BRITISH COLUMBIA UTILITIES COMMISSION Stargas Response to Commission Information Request No. 1. Application to Vary Rates

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1 B-2 BRITISH COLUMBIA UTILITIES COMMISSION Stargas Response to Commission Information Request No. 1 Application to Vary Rates 1.0 Reference: Shareholders Equity The Application, p. 3 of 10 Accumulated Unpaid Preferred Share Dividends Cumulative dividends prior to the Company s fiscal year ending May 31, 2006 aggregating $135,887 remain unpaid as at May 31, [The Application, p. 3 of 10] When recapitalized in 2002, its then shareholders acknowledged that the Company would not be in a position to pay on a current basis appropriate returns on their $400,000 investment. Cumulative dividends would, it was determined, be an effective measure of foregone returns in that they would not compound (as would unpaid interest) nor did their accumulation result in taxes payable by their holders without a current return from which to pay those taxes. [The Application, p. 3 of 10] 1.1 Please confirm the years in which the unpaid dividends of $135,887 accrued and the amount accrued per year. The total should agree to $135,887. Preferred share balance $ 400, Amount Amount Accumulated but unpaid dividends BCUC Rate Premium Rate June to Dec Jan to May Fiscal Cumulative BCUC rate - calendar year % 0.75% 9.88% $3, % 0.75% 10.17% $23,730 $16,950 $20, % 0.75% 9.90% $23,100 $16,500 $40,230 $60, % 0.75% 9.78% $22,820 $16,300 $39,400 $99, % 0.75% 9.04% $21,093 $15,067 $37,887 $137, % 0.75% 9.14% $21,327 $15,233 $36,327 $174,087 Dividend payment (per BCUC)* 9.55% -$38,200 $135,887 *Order G Stargas paid its first dividend ($38,200) on its preferred shares on May 31 st, For each year that unpaid dividends of $135,887 accrued, please confirm if any return on equity amount was included in Stargas revenue requirement. If confirmed, please provide the amount per year. No return on equity was included during that period. G80-02 (November 7, 2002) approved an increase in our delivery component of $2.00 from $5.20 to $7.20; there was no return on equity included in the schedule on which the increase was based. The delivery rate was unchanged through the fiscal years ended May 31, Pursuant to G (November 15 th 2005) delivery rates were increased by.06 cents per gigajoule to $7.26. The calculation of the costs to be recovered in establishing that rate excluded any return on equity. In our August 2006 application, we sought to include a return on notional equity in the determination of our revenue requirement. In G (December 16, 2006) the Commission directed that Stargas exclude any return on notional equity in that or in future applications. In that same order, Stargas was directed to pay a dividend on its outstanding preferred shares in order to provide a return to its shareholders and the Company paid the $38,200 dividend reflected in the above table. Stargas Alter rates IRR No.1 Page 1

2 1.2 Please discuss what is meant by the following sentence: Cumulative dividends would, it was determined, be an effective measure of foregone returns in that they would not compound (as would unpaid interest) Investor capital, and loan guarantees were provided to Stargas by investors who saw that, in the long term, heating fuel economies would accrue to the Resort if it were linked to available natural gas supplies in nearby Vernon. Fortis (its predecessor companies) had for years prior sought to connect the resort to those supplies but insisted (reasonably) on a not insignificant investment from stakeholders in the resort. Messrs. Buchanan and Blumes, then the two senior executives within the resort ownership, committed the financial and human resources necessary to the formation of Stargas and in so doing, accepted the initial and ongoing financial obligations associated with it. When, for strategic purposes, the majority of the assets of the resort were sold to new owners (Big White), Stargas was segregated as an independent and self-sustaining enterprise under the joint ownership of the holding companies of the two men. The investors recognized that a return on their investment would necessarily occur some years following their initial investment; were they to have provided the $400,000 by way of an interest bearing obligation, interest would be accrued as payable to them but the financial resources would not be generated to fund payment. The result, taxable interest income in the hands of each of the investor holding companies with no cash receipts from which to pay those taxes. Nor would the investors have been willing to provide their funds in the purchase of common shares since there would not then be either a real nor notional measure of returns foregone. At the time, the matter was subject to the review of the Commission and after due deliberation, the preferred share option was accepted and the approved cumulative dividend rate set at 75 basis points over the BCUC s benchmark return. 2.0 Reference: Shareholders Equity The Application, p. 3 and p. 7 of 10 Accumulated Unpaid Preferred Share Dividends At the direction of the Commission, from June 1, 2007, the Company has declared and paid the annual dividend on these shares and where necessary, pursuant to the terms of its financing arrangements, advanced equivalent funds to the company as subordinated shareholder advances. [The Application, p. 3 of 10] From June 1, 2006 to date, the current year s dividend was paid and included in the utilities revenue requirement. [The Application, p. 7 of 10] 2.1 Please confirm if the Company has declared and paid the annual preferred share dividend from June 1, 2006 or June 1, The Company has declared and paid the dividend annually on May 31 of each year, commencing in its fiscal year ended May 31, 2007 and through to its fiscal year ended May 31, Please confirm the amount declared and paid per year. Dividend declared and paid May 31, 2007 $38,200 May 31, 2008 $36,944 May 31, 2009 $37,230 May 31, 2010 $40,656 Stargas Alter rates IRR No.1 Page 2

