taking into consideration current economic conditions (as reflected in historically low interest rates which appear poised to continue, and indications that investors are returning to the equity market), the Commission finds and concludes that Gaske’s recommended ROE of 12.75% is excessive and that a more reasonable ROE is appropriately closer to the midpoint of OCA’s range of reasonableness.  The Commission finds that a ROE of 10.0% for MDU’s Wyoming electric utility operations is reasonable and appropriate.  It meets the standards and requirements of the Hope and Bluefield cases.  Based on our determination, that a 10.0% cost of common equity is supported by the preponderance of the evidence, we find the appropriate and reasonable overall rate of return for MDU’s Wyoming electric utility operations to be 8.25%, calculated thusly:

 

Component

Percentage

Cost

Weighted cost

long-term debt

44.959%

6.79%

3.05%

average short-term debt

2.771%

3.77%

0.104%

preferred stock

2.5%

4.59%

0.115%

common equity

49.77%

10.0 %

4.977%

TOTAL

100.00%

 

8.25%

 

Wygen III Depreciation Life

 

            118.     In its application, MDU proposed a 40-year depreciable useful life for Wygen III, stating the Company utilized the depreciation rate assigned by Black Hills Power & Light to the facility.  The Company did not present an independent analysis of an appropriate depreciable life or corresponding depreciation rate for Wygen III and stated its recently completed depreciation studies did not include Wygen III because it was not constructed at the time the depreciation studies were prepared.  (Tr., pp. 309-310.)  Also, the Company originally proposed an annual depreciation rate for the Plant of 2.72% which translates to a 36.7 year life for the Plant.  Mulkern subsequently testified on rebuttal that she was updating the depreciation rate for the Plant to 2.5% to reflect the 40-year life which the Company maintained was reasonable.  (Tr., p. 756.)  MDU witness Neigum acknowledged on cross examination that the Company had several older coal plants that have operated in excess of 50 years.  From a technological standpoint, he was unaware of any reason which would limit a coal plant’s life to 50 years.  He stated a 40-year life for Wygen III was a “safe” estimate.  (Tr., pp. 253-254, 281.)

 

            119.     OCA witness Zamora testified in support of a depreciable life of 50 years for Wygen III, basing her recommendation on the depreciation rates and lives assigned to similar coal-fired power plants by Rocky Mountain Power and Black Hills (which possesses plants similar to Wygen III).  She stated that a 40-year life was a good starting point but that it was logical to extend the lives of these plants to address continued capacity deficits.  (Tr., pp. 541, 563.)  In discussing the depreciable lives of other vintage coal-fired plants in MDU’s inventory, Parrish noted the current updated MDU depreciation studies reflect depreciation lives ranging from 48 to 66 years.  (Tr., p. 645.)

 

            120.     The Commission finds the evidence presented on this issue supports a depreciable life of 50 years and a corresponding depreciation rate for MDU’s share of Wygen III of 2.0% per annum.  The Company presented no independent analysis to support its 40-year depreciable life, and based its decision on nothing more than the 40-year life assigned to Wygen III by Black Hills.  We note the 40-year life assigned to Wygen III by Black Hills has not been brought before this Commission for consideration or approval.  It will, however, be an issue for consideration in the pending Black Hills general rate increase filing.  Our determination, based on the evidence in this case, is, we note, also consistent with the representations of OCA regarding useful coal plant lives in excess of 50 years for other coal-fired plants operated by Rocky Mountain Power and Black Hills.  The use of a 50-year depreciable life for Wygen III is further supported by the Company’s acknowledgment that the actual coal contract to serve the Wygen III Plant is set to run for 50 years.  A 50-year life is within the range of reasonableness as developed in this case.  (Tr., pp. 245, 254.)  In addition, the Commission finds OCA’s concession to accept a 45 year depreciation life for Wygen III understates the reasonable useful life of this generating facility, which will also be addressed herein.

 

Revenue Requirement

 

            121.     The OCA recommended a number of adjustments to the Company’s proposed pro forma revenues, O&M expenses, federal income taxes, other taxes and depreciation expenses.  In her revenue requirement analysis, Zamora separated Wygen III expenses and investment costs from the rest of the revenue requirement to accommodate the OCA levelization proposal.  Because the Commission rejects OCA’s levelization proposal, it is unnecessary for us to consider Zamora’s Wygen III adjustments separately from non-Wygen III-related expenses and investment costs.

