-BEFORE THE PUBLIC SERVICE COMMISSION OF UTAH-

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ISSUED: December 30, 2002

SYNOPSIS

The Commission increases Questar Gas Company's annual revenue requirement by $11,162,650. The revenue requirement is based on an allowed rate of return on equity of 11.2 percent.

TABLE OF CONTENTS

APPEARANCES iv

I. BACKGROUND AND PROCEDURAL HISTORY 1

II. TEST-YEAR REVENUE REQUIREMENT 2

A. REVENUE ISSUES--GENERALLY 2

Stipulation and Settlement 2

Stipulation Structure 3

Test Year 3

4. General Method for Determining Utah Revenue Deficiency 4

B. UNCONTESTED ISSUES 4

New Customer Adjustment 4

Unqualified FT-2 Customers 5

2002 Imputed Revenues for Industrial Customers 5

Capital Budget Adjustment 5

Banked Vacation 6

Phantom Stock 6

Advertising Expense 6

Y2K Amortization 6

Annualizations 7

2001 Property Insurance 7

Miscellaneous Adjustments 7

Closure of Cedar City Office 7

Distrigas Allocation 8

Tax Rate Update Adjustment 8

Incentive Compensation 8

Labor Annualization 8

Usage Per Customer 9

Section 29 Tax Credits 9

C. SETTLED ISSUES 10

Bad-debt Ratio 10

Gain on Sale of Property 11

Research & Development Delta Funds 11

4. Agents Fund 11

Postage 11

AGA Dues 12

Salary of Loaned Executive 12

Restricted Stock 12

Advertising Adjustment 12

Dues, Donations and Lobbying 13

Test Year 13

D. LOW-INCOME WEATHERIZATION 13

E. IMPUTED INCOME TAX CALCULATION 15

F. COST OF CAPITAL 15

Positions of the Parties 16

Discussion, Findings and Conclusions: Return on Equity 19

Overview 19

Business and regulatory risk 21

Comparable or proxy companies. 26

Mean v. median 28

Financial Model Analysis 29

Role of other financial models 32

The range of reasonable rates of return and the allowed return on equity
34

Discussion, Findings and Conclusions: Capital Structure, Overall Rate of Return 35

Addition of short-term debt to capital structure 35

Financial, or capital structure, risk 37

Capital structure and rate of return on investment 38

G. ADJUSTED TEST YEAR REVENUE-REQUIREMENT SUMMARY 38

III. ALLOCATION AND RATE-DESIGN ISSUES 40

A. ALLOCATION AND RATE-DESIGN TASK FORCE 40

B. REVENUE-REQUIREMENT ALLOCATION 42

C. RATE-DESIGN REVISIONS 43

Transportation Administrative Charge 43

Basic Service Fee 43

D. MAIN AND SERVICE-LINE CONTRIBUTIONS 43

The Proposed Changes 44

Conclusion on Line Extensions. 45

E. CO₂ EXPENSE RECOVERY 45

Background 45

The Settlement Proposal 47

Conclusion on CO₂ Cost Recovery 48

IV. DEMAND-SIDE MANAGEMENT 48

V. SERVICE STANDARDS REPORTING 49

APPENDIX 1. Revenue Requirement Stipulation and Settlement

Settlement Exhibit 1 (See Email Attachment)

Settlement Exhibit 1U (See Email Attachment)

APPENDIX 2. Allocation and Rate-Design Stipulation and Settlement

Settlement Exhibit 2 (See Email Attachment)

Settlement Exhibit 3 (See Email Attachment)

APPENDIX 4. Service Standards Stipulation and Settlement

APPENDIX 5. Summary of Adjusted Distribution Non-gas Results of Operations

APPEARANCES:

Gary G. Sackett                                             For             Questar Gas Company
Jones, Waldo, Holbrook & McDonough

Jonathan M. Duke                                             "             Questar Gas Company
Questar Corporation

Michael L. Ginsberg                                         "              Division of Public Utilities
Assistant Attorney General

Reed T. Warnick                                              "              Committee of Consumer Services
Assistant Attorney General

Gary A. Dodge                                                 "              Utah Association of Energy Users
Hatch, James & Dodge

Steven F. Alder                                                "              Utah Energy Office
Assistant Attorney General

Captain Robert C. Cottrell, Jr.                       "              United States Executive Agencies
Attorney at Law

Bruce Plenk                                                     "             Salt Lake Community Action Program,
Attorney at Law                                                              Crossroads Urban Center, and Utah                                                                                             Legislative Watch

On May 3, 2002, Questar Gas Company ("QGC," "Questar Gas" or the "Company") filed an Application to increase annual distribution non-gas revenues by $23,017,000 or 5.65 percent. Distribution non-gas ("DNG") revenues recover about 41 percent of the Company's total costs; the remaining 59 percent is recovered through Account 191 by means of separate gas-cost pass-through proceedings.

On May 28, 2002, a hearing was held to consider the appropriate test year to be used in this docket. On May 31, 2002, the Commission issued an Order on Test Year and deferred determination of the appropriate test year to the hearing to be held in October in order to allow the participants an opportunity to obtain evidence and develop their respective positions on the appropriate test year and adjustments.

On June 24, 2002, intervention was granted to Salt Lake Community Action Program ("SLCAP"), Crossroads Urban Center ("CUC"), Utah Legislative Watch ("ULW") and the Utah Energy Office ("UEO"). On July 8, 2002, intervention was granted to American Pacific Corporation and Western Electrochemical Company.

On July 23, 2002, intervention was granted to the United States Executive Agencies ("USEA"). On August 2, 2002, intervention was granted to the Utah Association of Energy Users ("UAE"), Deseret Power, L.P. and US Magnesium LLC. On August 21, 2002, intervention was granted to the Industrial Gas Users Group ("IGU").

Questar Gas, the Division of Public Utilities ("Division"), the Committee of Consumer Services ("Committee"), UAE, USEA, IGU, US Magnesium, UEO, and the SLCAP/CUC/ULW filed extensive written testimony and exhibits prior to hearings held on October 17, 18 and 21, 2002. Public witnesses were heard October 21, 2002. After the close of the hearings, the Commission requested that the Company late-file an exhibit containing additional information on rate of return. This was filed on October 31, 2002. QGC also submitted a late-filed exhibit on November 14, 2002, consisting of the Moody's Investor Services rating action for Questar Corporation and its subsidiaries that was issued just after the close of the hearings.

On November 12, 2002, the Company, the Division, the Committee, the UAE group, and SLCAP/CUC/ULW filed post-hearing briefs. The Company, Division and Committee filed reply briefs on November 25, 2002.

A. REVENUE ISSUES--GENERALLY

1. Stipulation and Settlement

At the outset of the hearings on October 17, 2002, the Company, the Division and the Committee submitted a Revenue Stipulation and Settlement ("Stipulation No. 1" or the "Revenue Stipulation") for consideration by the Commission. (For purposes of the discussion in this Part II only, "the Parties" will refer to the Company, the Division and the Committee.) The Revenue Stipulation constituted a comprehensive settlement of all revenue issues except the cost of common equity and the capital structure to be used to calculate the overall rate of return to be applied to the Company's rate base. This stipulation was unopposed by the other parties in the case.

2. Stipulation Structure

As detailed in the Revenue Stipulation, the Parties have agreed on adjustments to the Company's original filing that are separated into two categories. First, a group of issues was settled on an individual basis; these are denominated "Uncontested Issues," or Group I issues. Second, the stipulation designated as Group II issues those that were not resolved among the Parties item-by-item, but for which an overall adjustment was agreed to.

Thus, the adjustment values for each of the undisputed and settled issues discussed below are relative to the values that were set forth in the Company's original filing, which had sought a total annual Utah revenue deficiency of $23,017,000. Further, each of the values below represents an adjustment to the annual revenue requirement attributable to the Company's Utah service territory.

3. Test Year

The Revenue Stipulation is based on a test year consisting primarily of the 12 months of calendar 2002. QGC structured its initial filing to begin with the Company's fully adjusted year-end 2001 Results of Operations and then made a variety of adjustments to reflect the conditions the Company believed were representative of calendar year 2002. Although the Parties reached no definitive agreement on the test year to be used in the case, the Revenue Stipulation sets forth adjustments that represent the Parties' agreement on rate-making elements based primarily on calendar year 2002, as discussed in more detail below.

4. General Method for Determining Utah Revenue Deficiency

Beginning with Docket No. 93-057-01, Utah DNG revenues for the test year have been determined by using a computer model that was developed in that docket. This model begins with the Company's unadjusted, system-wide results of operations for a designated 12-month period, presented in detail by account under the Uniform System of Accounts adopted previously by the Commission. As applied to this case under the Revenue Stipulation, the model has produced a revenue deficiency for the test year by incorporating the various adjustments from the Company's original filing, as modified by the terms of the Revenue Stipulation and the cost of equity capital and capital structure discussed in Part II.D below.

The model used to determine the revenue requirements uses system-wide data for the costs and revenues, along with assignments and allocations to develop the Utah DNG revenue requirements discussed in the following sections and set forth in Appendix 5 to this Order.

B. UNCONTESTED ISSUES

We approve the adjustment for Group I issues set forth in Stipulation No. 1. The following are brief descriptions of those adjustments.

1. New Customer Adjustment (line 2⁽¹⁾)

The revenues from three customers who are receiving natural gas for the first time in 2002 are annualized. This adjustment reduces the revenue deficiency by $149,000.

2. Unqualified FT-2 Customers (line 3)

This adjustment accounts for additional revenues from customers who have migrated or will migrate to the GS-1 and F-1 rate schedules because their load factors no longer qualify for Rate Schedule FT-2 status. This adjustment reduces the revenue deficiency by $89,000.

3. 2002 Imputed Revenues for Industrial Customers (line 4)

This adjustment reflects expected increased transportation volumes of two large industrial customers during 2002 by imputing additional revenues of $228,000 in the test year.

4. Capital Budget Adjustment (lines 6-10)

The Parties agreed to adjust the Company's test-period rate base and depreciation expense to reflect a reduction in the 2002 Questar Gas capital budget. This budget reduction occurred after the Company's May 3, 2002, filing. The effects of these adjustments on the revenue deficiency are:

(a) a decrease of $2,832,000 resulting from a reduction to Gas Plant in Service (Account 101);

(b) a $29,000 decrease due to an adjustment to Wexpro-related plant (Account 101);

(c) an offsetting increase of $780,000 from adjustments to Accumulated Depreciation (Account 108) and Deferred Taxes (Account 282);

(d) a reduction of $475,000 due to the related reductions in Depreciation Expense (Account 403).

The aggregate effect of these adjustments is to reduce the revenue requirement by $2,556,00 0.

5. Banked Vacation (line 11)

QGC's employees can accrue up to one year's worth of vacation and carry it forward. Because the allowed vacation in each year is included in the labor overhead of that year, the "banked" vacation represents compensation for work performed and not yet paid for. In the Company's original filing, an adjustment was made to reduce rate base by the year-end banked vacation balance. The Parties agreed to use a 13-month average for this account balance. This adjustment reduces the test-period deficiency by $9,000.