3 May 31, 2011 $41,000 May 31, 2012 $41, Please discuss the tax treatment of the cumulative deferred share dividend declared and paid by Stargas each year, from the perspective of the shareholder. Each of Rundle Investments and CMI (1998), the corporate shareholders of Stargas, receive intercompany dividends on a tax-free basis; tax is paid by the individual shareholders of those companies only when dividends are flowed through to shareholders. Given that, in the years 2007 through 2011, financing constraints required that the amounts be advanced back to Stargas as 6% loans, funds were not then available to distribute to shareholders. 3.0 Reference: Shareholders Equity The Application, p. 3 of 10 Accumulated Unpaid Preferred Share Dividends Unless [the dividend arrears are] included in the revenue requirement we would not ever be in the position to be able to pay the arrears and so propose that we be allowed to amortize the arrears into our revenue requirement over twenty years. By doing so, we will have positioned ourselves to, in years following, to replace higher cost preferred share dividends with interest on term debt and / or further shareholder advances. [The Application, p. 3 of 10] 3.1 If the dividend arrears are amortized over a twenty year period, as suggested in the Application, please provide a proposed schedule to declare and pay the dividends. In each of the twenty years, on the last day of each fiscal year, Stargas would declare and pay a dividend on its preferred shares in whatever amount was determined for that year based on the BCUC s benchmark return plus $6,794 so that over the twenty year period the arrears would have been paid out to the shareholder. 3.2 Would Stargas consider amortizing the accumulated unpaid dividends into the revenue requirement over a period of ten years? Please discuss why or why not. Were we to amortize the arrears over ten years the catch-up amount would be $13,588 in each of those years. While we had initially considered a ten year program, we made application for the twenty years that we did because we were concerned with the impact of doing so on delivery rates. Based on an estimated annual volume of 40,000 gigajoules over the time horizon, the two alternatives would represent 17 cents or 34 cents of additional delivery cost. 3.3 If the dividend arrears are amortized over a ten year period, please provide a proposed schedule to declare and pay the dividends. See Would Stargas consider amortizing the accumulated unpaid dividends into the revenue requirement over a period of five years? Please discuss why or why not. Here again, our suggested twenty year term was based on our seeking to minimize the current impact on delivery rates. We would, in deed, consider a five year amortization on the arrears recognizing that in doing so, we d be in an earlier position to commence a serial conversion of preferred shares to lower cost Stargas Alter rates IRR No.1 Page 3

4 bank debt. Note that assuming volumes approaching 40,000 GJ s, a five year amortization of the arrears would dictate a 68 cent per gigajoule increase in our delivery charge. 4.0 Reference: Shareholders Equity The Application, p. 3 of 10 Preferred Share Dividends As the [dividend] arrears are addressed, Stargas could, in a series of re-financings, redeem preferred shares and replace those with lower cost bank debt. [The Application, p. 3 of 10] As the holder of the Class G preferred shares have waived their right, indefinitely, to redeem their Class G preferred shares, the outstanding Class G preferred shares have been presented as a component of shareholder equity. [Stargas F2012 Financial Statements, Note 8] 4.1 Please discuss if Stargas has considered replacing the preferred share dividends with common equity, as opposed to debt financing, and explain why or why not. We recognize that ours is not a conventional financial model. We have not considered replacing preferred shares with common equity as in doing so we d have lost any marker on the returns that would otherwise have accrued to long patient investors. We believe that the current inclusion of an annual dividend on our preferred shares and amortization of the arrears (over whatever period 5, 10, 20 years) is and would continue to be a reasonable surrogate for a conventional model. If, however, we had established a basis on which to recover what we believe to be were fair and reasonably measured foregone returns we would then be prepared to transition to a conventional model. 4.2 Please discuss why the holder of the Class G preferred shares has waived their right to redeem the preferred shares on an indefinite basis. The holder waives the right on an annual basis as an accommodation necessary to the selected financial statement presentation. As a factual matter, not doing so would have no material adverse consequence; rather than including the preferred shares under the caption Shareholder s equity in the Company s annual financial statements, the amount would be disclosed under shareholder interests. We have provided our accountants this waiver to support the current financial statement presentation but, as noted, we may or may not continue to do so as would meet regulatory requirements Are there any conditions that must be met in order for the holder of the Class G preferred shares to redeem the preferred shares, given that the right to redemption has been waived indefinitely? Please discuss. In completing its year-end financial statements for any subsequent year end, the investor could rescind its waiver (by not providing a further waiver) and accept that the preferred shares reflect as a liability rather than equity in its annual financial statements. The presentation adopted was, it was felt, the most favorable representation in addressing the Company s current and future financial needs to its banker. Any redemption of preferred shares and /or repayment of shareholder advances are and will remain, the subject of constraints legislated by the TD Bank as a part of its ongoing financing of the Company. 5.0 Reference: Rate Base The Application, p. 1 of 10 The Application, p. 1 of 10 includes a calculation of Stargas F2013 and F2012 mid-year rate base. 5.1 Please confirm if a British Columbia Utilities Commission (Commission) Order has approved the Stargas Alter rates IRR No.1 Page 4