 

            122.     OCA proposed an adjustment to usage which corrects an error identified by the Company regarding the revenues associated with the Rate 39 – Large General Service Class.  This increases the Company’s pro forma revenues by $18,726 to reflect additional revenue from demand and energy charges collected from the class due to an upward adjustment to usage.  This adjustment simply corrects errors and was not contested by the Company.  It is adopted by the Commission.

 

            123.     The Commission finds OCA’s adjustment to purchased power and fuel costs associated with Wygen III is appropriate.  It reflects updates in the gross tons of coal (629,355 tons) and uses a more updated cost of coal of $11.70 per ton.  MDU witness Neigum testified to these statistics as representing the most current 2010 projections.  (Tr., p. 237.)  Mulkern provided updated coal expense information agreeing that the most recent updates should be utilized and stated they would match the update of the Wygen III Plant value she identified in her rebuttal testimony.  (Tr., p. 746; MDU Exhibit No. 155.)  Zamora agreed the most current Statement R price regarding the coal price should be used.  (Tr., p. 558.)  OCA’s adjustment also incorporates a purchased power adjustment to reflect the correction to the Rate 39 usage. 

 

            124.     In its initial testimony, OCA proposed an adjustment to Wygen III-related O& M expenses.  During the course of the hearing, the parties agreed that updated information regarding Wygen III available at the time of the hearing should be incorporated into these adjustments.  As to this specific adjustment, Zamora stated that she did not disagree with the updated amounts provided by Mulkern on rebuttal and said they should be adopted; and MDU agreed to the inclusion of the update.  (Tr., p. 746.)  The Commission finds the updated O & M expense total associated with Wygen III in the amount of $2,668,722 (as reflected in Commission Exhibit C), are appropriate and should be incorporated in the calculation of the revenue requirement.

 

            125.     OCA proposed to exclude $2,413 in advertising expense and industry dues, stating the expenditure of these funds are not needed in the provision of utility service and should more appropriately be shareholder funded.  Company witness Mulkern, on rebuttal, testified the Company disagreed with the exclusion of the advertising expense in the amount of $1,683, arguing that institutional advertising benefits the communities it serves, thereby benefiting customers.  (Tr., p. 743.)  Commission Rule Section 248 addresses the issue of “promotional”, “political” and “institutional” advertising and sets out the general prohibition of cost recovery in rates for these types of advertising, stating that such costs should be recovered by shareholders or owners of the utility.  Commission Rule Section 248(e) specifically excludes certain forms of advertising from the general prohibition of cost recovery through customer rates, allowing recovery of the costs of advertising required by the public interest, as determined on a case-by-case basis.  The Commission finds the advertising for which the Company seeks rate recovery does not fall within the exceptions in Section 248(e).  We do not find that the Company has supported its argument for recovery of these advertising expenses in this case.  The denial of rate recovery for these advertising expenses and industry dues in the amount of $2,413 is in the public interest and is consistent with past Commission practice.

 

126.     The OCA proposed to amortize regulatory commission (rate case) expenses over a ten year period, stating the normal time frame between MDU rate case filings is 8-15 years.  (OCA Exhibit No. 209, p. 9.)  Company witnesses proposed a three-year amortization period.  The Commission finds the shorter amortization period of three years for recovery of regulatory commission expense is more reasonable and should be adopted as it provides for a more timely recovery of these expenses.  The Commission anticipates that the historically lengthy period of time between MDU rate case filings may no longer be possible given the rapidly changing financial markets, which may require a more frequent review and evaluation of a reasonable cost of capital for MDU’s Wyoming utility operations.  It is also possible that carbon emission legislation and other regulatory issues might arise, which could necessitate further rate case filings.  Many such issues may arise at the federal level -- beyond the power of the Commission or MDU to ignore or defer.

 

127.     The Commission finds the Company has failed to support by a preponderance of the evidence its proposed generalized inflation adjustment to certain O&M expense accounts it had not individually adjusted for inflation.  The Commission concurs with the position advocated by OCA that the adjustment of these specific expenses by a blanket percentage inflation factor is inconsistent with general past Commission practice of allowing adjustments for known and measurable changes.  Therefore, the Commission adopts OCA’s downward adjustment in the amount of $6,551.

