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Home My WebLink About20090819Application.pdfEXECUTIVE OFFICES August 19, 2009 RECË\\t.û oM 2: 36 iUß~ ~UG \ 9 \" \OP~O cldt~~\~S\ON ü1\l\1h::S .. INTERMOUNTAIN GAS COMPANY 555 SOUTH COLE ROAD · P.O. BOX 7608. BOISE,IDAHO 83707. (208) 377-6000 . FAX: 377-6097 Ms. Jean Jewell Commission Secretary Idaho Public Utilities Commission 472 W. Washington St. P.O. Box 83720 Boise, 10 83720-0074 RE: Case No. INT-G-09-02 Dear Ms. Jewell: Attached for consideration by this Commission are the original and seven (7) copies of Intermountain Gas Company's Application for Authority to Decrease Its Prices on October 1,2009. If you have any questions regarding the attached, please contact me at (208) 377-6168. MPM/sc Enclosures cc: K.F. Morehouse E.N. Book S.W. Madison RECEtVEO 200' ~UG \ 9 PM 2t 31 INTERMOUNTAIN GAS COMP ~~o p \SlS\ON U1\L\1h:.S C '"CASE NO. INT -G-09-02 APPLICATION, EXHIBITS, AND WORKAPERS In the Matter of the Application of INTERMOUNTAIN GAS COMPAN for Authority to Decrease Its Prices on October 1, 2009 (October 1, 2009 Purchased Gas Cost Adjustment Filing) RECENED Morgan W. Richards, Jr., ISB No.1913 RICHARS LAW OFFICE 804 East Pennsylvania Lane Boise, Idaho 83706 Telephone: (208) 283-0334 Attorney for Intermountain Gas Company inU9 ~UG \ 9 PM 2: 31 f"~,~, 1 r~'~ j 1,,'--' \o.AEHSO/OL~\~~íi'ŠS\ON UT\Ll1 \ _,. iV ,BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION In the Matter of the Application of INTERMOUNTAI GAS COMPAN for Authorit to Decrease Its Prices Case No. !N -G-09-02 APPLICATION Intermountain Gas Company ("Intermountain" or "Company"), a subsidiar of MDU Resources Group, Inc. with general offices located at 555 South Cole Road, Boise, Idaho, hereby requests authority, pursuant to Idaho Code Sections 61-307 and 61-622, to place into effect October 1, 2009 new rate schedules which wil decrease its anualized revenues by $72.4 millon, puruant to the Rules of Procedure of the Idaho Public Utilities Commssion ("Commssion"). Because of changes in Intermountain's gas related costs, as described more fully in ths Application, Intermountain's earngs wil not be decreased as a result of the proposed decrease in prices and revenues. Intermountain's curent rate schedules showing proposed changes are attached hereto as Exhibit No.1 and are incorporated herein by reference. Intermountain's proposed rate schedules are attached hereto as Exhibit No.2 and are incorporated herein by reference. Communcations in reference to this Application should be addressed to: Michael P. McGrath Director - Gas Supply & Regulatory Mfairs Intermountain Gas Company Post Office Box 7608, Boise, ID 83707 and Morgan W. Richards, Jr. Richards Law Office 804 East Pennsylvana Lane Boise, ID 83706 In support of this Application, Intermountain does allege and state as follows: APPLICATION - 2 I. Intermountain is a gas utility, subject to the jursdiction of the Idaho Public Utilities Commission, engaged in the sale of and distrbution of natual gas with the State of Idaho under authority of Commission Certificate No. 219 issued December 2, 1955, as amended and supplemented by Order No. 6564, dated October 3, 1962. Intermountain provides natual gas service to the following Idaho communties and counties and adjoining areas: Ada County - Boise, Eagle, Garden City, Kuna, Meridian, and Star; Bannock County - Chubbuck, Inom, Lava Hot Springs, McCammon, and Pocatello; Bear Lake County - Georgetown, and Montpelier; Bingham County - Aberdeen, Basalt, Blackfoot, Firth, Fort Hall, Moreland/verside, and Shelley; Blaine County - Bellevue, Hailey, Ketchum, and Sun Valley; Bonneville County - Amon, Idaho Falls, Iona, and Ucon; Canyon County - Caldwell, Greenleaf, Middleton, Nampa, Parma, and Wilder; Caribou County - Bancroft, Conda, Grace, and Soda Springs; Cassia County - Burley, Declo, Malta, and Raft River; Elmore County - Glenns Ferr, Hammett, and Mountain Home; Fremont County - Parker, and St. Anthony; Gem County - Emmett; Gooding County - Gooding, and Wendell; Jefferson County - Lewisville, Menan, Rigby, and Ririe; Jerome County - Jerome; Lincoln County - Shoshone; Madison County - Rexburg, and Sugar City; Minidoka County - Heyburn, Paul, and Rupert; Owyhee County - Bruneau, Homedale; Payette County - Fruitland, New Plymouth, and Payette; Power County - American Falls; Twin Falls County - Buhl, Filer, Hansen, Kimberly, Murtugh, and Twin Falls; Washington County - Weiser. Intermountain's properties in these locations consist of transmission pipelines, a liquefied natual gas storage facility, distrbution