6. Phantom Stock (line 12)

In the Company's original filing, an adjustment was made to remove the effect on expenses during the test year of required quarterly "mark to market" entries related to phantom stock (previously issued, unexercised stock options). To properly reflect the test-year quarterly entries, an adjustment was made that decreased the revenue deficiency by $213,000.

7. Advertising Expense (line 13)

This $127,000 adjustment makes corrections to the Company's originally filed position regarding informational advertising expenses.

8. Y2K Amortization (line 14)

In Docket No. 99-057-20, the Commission-approved stipulation included a three-year amortization of certain Y2K expenses. During 2001, the amortization of deferred Y2K costs was recorded on the books of QGC. The Parties agree that the Y2K adjustment made by the Company in the 2001 Results of Operations results in a double-counting of these costs, and the removal of the expenses booked during 2001 results in a reduction of the revenue deficiency by $532,000.

9. Annualizations (lines 15, 16, 17, 19, 20)

Expenses incurred for software maintenance fees and rent were annualized to reflect changes that occurred during the test-year. This group of annualization adjustments decreases the revenue deficiency by $435,00 0.

10. 2001 Property Insurance (line 18)

The Parties have agreed that the increases in property insurance premiums that occurred in November 2001 and are attributable to QGC should be annualized. This annualization adjustment increases the revenue deficiency by $411,000.

11. Miscellaneous Adjustments (lines 21, 22, 23, 27)

During the course of the audit of the Company's records in this proceeding, the Parties identified and have agreed to various adjustments to correct several accounting entries involving intracorporate allocations, prior-period expenses, misclassifications and other miscellaneous items. The aggregate of these adjustments decreases the revenue deficiency by $880,000.

12. Closure of Cedar City Office (line 24)

In February 2002, Questar Gas closed its Cedar City office and relocated these operations to a smaller facility. The rate-base effect of this move has been included in the stipulated rate base value, and the corresponding reduction in operating expenses results in a decrease to the revenue deficiency of $34,000.

13. Distrigas Allocation (lines 25, 26, 29, 30)

The Distrigas formula has been adopted by the Commission as a reasonable method for allocating Questar Corporation common costs to subsidiaries and to allocate common Questar Regulated Services costs among Questar Pipeline Company, Questar Energy Services and Questar Gas. The Parties agreed to update the allocation formulas to reflect test-year changes and to true-up the allocations for the 2002 test year. This adjustment reduces the test-period revenue requirement by $241,000.

14. Tax Rate Update Adjustment (line 32)

The Company proposed a combined federal and state corporate income tax rate of 38.02491 percent in its application. The Parties agreed to update this rate to 38.03400 percent to incorporate the most recent effective combined federal and state income tax rates. This increases the revenue deficiency by $13,000.

15. Incentive Compensation (line 31)

Questar Gas sought recovery of incentive compensation paid to employees based on company attainment of goals related to safety, customer satisfaction, capital productivity and operating productivity during 2001. The Company also incorporated an overhead rate of 33.77 percent. The Division proposed an overhead rate of 26.69 percent. The Parties stipulated to an overhead rate of 30.62 percent and the removal of the payout related to the capital-productivity goal. The combination of these changes decreases the test-period revenue requirement by $280,000.

16. Labor Annualization (line 35)

The Company's application included expenses for employees the Company expected to hire. The Parties agreed to remove expenses associated with projected employees who had not been hired by the end of the test year. This adjustment reduces the revenue deficiency by $445,000.

17. Usage Per Customer (line 36)

The Parties agreed to adjust the test-year revenues to reflect the temperature-adjusted Utah GS-1 usage per customer as of November 30, 2002. The usage data and related test-year revenues were filed with the Commission in QGC's settlement compliance filing on December 11, 2002. The updated information established an average annual GS-1 usage per customer of 115.51 Dth, 0.65 Dth lower than included in the Company's original filing. This increases the revenue requirement by $599,000.

18. Section 29 Tax Credits (line 37)

Certain gas-production tax credits under IRC § 29 have been available to the Company for several years and will expire at the end of 2002. Energy legislation had been pending in Congress that could have continued, modified or replaced the credits in some form. The Parties agreed that the final order in this case should reflect any enacted legislation concerning such tax credits. The 107^th Congress adjourned without passing any such legislation. The effect of this Congressional inaction is to leave the revenue requirement unchanged.

19. 2002 Property Insurance (line 38)

The premiums for QGC's property insurance are negotiated and finalized in November of each year for coverage applicable to the following year. Under the Revenue Stipulation, the Parties agreed to adjust test-period expenses for premium increases negotiated in November 2002 for coverage beginning November 1, 2002. The initial estimate of the increase to the deficiency related to this expense and reflected in the Revenue Stipulation was $614,000. Under the terms of the stipulation, QGC made a compliance filing on December 11, 2002 to provide the updated insurance-premium information. This increases the revenue requirement by $104,000 relative to the Company's original filing and is $510,000 lower than reflected in the Revenue Stipulation.

C. SETTLED ISSUES

The Parties identified 11 issues that were not settled individually, but instead were aggregated for settlement purposes. The aggregate adjustment of Group II issues reduces the revenue deficiency originally filed by the Company by $485,000. The following discussion of these 11 issues sets forth a brief statement of the positions of the individual parties. Because we approve and adopt the provisions of Stipulation No. 1, as discussed below, we do not find it necessary to decide each individual issue.

1. Bad-debt Ratio (line 42)

The Company's original filing applied a bad-debt expense ratio of .9 percent to revenues to calculate the test-year bad-debt expense. The Division recommended a ratio of .7 percent to match the ratio allowed in Utah Power's last general rate case. This would reduce the revenue deficiency by $421,000. The Committee concurred with this adjustment. In its rebuttal filing, the Company updated its bad-debt expense to 1.1 percent of revenues to correspond to the most recent information regarding this expense. This would increase the revenue deficiency by $421,000 over the Company's original filing.

2. Gain on Sale of Property (line 43)

The Division and Committee both proposed that gains on sale of utility property accrue to customers rather than shareholders. This adjustment would decrease the revenue deficiency by $313,000. The Company took the position that these gains should not be credited to customers' rates.

3. Research & Development Delta Funds (line 44)

Research and development expenses are subject to a transition from interstate pipeline rates to QGC's rates over a five-year period pursuant to our order in Docket No. 99-057-20. The amount QGC actually spent in 2001 was less than the amount transferred from interstate pipelines. The Division proposed that the revenue deficiency be reduced by $57,000 to account for this difference. The Committee did not recommend an adjustment. 

4. Agents Fund (line 45)

The Committee and the Company agreed to this $47,000 adjustment to the revenue deficiency as a prior-period expense. The Division did not take a position on this adjustment.

5. Postage (line 46)

The Committee proposed to adjust the Company's postage expense by $332,000 to exclude an allocation of affiliate and Olympics-related mailing-envelope insert costs from the previous year. The Company disagreed with this adjustment, asserting: (a) the Company now charges subsidiaries the embedded cost of any mailing, and (2) Olympics inserts will not recur in the rate-effective period. The Division proposed a $40,000 reduction for postage for affiliate inserts.

6. AGA Dues (line 46)

In its original application, the Company removed the lobbying portion of the American Gas Association ("AGA") dues. The Committee proposed to remove additional governmental-affairs-related costs from the AGA dues for which the Company sought recovery. The Company disagreed with this adjustment, arguing that the AGA's "governmental affairs" activities include costs that were previously approved by the Commission and that are beneficial to customers. The Committee's proposed adjustment would decrease the revenue deficiency by $24,000. The Division did not propose an adjustment.

7. Salary of Loaned Executive (line 48)

QGC loaned an executive during the test-period to spend time working for the Economic Development Corporation of Utah and takes the position that these are proper costs of doing business. The Committee proposed to remove this cost, which would decrease the revenue deficiency by $63,000. The Division made no adjustment.

8. Restricted Stock (line 49)

Restricted stock benefits were offered as an employment incentive to Questar Corporation's new Chief Executive Officer. This benefit, which has a three-year life, was partially allocated to Questar Gas and 1/3 of the allocation was included in the Company's application. The Division and Committee both proposed to remove this test-period expense and reduce the revenue deficiency by $202,000.

9. Advertising Adjustment (line 50)

The Company and Division agreed to additional minor advertising adjustments that reduced the revenue deficiency by $17,000. The Committee proposed to disallow $70,000 of additional financial advertising expenses that the Company believes are reasonable business expenses and have previously been allowed by the Commission.

10. Dues, Donations and Lobbying (line 51)

During the discovery phase of this case, certain lobbying expenses were identified that had been incorrectly accounted for as recoverable expenses. The Company agreed to remove these expenses and reduce the revenue requirement by $92,000. In addition, the Division and Committee proposed to remove various other items, primarily dues, donations and expenses related to economic development. These adjustments would reduce the revenue deficiency by $185,000 and $132,000, respectively. The Company argued that these are reasonable business expenses that should be recovered in rates.

11. Test Year (line 52)

The Company and the Division agreed to use the year-end 2002 rate base and revenues based on the year-end number of customers in determining the annual revenue requirement. The Committee proposed that, for a 2002 test year, average rate base and revenues based on average number of customers throughout the test year should be used. This adjustment to average test year would increase the test-year revenue requirement by $33,000.

D. LOW-INCOME WEATHERIZATION

In Docket No. 99-057-20, the SLCAP and the CUC proposed for the first time a low-income weatherization program that would make available $250,000 to weatheri ze the residences of low-income customers. The funds, which would come from QGC's general rates, supplement efforts of the Utah Department of Community and Economic Development, reduce the energy burden of participants, promote cost-effective energy conservation and leverage federal funds to meet requirements of federal law. In that docket, we concluded that customer funding of the proposed weatherization program was in the public interest and allowed for its recovery in general rates.

In this docket, witnesses for SLCAP, CUC and ULW proposed that the original annual funding of $250,000 be increased to $500,000. In the Allocation and Rate-Design Stipulation and Settlement submitted by all active parties in the case (and described in more detail in Part III below), "The Parties either support or do not oppose the proposed increase from $250,000 to $500,000 in low-income weatherization assistance as proposed."

While we acknowledge the value of the weatherization program, we are hesitant to double the funding for it. When we authorized the original funding of $250,000 in Questar's last rate case, there was a question about federal funding for the program. It appeared there was a matching requirement of non-federal funds. Apparently, that is no longer true. Based on the evidence on this record, the federal Department of Energy (DOE) increased funding to the Department of Community and Economic Development's (DCED) from $1.4 million to $2 million, though the DOE gave DCED additional responsibilities.

We believe it is too soon to conclude that additional state funds are necessary. We are not willing to consider doubling the funding in every subsequent Questar rate case and, therefore direct the DSM task force established by this order to study the optimal state funding for this program. In addition, we encourage DCED to take up additional state funding for weatherization with the state legislature.

Accordingly, we will authorize Questar Gas to file DNG rates to reflect $250,000 in its annual Utah revenue requirement, such rates to be designed in accordance with the findings and conclusions set forth in Part III below.