 

128.     OCA proposed to adjust O&M expenses to exclude certain costs related to one-time occurrences and prior period adjustments from 2007, and costs recovered through the Company’s Load Management Program.  Zamora corrected an error in the calculation of her prior period expense adjustment, reducing the total adjustment from $46,454 to $30,994.  (Tr., p. 587.)  Mulkern, on rebuttal, testified the Company did not take issue with OCA’s adjustments regarding Account 902, Prior Period Adjustments from 2007, as corrected by Zamora; Account 925, the one-time occurring Wrench Ranch Fire expenses; or Account 908, Refrigerator Round Up Program Costs.  Mulkern however, took issue with the exclusion of $3,499 associated with the Basin Electric Facilities Addition, which were related to transmission substation expenses, on the basis that even though the specific expense activity was non-recurring, such expenses regularly recur.  (Tr., p. 744-745.)  The Commission concurs with the Company’s rationale that inclusion of the $3,499 in expenses associated with the Basin Electric Facilities Addition is appropriate and reflects the recovery of a recurring expense.  The Commission finds the OCA’s other adjustments to O&M expense accounts, as corrected, are uncontested, and therefore an adjustment in the amount of $27,495 is adopted.

 

129.     The Commission finds OCA has supported its proposed adjustments related to Taxes Other Than Income, which included, [i] adjustments to Franchise Taxes of $125 and Gross Revenue Taxes of $57 to reflect OCA’s Rate 39 revenue adjustment, and [ii] an adjustment to ad valorem taxes of $3,503 for Wygen III based on 2009 mill levies.  The correct mill levy amounts were not available to the Company at the time of the filing.  We thus adopt a total net adjustment of $3,321.

 

130.     MDU witness Mulkern offered a depreciation expense adjustment to reflect updated depreciation rates and associated expenses as shown in the Company’s updated and very recently filed Electric Depreciation Study and Common Plant Depreciation Study.  She stated the effect of utilizing the new depreciation rates would be to reduce her pro forma depreciation expense by $218,211 per annum.  Mulkern stated factoring the effects of the revised depreciation expense on rate base, O&M expenses, and income taxes has the effect of reducing the Company’s revenue increase by $220,358.  (MDU Exhibit No. 142, pp. 2-3.)  OCA witnesses accepted the Company’s adjustment but recommended the Commission not accept or approve the updated depreciation studies because the OCA had insufficient time to review the studies in detail.  OCA suggested that a more thorough review and full consideration of the studies would be best handled in the context of future rate proceedings.  (Tr., pp. 564-566, 639-646.)  Mulkern testified the Company did not object to the utilization of the revised depreciation expenses as set forth in the studies or allowing the OCA and Commission staff adequate additional time to review and inquire into the depreciation studies.  (Tr., p. 759.)  Based upon the concurrence of the parties in the adjustment to depreciation expense which reduced the Company’s revenue requirement by $220,358 per annum, and general agreement that additional time for review of the updated depreciation studies is appropriate, the Commission finds the adjustment to depreciation expense should be accepted and factored into the calculation of the Company’s revenue requirement.  Further, the Commission finds the Company should be directed to refile its updated depreciation studies, as a separate docketed matter, so they can be reviewed, noticed, and additional proceedings can be held, if necessary, and a final determination can be made by this Commission regarding their reasonableness and possible approval of the studies.

 

131.     In her supplemental testimony in support of the Company’s amended application, Mulkern proposed an additional decrease to the Company’s revenue request to recognize the impact of a proposed 50% bonus tax depreciation adjustment available for federal income tax purposes for certain qualifying property additions.  The Company presented testimony to support its belief that its investment in Wygen III qualified for the bonus depreciation deduction.  (Tr., pp. 297-300; MDU Exhibit No. 126, pp. 3-4.)  Mulkern testified that the head of the Company’s tax department, its internal auditors, and external tax experts had come to the common conclusion that the Company qualified for the bonus tax depreciation adjustment.  (Tr., pp. 470-471.)  OCA witness Zamora also recommended the bonus tax depreciation adjustment be adopted and incorporated in the calculation of the Company’s revenue requirement.  Zamora incorporated this deduction in her adjustments to deferred income taxes.  She agreed her proposed adjustment, as reflected in her prefiled direct testimony, should be revised to reflect the update of MDU’s Wygen III investment.  (Tr. p. 559.)  Mulkern’s bonus depreciation adjustment was updated to reflect the updated estimate of MDU’s Wygen III investment, as reflected in MDU Exhibit No. 139.  OCA and MDU concurred that the most current updated numbers should be utilized for many of the Wygen III adjustments.  The Commission concurs with the parties’ position that an adjustment to reflect the 50% bonus tax depreciation deduction for the Company’s Wygen III investment is appropriate and should be adopted.