mains, services, meters and regulators, and general plant and equipment. II. Intermountain seeks with this Application to pass though to each of its customer classes changes in gas related costs resulting from: 1) an increase in costs billed Intermountain due to higher prices charged by Northwest Pipeline GP ("Northwest" or "Northwest Pipeline") offset by a small decline in contract volumes on Northwest, 2) an increase in costs from Intermountain's APPLICATION - 3 "upstream" Canadian pipeline suppliers, 3) a decrease in the Company's projected costs relating to its storage contracts, 4) a decrease in Intermountain's Weighted Average Cost of Gas, or "WACOG"; 5) an updated customer allocation of gas related costs pursuant to the Company's Purchased Gas Cost Adjustment ("PGA") provision, 6) the inclusion of temporar surcharges and credits for one year relating to gas and interstate transportation costs from Intermountain's deferred gas cost accounts, and 7) benefits included in Intermountain's fi transportation and storage costs resulting from Intermountain's management of its storage and firm capacity rights on pipeline systems. Intermountain also seeks with this Application to eliminate the temporar surcharges and credits included in its curent prices durng the past 12 months, pursuant to Order Nos. 30649 and 30676 per Case Nos. IN-G-08-03 and INT-G-08-04. The aforementioned changes would result in an overall price decrease to Intermountain's customers. These price changes are applicable to service rendered under rate schedules affected by and subject to Intermountain's PGA, initially approved by this Commission in Order No. 26109, Case No. INT-G-95-1, and additionally approved through subsequent proceedings. Exhibit No. 3 contains pertinent excerpts from pipeline and related facilities' tarffs. Exhibit No. 4 sumarzes the price changes in: 1) Intermountain's base rate gas costs and its rate class allocation, and 2) adjusting temporar surcharges or credits flowing though to Intermountain's direct sales customers. Exhibit Nos. 3 and 4 are attached hereto and incorporated herein by reference. III. The curent prices of Intermountain are those approved by ths Commission in Order Nos. 30649 and 30676 per Case Nos. INT -G-08-03 and INT -G-08-04. IV. Intermountain's proposed prices incorporate all price changes impacting Intermountain's firm interstate transportation capacity including, but not limited to, any such changes implemented by Northwest and TransCanada's Pipelines which have occured since Intermountain's PGA filing in Case No. INT-G-08-03. Intermountain delivers transported natual gas to its Idaho Citygates via capacity leased from Northwest. Effective Januar 1, 2009, Northwest increased its rates to adjust for the higher APPLICATION - 4 number of leap year days included in its 2008 prices which, in tu, increased Northwest's 2009 full-rate capacity costs. In Case No. INT -G-08-03, Intermountain included the cost of incremental Northwest capacity which became effective November 1, 2008. The Company proposes to recover the additional cost resulting from including that same capacity for a full twelve (12) months (i.e. one additional month). Additionally, and pursuant to the contractual terms of an existing contract held by the Company on Northwest, a slight decline in the daily contracted volume on Northwest's system resulted in a decrease to the anual capacity costs charged to the Company. Also, Northwest's aforementioned leap year related price change increased the annual cost of the Company's capacity priced at a discount to (or indexed to) Northwest's full rate costs. These discounted, or indexed, contracts provide $5.4 milion in savings when compared to the otherwise full-rate cost. Intermountain also transports natural gas sourced from Alberta utilizing pipeline capacity on TransCanada's Foothils Pipeline system ("Foothills") and its Alberta system (also known as Nova Gas Transmission or "Nova") for ultimate delivery into Northwest. Both pipelines placed new rates into effect on Januar 1, 2009 resulting in an anualized increase for Nova capacity and a parially offsetting decrease at Foothils. Additionally, a contract held by the Company on the Nova pipeline expired on November 1, 2008 which results in a slight decrease to the cost incured on this pipeline. Intermountain formerly leased capacity at a Canadian storage facility known as Aeco. Aeco proposed a significant cost increase to renew the contract which caused the Company to re~ evaluate the cost-effectiveness of this facility. Intermountain determined that abundant gas