E. IMPUTED INCOME TAX CALCULATION

Test-year income taxes are calculated on the basis of adjusted test-year results in which the deduction for interest expense is obtained as the product of weighted cost of debt and the adjusted rate base. This method of determining interest expense is often referred to as "interest synchronization." Income taxes are calculated using a federal income tax rate of 35 percent and an effective Utah state income tax rate of 5 percent. In the computer model of the Company's Results of Operations, each of the adjustments discussed above has an associated income tax effect. This adjustment is the difference between the calculated test-year income taxes and the sum of income taxes reported on an unadjusted basis and the income taxes associated with all previous adjustments. It has been used in the Company's previous general rate cases and is undisputed in this case. It increases system income taxes by $4,207,879.

F. COST OF CAPITAL

The current allowed rate of return on common equity, 11 percent, was established by Commission order of August 11, 2000, in Docket No. 99-057-20. To aid the Commission's examination of the adequacy of this rate, as well as the capital structure to be used in determining overall return on investment, Questar Gas presents the direct and rebuttal testimony of J. Peter Williamson and, on capital structure, that of David Curtis. The Division presents the direct and surrebuttal testimony of William A. Powell; the Committee, the direct and surrebuttal testimony of David C. Parcell. Post-hearing briefs on these subjects were filed November 12, 2002, by Questar; the Division; the Committee; the UAE Intervention Group; and Salt Lake Community Action Program, Crossroads Urban Center, and Utah Legislative Watch (collectively, the Utah Ratepayers Alliance). Reply briefs were filed November 25, 2002, by Questar, the Division, and the Committee.

Questar Gas. In its direct testimony, the Company argues for an increase in the allowed rate of return on equity to 12.6 percent from the current 11 percent. This position is developed using a Discounted Cash Flow (DCF) financial model analysis of nine gas distribution and diversified gas companies selected, for risk characteristics similar to Questar Gas's, from Value Line Investment Service reports. The DCF estimate of cost of equity for each of these "proxy" companies depends upon a selection of stock price, dividend yield, and expected growth rate for each company. The Company uses forecasts of earnings growth, published by IBES International, Inc. ("IBES") and Value Line Investment Survey ("Value Line"), to estimate growth rates.

The mean and the median of the DCF estimates for the nine-company sample are examined. Questar Gas concludes that the median is the better indicator of appropriate sample values. With Value Line earnings growth forecasts, the median of the sample is 13.8 percent; the mean, 13.77 percent. Using IBES earnings growth forecasts, the median is 11.68 percent and the mean is 11.23 percent. An internal growth, or retained earnings, method is also used to ascertain a third estimate of earnings growth for the nine companies. It yields a median of 12.36 percent and a mean of 11.62 percent. The average of the 13.8, 11.68, and 12.36 percent medians is 12.6 percent, the Company's rate-of-return request in this Docket.

Two other methods, the Capital Asset Pricing Model and a risk premium analysis, the former rejected for reason of statistical deficiency, were examined, found to support the request, but not relied upon. A comparison of financial or capital structure risk, based on the Company's proposed 52.6 percent equity ratio, to that of the proxy companies, is offered in support of 12.6 percent as the proper rate of return on equity.

On rebuttal, more recent stock prices, dividends, and growth forecasts were examined. Retracing the above steps with this data gives 12.46 percent as the average of the three medians.

The Division. The Division reaches its recommendation using the same nine-company sample that Questar Gas employs, with a similar reliance on the DCF. In addition, the Division employs an alternative form of the DCF model called the Terminal Value Model (TVM). Instead of the sample median, however, the Division employs the mean, and in place of the Company's sole reliance on earnings forecasts as the estimator for the DCF model's growth variable, the Division employs dividend and earnings forecasts produced by Value Line and earnings forecasts produced by Zacks Investment Research ("Zacks"). As a number of earnings forecasts are available from these sources, the Division applies them on a weighted basis. Sample DCF results range from a low of 7.2 percent (based on Value Line's dividend growth forecast) to a high of 12.3 percent (based on the TVM). These results are averaged to produce the Division's recommended allowed rate of return on equity of 10.5 percent. Questar Gas's proposed capital structure is accepted.

The Committee. Using DCF, Capital Asset Pricing Model, and Comparable Earnings methods, applied to three groups of proxy companies - the nine-company Questar Gas group, the Moody's gas distribution group, and the Value Line natural gas distribution industry group - the Committee's cost of equity estimate for gas distribution utilities ranges from 9.5 percent to 11 percent. For the DCF, the growth variable for each company is estimated as an average of five data sets: five-year historic retention growth; projections of retention growth; an average of the five-year historic growth of earnings per share, dividends per share, and book value per share; an average of projected earnings per share, dividends per share, and book value per share; and analysts' (First Call) projections of earnings per share. The Committee argues that Questar Gas's business and financial risk are each below the average for gas distribution utilities. Because of lower risk, which the Committee asserts is due to regulatory mechanisms such as a gas balancing account and a weather normalization clause, to company owned production, to its position as the only gas distribution company in the state, and to its higher capital structure equity ratio, Questar Gas's cost of equity, concludes the Committee, is in the range of 9.5 percent to 10.5 percent. The recommendation is an allowed rate of return on equity of 10 percent.

The Committee also recommends a different capital structure than that proposed by the Company. It would add short-term debt in the amount of 10.28 percent to the capital structure, at a cost of 2.27 percent, thereby reducing the weight given the long-term debt and common equity components.

Discussion, Findings and Conclusions: Return on Equity

Overview

We are guided by U. S. Supreme Court decisions in the Hope (FPC v. Hope Natural Gas Company, 320 US 591 (1944)) and the Bluefield (Bluefield Water Works v. PSC, 262 US 659 (1923)) cases. From them, we learn that our rate-of-return decision should give investors the opportunity to earn a return on an investment in the Company comparable to the return the investor might earn in other investments of similar risk, and it should be a return sufficient to attract capital on reasonable terms and to maintain a financially viable utility. This points to the importance of an analysis of risk, and to the selection of comparable companies for that purpose. Investors' required return, the opportunity cost of capital, is thus the utility's cost of capital.

In prior rate-of-return decisions, this Commission has been concerned to state that rate-of-return analysis is a subjective exercise, even though use of financial models conveys an appearance of objectivity. Applying these models requires judgment at each important step and with this role for judgment comes the possibility of bias. We repeat this here not as criticism but to indicate how important it is for us to ascertain that each witness's judgments are finely and carefully made. Considered in this light, financial model analysis will provide a good framework for analysis and a useful means of organizing relevant information, but not objective cost-of-equity estimates. Assessment of other, including qualitative, information is necessary. (Bluefield, directing the Commission to "exercise. . . fair and enlightened judgment, having regard to all relevant facts. . . ," and stating that, "A rate of return may be reasonable at one time, and become too high or too low by changes affecting opportunities for investment, the money market, and business conditions generally.")

Among financial models, we continue to favor, and nothing in the record suggests we should not, the DCF model. The theory upon which it is based is widely accepted, and the information required for model inputs is readily and publicly available. In this Docket, each witness mainly relies on the DCF, and employs other financial analyses to corroborate results. For example, though the Capital Asset Pricing Model makes an appearance here, we do not face arguments that it should be given analytical prominence such as this Commission has addressed in prior dockets. We do not mean to suggest that the DCF is without controversy. Indeed, witness selection of DCF inputs produces an unusually wide variation in cost-of-capital estimates in this Docket, and the record shows that 100 basis points in equity return is about $4.8 million in revenue requirement. DCF recommendations vary from 10.0 to 12.6 percent, a revenue requirement difference of $12.26 million. This illustrates our point about the need to assess witnesses' judgments carefully.

As in past deliberations, record evidence is used to define a range of reasonable equity return estimates. At the low end, the range is defined not simply by ratepayer interest in low-cost utility service but by possible confiscation of shareholder property. At the high end, the range is likewise not simply defined by shareholder interest in high returns on investment but by ratepayer interest in avoiding excessive rates; that is, rates based on no more than is required to meet the capital attraction, comparable risk, and utility financial viability standards. The allowed return, in short, must be reasonable, and it must be fair to shareholders and to ratepayers. Within this range, all returns are by definition reasonable.

Thus, we seek the cost of capital, or required return on equity, for the regulated gas distribution operations of the integrated Questar Corporation, that is, for Questar Gas Company, a business entity that does not issue common equity. Its cost of equity capital must be estimated indirectly by comparing it to companies, termed "proxy" companies, in the same line of business and having similar risk characteristics. Risk and return are directly, or positively, correlated. The record shows some disagreement among witnesses about the companies that should play this role. They also disagree about the consequences for equity return estimation of Questar's risk profile, that is, of its business and financial risk.

We turn first to a discussion of business risk because its regulatory risk aspect is central to Questar Gas's case. Financial risk, sometimes referred to as capital structure risk, since it depends upon the relative proportions of debt and equity in the capital structure, will be considered in a later section on capital structure.

Business and regulatory risk

Business risk arises from the supply and demand aspects of the operational environment of the utility. The business risk a public utility faces differs from that of other firms because little or no competition for the service it provides occurs in its service territory. Under normal conditions, its operating costs are predictable, and, given regulatory practices, its revenue stream stable. There is little expectation of earnings swings. In this Docket, however, the Company argues that the long-standing regulatory practice of using fully historical test years to determine revenue requirement is a continuing source of substantial risk.

Though it may be thought, and this Commission has so stated, that consistency in the application of regulatory principles and practices reduces regulatory risk, the Company asserts that it faces a damaging combination of declining use per customer of natural gas service and an increasing investment per customer, and both influences are exacerbated by high customer growth. Together with the ratemaking use of historical test years, the result is adverse regulatory lag in which rate base increases, revenues decline, and, unless offset by improvements in business efficiency, earnings decrease.

In raising the issue of regulatory lag as the source of regulatory risk and seeking a change in the Commission's test-year policy, the Company states that it is not asking for a premium on rate of return. (Transcript, p. 288.) In fact, the Company and the parties have reached a revenue requirement stipulation redressing in part the regulatory-lag effect of customer growth on earnings. We have accepted the Stipulation, and address its terms elsewhere in this Report and Order. For present purposes, we conclude, and the Company agrees, that the Stipulation reduces the adverse effects of regulatory lag and therefore regulatory risk. While the Company has not in consequence reduced the request for a 12.6 percent rate of return, its counsel proffers that a rate of return "in the high 11's," 11.75 percent is specifically mentioned, would now be something "we believe we and the investment community can work with." (Transcript, p. 529.) What this reveals is distinctly different from the Company's clear reliance on the results of its witness's financial modeling analysis as the basis of support for its requested 12.6 percent rate of return (updated on rebuttal to 12.46 percent). At hearing's close, in other words, the Company directly acknowledges the importance to our decision of a qualitative consideration of risk. The Committee describes this, and not without justification, as "a dis-connect between the evidence [the Company] originally presented to support its proposed return on equity. . . ." (Post-Hearing Brief, p. 5.) Reduction of risk may also have implications for the selection of comparable companies, particularly if there is record evidence to suspect that some of those used by witnesses have characteristics suggesting greater risk than is the case for Questar Gas.

The Company, however, avers that regulatory risk has not been eliminated because the Stipulation neither prescribes a fully forecast test year nor determines future Commission test-year policy. Nevertheless, the record makes clear that regulatory risk is reduced, and we conclude that such risk now has less effect for rate-of-return decisions than has been true previously.