 

132.     The Commission further finds that OCA’s testimony supports its adjustment to deferred income tax expense to reflect the use of a full year of book depreciation -- in contrast to MDU’s use of a half year -- in the calculation of the 50% bonus depreciation.  The Commission concurs with OCA’s adjustment.  The use of a full year of depreciation is consistent with the normalizing of book depreciation in general and with specific reference to the calculation of deferred income tax expense.  This adjustment increases book depreciation in the calculation and the annual tax effect of the difference between book and tax depreciation in the calculation, as depicted in the OCA calculation, is applied to deferred income tax expense and accumulated deferred taxes in the rate base calculation.  The changes in book depreciation in the calculation are included in the current tax calculation.

 

133.     The Commission accepts the OCA adjustment to synchronize interest expense in calculating current income taxes to reflect the interest deduction and the recovery of the interest expense necessary to finance the utility plant needed to provide service to the public.  The Commission also agrees with OCA’s adjustment to ad valorem taxes, which reflects the use of the 2009 mill levy for Wygen III, consistent with updated information.  In addition, the Commission adopts the OCA adjustment to Bad Debt Expense based on a five year average of the bad debt expense ratio, which is applied in the revenue requirement calculation.

 

Rate Base

 

134.     In its initial application, MDU presented a pro forma rate base for its Wyoming utility operations of $80,489,334, which it lowered in its amended application to $71,779,243, after taking into account the 50% bonus depreciation deduction.  (MDU Exhibit No. 128, p. 7 and revised p. 7.)  In her supplemental testimony, Mulkern calculated a revised pro forma rate base of $72,038,689 that took into account the depreciation rates in MDU’s updated depreciation studies.  (MDU Exhibit No. 150, 2nd revised p. 7.)  During the hearing, the parties provided their respective calculations of MDU’s Wygen III investment costs, which must also be factored into the calculation of an updated rate base.  Zamora calculated the capital cost for Wygen III at $61.7 million.  (Tr., p. 559.)  Both Mulkern and Zamora agreed the most updated Wygen III capital costs should be used in determining the appropriate rate base.  Zamora testified that, with an asset the size of Wygen III, it is appropriate to use the most current data.  She further stated she had verified the Company’s AFUDC calculation for 2010 but needed to verify the Company’s AFUDC calculation for 2009.  (Tr., pp. 559, 604.)  The 2009 AFUDC calculation was subsequently provided in MDU late-filed Exhibit No. 157.  On rebuttal, Mulkern provided an updated capital investment amount for Wygen III of $63,354,500, which includes AFUDC for 2009 and 2010.  (Tr., pp. 312; MDU Exhibit No. 139.)  The Commission concurs with the parties that the most current numbers must be used in calculating MDU’s Wyoming rate base.  Factoring in the adjustments to accumulated deferred depreciation to reflect the Commission use of a 50-year depreciation life for Wygen III (2.00% per year), the effects of the updated depreciation studies, and the accumulated deferred income tax, the Commission finds MDU’s Wyoming electric utility rate base to be $71,863,966, as reflected in the following table which illustrates the Commission’s calculated revenue deficiency of $1,703,954,  We must thereafter make provision for payment by MDU of federal corporate income tax at the rate of 35%, which required the application of a “tax gross up” factor of 1.55612 to the revenue deficiency, yielding an additional revenue requirement of $2,651,565, all as based on the Commission’s findings as set forth above.

 

 

Operating Income and Adjustments

A

MDU Initial Filing - Revenues

$          3,726,284

 

Commission Adjustments

B

Add Revenues

18,726

 

Deduct (or add) Expenses

C

   Purchased Power and Fuel

(134,010)

D

   Wygen III O&M Expenses

6,817

E

   Advertising and Dues

(2,413)

F

   Regulatory Commission Expense[2]

0.00

G

   Remaining O&M Expenses (Inflation)

(6,551)

H

   Miscellaneous O&M Expenses

(27,495)

I

   Depreciation expense

(731,581)

J

   Taxes Other Than Income

(3,321)

K

   Deferred Income Taxes

8,557,461

L

   Income Taxes[3]

(8,138,783)

M

Total Expense Adjustments

(479,876)

N

Adjusted Test Year Operating Income

$          4,224,823

 

 

 

Rate Base

O

MDU Initial Filing - Rate Base

$          80,489,334

 

Commission Adjustments

P

Plant Costs & Accumulated Depreciation

(67,907)

Q

Accumulated Deferred Income taxes

(8,557,461)

R

Commission Determined Rate Base

$          71,863,966

 