5 inclusion of each item listed below in rate base. If confirmed, please provide the Order number. Terasen Contribution, net; We have not identified a specific order from the Commission approving the inclusion of the Terasen Contribution in rate base but note that it has been included as such from the initial filings of the Company dated from its annual report for its initial fiscal year ended May 31, We would assert that the contribution, which paid for the construction of a gas main from Vernon, BC to the border of the Resort, is and should continue to be an element of rate base. Deferred Finance Charges. Deferred finance costs were included in rate base pursuant to G107-5 (November 1, 2005). 5.2 Please provide Stargas deferred income tax balance for each of May 31, 2011 (Actual), May 31, 2012 (Actual) and May 31, 2013 (Forecast). As at May 31, 2012, the Company had a future income tax asset estimated at $9,000 ($6,000 at May 31, 2011). The Company estimates that it will have a future income tax asset of $12,000 at May 31, Based on their relative immateriality, the asset and corresponding regulatory liability have not been reflected in the Company s balance sheets. 5.3 An amount for accumulated unpaid dividends of $129,093 and $135,887 is included in the midyear rate base for Test Year F2013 and F2012, respectively. Please discuss the rationale for including this item in rate base, despite the fact that these dividends have not yet been declared or paid by Stargas. If as we believe appropriate, the measure of foregone returns represented by the amortization of cumulative dividend arrears is to be included in the determination of our revenue requirement, we assert it entirely consistent that the corresponding unamortized amount be included in the determination of rate base. Thus, if, as and/or when we introduce a return on rate base in the computation of our revenue requirement, we would generate an additional amount awarding the holder a return on the unpaid amount dating from Reference: Rate Base The Application, p. 1 of 10; The Application, Exhibit B-7 Working Capital, Methodology Exhibit B-7 includes Stargas lead-lag schedule for the Test Year F2013 (The Lead-Lag Schedule). 6.1 Please describe the methodology used in calculating the cash working capital of $56,477 per the Lead-Lag Schedule. The schedule was initially prepared in the current format based on a precedent supplied by Commission staff as a part of an earlier application. We have followed that precedent without change. Given the tenor of the remaining questions in this section and the work necessary to understand/comply with the detailed questions/responses required, we ve elected to use the formula approach to Working Capital as described in the following section Please confirm if the methodology used in the Lead-Lag Schedule has been reviewed by a third party for appropriateness of components, completeness and the reasonableness of the calculation. Stargas Alter rates IRR No.1 Page 5

6 We have not had third party corroboration/review of the Schedule but repeat that it has been prepared entirely consistent with earlier versions accepted by the Commission (and based upon an example provided to the Company by it). 6.2 Please discuss why the calculation of the Days in receivable per the Lead-Lag Schedule is based on the opening accounts receivable balance for each month, as opposed to the month-end balance. We merely following the format provided given our decision to follow the formula approach we have not responded further Please discuss why the calculation of the Days in receivable per the Lead-Lag Schedule has not been separated into the following individual revenue components: large commercial service, small commercial service, residential service. We do not have monthly data supporting breaking out receivables by revenue component Was consideration given to incorporating service lag, billing lag and collection lag into the calculation of the revenue lag days per the Lead-Lag Schedule? Sadly, we ve not experienced either these terms nor do we understand their application in our circumstances. As noted in each of our applications, we attempt to meet and exceed all of the requirements of the regulatory process but, in order to avoid the issue have opted for the formula approach. 6.3 Please confirm if all expense categories were used in determining the expense lead days per The Lead-Lag Schedule. If not confirmed, please list what expense categories were excluded and explain why. All expense categories were brought into our calculations Please discuss how the lead days for each expense category were determined. Each of Fortis Gas, Fortis Alternate Energy and Cascadia were calculated based on our long standing payment schedules. Okanagan Funding Management fees were based on a 30 day after month end payment schedule which has been the program upon which we ve disbursed funds from the Company in settlement of management costs. 6.4 Please confirm the following information in relation to Lead-Lag Schedule: The estimated total revenue lag days; The estimated total expense lead days; The estimated net lead-lag days. We have not responded to this point as we ve elected to follow the formula approach Please recalculate the working capital component of rate base for Test Year F2013 based on the net lead-lag days, multiplied by the operating and maintenance expenses for the Test Year F2013. We have not responded to this point, again, because we ve elected to follow the formula approach. Stargas Alter rates IRR No.1 Page 6

7 7.0 Reference: Rate Base The Application, Exhibit B-7 Working Capital, Methodology The Panel recognizes that a formulaic approach to calculating cash working capital is acceptable for small utilities where the resources required for a detailed lead/lag study would be too costly and time consuming. The Panel accepts the formula method of calculating cash working capital as 1/8th of operating expenses. [Appendix A to Commission Order G , p. 2 of 5] 7.1 Please discuss if a formulaic approach to calculating cash working capital would be considered by Stargas for the Test Year F2013, and explain why or why not. Yes; we d be most appreciative of a short cut to avoid the calculations called for in a detailed lead/lag study and will adjust our schedules accordingly. 7.2 Please provide a calculation of the working capital component of rate base as 1/8 of Test Year F2013 operating expenses, excluding purchased gas costs. Operating costs, per forecast $ 310,575 Meters, etc. 5,760 Total operating costs $ 316,335 Formula calculation $ 39, Reference: Rate Base The Application, p. 1 of 10; The Application, Exhibit B-7 Working Capital The Application, p. 1 of 10 calculates the mid-year rate base using the average of working capital from Test Year F2013 ($55,693) and F2012 ($67,687). Exhibit B-7 includes a Lead-Lag Schedule that calculates the working capital component of rate base for Test Year F2013 based on forecast revenues and expenditures for Test Year F Please discuss why an average of the Test Year F2013 and F2012 working capital component is used in the determination of the Test Year F2013 mid-year rate base, when the Test Year F2013 working capital amount of $55,693 is calculated using forecast revenues and expenditures for the entire twelve month period of the Test Year F2013. We were in error and will correct in the future. 9.0 Reference: Financing The Application, p. 2 and 4 of Please provide a working excel copy of the Section III table entitled Financing on p. 2 of 10. The excel spreadsheet was sent by to the attention of Laurel Ross on October 8 th, 2012 and its receipt acknowledged on October 10 th, For the Test Year F2013, please provide the detailed calculation for each of the following items Stargas Alter rates IRR No.1 Page 7