supplies and suffcient market liquidity in Alberta would provide the necessar winter delivery securty at a lower cost to Intermountain's customers. Therefore, the Company determined the most economic course of action was to allow the contract to expire on March 31, 2009, thereby lowering Intermountain's fixed storage costs. Intermountain continues to utilize storage capacity at Questar Pipeline's Clay Basin storage facility and also proposes to pass back to its customers a decline in cycling fuel costs at Clay Basin reflecting the lower market price of natural gas. Intermountain continues to effectively manage its natural gas storage at Northwest's Plymouth LNG and Jackson Prairie facilities and Questar Pipeline's Clay Basin facility. Line 19 APPLICATION - 5 of Exhibit No.4, CoL. (h), contains over $2.2 milion in savings from the management of these assets which include the benefits generated from certain asset management agreements with third paries. Exhibit No.4, Lines I through 19, details the proposed changes in Intermountain's prices resulting from the aforementioned adjustments to Intermountain's cost of storage, and interstate and upstream capacity from its varous suppliers. V. The W ACOG reflected in Intermountai's proposed prices is $0.49600 per therm, as shown on Exhibit No.4, Line 21, CoL. (t). This compares to $0.67482 per therm curently included in the Company's tarffs. Driven by the downtur in our regional and national economy, weather adjusted demand for natual gas has diminished while, at the same time, natual gas supplies are plentifuL. Ths curent imbalance between supply and demand has drven down the near term prices for natural gas. Adding to this fudamental decrease, the proposed W ACOG includes the benefits to Intermountain's customers generated by Intermountain's management of signficant natual gas storage assets whereby gas is procured durng the sumer season for withdrawal and use durg the winter when prices would otherwise be higher. Additionally, and in an effort to fuher stabilize the prices paid by our customers durng the upcoming winter period, Intermountain has entered into varous hedging agreements to lock-in the price for signficant portions of its underground storage and other winter "flowing" supplies. Intermountain believes that the W ACOG proposed in ths Application, subject to the effect of actual supply and demand, wil likely materialize durg the upcoming PGA period. Intermountain will employ, in addition to those natual gas hedges already in place for the high winter demand, cost effective financial instrents to secure those prices embedded within the filed WACOG when and if those pricing opportties materialize in the marketplace. However, liquidity in the market is sustained by contrar opinions and natual gas prices could indeed realize levels different from those included in this Application. Although curent commodity futues prices dictate the use of this $0.49600 per therm W ACOG, Intermountain continues to remain vigilant in monitorig natual gas prices and is commtted to come before this Commission prior to this winter's heating season with an Application to fuher amend these APPLICATION - 6 proposed prices, should forward prices materially deviate from the $0.49600 per thermo Timely natual gas price signals and the accounting for any cost differences brought about by changes in the natual gas market, facilitated through the use of the PGA mechansm, enhance our customers' ability to make timely and inormed energy use decisions and ensure they only pay the actual cost of such supplies. It is important to continue to alert our customers in a timely maner to impending changes before their winter natual gas usage is before them. By employing the use of customer mailings and varous media resources, Intermountain wil continue to educate its customers regarding the wise and efficient use of natual gas, billing options available to help our customers manage their energy budget, and pending natual gas unt price changes. VI. Pursuant to Case No. INT-G-08-03, Intermountain has included temporar surcharges and credits in its October 1, 2008 and November 15, 2008 prices for the pricipal reason of collecting or passing back to its customers deferred gas cost charges and benefits, as outlined in Case No. !N- G-08-03. Line 26 of Exhibit No.4 reflects the elimination of these temporar surcharges and credits. VII. Intermountain's PGA tarff includes provisions whereby Intermountain's proposed prices will be adjusted for updated customer class sales volumes and purchased gas cost allocations, pursuant