In addition to the amelioration of regulatory lag effects, the record shows a number of regulatory practices in this jurisdiction, some new since the Company's last general rate case, that reduce regulatory risk. These include the 191 balancing account or pass-through treatment of gas costs, acceptance of gas supply risk-hedging techniques, a weather normalization clause, a reduction of Company exposure to bad debt through incorporation into the 191 Account of gas-related bad debt expense, and changes in contributions in aid of construction that reduce the between-rate-cases growth in rate base while improving cash flow and reducing the capital budget. We note that one bond rating entity has pronounced Utah regulation "sound." The record shows no systematic effort by any witness to compare these, and for that matter other business risk factors, with the situations of the proxy companies. Nevertheless, we find, as this Commission has in past dockets, a consideration of them instructive for the rate-of-return decision.

In general, business risk is uncertainty about the rate of return investors expect the Company to earn, and the possibility that actual return will deviate from it. Though on this record the principal source of this risk, regulatory lag, has been reduced by Stipulation, characteristics of service-area supply and demand, and general economic circumstances, are also important. The salient characteristic of service demand is continuing service territory growth. The rate of this growth, though slower than in recent years, continues to be among the most rapid in the nation. As is true of the national economy, the area economy is slowing after a period of robust growth. On this record, however, no relationship is established between the rate of change in jurisdictional growth and the demand for natural gas service. Suffice it to say that the service territory remains healthy and the number of utility service customers grows. The Company testifies that the number of new service connections annually, though fewer than in recent years, is still some 18,000. Likewise, there is a salient feature of supply that has been and continues to be important: Company ownership of some 50 percent of its natural gas supply, a situation that may be unique among gas distribution companies. This ensures stability both in the source of supply and its price. Even in the wholesale gas market, prices are much lower today than they were during the peak experienced in 2000 - 2001.

In the general economic environment, long-term interest rates have declined, short-term interest rates are at historic lows, and the cost of borrowed funds has decreased since the last general rate case, when interest rates were rising. Yields on Moody's AAA corporate bonds have changed little since the previous docket. At 1.6 percent, the inflation rate, measured by changes in the Consumer Price Index, is the lowest in many years. If interest rate behavior and recent Federal Reserve decisions are a guide, it may remain so. All these, we find, are positive for the Company, which on this record points to no negative business risk factors not already addressed herein. Our general conclusion is one of a stronger picture for the Company than in the previous general rate case, Docket No. 99-057-20, with regulatory lag reduced, the service territory healthy, and financing costs low. The only dark cloud in this picture is a current weakness in the general economy, with mixed signs of its possible duration. We have no record evidence, however, of an adverse effect on service demand in this jurisdiction.

We reach this conclusion in spite of the November 12, 2002, decision by Moody's Investors Service to downgrade the debt securities of Questar Corporation and its subsidiaries. In the case of Questar Gas Company, the Senior unsecured rating moves to A2 from A1. We are troubled by the downgrade and its potential impact on Questar Gas customers. The rating decision reflects the Company's recent history of earned returns below authorized, weak earnings coverage, and the regulatory lag effect of customer growth. As the diversified Questar Corporation's business risks have grown with investments in unregulated businesses, the decision notes that the proportion of regulated gas distribution assets to consolidated assets has declined to 24 percent. This rating decision, while mentioning positive factors for the gas distribution company in a context of the parent corporation's increasing business risk, fails to consider the amelioration of regulatory lag accomplished in this Docket. Since, by the Company's repeated assertion, regulatory lag is the primary source of its failure to earn its authorized rate of return, the reduction of that influence directly and positively addresses the factors upon which Moody's bases its derating decision.

Comparable or proxy companies.

Nine companies form the sample group offered by Questar Gas. Selection criteria include similar bond ratings, similar safety ratings, and similar revenue from gas operations. The Company asserts that these factors, and particularly similar bond ratings, should result in a list of companies of similar business and financial risk. Even so, Questar Gas claims that it faces more regulatory risk than do the others. The nine-company sample includes Questar Corporation, the Company's parent, and National Fuel Gas, each a diversified gas rather than a gas distribution company. As we have concluded in prior dockets, a diversified gas company is generally regarded as having higher risk than a gas distribution company. Though recognizing the point, the Company includes the parent in the sample because Value Line provides ratings for it and not for Questar Gas Company.

The Division accepts the nine-company sample but, because of the difference in risk characteristics, questions whether Questar Corporation and National Fuel Gas should be included. If removed from the sample group, the Division's return calculation is reduced by 30 basis points. Inclusion of Peoples Energy in the sample is also questioned, because it has higher than average return estimates and may be considered atypical of the group. Though the Division does not recommend removing the three from the sample, it notes the remaining six-company sample would consist of the same six companies used in the previous Questar Gas general rate case, and use of the smaller group would reduce the Division's return calculation to 9.81 percent from the recommended 10.5 percent.

In contrast to the Company and the Division, the Committee bases its return calculation on three sample groups: the same nine-company sample used by Questar Gas and the Division, Value Line's natural gas distribution group, and Moody's gas distribution group.

Two problems arise. First, as mentioned previously, the nine-company sample contains at least two and perhaps three that may not be representative. As the Commission has in previous dockets, we find that diversified gas operations have different risk characteristics and greater risk than do gas distribution operations. It therefore would be incorrect to use Questar Corporation and National Fuel Gas as proxy companies. We find support for this view in the Division's calculation showing a higher return requirement when they are included in the sample and in this Docket's reduction of regulatory risk, and correspondingly of business risk, faced by Questar Gas. Questar Corporation and National Fuel Gas should be removed from the sample group.

Second, the Committee's two other sample groups may not be selective enough to provide proper guidance to our return decision. Nineteen gas distribution companies are in the Value Line group, but the witness has applied no criteria to select them for the present purpose. Six of the Value Line 19 are in the Moody's group, and Questar Gas's nine-company sample includes the Moody's six. We are influenced by the Company's criticism that some of these companies have lower quality ratings, some, though the DCF is only appropriate for dividend-paying companies, pay no dividends, and some derive a different percentage of revenues from gas distribution operations. The Committee did not effectively rebut these points. The record convinces us that the Committee's Value Line and Moody's groups contain companies that do not mirror Questar Gas's risk characteristics closely enough.

Therefore, the principal sample group to which financial model analysis should apply consists of seven gas distribution companies. As we do not have the record to refine the Committee's broader groups, the role they can play in our rate-of-return decision is at most a subsidiary one.

Mean v. median

We now briefly address a technical point concerning the measure of sample central tendency. The Company advocates use of the sample median; the Division, the sample mean. The issue is which statistic best summarizes sample return estimates. As calculated by the Division, if the Company's sample medians are replaced with sample means, its 12.6 percent recommendation becomes 12.21 percent.

The argument about which, the mean or the median, is appropriate turns on the presence of sample outliers. If there are sample outliers, the median should be used; otherwise, the mean is the preferred indicator of the sample's typical value. The Division employs a statistical test called the "box plot," which examines whether any of the sample results fall outside a constructed range, to show that the sample does not contain outliers. On this basis, it argues the mean is the more appropriate statistic.

This debate contributes little to our analysis of record evidence because of the approach we adopt to solve the problem of estimating the dividend growth rate for DCF applications. Our discussion below of the range of reasonable returns should make this clear.

Financial Model Analysis

The DCF. Parties employ a standard, constant growth version of the DCF model, with the dividend yield portion influenced by the dividend growth rate. The DCF estimates capital cost, "k", as a function of dividend yield, "D/P", plus the dividend growth rate, "g". The Company and the Division agree that DCF calculations should be made with the most recent share prices, current dividends factored in at one plus the dividend growth rate, and an acceptable representation of that rate. The Committee, on the other hand, uses current dividends adjusted by one plus one-half the retention rate, producing a slightly higher dividend yield. Even with the effect of witnesses' dividend growth rate recommendations, the dividend yield portion of their DCF calculations vary little. On this basis, we find that the most recent share prices on this record, an average of those for June, July and August 2002, provided by the Company in rebuttal testimony, should be used. All parties used the most recent quarterly dividend distribution for each company. These will be the basis for the dividend yield portion of the DCF.

Witnesses do not agree about the appropriate dividend growth rate, "g". They present several data sets for the estimation of the dividend growth rate, including retained earnings growth, book value growth, and both dividend and earnings growth. Both historical and forecast data are employed.

The Company argues that earnings growth forecasts are a better basis than dividend growth forecasts for two reasons. First, it believes investors rely on earnings rather than dividends. Second, in its view, dividend growth rate forecasts produce unreasonably low rate-of-return estimates. Dividend growth once was important, the Company further opines, but now, when dividend payout ratios are declining, is no longer. But, counters the Division, in theory dividend growth is the proper basis for "g" because dividends are the source of cash value and earnings are important only insofar as they provide dividends. The Committee shares this view.

The growth rate for the DCF developed by the Committee is an average of five data sets. One of these consists of dividend and earnings forecasts no different from those used by the Division and the Company. We conclude that this adds little that is new. The Committee's approach, by averaging historical and forecast book value and retained earnings growth in with dividend and earnings information to derive the DCF growth rate, does present complications we are unable to resolve on this record.

We are unfamiliar with the retained earnings approach as presented by the Company. The record contains no analysis of it by parties that might permit us to conclude that it is consistent with the assumptions of the DCF model. For example, the DCF estimates the cost of capital, "k", but the Company's retained earnings method employs "k" as an explanatory variable in the estimation of "g", which is then added to dividend yield to produce "k". The Company criticizes the retained earnings averaging of the Committee, and is not effectively rebutted. In consequence, we determine not to rely on retained earnings as the basis for the growth variable "g".

Reliance on dividend growth exposes the Division to criticism. With the dividend growth rate forecast as the growth rate "g", and the mean of the sample company DCF results, the Division produces a required return of 7.2 percent. The 7.2 percent is averaged with its two other DCF results, both much higher, to produce the Division's 10.5 percent recommendation. The Company attacks the 7.2 percent rate, which it claims is about the same as the yield on AAA corporate bonds, as too low for serious consideration.

In theory, dividend receipts are modeled to infinity, so the basis for the growth rate should be very long run. In practice, long-run forecasts are not available; those on the record are for periods of but three to five years. DCF theory also assumes a constant rate of dividend growth through time, implying that earnings will grow at the same rate. Record evidence, however, shows that earnings are more volatile than dividends and are forecast to grow much more rapidly.

Shortcomings in concepts and data have, in previous dockets, convinced this Commission to use all relevant information to establish a reasonable growth rate. The record shows this to be a consistent theme since Docket No. 89-057-15 (use of earnings alone "imparts an upward bias" to cost-of-equity estimates). In Docket No. 93-057-01, the Commission did not resolve the dividends-versus-earnings debate, finding that a forecast is simply "an exercise of informed judgment about an uncertain future," and using each forecast as a reasonable way to bound the growth rate estimate. This reasoning carries forward in Docket No. 95-049-05, and in Questar Gas's most recent general rate case, Docket No. 99-057-20, the Commission again decided to employ forecast earnings growth as the upper limit for the dividend growth rate "g". The Division's review of this history, in the context of the present Docket, reveals to it no convincing reason to abandon the use of dividend growth forecasts.