8 on p. 2 of 10: Return on rate base $46,624 Rate of return on rate base 5.05% Return on equity $26,911 Return to equity - % 11.83% Return on rate base: Net income (exhibit B-2) $ 26,911 Interest - term debt $ 19,713 46,624 Rate base, as filed $ 923, % Rate base, as restated $ 901, % The percentages were computed by dividing net income and return by rate base restated amount replaces earlier working capital estimate by amount determined using 1/8 formula. 9.3 The Revenue Requirement calculation on p. 4 of 10 includes an amount of $41,000 for the current preferred dividend but excludes amounts for return on equity and debt return based on Stargas rate base. Considering this, please explain the purpose of including the table entitled Financing on p. 2 of 10 of the Application. While perhaps supplied unnecessarily, we suggest that it allows the reader to estimate the impact on rates, etc. were Stargas to transition to the conventional model and to assess its current surrogate (inclusion of preferred share dividends in the calculation of revenue required). It has been our practice to include this schedule in both of our annual reports and full rate applications Reference: Shareholders Equity The Application, p. 4 of 10 Deficit The following reconciliation of the Deficit balance per Stargas financial statements and the Deficit balance for regulatory purposes is included on p. 4 of 10: 31-May May-12 Deficit per financial statements $190,732 $169,849 Disallowed management fees 5,125 5,125 Disallowed financing costs 1,824 1,583 Regulatory deficit $183,783 $163,141 The Revenue Requirement calculation on P. 4 of 10 includes an amount for Management fees of $77,466 in the Test Year F2013 and $76,600 in F For F2011, please provide a reconciliation between the ending Deficit per the Company s financial statements of $143,366 and the ending regulatory Deficit. The deficit in our financial statements at May 31, 2011 was $143,366; it differed from our regulatory Stargas Alter rates IRR No.1 Page 8

9 deficit of $136,900; a difference of $6,466. The reconciling items were $5,125 in disallowed management fees and the amortization of disallowed financing costs of $1, Please describe what the disallowed management fees of $5,125 in F2013 and $5,125 in F2012 relate to and how these amounts were calculated. The $5,125 amount represents management fees charged by Okanagan Funding to Stargas in its fiscal year ended May 31, 2005 that were, subsequently, determined excessive and excluded from the determination of revenue requirements in that year. The Commission determined that executive time charged by Mr. Blumes at $250 per hour would, given comparable rates for management of a similar utility, be limited to $120 per hour. Therefore, the amount remains a reconciling item between allowed and reported deficits but does not impact current income or the computation of our revenue requirement Are the management fees of $77,466 included in the revenue requirement calculation on p. 4 of 10 inclusive of the $5,125 of disallowed management fees? The management fee of $77,466 includes executive time at proposed rates (see below) and does not include any amounts related to the rejection of a portion of the 2005 management fee amount charged but not allowed for regulatory purposes at that time Please provide the management fees included in the Stargas revenue requirement, as opposed to actual management fees per the financial statements, for each of F2012, F2011, F2010 and F2009. In each of the years 2009, 2011 and 2012 the Company did not request any change in its delivery pricing so that a detailed calculation of its revenue requirement for those years was not tabled. Actual management fees approximated budget in each of those years. Management fees were $79,300 in the fiscal year ended May 31, 2010 and had been forecast at $71,500 in the revenue requirement table submitted in the Company s application for that year. The overage related to protracted negotiations on a new service contract with Terasen/now Fortis Alternate and in addressing GCVA issues with staff at the Commission Please describe what the disallowed financing costs of $1,824 in Test Year F2013 and $1,583 in F2012 relate to and how these amounts were calculated. A portion of management fees were, in 2005, included in deferred financing costs so that when the rate charged in that year was challenged, that portion of the amount deferred was therefore excluded as allowable in the determination of rates. No, it does not Does the revenue requirement calculation on p. 4 of 10 include the disallowed financing costs of $1,824 and $1,583 for Test Year F2013 and F2012, respectively? Please confirm what line item of the F2012 Stargas financial statements includes the disallowed financing costs of $1,583. The amount disallowed but included in expenses each year is $241; for financial statement purposes, amortization of deferred finance costs is treated as an interest cost so that the $241 is included in interestterm debt in the 2012 financial statements. Stargas Alter rates IRR No.1 Page 9