Revenue Requirement for This Case

S

Commission Determined Required Return on Rate Base at 8.25% [R x 8.25%]

5,928,777

T

Return Deficiency  [S - N]

1,703,954

U

Commission Determined Additional Revenue required [T x 1.55612][4]

$            2,651,565

 

Rate Spread/Rate Design

 

            135.     Aberle described the Company’s proposed rate spread.  She testified the Company proposes to increase rates so that each customer class would produce revenue at the overall rate of return with the exception of Schedule 24, the private lighting class, which is currently contributing more than the overall rate of return.  The Company proposes to maintain Schedule 24 rates at their current levels.  (Tr., p. 324.)  She further stated the Company’s proposal to move the customer charges and energy components of the various rates closer to their respective embedded costs, consistent with the results of its embedded cost of service study.  She said this movement complies with the Commission’s prior directives that such movement toward actual cost be made.  (Tr., p. 325.)  The OCA concurred with the use of the Company’s class cost of service study results in apportioning its proposed revenue increase between the various classes, concurring that the Schedule 24 Class was exceeding the overall rate of return.  OCA used the Company’s model in developing its proposed rate design for each customer class with the objective of continuing movement toward recovery by each class of its respective cost of service, and movement towards, or recovery of, cost of service for the individual rate components for each class. (Tr., p. 544-546.)  The Commission concurs with the general objectives of the parties in continued movement to cost of service based rates in developing their respective rate proposals.  The Commission finds generally that setting rates with the objective of recovering the actual embedded costs incurred in providing service to the respective customer classes, and the rate components within the classes, is consistent with the past policy directives of this Commission.

 

136.     MDU offered an alternative inverted block rate design for the Residential Rate Class, Schedule 10, as directed by the Commission in the prior rate case.  The Company, however, recommended continuing its current rate design which contains a monthly base rate and a flat energy charge, but agreed that an inverted block rate design was acceptable as long as a minimum base rate of $25.00 was incorporated.  MDU proposed an initial energy block of 1,000 kWh with the second block of energy use having an additional $0.02 per kWh differential. (MDU Exhibit No. 118, p. 12.)  OCA proposed the use of an inverted block rate design with a minimum base rate/monthly charge of $25.50 and a similar $0.02 per kWh differential for all energy above the initial block of 1,000 kWh.  (OCA Exhibit No. 209, pp. 26-27.)  The Commission finds the use of an inverted block rate design for Schedule 10 will provide better pricing signals to customers and will promote conservation.  The use of a $25.00 base rate/monthly charge is consistent with the results of the embedded cost of service study and provides additional movement towards recovery of the fixed costs associated with this rate component.

 

137.     The OCA proposed a rate design for the Small General Service Class, Schedule 20, that provided for a $4.00 demand charge for the first 10 kW of usage and $10.00 per kW for usage over 10 kW for primary customers and a $4.50 demand charge for the first 10 kW of usage and $10.50 per kW for usage over 10 kW for secondary customers.  MDU’s current rate design does not provide for a separate demand charge for the first 10 kW of usage.  MDU witness Aberle testified that OCA’s proposal to implement a demand charge for the first 10 kW of usage for small use Schedule 20 customers would require the use of approximately 1700 demand meters at an installed cost of approximately $485,500, which she recommended not be implemented.  (Tr., p. 764.) OCA witness Zamora subsequently acknowledged that her proposed rate design was not workable if demand meters were not in place for all customers in this class. (Tr., p. 548.)  The Commission finds acceptable the proposal of the parties in the Stipulation at ¶ 21, that a Small General Service Rate 20 Non-Demand Metered provision is added and charged separately under Schedule 20, with this provision being applicable to customers that do not currently have a demand meter.  The proposal is reasonable and supported by the preponderance of the evidence.  Given the small benefit to be derived, the expenditure of approximately $485,500 to purchase and install demand meters for small use customers in this class to track their demand usage is not supportable.

 

138.     Members of the Irrigation Class, Schedule 25, raised concerns at the public hearings regarding the negative impacts of the current Irrigation rate design on their farming operations and their rates.  In response, the Company proposed on rebuttal to bifurcate the current Irrigation Rate Schedule and offer an optional rate schedule under which Irrigation customers could take service under a time differentiated demand rate (time-of-day), or a more traditional non-time differentiated rate with a flat demand and energy charge.  The Company witness testified that the optional schedule would provide an appropriate price signal due to an increase in demand charges and an incentive to customers to move their loads to off-peak periods.  (MDU Exhibit No. 140, p. 4.)  OCA proposed continuation of the current Schedule 25 with an increase in the monthly charge to $50.00, a reduction in the on–peak demand rate from $9.50 per kW to $8.30 per kW, continuing the off-peak rate of $3.00 per kW, and an increase in the energy charge.  (OCA Exhibit No. 209, pp.  29-30.) 