We observe on the present record, however, two contrasting assertions. First, analysts are said to have a history of overstating earnings growth (are "persistently overly optimistic"), and second, investors, according to the Company, rely less on dividend growth than previously, citing as evidence the widening divergence between dividend and earnings growth estimates, and declining payout ratios.

The history of prior decisions on the subject, the assertion of declining investor interest in dividend growth, and the assertion of overly optimistic earnings forecasts, taken together, do not lead us to ignore dividend growth. Though dividend growth may deserve less weight in the determination of "g" than this Commission has previously permitted, we conclude that use of earnings growth forecasts as the sole basis for "g" produces high DCF estimates of required return. In the previous Questar Gas general rate case, the Division accorded dividend forecasts a 25 percent weight. On balance, we believe the prudent course is to give weight to earnings growth and to dividend growth, and to employ them both to develop an acceptable DCF growth rate. We do this below, as we establish the range of reasonable return estimates.

Role of other financial models

Capital Asset Pricing Model (CAPM), comparable earnings, and risk premium financial analyses are employed by witnesses to support their equity return recommendations, primarily as checks on the reasonableness of DCF results.

CAPM has always been particularly problematic for this Commission because of both theoretical and practical shortcomings. The Committee's CAPM analysis yields a range of 10.25 to 10.5 percent for the gas distribution industry. The Division employs CAPM solely as a check on its DCF results, developing a range of CAPM results of 7.3 to 13.63 percent. As its 10.5 percent recommendation is within this range, the Division believes the reasonableness check is met. Questar Gas performs a statistical analysis of CAPM's key variable, beta, finding estimates of it to be of no statistical significance, and therefore does not rely on CAPM results.

A comparable earnings analysis by the Committee examines historical (1992 - 2001) and projected (2002 - 2005/07) rates of return on equity for companies in the gas distribution industry. The result suggests 11 percent for the gas distribution industry. The Committee's market-to-book ratio discussion is said by the Company to have been wrongly developed, confusing investors' expected return with return on book common equity when the capital attraction standard applies to the former. The Company also argues that the Committee suggestion that an allowed rate of return should be set to bring market-to-book to one is without precedent. Lastly, Questar Gas develops a Risk Premium analysis, derives a 12.3 percent result, but does not rely on it.

The Division, while relying on the DCF, employs an alternative version called the Terminal Value Model which is characterized by a finite horizon. Results are derived that are not substantially different from its other DCF results.

These modeling exercises are observed to produce results in the same range as the DCF results. This merely reinforces the problem we face with the judgments witnesses must make in selecting the data to calibrate model variables. With the exception of the TVM, these model results buttress witness recommendations and are no more to be relied upon than the principal DCF results. In particular, we cannot rely on the CAPM. In addition to this Commission's previous concerns with this model, which are not successfully addressed on the present record, we now have the unrebutted assertion that the estimates of the variable beta are of no statistical significance. These observations support the approach we will employ to establish the range of reasonable returns. It continues the Commission's reliance on the DCF, but resolves the conflict over the estimation of the growth rate "g".

The range of reasonable rates of return and the allowed return on equity

To define the range of reasonable returns, we employ the best evidence available to us on this record. We believe the best evidence is found in witness applications of the DCF model. Taking this, and other factors, primarily business and financial risk, into account, we select the rate of return on equity we will allow from the range of reasonable returns.

We resolve the dispute over the relative role of dividend growth forecasts and earnings growth forecasts as the basis for the DCF growth rate "g". We will use three earnings growth forecasts - the Company's IBES forecast, the Value Line forecast, and the Division's Zacks' forecast - averaging the three observations for each proxy company in the seven-company sample. We will also employ the Value Line dividend growth forecast. From these, we derive a weighted average (three-fourths earnings growth, one-fourth dividend growth) growth rate. When applied to each proxy company, the mean DCF result is 10.9 percent. This value, we conclude, will be the low end of the range of reasonable returns. The high end of the range is similarly derived, but 100 percent weight is accorded to earnings growth forecasts. When this growth rate is used, the mean of sample results is 12.2 percent. This is the value we will use as the high end of the range.

The midpoint of the 10.9 percent to 12.2 percent range of reasonable returns is 11.5 percent. Though the midpoint may be thought a fair balance of ratepayer and shareholder interests, we find reason for further adjustment before selecting the allowed rate of return on equity from the range. We have thoroughly reviewed the regulatory risk aspect of business risk and have reached conclusions about it. We think the record clearly supports our observation that recent changes in risk favor the Company in such a way as to distinguish this Docket from previous ones. The reduction in interest rates and in the inflation rate, the addition of new regulatory practices that have the effect of reducing regulatory risk, and the continuing growth in demand for the Company's natural gas service are all positive factors. In addition, as we decide in the following section on capital structure, the heavier than average equity ratio means lower financial risk for Questar Gas than for sample companies.

Taking business risk, regulatory risk, financial risk, and witness financial analyses, as modified above, into consideration, we conclude that a fair and reasonable rate of return on equity for this Company, the rate we hereby allow, is 11.2 percent.

The Committee argues for inclusion of short-term debt in the capital structure. Questar Gas, it asserts, has maintained levels of short-term debt since 1991, and the 2001 level exceeds that required to finance construction work in progress (CWIP) and gas balances. In addition, the Committee states that rating agencies include short-term debt in benchmark ratios for security ratings. The Company's rate base is larger, the Committee asserts, than is supported by long-term financing. Many states are said to have short-term debt in capital structure. Short-term debt can be bridge financing, the Committee testifies, which is thereafter refinanced with long-term instruments. Thus, the Committee recommends inclusion of the December 31, 2001, level of actual short-term debt on Questar Gas's books in capital structure for ratemaking purposes in this Docket.

The Company opposes the inclusion of short-term debt in capital structure, citing as a principle of corporate finance that long-term assets (rate base) should be financed by long-term instruments, while short-term debt should be used to finance items that change over a relatively short period. Short-term debt rates are said to be less stable than long-term rates, and even now, when short-term rates are low, the Company testifies it is a good time to lock in long-term financing. Long-term financing is said to closely track rate base, including working gas in storage, the latter totaling about $23 million at year end 2001, but declining to about $13 million in summer. Short-term debt, states the Company, is used to cover swings in cash balances up to $20 million, or even higher if swings in wholesale market gas prices require it. A further reason for short-term debt is to cover gas receivables, which are seasonal and highest in winter. Further, short-term debt finances construction work in progress, which is not in rate base, and short-term debt may be used to finance negative balances in the gas balancing account. The Company also states that the point at which the Committee examines the short-term debt situation coincides with both monthly and seasonal peaks. By contrast, the Company asserts that for the March-through-September period of the test year, short-term debt was zero.

The Division testifies that the Committee has not provided enough information to warrant the addition of short-term debt in capital structure, but neither has the Company made a convincing argument that it should not be. The Division's own examination is incomplete. Until more research can be done, the Division recommends against including short-term debt in capital structure.

We will accept the Division's recommendation. No criteria are present in the record that guide us to a different conclusion. We agree with Questar Gas's assertion that change in a long-standing policy requires a complete record of support. As we do not have such a record, we will not at this time include short-term debt in capital structure.

Financial, or capital structure, risk

As the Commission stated in its August 11, 2000 Report and Order in Docket No. 99-057-20, "The larger the equity ratio, the lower is financial, or capital structure, risk. As the firm's equity ratio increases, however, the overall cost of capital rises because equity capital usually commands a higher return than debt. An optimal combination of capital structure and capital costs exists that will minimize the overall cost of capital while maintaining the Company's financial health." Finding that Questar's equity ratio was higher than that of the proxy companies, the Commission took financial risk into consideration when it set the equity return. Though in theory a least-cost capital structure may exist for ratemaking purposes, the record does not permit us to fully address the point. The question to be answered, nonetheless, is whether Questar's proposed capital structure, with a 52.6 percent equity ratio, reduces its financial risk, and if so, whether this should be taken into account in setting the allowed return on equity. We have answered these questions in the affirmative.

Citing exhibits showing that proxy companies have roughly 3 percent less equity in their capital structures than does Questar Gas, the Committee opines that the higher equity level is not required by the business risk Questar Gas faces. In the Company's view, the added 3 percent is neither significant nor out of line with business risk. The major such risk cited by the Company, as we recount fully above, is regulatory lag.

A larger equity proportion in capital structure, depending on the allowed rate of return on equity, could overcompensate shareholders. Since we accept the proposed capital structure, our analysis shows this would be the case without an adjustment for financial risk. We have made such an adjustment in reaching our equity return award of 11.2 percent.

Capital structure and rate of return on investment

We adopt the capital structure recommended by the Company. It consist of 52.61 percent equity, at a cost of 11.2 percent, and 47.39 percent long-term debt, at a cost of 7.92 percent. The weighted cost of capital, which we conclude is fair and reasonable, is therefore 9.64 percent.

G. ADJUSTED TEST YEAR REVENUE-REQUIREMENT SUMMARY

We approve and adopt Stipulation No. 1 submitted by QGC, the Division and the Committee. As noted above, no party has opposed any of the terms of this settlement of the annual revenue-requirement issues. We find that the individual resolution of the Group I issues and the composite agreement on the Group II issues is in the public interest and that rates based on these conclusions will be just and reasonable. We, therefore, find it unnecessary to resolve Group II items on an issue-by-issue basis. We specifically find that the test year revenue requirement as set forth in the Revenue Stipulation, is appropriate for determining just and reasonable rates for the Company.

A summary of the effects of our decisions is shown in Appendix 5, attached to this order. The Company's reported unadjusted results of system operations are shown in column 1. These results include both gas supply and distribution non-gas functions for the Company's operations in all its jurisdictions. The effect of all adjustments, including those in the stipulations, are shown in column 2. The adjusted results of system operations are shown in column 3. The adjusted system results are then allocated to the Wyoming and Utah jurisdictions. The results for Utah are in column 4. The Utah distribution non-gas results are separated from the total Utah results by removing the gas supply function, and that is shown in column 5. This is the basis for determining the change in distribution non-gas revenue requirement. Given our decisions on capital structure and rate of return on common equity, the change in distribution non-gas revenues is $11,162,650. This revenue change, as well as the resulting change in expenses associated with uncollectible accounts and income taxes, is shown in column 6. This $11,162,650 increase in revenue is necessary to give the Company the opportunity to earn the allowed 11.2 percent rate of return we order in this docket. Based on the results of the adjusted test year, the rate of return on rate base in 9.64 percent.

The Company, Division, Committee, UAE, IGU, USEA and SLCAP/CUC/U LW filed an Allocation and Rate-Design Stipulation and Settlement ("Stipulation No. 2"), which was described as a settlement of all the allocation and rate-design issues in the case. (For purposes of the discussion in Part III, "the Parties" will refer to the nine signatories to Stipulation No. 2.) No party has opposed any aspect of the stipulation. In general, the stipulation provides for the allocation of the test-year revenue requirement among the Company's customer classes for this case, addresses the recovery of certain CO₂ gas-processing costs, proposes several tariff changes for main and service-line extensions and construction work in progress ("CIAC") and seeks formation of a task force to take up various issues for possible future application.