10 11.0 Reference: Management Fees The Application, Attachment B-5 Attachment B-5 includes a Management Budget Submitted by Okanagan Funding Ltd., with the following total hours by category: Accounting 338 Administrative 559 Executive 187 Total 1,134 Commission Order G established the following approved hourly rates for management fees charged by Okanagan Funding Ltd.: Accounting $42.40 Administrative $63.60 Executive $ Please provide the actual hours for F2012 for each of the following categories: Accounting, Administration and Executive. Executive time $ $22,393 Administrative $ ,613 Accounting $ ,574 $76, Please confirm the actual rate per hour used to determine the management fees of $76,600 per the F2012 financial statements, for each of the following categories: Accounting, Administrative and Executive. Management fees were booked at the approved rates for each category Please provide the source from which the BC Consumer Price Index of and for April to March and April to March , respectively, were obtained and provide the hyperlink to the source. BC CPI - April to March BC CPI - April to March Increas e as a percentage 3.82% Current Propos ed Executive rate $ $5.06 Accountant $63.60 $2.43 Administrati ve $42.40 $1.62 The CPI index was obtained online at: Once on that site, select consumer price index by fiscal year. Stargas Alter rates IRR No.1 Page 10

11 12.0 Reference: Office and Sundry The Application, Attachment B-5; The Application, p. 4 and p. 5 of 10 P. 4 of 10 notes $15,768 and $13,341 in Office and Sundry expenses for the Test Year F2013 and Actual F2012, respectively. This represents an increase of $2,517, or 19%, from Actual F2012 to Test Year F2013. Included in the test year estimate our third party charges of $857 incurred in the development of a Company webpage added to improve the utilities profile at the resort. [The Application, p. 5 of 10] 12.1 The third party charges of $857 for the Company webpage explain a portion of the $2,517 increase in Office and Sundry Expenses. Please discuss what accounts for the remaining $1,630 increase in Office and Sundry Expenses. As an adjunct to our introducing the webpage, our administrator answers his personal cell phone as that of Stargas (that to provide improved and timely responses to customers/others so that we ve included a portion of his cost to our expenses. We ve an increasing numbers of customers who have moved from mailing their payments to using on line services that come with additional bank charges. As well, we ve made provision in our estimate for unusual administrative costs. We are engaged in a small claims court action where we are seeking to recover the cost of damages to our service line denied by the responsible party. That party has made a counter-claim against our contractor so that while we are confident that Stargas will not incur a cost, we are duty bound to support the position of the contractor in defending the action taken by our customer Reference: Return on Rate Base The Application, p. 3 and 4 of Please discuss the rationale for including an amount of $41,000 for preferred share dividends in the revenue requirement calculation on p. 4 of 10, as opposed to debt return and return on equity amounts based on Stargas rate base. Our inclusion of the preferred share dividend and the proposal to add an amortization of a portion of the dividend arrears is based upon the precedent established by the BCUC in its earlier decision that stipulated that In order to provide a return to its shareholders, Stargas is directed to pay a dividend on its outstanding cumulative preferred shares... Following the program specified in that December 2006 order we have generated modest accounting profits and returns on conventional equity ranging as follows: Return on equity % % % % % % Average 8.48% Including the annual amount of our preferred share dividend, and prospectively, an allocation of the arrears, has and would continue to provide a reasonable surrogate for returns that would have been generated in the conventional model. We are, therefore, hopeful of continuing to compute our revenue Stargas Alter rates IRR No.1 Page 11

12 requirement as at present In future rate applications, is it Stargas intention to continue to include an amount for current year preferred share dividends (i.e. $41,000 for Test Year 2013) in the revenue requirement calculation or does Stargas anticipate instead including amounts for return on equity and debt return based on rate base? Please discuss. As noted above, we anticipate continuing on the existing program into the future. Our application included a calculation of rate base aggregating $923,033 (amended to $901,076 by the adoption of the formula calculation of working capital) so that if allowed a return on rate base of, say, 7% we d include $63,075 in our revenue requirement. If our inclusion in rate base, of the unamortized amount of preferred dividend arrears were to be rejected, the $901,076 would be reduced by $129,093 to $771,983 and, at 7% we d include $54,039 in our revenue requirement. While either of these estimates would result in a higher delivery charge/and increased returns to equity, we believe continuing the current program reasonable and consistent with our financial goals In the event that the preferred shares of $400,000 are redeemed for debt financing, as indicated on p. 3 of 10 of the Application, please discuss the methodology that Stargas would employ for including a return on equity or debt return in the revenue requirement. We would not expect to redeem the preferred shares on other than a serial basis; we would, for example, expect to redeem ¼ of the shares at a time and while we ve not established a time table would expect to redeem the first tranche of preferred shares May 31, 2015 with successive amounts converted each three years thereafter. We would ask our banker to finance redemptions with additional term loans (secured by off balance sheet guarantees of the investor company/shareholder) but would, if not available, redeem shares by further 6% shareholder advances Please discuss what Stargas considers to be the appropriate percentage debt and equity components of the company s capital structure. We believe that term bank debt should be maintained in the range of 50 to 65% of our rate base Please discuss Stargas plans moving forward for maintaining an appropriate capital structure. As noted in 13.3 we believe that we/our customers would be fairly served should we adopt a serial conversion of the existing preferred shares and while we are not yet resolved as to the timeframes for doing so, believe that in consultation with the Commission we can continue to use the current revenue requirement model into the future Reference: Competing Heat Resources The Application, p. 9 of 10 The requested $0.50 increase in our delivery rate (from $6.85 to $7.35) will increase the average homeowners cost by $40 ($from $548 to $588). [The Application, p. 9 of 10] 14.1 Please provide the breakdown of the forecast number of customers in Test Year F2013 in each of the following rate classes: residential service, small commercial service, large commercial service. Our test year contemplates deliveries to 212 residential customers, 46 small and 6 large commercial Stargas Alter rates IRR No.1 Page 12