 

139.     The Commission finds that a proposed bifurcated Irrigation Rate Schedule which offers optional time-of-day rates, with an on-peak hours period[5], and the use of a non-time-of-day rate design[6] which uses a flat demand charge, will provide irrigation customers with the ability to control their respective costs by determining which rate schedule is most compatible with their usage characteristics.  Adoption of a bifurcated rate schedule proposal is consistent with and supported in the rebuttal testimony of Aberle. (Stipulation Comment Tr. p. 79-80.)  The Company initially proposed continuation of a 12:00 noon to 8:00 p.m. on-peak period which it subsequently shortened to the four hour period proposed in the Stipulation.  In response to cross-examination, Aberle expressed her reluctance to move off the 12:00 noon to 8:00 p.m. on-peak period as she did not have available data to support another time period.  However, we find the Company failed to offer any evidence which would support continuation of the current eight hour peak period. (Tr., pp. 790-791.)  On the contrary, the Company provided actual data which showed its system peaks occurring between 4:00 p.m. to 6:00 p.m., with the majority occurring at 5 p.m.  (MDU Exhibit No. 122.)  The Commission finds that use of a peak period that runs from 4:00 p.m. to 6:00 p.m. for Rate Schedule 26 is supported by the evidence and should be adopted.  The Commission further finds a monthly Basic Service Charge of $50.00, an on peak demand rate of $8.30 per kW, and an off-peak demand rate of $3.00 per KW under Rate Schedule 26 are reasonable and supported by the evidence.  The Commission Staff will monitor the use of Schedules 25 and 26 and their impact on irrigation customers.

 

140.     The Commission also finds that irrigation customers should be allowed to select at any time the irrigation schedule under which they wish to be served; however, once the customer selects an irrigation schedule service must continue to be taken under that schedule for at least a one year period.  The Company agreed this selection process which required the customer to be bound for at least a year was acceptable and would address prior concerns expressed by the Company regarding the administrative burden and costs associated with having to reprogram its irrigation meters if customers were able to switch schedules more frequently.  (Public Comment Tr., pp. 64, 88.)  We expect some confusion among irrigation customers as a result of the adoption of Schedules 25 and 26.  Consequently, at the public deliberations on April 14, 2010, the Commission directed the Company to send a letter to its irrigation customers prior to May 1, 2010, describing the new Schedules 25 and 26 and scheduling a meeting with its irrigation customers for the purpose of explaining, inter alia, how the schedules operate and how the rates were calculated and providing a full understanding of the possible consequences of adopting a particular schedule.  We also directed that a customer making a selection prior to the date of the customer meeting shall not be bound by his initial election.  The meeting must include a Commission staff member.

 

141.     Based upon the above rate design and rate spread findings the Company is directed to file compliance tariffs that recover the approved revenue requirement from the various customer classes as follows:

 

Rate Class

Revenue Increase

$

%

Residential Service

   Rate 10

   Rate 11

 

1,113,404.00

10,968.00

1,124,372.00

 

10.1%

  2.8%

9.9%

Small General Service

   Rate 20

   Rate 22

 

 

803,672.00

       348.00

804,020.00

 

21.5%

  2.9%

21.4%

Irrigation Service

   Rate 25

   Rate 26

 

23,950.00

new tariff: insufficient data[7]

 

9.2%

Large General Service

   Rate 39

 

726,901.00

 

15.8%

Lighting

   Rate 24

   Rate 41

 

(29,889.00)

2,525.00

(27,364.00)

 

-34.9%

3.0%

-16.1%

Total Wyoming Electric

2,651,879.00

13.1%

 

Tariff Revisions

 

142.     The Commission finds OCA has supported the use of separate demand and energy components for purchased power and fuel recovered under the PSCA mechanism.  On rebuttal, Aberle provided an alternative proposal to collect the demand charges associated with the power purchase agreement from the cost of service component of each rate with only the prospective changes in the demand component billed through the energy charge, stating the demand costs do not fluctuate significantly from year to year.  The Commission finds the base cost of power supply, including the demand, energy and transmission components are those established in this case as a result of the Commission’s determinations.  The demand and transmission components that change as a result of changes to MDU’s power purchase agreement, and filed under the Company’s PSCA tariff pursuant to Commission Rule Sections 249 and 250, will be reflected in the energy or demand components, as applicable, and will be allocated to the primary and secondary service customer classes.