A. ALLOCATION AND RATE-DESIGN TASK FORCE

In Stipulation No. 2, the Parties have agreed that numerous rate-design and cost-allocation issues should be considered by a collaborative task force consisting of the Company, Division, Committee and other interested parties and groups (the "Task Force"). The goal of the Task Force is to analyze a variety of rate-design and cost-allocation issues that have arisen in this case and attempt to agree on how to resolve these issues for possible application in future proceedings. The Task Force would undertake its deliberations during the first six months of 2003.

The Parties agreed to study the following issues related to QGC's rate-design and cost-allocation methodologies:

(a) Development of a new class cost-of-service study, including appropriate allocation factors.

(b) The value of peaking gas available from IT customers during periods of interruption, for consideration in the class cost-of-service methodologies for allocation and rate-design purposes.

(c) Possible separation of the current GS-1 residential and commercial customer class into separate classes.

(d) Modification of the current GS-1 rate design.

(e) The amount of the basic service fee.

(f) Qualification for and design of the FT-1 rate schedule.

(g) Transportation rate design, including transportation service for smaller customers.

(h) The amount and applicability of administrative fees, criteria for qualification, and demand charges for transportation service.

(i) The DNG summer/winter rate differential and issues related to supplier non-gas cost and commodity rate design.

(j) Possible compliance incentives to be offered in connection with the Company's "green tag" program for inspecting natural gas appliances.

The Parties agreed that QGC shall provide information and data reasonably requested by task force participants, subject to appropriate confidentiality agreements pursuant to a protective order to be prepared and submitted by the Company for Commission approval.

We find that pursuing a collaborative rate-design and cost-allocation effort may be beneficial and in the public interest and could assist the Commission in resolving many of these issues future proceedings. We direct that the Task Force be chaired by a representative of the Division and that an organizational meeting to consider representatives, subjects and scheduling be conducted no later than January 17, 2003. The Task Force should conclude its deliberations by June 30, 2003.

In Stipulation No. 2, the Parties have agreed to use the Company's most recent cost-of-service study for setting rates in this proceeding, with certain modifications. Settlement Exhibit 3, attached to Stipulation No. 2, adjusts the Company's originally proposed allocation methodology by modifying the treatment of CO₂ processing costs (as discussed in section III.E below); using an updated allocation factor 6; and limiting the percentage of increase to certain customer classes. The method adopted by the Parties for this last provision was to "cap" the percentage increase allocated to any class at twice the average percentage increase that would be allocated to all classes, as illustrated in Settlement Exhibit No. 3.

Stipulation No. 2 is approved as filed. We find it to be just and reasonable and in the public interest to allocate the revenue-requirement increase to the Company's rate classes as set forth in Stipulation No. 2 and illustrated in Settlement Exhibit No. 3. However, we recognize that the Task Force will consider a new class cost-of-service study and cost-allocation factors for possible use in future rate proceedings and that the methods approved for this case do not set any precedent for subsequent cases.

C. RATE-DESIGN REVISIONS

1. Transportation Administrative Charge

In Stipulation No. 2, the Parties agreed to an interim reduction in the annual administrative charge for Rate Schedules FT-1, FT-2, IT and IT-S customers from $8,000 to $6,800 for the first end-use site and from $3,000 to $2,550 for additional end-use sites. Revenues previously associated with the higher administrative charges will be allocated across all block rates for these rate schedules. The stipulation provides that this treatment will be addressed by the Task Force. The Parties agreed that, as a temporary classification provision to the FT-1, FT-2, IT and IT-S rate schedules, migration to these schedules by firm sales customers should be prohibited, unless the Commission determines otherwise in response to an individual request. We approve these proposed adjustments to the transportation administrative change, and the migration restrictions proposed in Stipulation No. 2.

2. Basic Service Fee

Questar Gas currently charges a $5.00-per-month, meter-based customer charge for Category I customers. Stipulation No. 2 proposes that this charge be retained in this case, and that Category II, III and IV customer charges be adjusted to reflect the authorized overall rate of return established in section II.D above. The Parties also agreed that the meter-based customer charge should be renamed as the "Basic Service Fee." We find these changes to be reasonable and approve them.

D. MAIN AND SERVICE-LINE CONTRIBUTIONS

1. The Proposed Changes

In QGC's current Tariff PSCU 300, a customer requiring a main or service-line extension is granted a footage allowance based on the natural gas appliances to be installed at the residence. Construction costs for footage greater than the allowance have been paid for by the customer and classified as a contribution in aid of construction ("CIAC"). As an approved practice since our final order in Docket No. 87-057-13, the Company has accounted for these contributions as revenues rather than as reductions to rate base. Stipulation No. 2 proposes to reverse this treatment and account for these amounts as a reduction to rate base, rather than as revenues.

The Parties have also agreed that §§ 9.01 and 9.02 of QGC's Tariff should be revised to terminate the various footage allowances currently granted to new residences. In place of the footage allowances, the stipulation proposes that a general main-extension allowance of $645 be granted for a new residential premises that will incorporate natural gas-fired space heat and water heat when completed.

With respect to service-line extensions, the revised § 9.02 would provide an additional $505 allowance for a residence utilizing space heat and water heat, with $100 of this allowance being dependent upon the premises being "stubbed" for a dryer and natural gas range. In addition, the Parties agreed to the termination of the current new-premises fee for GS-1 customers who initiate service. This current fee is $12 per month for the first 12 months of service.

The Parties agreed that default payments received from main and service-line extension contracts should also be treated as a CIAC and, therefore, as a reduction of rate base. Likewise, the Parties agreed that any interest accruing from such default payments should be treated consistently with generally accepted accounting principles (GAAP).

2. Conclusion on Line Extensions.

First, we approve the proposal to record CIAC as a reduction to rate base rather than as revenue. This accounting practice is consistent with the practice of other utilities in the country and is also consistent with GAAP.

We approve all the tariff revisions set forth in Stipulation No. 2, including the revisions to §§ 9.01 and 9.02 of the tariff, elimination of the words "in the Company's judgment" regarding "other excess construction costs," removal of the footage-based allowances, discontinuance of the new-premises fee, and such other modifications as are necessary to implement the terms of Stipulation. No. 2 with respect to these issues. We also adopt the proposed revision to the required contribution amounts and note that this subject will be considered in more detail by the Task Force.

Finally, we adopt the proposed treatment of default payments and interest with respect to extensions made where natural gas service is not initiated.

E. CO₂ EXPENSE RECOVERY

1. Background

In Docket No. 99-057-20, the Company requested an annual recovery of $7,343,000 in CO₂ processing costs in its general rates. This was initially opposed by several parties in that docket. A contested settlement agreement was filed by QGC and the Division in that case proposing that the Company recover a portion of its CO₂ processing costs, not to exceed $5 million per year beginning June 1, 1999. In addition, a separate, unopposed allocation and rate-design stipulation in that docket provided that approximately 5 percent of any CO₂ processing-cost recovery would be allocated to QGC's transportation customers. In our final Report and Order in that docket, we approved and adopted the CO₂ cost-recovery proposals of both stipulations, which went into effect on August 11, 2000.

Previously, QGC had appealed to the Utah Supreme Court our December 3, 1999 Order in Docket No. 98-057-20, which had disallowed recovery of CO₂ costs under the pass-through procedures of QGC's 191 Account. Questar Gas Co. v. Utah Public Service Commission, 34 P.3d 218 (Utah 2001). The Court set aside our order and concluded that the 191 Account process is not constrained by the Utah pass-through statute provisions, but represents "a separate rate-charging mechanism through which the Commission can set rates that are just, reasonable and sufficient." Id. at 222. We were directed to reconsider recovery of CO₂ processing costs through the 191 Account mechanism.

In Docket Nos. 01-057-14 and 98-057-12, we considered the recovery of the Company's CO₂ processing costs incurred prior to August 11, 2000, when cost recovery was authorized in QGC's general rates in Docket 99-057-20. In those dockets, we determined that the $5 million annual cap approved in Docket No. 99-057-20 should also apply to the 12-month period from June 1, 1999, through May 31, 2000. We concluded that $1.59 million had been previously collected through an interim rate order in Docket No. 99-057-20, leaving $3.41 million yet to be recovered by QGC for that period, and that an additional $0.35 million was recoverable for June 1, 2000, through August 10, 2001. Hence, we allowed recovery of an additional $3.76 million for CO₂ processing costs.

We also concluded that recovery of these costs should be allocated among all customer classes, including transportation customers consistent with the allocation approved in Docket No 99-057-20. Accordingly, we approved the recovery of sales customers' proportionate share of the additional CO₂ costs through the 191 Account pass-through process. Because transportation customers are not charged any rates through the 191 Account, we directed that these customers' proportionate share of costs were to be determined in QGC's pending general rate case, the current docket.

2. The Settlement Proposal

The Parties have agreed that the post-August 10, 2000, CO₂ expenses approved in Docket No. 99-057-20 should be allocated on the same basis as directed in Docket No. 99-057-20. Under that method, approximately 5 percent of the CO₂ costs were to be collected from transportation customers.

The Parties also agreed that sales customers' share of post-August 10, 2000, CO₂ costs, as well as pre-August 11, 2002, CO₂ costs addressed in Dockets 01-057-14 and 98-057-12 should be allocated in the same manner. With respect to transportation customers, their approximately 5 percent share of the costs would be included as a separate charge as described in § 2.12 of QGC's proposed tariff modifications and illustrated in Settlement Exhibit No. 2.

The result of this agreement is that sales customers' share of CO₂ processing costs would be recovered through the 191 Account pass-through mechanism, while transportation customers in the FT-2, IT and IT-S classes would pay their allocable portion through a separate charge described in detail on proposed § 2.12 of QGC's Tariff, page 22 (Settlement Exhibit No. 2).

Finally, Stipulation No. 2 addresses possible future recovery of CO₂ processing costs after the five-year, $25 million recovery is reached. If QGC desires further rate recovery of CO₂ processing costs, it must file a request with the Commission for that coverage, to be considered as a first-time request for costs included in account 813 and recovered in future rates. QGC would provide the 60-day notice as required under§ 2.12 of the Company's Tariff.

3. Conclusion on CO₂ Cost Recovery

We approve the CO₂ expense-recovery provisions contained in Stipulation No. 2 as a reasonable mechanism for recovering these costs through the 191 Account from sales customers and through a separate charge for transportation customers in the FT-2, IT and IT-S classes. The provisions set forth in the Stipulation No. 2 are a just and reasonable solution to the CO₂ allocation issues in this case as well as the remand portion of the costs to be recovered prior to August 11, 2000. Therefore, the proposed tariff sheets that detail these provisions in Settlement Exhibit No. 2 are hereby approved. We also concur with the proposed procedure concerning any continued CO₂ gas processing recovery after the five-year recovery period approved in Docket No. 99-057-20 has expired.

We note that the recovery of the Company's CO₂ costs is still subject to the outcome of an appeal filed with the Utah Supreme Court in Committee of Consumer Services v. Public Service Commission, No. 20000893 SC (Utah, filed Oct. 7, 2000).

On October 21, the Company, Division, Committee and Utah Energy Office submitted a Demand-Side Management Stipulation and Settlement ("Stipulation No. 3") for the Commission's consideration.