13 customers Please provide the average number of gigajoules consumed per year per small commercial service customer. The average consumption by residential customers is 80 gigajoules annually. 1 GJ = 39.4 Liters 1GJ = Kwh Gas Delivery Varia ble Ba s ic/other Ca rbon T Avera ge res identia l us e 80 GJ $4.32 $7.35 $ $ $ $ $1, Per liter Delivery (2) Equivalent propa ne 3,152 Liters $0.65 $2, $40.00 $ $ $2, Per Kwh Equivalent electricity 22,226 KWh's $ $1, $ n/a $2, Please provide the average cost per small commercial service customer for a full year s supply of natural gas, based on the rate of $11.67 per gigajoule. The average consumption by small commercial customers is 206 gigajoules annually. At $17.35 per gigajoule, their cost, before taxes would be $3,574 plus $300 (monthly basic charge of $25) or a total of $3, Please provide the average number of gigajoules consumed per year per large commercial service customer Please provide the average cost per large commercial service customer for a full year s supply of natural gas, based on the rate of $11.67 per gigajoule. The average consumption by large commercial customers is 2,084 gigajoules annually. At $17.35 per gigajoule, their cost, before taxes would be $36,157 plus $1,200 (monthly basic charge of $100) or a total of $37, Please provide the source of information for the average cost per liter of propane of $0.65. Obtained in a random survey of property managers at the resort; estimate reflects that input and a conversation with a representative of Superior Propane servicing the resort area. Propane prices vary dramatically by season in season prices approximated $.90 so that we believe the $.65 estimate conservative Please provide the source of information for the average cost per KwH of electricity of $ BC Hydro customers pay 6.80 cents per kwh for the first 1,350 kwh they use over an average two-month billing period and cents per kwh for the balance of the electricity used during the billing period. (Prices extracted from BC Hydro website). Residential customers at the Resort consume an average of 22,226 Kwh s. Of that consumption, 8100 KWh s are consumed at 6.80 cents (a total of $ and the balance at the price ($1,439.40) so that their total cost is $1, the average cost then is 8.9 cents per gigajoule. Stargas Alter rates IRR No.1 Page 13

14 15.0 Reference: Forecast Test Year Ended May 31, 2013 The Application, Exhibit B-2 Exhibit B-2 is a forecast balance sheet and income statement for the Test Year F Please discuss how the forecast income statement and balance sheet amounts per Exhibit B-2 for Test Year F2013 were determined. Stargas maintains an ongoing forecast of its income, cash flow and balance sheet and has done since inception of its operations in Its financial model has been modified and improved over numerous iterations. The current version has proven to be a reliable estimate of future performance For the period June July, 2012, please confirm if the amounts included in Exhibit B-2 are based on actual or forecast results. If amounts are based on forecast results, please discuss why actual results were not used. We did not introduce actual results into our test year based on the very reliable estimates available on all of the costs to be included in our revenue requirement in our existing and long proven forecast tool. The revenue amount included in forecast and the corresponding actual for the two months was $42,775 and budget $40,354. Gas costs were forecast at $13,148 and actual costs incurred were $ Operating expenses were forecast at $57,196 and actual expenditures were $56, Please provide an updated Exhibit B-2 (both income statement and balance sheet) with actual results for the period June August, Filed as IRR No.1 Attachment A We ve provided an attachment reflecting the first quarters actual and budget results, and include the test years result based on inclusion of Q1 actual rather than forecast activity Reference: Draft Order Please prepare a draft Commission order indicating the desired approvals sought by Stargas in this filing. Draft order has been attached as IRR No. Attachment B 17.0 Reference: Commodity Recovery/Cost The Application, p. 8 of 10 Mindful of the recent position of the Commission on the costs involved in hedging supply, and holding the view that supply side pressures will continue to mitigate commodity prices, we propose to accept all of our fiscal 2013 deliveries at index and will not, therefore, be filing a price mitigation strategy with the BCUC as had we in the past several years. [The Application, p. 8 of 10] 17.1 Please describe the natural gas market pricing scenarios, if any that would cause Stargas to revisit its decision to accept all fiscal 2013 deliveries at index. We do not expect to revisit our decision to accept 2013 deliveries at index In particular, describe the market place factors and the magnitude of the variance between forward prices and the estimated gas commodity prices utilized to set rates for the test year ending May 31, 2013 that might lead Stargas to consider revisiting its decision to accept all deliveries at index. Stargas Alter rates IRR No.1 Page 14