 

            143.     The Commission further finds OCA has supported its recommendation that the use of the term “Base Rate” in all applicable retail rate schedules be replaced with the term “Basic Service Charge,” as it will eliminate confusion that currently arises from the use of the term “base rate” in other contexts in the calculation of various rates.

 

Power Supply Cost Adjustment (PSCA) Mechanism

 

            144.     In its initial testimony, OCA proposed a revised PSCA mechanism which would accommodate the purchased power and fuel costs associated with MDU’s interest in Wygen III.  OCA argued that Commission Rule Sections 249 and 250, which provide for the recovery of commodity and commodity-related costs by utilities that purchase all their power requirements from a wholesale provider, do not provide for the recovery of accumulated production costs from self-generation and the subsequent passing of them on to customer.  Zamora stated these production costs are usually addressed at the time base rates are computed in a general rate case.  (OCA Exhibit No. 209, p. 33.)  She recommended the adoption of a revised PSCA mechanism that incorporates a dead band and sharing mechanism as more fully described in the summary of her testimony, above.  The Company argued that its current PSCA tariff language would accommodate its partial self-generation status and that Rules 249 and 250 do not preclude recovery of production or fuel costs.  The Company further disagreed with the incorporation of the dead band and the sharing mechanism as proposed by the OCA.  (Tr., pp. 748-754.)  As shown in the Stipulation at ¶ 26, the Company and OCA negotiated a revision to the PSCA mechanism consistent with OCA’s proposal of incorporating a dead band and sharing mechanism.  The Commission rejected the Stipulation, and with it, the above-described mechanism.  We therefore infer that MDU retains its initial opposition to OCA’s revised PSCA mechanism. 

 

            145.     The Commission finds OCA’s proposal of a revised PSCA mechanism which incorporates a dead band and a sharing mechanism falls under the innovative and non-traditional ratemaking provisions contained in W.S. § 37-2-121, which states in part:

 

Any public utility may apply to the commission for its consent to use innovative, incentive or nontraditional rate making methods.  In conducting any investigation and holding any hearing in response thereto, the commission may consider and approve proposals which include any rate, service regulation, rate setting concept, economic development rate, service concept, nondiscriminatory revenue sharing or profit-sharing form of regulation  and policy, including policies for the encouragement of the development of public utility infrastructure, services, facilities or plant within the state, which can be shown by substantial evidence to support and be consistent with the public interest.

 

This statute sets up a mechanism whereby it is the utility which must apply for innovative, incentive or nontraditional rate making methods.  The Commission is limited to consenting (or not) based on substantial evidence that the public interest is thereby served.  MDU has neither applied for nor proposed the adoption of OCA’s revised PSCA mechanism.  The Commission finds that we are precluded under W.S. § 37-2-121 from imposing such a mechanism on the Company.  MDU may make such a filing in the future.  However, the Commission advises the Company that it will not be receptive to a filing under Rule Sections 249 and 250 which seeks recovery of items or costs for which we have not previously allowed recovery under these Rules.

 

Net Metering Tariff

 

146.     In response to the Commission’s inquiry regarding the need for an updated calculation of the Company’s avoided cost for purposes of its net metering tariff, the Company expressed its belief that the Company’s avoided cost would not change as a result of its acquisition of an interest in Wygen III in meeting its load requirements.  Aberle argued the Company’s current avoided cost is based on its Black Hills PPA.  Any power needed over and above its Wygen III production will be purchased under the PPA; and this, she offered, establishes the marginal cost MDU avoids.  (Tr., p. 335.)  Aberle subsequently conceded the inclusion of the generation costs of Wygen III in its avoided cost calculation would result in a decrease in its current avoided costs.  (Tr., pp. 338, 344-345.)  We note that, when the MDU system is not utilizing its entire share of Wygen III’s output, and a net metering customer is producing electricity, MDU avoids nothing with reference to the PPA.  The Commission finds the evidence of record clearly supports the need for the Company to recalculate its avoided cost and submit a revised net metering tariff.  The Company is directed to submit its proposed revised avoided cost and net metering tariff for Commission consideration within sixty (60) days of the issuance of this Order.