Stipulation No. 3 proposes that a collaborative group examine gas DSM issues, and that QGC and UEO jointly fund a study of possible cost-effective DSM measures in Utah. The cost of the study is not to exceed $50,000 and is to be shared equally by the Company and UEO. The study, to commence after May 15, 2003, will specifically address opportunities for gas-fired generation and combined heat and power. The study group will report to the Commission no later than August 31, 2003. QGC has agreed to evaluate DSM measures in its integrated resource planning ("IRP") during the 2003-04 cycle.

We approve as being in the public interest the provisions set forth in Stipulation No. 3, including the formation of a study group to explore gas DSM issues.

On October 21, 2002, the Company, Division and Committee submitted a Service Standards Stipulation and Settlement ("Stipulation No. 4") for consideration by the Commission.

The three parties agreed that QGC will submit its quarterly customer satisfaction standards report substantially in the form presented in Division Exhibit DPU 2.5R to the Division, Committee and Commission on a confidential basis. This report was developed primarily as a management tool utilized by the Company that is also useful for monitoring and review purposes by regulators.

Stipulation No. 4 also proposes that a second QGC quarterly report be made public and provide information in at least the following areas: call answering, emergency response, customer service activations, response to billing inquiries and safety. Both quarterly reports will be segmented to show the results of each QGC region, except with respect to the call-center data and customer-survey information.

The parties to Stipulation No. 4 agreed that other interested parties would convene to accomplish the following tasks:

a. develop the data and format to be used in the public report;

b. determine consumer dispute resolution guidelines and Commission complaint information and procedures to be included on QGC's website and in a customer insert on an annual basis; and

c. develop a statement identifying what customer services QGC currently provides.

This group of interested parties will report to the Commission by January 31, 2003, with either an agreement on these issues or a request for a hearing for final determination. Stipulation No. 4 also proposes that the group continue meetings to discuss other topics, such as benchmarking, as it deems appropriate. QGC will submit a proposed protective order to the Commission to govern the dissemination of documents to the participating parties .

Stipulation No. 4 also proposes that QGC be required to file an annual statement with the Commission, Division and Committee on the customer services that the Company provides.

We approve the service-standard reporting provisions set forth in Stipulation No. 4 as just, reasonable and in the public interest.

VI. ORDER

NOW, THEREFORE, IT IS HEREBY ORDERED, that:

Pursuant to the foregoing discussion, findings and conclusions, we issue the following order:

1. Questar Gas Company shall file appropriate tariff revisions to effect an increase in annual revenues for its Utah operations of $11,162,650 and to implement such other rate and tariff changes as are necessary to conform with the foregoing discussions.

2. The tariff revisions shall reflect the Commission's determinations regarding individual rate schedule increases, charges and other cost-allocation and rate-design aspects designated and discussed in this Report and Order. The Division of Public Utilities shall review the tariff revisions for compliance with this Report and Order. The tariff revisions may become effective as designated by Questar Gas Company, but not earlier than the date of this order.

3. The Low-Income Weatherization program previously approved by this Commission shall be continued and funded with $250,000, as discussed in this Report and Order. The Division of Public Utilities shall audit the program as it determines necessary or as directed by the Commission. Questar Gas Company, the Division of Public Utilities and other interested parties may submit requests to modify the program as experience with the program is obtained or otherwise warranted. The Demand-Side Resource Task Force shall study the program to consider the optimal level of state funding.

4. To the extent the Commission has omitted from the ordering provisions of this Order any duty or obligation to be imposed as is otherwise clear from the foregoing provisions of this Report and Order, it is hereby incorporated in this Order by this reference.

This Report and Order constitutes final agency action on Questar Gas Company's May 3, 2002 Application. Pursuant to Utah Code Ann. § 63-46b-13, an aggrieved party may file, within 20 days after the date of this Report and Order, a written request for rehearing or reconsideration by the Commission. Pursuant to Utah Code Ann. § 54-7-12, failure to file such a request precludes judicial review of this Report and Order. If the Commission fails to issue an order within 20 days after the filing of such request, the request shall be considered denied. Judicial review of this Report and Order may be sought pursuant to the Utah Administrative Procedures Act (Utah Code Ann. §§ 63-46b-1 et seq.).

DATED at Salt Lake City, Utah, this 30th day of December, 2002.

/s/ Stephen F. Mecham, Chairman

/s/ Constance B. White, Commissioner

/s/ Richard M. Campbell, Commissioner

Attest:

/s/ Julie Orchard,
Commission Secretary

G#31929

APPENDIX 1. Revenue Requirement Stipulation and Settlement

Pursuant to Utah Administrative Code § R746-100-10.F.5 (2002) and Utah Code Ann. §§ 54-4-1 and 54-4-4 (2000), the undersigned parties (collectively, "the Parties") submit this Stipulation and Settlement as a resolution of the annual revenue-requirement issues in this proceeding that are set forth in Settlement Exhibit 1 and explained in further detail below.

A. On May 3, 2002 Questar Gas Company (QGC) filed an application and direct testimony with the Public Service Commission of Utah seeking an increase in its Utah rates in the annual amount of $23,017,000. This application contained QGC's recommendations regarding allocation of QGC's revenue requirement among rate classes and recommended rate designs for all customer classes.

B. On May 16, 2002, the Commission held a scheduling conference at which the parties agreed to a procedural schedule that was approved by the Commission's May 21, 2002, Scheduling Order.

C. On May 28, 2002, the Commission conducted an evidentiary hearing on the test year to be used in this case. On May 31, 2002, the Commission issued an order deferring the determination of the test year to its final order in the proceeding.

D. On August 30, 2002, parties submitted direct testimony and exhibits responding to QGC's case-in-chief. Rebuttal testimony was submitted on October 4, 2002, and surrebuttal testimony was submitted on October 11, 2002.

E. The Parties have entered into confidential settlement discussions during the pendency of the case and have reached a resolution of the issues set forth below.

F. Therefore, in settlement of the revenue-requirement issues in this case, the Parties submit the terms and conditions of this Stipulation and Settlement as well as Settlement Exhibit 1 for the Commission's approval and order. The development of Settlement Exhibit 1 begins from QGC's initial May 3, 2002, request for an annual increase in revenues of $23,017,000 on line 1, titled "Original QGC Filed Deficiency." The revenue-requirement issues raised by the Parties are then separated into three groups:

Group I -- Issues on which the Parties have reached specific agreement.

Group II -- Issues on which there is aggregate agreement, but for which unanimous agreement was not reached on individual issues.

Group III -- Issues on which the Parties have not reached agreement.

The amounts listed in column B on page 1 and columns B, C, D on page 2 of Settlement Exhibit 1 are adjustments to be made to the Company's filed 2002 test year revenue-deficiency of $23,017,000.

UNCONTESTED ISSUES -- GROUP I

1. The Parties have reached agreement or resolution of approximately 37 issues set forth on Settlement Exhibit 1 and titled Group I -- Uncontested Issues. Some of these are corrections or revisions to the Company's filing that were identified during the Parties' discovery and audit procedures and in preparation for filing responsive direct testimony. Other Group I issues reflect settlement and agreement among the Parties of the amounts to be incorporated in the test-year determination of QGC's annual revenue requirement.

2. The overall result of settlement of these Group I issues is to reduce QGC's originally filed annual Utah revenue deficiency by $4,647,000, as shown on line 39 of Settlement Exhibit 1, and correspondingly to reduce QGC's position on the annual deficiency to $18,370,000.

3. The total adjustment for Group I issues on line 39 of Settlement Exhibit 1 is subject to final adjustment depending on amounts and status of items shown on lines 36, 37 and 38 (see footnote 1, Settlement Exhibit 1) and discussed in paragraphs 4-6 below.

4. The 2002 test-year revenue requirement is based on an average annual usage per GS-1 customer of 116.16 therms, as set forth in QGC's direct case. Therefore, line 36 reflects a zero adjustment. However, the Parties have agreed that the final revenue deficiency should be adjusted to reflect actual temperature-adjusted usage per customer through November 30, 2002. QGC will submit this information to the Commission and the Parties on or before December 13, 2002, for a final determination of the test-year revenue deficiency.

5. The entry on line 37 of Settlement Exhibit 1 reflects the expiration of certain 2002 gas-production tax credits under IRS Section 29. This entry is subject to adjustment for the enactment of any version of the currently pending Congressional energy legislation containing tax-credit provisions on or before December 15, 2002. Should this occur, QGC will submit to the Commission and the Parties its projection of the credits that would be realized by QGC for the year 2003, and a corresponding adjustment to QGC's test-year revenue requirement would be made.

6. The adjustment for the test-year increase in property insurance rates on line 38 is based on QGC's projected insurance costs, as included in the Division of Public Utilities' (Division's) direct testimony and reflected in the Company's rebuttal case (Exhibit QGC 4.2R). As final premium invoices have not been received for the coverage period beginning November 1, 2002, the final test-year revenue requirement in this case is subject to further adjustment to reflect actual invoices received by QGC on or before December 13, 2002. QGC shall file this information with the Commission and the Parties no later than December 13, 2002.

7. Within five business days of any Company filing under paragraphs 4-6 above, any party in this docket may file a response with the Commission addressing the Company's filing and requesting appropriate supplemental proceedings.

SETTLED ISSUES -- GROUP II

8. The Parties have reached an aggregate resolution of a second group of issues without agreeing to individual adjustments for each item. These are designated as Group II -- Settled Issues on Settlement Exhibit 1.

9. The relative positions prior to reaching an aggregate settlement of Group II issues on lines 42-52 of Settlement Exhibit 1 are shown in columns B, C and D. The aggregate changes to each of the Party's positions for purposes of settling these Group II issues are shown on line 54. The overall result of the settlement of the Group II Issues, combined with the Group I issues, reduces QGC's original test-year revenue deficiency to $17,885,000 before consideration of equity-return and capital-structure issues.

10. The Parties stipulate that a rate base of $555,389,000 should be adopted by the Commission, with the overall rate of return determined by the Commission to be applied to this rate base for rate-setting purposes. Because any further adjustments for the issues set forth on lines 36, 37 and 38 of Settlement Exhibit 1 do not affect any rate-base accounts, the value set forth in this paragraph will require no further adjustment.

11. Group II issues include a bad-debt revenue-requirement adjustment (line 42), on which the Parties have not individually agreed. However, for final rate-setting purposes, the Parties agree that a bad-debt percentage of .9% of test-year revenues should be used.

CONTESTED ISSUES -- GROUP III

12. Among the Parties, there has been no concurrence on the issues listed in Settlement Exhibit 1, lines 56-59, as Group III -- Contested Issues. These are dependent on the Commission's final determination of QGC's cost of equity capital and the capital structure to be used in calculating the overall allowed rate of return.

13. Group III issues involve only the determination of capital structure and return on equity capital, as indicated in lines 56 and 57 (and the information in boxes below those lines). The adjustments on lines 60-61 are not contested issues, as they will be determined directly from the final determination of equity return and capital structure.

14. QGC, the Division and the Committee of Consumer Services (Committee) have submitted written testimony and exhibits addressing these Group III issues, and sponsoring witnesses will be called for examination and cross-examination at the hearings commencing on October 17, 2002.