15 Not applicable Did Stargas implement the price mitigation strategy approved for fiscal year 2012 in Commission Letter L-75-11? No, we did not; as noted in our annual report, based on current and expected trends in short term deliveries, Stargas made the determination to accept all of its deliveries at index so that no forward contracts were executed for the fiscal year ended May 31, Not applicable If so, please provide on a monthly basis the volumes purchased and the applicable prices If Stargas did not implement the price mitigation strategy, please explain why not. We were to come to the belief that supply side pressures would continue to mitigate prices; our advisors supported that view and suggested that their forecasts suggested savings would be generated at index Does Stargas intend to file a price mitigation strategy for fiscal 2014 gas purchases? We do not intend to file a price mitigation strategy for fiscal 2014 at this time; we will continue to monitor gas markets and access the advice of marketers but absent significant movement in our perception of emerging market circumstances expect to take deliveries at index into the foreseeable future. Not applicable When does Stargas propose it would file a price mitigation strategy for the Test Year ending May 31, 2014? 18.0 Reference: Estimated Commodity Prices The Application, Cover Letter, p.1; The Application, Exhibit B-3 In the cover letter to the Application, Stargas states that the proposed commodity price is based on estimated volumes through the test year and index prices provided by our marketer August 10, Please provide an updated version of the table set out in Exhibit B-3 reflecting current forward prices and extending the table to October 31, Stargas Alter rates IRR No.1 Page 15

16 Month by Month US/GJ CDN/GJ CDN/GJ CDN/GJ Month NYMEX Sumas AECO Stargas June $2.19 Actual July $2.61 Actual August $2.81 $2.45 $2.16 $2.40 Actual September $2.80 $2.48 $2.26 $2.56 Estimate October $2.83 $2.66 $2.35 $2.65 Estimate November $3.05 $3.32 $2.62 $2.92 Estimate December $3.33 $3.78 $2.87 $3.17 Estimate January $3.48 $3.77 $3.01 $3.31 Estimate February $3.50 $3.71 $3.04 $3.34 Estimate March $3.47 $3.53 $3.01 $3.31 Estimate April $3.45 $3.27 $2.95 $3.25 Estimate May $3.47 $3.19 $2.97 $3.27 Estimate June $3.51 $3.21 $2.99 $3.29 Estimate July $3.55 $3.36 $3.01 $3.31 Estimate August $3.58 $3.39 $3.03 $3.33 Estimate September $3.59 $3.39 $3.04 $3.34 Estimate October $3.61 $3.50 $3.09 $3.39 Estimate Our estimate includes a $.30 transportation charge. Prices obtained from Cascadia web site October 5, Reference: Updated Commodity Component of Rates The Application, Exhibit B-4 Fortis Gas rates are forecast to increase 1 % effective January 1 st, [The Application, Exhibit B-4] The Commission notes that FortisBC Energy Inc. permanent rates for 2012 and 2013 were approved in Commission Order G dated April 12, Using the approved charges for FortisBC Energy Inc. for 2012 and 2013 and the updated forward prices provided in response to IR 18.1, please provide an updated calculation of the commodity component of the rate for the Test Year ending May 31, Please also provide the update versions of the tables entitled Forecast GCVA and Forecast of Commodity Cost shown in Exhibit B-4 of the Application. Attached as B-4 Revised Based on current forward prices and Stargas proposed commodity component for the rate, estimate the outstanding GCVA balance will be effective October 31, As originally files, a commodity price of $ would bring the May 31, 2013 GCVA balance to zero. As amended (Exhibit B4 revised is attached) the adjusted commodity price would be $ Assuming that we do not vary the commodity rate applied for ($4.32) we d have an under-recovery resulting in a GCVA debit balance of $1,680. Stargas Alter rates IRR No.1 Page 16

17 19.2 Please describe any changes Stargas proposes to the commodity component of the rate as a result of the revised inputs to the calculation of the commodity component. None: 20.0 Reference: Updates to the Commodity Component of Rates The Application, Exhibit B Please confirm that Stargas will continue to file an annual application regarding the need to alter the commodity component of rates to be effective November 1, 2013 as has been the practice in the past. We will continue an annual filing to address the balance in our Gas Cost Variance Account and forecast gas costs and will do so in the same time frame using the same methodology as have we in the past several years If not confirmed, please describe Stargas proposed reporting and commodity component review process going forward. We will submit an annual document addressing commodity costs and revenue. Attachments: Attachment A: Actual results June 1 to September 30, 2012 Attachment B: Draft Commission Order Exhibit B-3 and B-4 (Revised): Forecast of gas costs and activity in GCVA to May 31, 2012 updating pricing and delivery volume assumptions where actuals available. Stargas Alter rates IRR No.1 Page 17

18 Stargas Utilities Ltd. Forecast/Actual for Test Year 11/10/2012 Income Statement Revenue Cost of sales Forecast Actual Forecast Forecast Q1 Q1 12 months 9 months 3 mths actual Gigajoules delivered 3, , , ,578.6 Commodity recovery $ 19,247 $ 18,166 $ 177,380 $ 176,299 Delivery 22,614 21, , ,322 Basic charges 14,790 14,540 59,430 59,180 Meters and line 2,112 3,700 6,336 7,924 Sundry revenue ,888 4,250 59,188 58, , ,975 Natural gas-variable per Gj 10,401 7, , ,502 Expenses Demand/other gas costs 15,507 17,380 61,053 62,926 GCVA adjustments - 6,661-6,660-36,958-36,957 Meters and line 1,920-5,760 3,840 21,167 18, , ,311 38,021 40, , ,664 Operations & maintenance 18,569 18, , ,152 Professional fees 5,400 5,675 5,400 5,675 Office and sundry 2,979 4,287 15,768 17,076 Insurance 3,894 3,892 15,647 15,645 Management fees 28,590 28,500 77,466 77,376 Interest - term debt 4,948 3,756 19,026 17,834 Shareholder interest ,660 3,660 Other interest ,386 3,379 Amortization 13,701 13,700 54,804 54,803 79,682 79, , ,600 Income (loss) before tax - 41,661-39,508 34,911 37,064 Provision for income tax - - 8,000 8,000 Net income - 41,661-39,508 26,911 29,064 IRR Attachment A