 

Conclusions of Law

 

147.     MDU is duly authorized by the Commission to provide retail electric public utility service in its Wyoming service territory under certificates of public convenience and necessity issued by the Commission.  MDU is an electric public utility as defined in W.S. § 37-1-101(a)(vi)(C); and, as such, the Commission has the general and exclusive jurisdiction to regulate MDU as a public utility in Wyoming under W.S. § 37-2-112.

 

            148.     Proper public notice of these proceedings was given in accordance with the Wyoming Administrative Procedure Act, W.S. § 37-2-203 and the Commission’s Rules, especially Section 106 thereof.  The public hearings were held and conducted pursuant to W.S. §§ 16-3-107, 16-3-108, 37-2-203, and applicable sections of the Commission’s Rules.  The intervention petition of the City of Sheridan was properly denied.  Intervenor OCA became a party to the case for all purposes.

 

149.     The Commission concludes, based on its findings above, that the offered Stipulation must be rejected as not being in the public interest.

 

            150.     The preponderance of the evidence of record, as shown in the Commission’s findings above, supports the Commission’s conclusion that MDU’s current rates for electric service are inadequate and unremunerative, and should be increased in the amount of $2,651,565 per annum, the same to be effective for usage on and after May 1, 2010.

 

151.     The Commission concludes an overall rate of return on rate base of 8.25%, based upon a reasonable return on equity of 10.0%, for MDU’s Wyoming electric utility operations is just and reasonable and in the public interest.  We conclude that these rates satisfy the capital attraction standards of the Hope and Bluefield cases, discussed, supra.

 

152.     The Commission further concludes the rates approved herein will allow MDU to continue to provide adequate, safe and reliable service.  The rates approved herein are just and reasonable, and the recovery of the rates pursuant to the rate spread and rate design adopted herein will not result in undue discrimination as between customer classes because they are based on the respective cost of serving each customer class consistent with the provisions of W. S. § 37-3-112.

 

153.     The Commission concludes the tariff modifications approved herein are supported by the preponderance of the evidence of record and should be approved as being in the public interest.

 

IT IS THEREFORE ORDERED:

1.         Pursuant to the Commission’s deliberations held on April 14, 2010, Montana-Dakota Utilities Co. is authorized to implement a general electric rate increase of $2,651,565 per annum, effective for usage on and after May 1, 2010, and done in the manner approved hereinabove.

2.         Based on the Commission’s deliberations, MDU filed compliance tariffs to reflect the approved general rate increase, the rate spread, the rate design and the tariff modification findings set forth above.  The compliance tariffs were approved by open meeting action taken on April 27, 2010, to be effective for service rendered on and after May 1, 2010.

3.         The Company is directed to refile its updated depreciation studies within thirty (30) days of the issuance of this Order for consideration in a separate docket.

4.         The Company is directed to submit its proposed revised avoided cost and net metering tariff for Commission consideration within sixty (60) days of the issuance of this Order. 

 

5.         With its compliance tariff filing, the Company submitted a proposed letter to Irrigation customers as described above in ¶ 140.  Having directed several needed revisions to draft letter notice, the Commission directs that the Company use the revised letter and shall hold the scheduled informational meeting as directed by the Commission.

 

6.         This Order is effective immediately.

 

MADE and ENTERED at Cheyenne, Wyoming, on May 26, 2010.

 

                                                            Public Service Commission of Wyoming

 

 

                                                                                                                                               

                                                            ALAN B. MINIER, Chairman

 

 

                                                                                                                                               

                                                            STEVE OXLEY, Deputy Chairman

 

 

                                                                                                                                               

(SEAL)                                               KATHLEEN A. LEWIS, Commissioner

Attest:

 

 

                                                                                   

DAVID J. LUCERO, Assistant Secretary



[1] The Commission’s concerns regarding Gaske’s credibility were further underscored by his willingness to testify under oath about an unrelated issue based on a text message received by another person in the hearing room.  (Tr., pp. 732-736.)  The Wyoming Administrative Procedure Act does not prohibit the Commission, as a learned tribunal, from accepting hearsay evidence, but, in this instance, acceptance would be far enough beyond what is reasonable that it would undermine the Commission’s process.

[2]  The Commission ordered no change from present practice.

[3]  Includes Interest Synchronization

[4]  The federal income tax gross-up factor.  See discussion directly above this table.

 

[5] Rate Schedule 26 offered in the Stipulation

[6] Rate Schedule 25 offered in the Stipulation

[7] Rate 26 is newly created.  There is therefore no “revenue increase” for this class and no data upon which to base a percentage of increase.  See the discussion of the rates for this class at ¶ 139.