15. Line 63 of Settlement Exhibit 1 shows the test-year revenue deficiencies of QGC, the Division and Committee after reflecting the agreement reached on Group I and Group II issues, with equity return and capital structure left as outstanding issues. Also shown at the bottom of page 2 of Settlement Exhibit 1 is a chart showing the test-year revenue deficiency for several combinations of equity return/capital structure outcomes.

GENERAL TERMS AND CONDITIONS

16. Except for the contested issues in Group III, the Parties have reached a full and final resolution of all other revenue-requirement issues and submit this Stipulation and Settlement for the Commission's approval of its terms and conditions.

17. Except for Group III issues, the Parties agree to waive cross-examination regarding all other issues related to the determination of the test-year revenue deficiency that have been addressed in the written testimony submitted by the Parties in this case. Accordingly, the Parties agree to request that witnesses whose testimony addresses only Group I and Group II revenue-requirement issues be excused from appearing at the hearings scheduled to begin October 17, 2002.

19. All negotiations related to this Stipulation and Settlement are privileged, and no Party shall be bound by any position asserted in negotiations. Neither the execution of this Stipulation and Settlement nor the order adopting it shall be deemed to constitute an acknowledgment by any Party of the validity or invalidity of any principle or practice of ratemaking; nor shall they be construed to constitute the basis of an estoppel or waiver by any party; nor shall they be introduced or used as evidence for any other purpose in a future proceeding by any Party to this Stipulation and Settlement. The Parties believe that settlement of these issues is in the public interest and that the rates, terms and conditions that result from the settlement of Group I and Group II Issues will be just and reasonable.

20. QGC, the Division and the Committee each will, and other Parties may, make one or more witnesses available to explain and support this Stipulation and Settlement to the Commission. Such witnesses will be available for examination.

21. The Parties are authorized to represent that the remaining intervenors in this docket who have not executed this Stipulation and Settlement either do not oppose or take no position on this Stipulation and Settlement.

22. This Stipulation and Settlement is an integrated whole, and any Party may withdraw from it if it is not approved in its entirety by the Commission. Should the Commission reject any part of the Stipulation and Settlement, any Party that withdraws its support retains the right to seek additional procedures before the Commission, including cross-examination of witnesses, with respect to such issues as it withdraws from.

23. The terms of this Stipulation and Settlement shall take effect on the date of the Commission's final order approving it and will remain in effect until the date of a superseding Commission order.

24. This Stipulation and Settlement may be executed by individual Parties through two or more separate, conformed copies, the aggregate of which will be consider as an integrated instrument.

In witness whereof, The Parties have executed this Stipulation and Settlement as of this 16^th day of October 2002.

Questar Gas Company

/s/ Gary G. Sackett
Jones, Waldo, Holbrook & McDonough

Jonathan M. Duke
Questar Corporation

Committee of Consumer Services

/s/ Reed T. Warnick
Assistant Attorney General

Industrial Gas Users Group

/s/ Michael Ginsberg
Assistant Attorney General

UAE Intervention Group

Gary A. Dodge

United States Executive Agencies

/s/ Captain Robert C. Cottrell, Jr.

APPENDIX 2. Allocation and Rate-Design Stipulation and Settlement

A. On May 3, 2002, Questar Gas Company (QGC) filed an application and direct testimony with the Public Service Commission of Utah seeking an increase in its Utah rates in the annual amount of $23,017,000. This application contained QGC's recommendations regarding allocation of its revenue requirement among rate classes and recommended rate designs for all customer classes.

B. On May 16, 2002, the Commission held a scheduling conference at which the Parties agreed to a procedural schedule that was approved by the Commission's May 21, 2002, Scheduling Order.

C. On August 30, 2002, the Parties submitted direct testimony and exhibits in response to QGC's direct case. Rebuttal testimony was submitted on October 4, 2002, and surrebuttal testimony was submitted on October 11 and 15, 2002.

D. The Parties have entered into confidential settlement discussions during the pendency of this case and have reached a unanimous resolution of the issues addressed herein.

E. In settlement of the allocation and rate-design issues in this case, the Parties submit the terms and conditions of this Stipulation and Settlement for the Commission's approval and order.

STIPULATION AND SETTLEMENT

1. The Parties agree that several of the issues raised by various Parties be the subject of further study and consideration by a collaborative task force. The Parties request that the Commission direct in its final order in this docket that the task force engage in a study over the first six months of 2003 regarding the various issues outlined in this paragraph 1 and attempt to reach accord and resolution of these issues for consideration in subsequent regulatory proceedings. QGC agrees to provide information and data reasonably requested by task force participants subject, when appropriate, to confidentiality agreements pursuant to a protective order to be prepared and submitted for Commission approval by QGC. Specifically, the Parties agree generally to study QGC's rate-design and allocation methodologies including, but not limited to:

(a) A class cost-of-service study, including allocation factors.

(b) The value of peaking gas available from IT customers during periods of interruption, for consideration in the class cost-of-service methodologies for allocation and rate-design purposes.

(c) Separation of the residential and commercial customers in the GS-1 class into separate classes.

(d) Modification of the GS-1 rate design.

(e) The amount of the basic service fee.

(f) Qualification for and design of the FT-1 rate schedule.

(g) Transportation rate design, including transportation service for smaller customers.

(h) The amount and applicability of administrative fees, criteria for qualification and demand charges for transportation service.

(i) The DNG summer/winter rate differential and issues related to SNG and commodity rate design.

(j) Possible "green tag" compliance incentives.

2. Additionally, the Parties have agreed to study separately the possible development of a tracker mechanism for usage per customer.

3. Contributions in aid of construction (CIAC) shall be accounted for as a reduction to rate base rather than as revenue (as has been done in the past).

4. The Parties agree to the main-extension and service-line extension revisions described in QGC Exhibits 5.0 and 5.3, including tariff provisions eliminating the new- premises fee, except as otherwise described in paragraph 5.

5. The average CIAC required of new residential customers will be increased by $250. This results in a $645 allowance for main extensions and a $505 allowance for residential service-line extensions.

6. The language "in the Company's judgment" currently included in Sections 9.01 and 9.02 of QGC's Tariff PSCU 300 regarding excess construction costs shall be deleted.

7. Default payments received from main-extension and service-line extension contracts shall be accounted for as reductions to rate base, and interest associated with these payments shall be accounted for as interest income consistent with Generally Accepted Accounting Principles.

8. The allocation of all remaining CO₂ expenses approved in Docket No. 99-057-20 shall be in accordance with the method adopted by the Commission in Docket No. 99-057-20. CO₂ processing costs that the Commission authorized for recovery in Docket No. 01-057-14 shall be allocated to transportation customers using the same method.

9. QGC shall commence collecting all remaining CO₂ processing costs as approved in Docket Nos. 01-057-14 and 98-057-12 through the provisions of § 2.12 of the QGC Tariff, as modified in Settlement Exhibit 2. The tariff language has been modified to provide for the limited applicability to track the portion of the CO₂ processing costs collected from transportation customers.

10. For purposes of this docket, and pending analysis of the task force, the annual administrative charge for rate schedules FT, FT-2, IT and IT-S will be reduced from $8,000 to $6,800 for the first end-use site and from $3,000 to $2,550 for additional end-use sites. Revenues previously associated with the higher administrative charges will be collected across all block rates for these rate schedules. As a temporary classification provision to the FT, FT-2, IT and IT-S rate schedules, migration to these schedules by firm sales customers shall be prohibited subject to case-by-case determination by the Commission.

11. If QGC proposes to continue charging for CO₂ processing expenses after the charges in accordance with the stipulated amount in Docket No. 99-057-20 are reached, ($25 million), QGC shall treat the proposed charges for additional CO₂ processing as a first-time inclusion of material costs included in Account 813, and it shall provide the 60 days' required in § 2.12 of QGC's Tariff.

12. For purposes of this docket, the Parties agree generally to utilize the Company's cost-of-service study for setting rates as modified by this Stipulation and Settlement. The Parties also agree to adjust the methodology shown in Exhibits QGC 5.7 and QGC 5.7R, with results as illustrated in Settlement Exhibit 3. The adjustments shown in Settlement Exhibit 3 correct Exhibits QGC 5.7 and 5.7R for the treatment of CO₂ processing costs, incorporate the use of an updated allocation factor 6, and incorporate a limitation on the increase to any class of 200% of the average system increase. Settlement Exhibit 3 illustrates the methodology used to mitigate and reassign the increase to classes that otherwise would have exceeded the 200% limitation.

13. QGC shall perform a depreciation study within one year for consideration in future regulatory proceedings.

14. The current Category I meter-based customer charge of $5.00 shall be maintained. Category II, III and IV customer charges will be adjusted to reflect the authorized overall rate of return in this case. The meter-based customer charge shall be renamed the "Basic Service Fee."

15. The Parties either support or do not oppose the proposed increase from $250,000 to $500,000 in low-income weatherization assistance as proposed by witnesses Fox, Wolf and Johnson. Positions may be stated by counsel for each of the Parties at the hearing.

GENERAL TERMS AND CONDITIONS

16. This Stipulation and Settlement addresses and resolves among the signatories all of the contested issues involving rate design and allocation.

17. The Parties agree to waive cross-examination on allocation and rate design issues addressed in the written testimony submitted by the Parties in this case. Accordingly, the Parties request that witnesses whose testimony addresses these issues be excused from appearing at the hearings scheduled to begin October 17, 2002.

18. All negotiations related to this Stipulation and Settlement are privileged, and no Party shall be bound by any position asserted in negotiations. Neither the execution of this Stipulation and Settlement nor the order adopting it shall be deemed to constitute an acknowledgment by any Party of the validity or invalidity of any principle or practice of ratemaking; nor shall they be construed to constitute the basis of an estoppel or waiver by any party; nor shall they be introduced or used as evidence for any other purpose in a future proceeding by any Party. The Parties believe that settlement of these issues through this Stipulation and Settlement is in the public interest and that the rates, terms and conditions it provides for regarding the issues set forth above are just and reasonable.

19. QGC, the Division, and the Committee will, and other Parties may, present testimony of one or more witnesses to explain and support this Stipulation and Settlement before the Commission. These witnesses will be subject to examination.

20. This Stipulation and Settlement is an integrated whole, and any Party may withdraw from it if it is not approved in its entirety by the Commission. Should the Commission reject any part of the Stipulation and Settlement, any Party that withdraws its support of it retains the right to seek additional procedures before the Commission, including cross-examination of witnesses, with respect to such issues as it withdraws from.

21. The Stipulation and Settlement shall take effect on the date of the Commission's order approving it and shall remain in effect until the date of a superseding Commission order.

In witness whereof, The Parties have executed this Stipulation and Settlement as of this 16^th day of October 2002.

Questar Gas Company

Gary G. Sackett
Jones, Waldo, Holbrook & McDonough

/s/ Reed T. Warnick
Assistant Attorney General

Industrial Gas Users Group

/s/ Glenn Bailey

/s/ Charles E. Johnson

Division of Public Utilities

/s/ Michael Ginsberg
Assistant Attorney General

UAE Intervention Group

/s/ Gary A. Dodge

United States Executive Agencies

/s/ Captain Robert C. Cottrell, Jr.

Salt Lake Community Action Program

/s/ Catherine C. Hoskins

APPENDIX 3. Demand-Side Management Stipulation and Settlement