19 IN THE MATTER OF the Utilities Commission Act, R.S.B.C. 1996, Chapter 473 and an Application to alter rates charged by Stargas Utilities Ltd. for Approval to Alter Rates BEFORE: October, 2012 WHEREAS: ORDER A. The Commission by Order C-4-00 approved a Certificate of Public Convenience and Necessity for Stargas Utilities Ltd. ( Stargas, the Company ) to operate a natural gas distribution system at the resort community of Silver Star; and B. On August 17, 2012, Stargas applied to the Commission for approval to decrease residential and commercial rates by $.98 per gigajoule ( GJ ) for the combined delivery and commodity cost component of rates, effective November 1, 2012 ( the Application ). The decrease in rates is the result of lower commodity costs and higher delivery charges; and C. The lower commodity costs are the result of decreases in the cost of natural gas and the amortization of a Gas Cost Variance Account ( GCVA ) credit balance of $36,958 at May 31, The Application requests approval to decrease the commodity charge, including the amortization of the GCVA, by $1.51/GJ, and D. The Application also requests Commission approval to increase the delivery charge by $.53 per GJ due to increases in operating and maintenance expenses as well as to include as an additional deferred charge preferred share dividend arrears arising in fiscal years prior to May 31, 2007 aggregating $135,887. The Applicant proposes amortizing the amount over twenty years, and E. The Commission, by Order G119-12, established a written hearing process to review the Application; and F. The Commission issued Information ( IR ) No. 1 on October 4, 2012 and Stargas responded on October 12, 2012; and G. The Commission has reviewed the Application by Stargas to Alter Rate and the evidence adduced thereon, all as set forth in the Reasons for Decision attached as Appendix A. NOW THEREFORE pursuant to Sections 60 and 61 of the Utilities Commission Act, the Commission orders as follows: Attachment B IRR No.1

20 1. The Commission approves the $.98 decrease in rates for the combined delivery and commodity cost components in rates on a permanent basis, effective November 1, The Commission approves the increase in delivery rates by $.53 per GJ on a permanent basis, effective November 1, The Commission approves the amortization of the Gas Cost Variance Account credit balance of $36,958 in the Stargas fiscal year ending May 31, The Commission approves the Stargas request to include in its rate base, as an additional deferred charge, preferred share dividend arrears of $135,887, and to amortize that amount as an element of its cost of service over twenty years. 5. Stargas is to provide, subject to timely filing, amended Gas Tariff Rate Schedules in accordance with this Order. DATED at the City of Vancouver, in the Province of British Columbia, this day of October, BY ORDER Commissioner Attachment B IRR No.1

21 Stargas Utilities Ltd. Forecast GCVA Fiscal Year Ended May 31, 2013 (Test Year) Exhibit B-4 REVISED Calculation - Commodity Price Effective November 1, 2012 Anticipated deliveries - June 1, 2012 to October 31, ,910.8 Anticipated deliveries - Nov 1, 2012 to May 31, ,115.5 Anticipated deliveries - Fiscal ,026.3 Allowance for lost and accounted for gas - percentage 1.35% Allowance for lost and accounted for gas - gigajoules Gas Purchases - includes allowance for lost gas 38,539.6 Forecast cost of gas - fiscal 2013 (see attached) $ 211,837 Gas Cost Variance Credit Balance - May 31, 2012 $ 36,958 Gas Costs to be recovered in Fiscal 2012 $ 174,879 BCUC currently approved price to October 31, 2012 $5.83 5,910.8 $ 34,460 Balance to be recovered - November 1 to May 31, 2013 $ 140,419 Commodity price calculated for balance of fiscal ,115.5 $ ,026.3 Proof GCVA should reduce to nil balance May 31, 2012 Balance Application Deliveries Price Recovery Cost Movement $ 36,958 Rate Recovery June 1,331.1 $5.83 $ 7,760 $ 9,205-1,445 35,513 $5.83 $ 7,760 July $5.83 5,465 $ 8,411-2,945 32,567 $5.83 5,465 August $5.83 4,940 $ 7,919-2,979 29,589 $5.83 4,940 September $5.83 4,983 $ 8,081-3,098 26,491 $5.83 4,983 October 1,940.2 $ ,311 $ 11, ,845 $ ,311 November 4,499.8 $ ,675 $ 22,143-2,469 23,376 $ ,439 December 5,941.9 $ ,980 $ 29,089-3,109 20,267 $ ,669 January 6,207.8 $ ,143 $ 30,840-3,698 16,570 $ ,818 February 5,860.0 $ ,622 $ 29,566-3,945 12,625 $ ,315 March 4,908.5 $ ,462 $ 25,416-3,954 8,671 $ ,205 April 2,955.8 $ ,924 $ 17,085-4,161 4,510 $ ,769 May 1,741.6 $4.37 7,615 $ 12,125-4,510 $ 0 $4.32 7,524 38,026.3 $ 174,879 $ 211,837-36, ,199 36,958 Recovery 210,157 Cost 211,837 $ 1,680 Based on actual deliveries June thru September and delivery volumes and commodity prices estimated as of October Prepared 10, 2010 by M.A. Blumes