to the Company's approved cost of service methodology. Intermountain's proposed prices include a fixed cost collection adjustment pursuant to these PGA provisions, as outlined on Exhibit No.5, Line 24. The price impact of this adjustment is included on Exhibit No.4, Line No. 27. Exhibit No.5 is attached hereto and incorporated herein by reference. VIII. Intermountain proposes to pass back to its customers the benefits generated from the management of its transportation capacity totaling $5.9 millon as outlined on Exhibit No.7. These benefits include those generated from the release of segmented portions of Intermountain's firm capacity rights on Northwest Pipeline and other non-segmented capacity releases on Nortwest Pipeline. Intermountain proposes to pass back these credit amounts via the per therm credits, as detailed on Exhibit No.7 and included on Exhbit No.6, Line 1. Exhibit No.'s 6 and 7 are attached hereto and incorporated herein by reference. APPLICATION - 7 IX. Intermountain proposes to allocate deferred gas costs from its Account No. 186 balance to its customers through temporar price adjustments to be effective durng the 12-month period ending September 30, 2010, as follows: 1) Intermountain has been deferrng in its Account No. 186 fixed gas costs. The credit amount shown on Exhibit No.8, Line 8, CoL. (b) of $741,556 is attbutable to a tre-up of the collection of interstate pipeline capacity costs, the tre-up of expense issues previously ruled on by this Commission, and mitigating capacity release credits generated from the release of Intermountain's pipeline capacity. Intermountain proposes to collect or pass back these balances via the per therm surcharges and credits, as detailed on Exhibit No. 8 and included on Exhibit No.6, Line 2. Exhibit No.8 is attached hereto and incorporated herein by reference. 2) Intermountain has been deferrg in its Account No. 186 deferred gas cost amounts of $12.7 millon, as shown on Exhibit No.9, Line 2, CoL. (b), attbutable to Intermountain's varable gas costs since October 1, 2008. Intermountain proposes to pass back ths balance via a per therm credit, as shown on Exhibit No.9, CoL. (b), LineA and included on Exhibit No.6, Line 3. Exhibit No.9 is attached hereto and incorporated herein by reference. 3) Intermountain has been deferrng in its Account No. 186 defered gas costs related to Lost and Unaccounted for Gas as shown on Exhibit No.9, CoL. (b), Lines 5 though 20. This deferral results in net per therm decreases to both Intermountain's sales and transportation customers, as illustrated on Exhibit No.6, Line 3. Exhibit No.9 is attached hereto and incorporated herein by reference. X. Intermountain has allocated the proposed price changes to each of its customer classes based upon Intermountain's PGA provision. A straight cent per therm price decrease was not utilized for the LV -1 tarff. No fixed costs are curently recovered in the tail block of Intermountain's LV -1 tarff. Absent the proposed change to the W ACOG and the Lost and Unaccounted for Gas recovery as included on Exhibit No.9, the proposed decrease in the LV-1 tarff is fixed cost related, and therefore, a cent per therm decrease relating to fixed costs was made only to the first two blocks of the LV -1 tarff. APPLICATION - 8 XI. Each block of the proposed LV-I, T-3, T-4 and T-5 tarffs include a unform cents per therm decrease to adjust for Lost and Unaccounted for Gas as detailed on Exhibit No.9, Lines 13 through 20, CoL. (b). The prices, including the proposed adjustment for each block of the T-3, T-4 and T -5 tarffs, which include the removal of existing temporar price changes, are outlined on Exhibit No.1, Page 1, Lines 21 through 32. XII. Exhibit No. lOis an analysis of the overall price changes by class of customer. Exhibit No. lOis attached hereto and incorporated herein by reference. XIII. The proposed overall price changes herein requested among the classes of servce of Intermountain reflects a just, fair, and equitable pass-though of changes in gas related costs to Intermountain's customers. XIV. This Application is filed pursuant to the applicable statutes and the Rules and Regulations of the Commission. This Application has been brought to the attention of Intermountain's customers though a Customer Notice and by a Press Release sent to daily and weekly newspapers, and major radio and television stations in Intermountain's servce area. The Press Release and Customer Notice are attached hereto and incorporated herein by reference. Copies of this Application, its Exhibits, and Workpapers have been provided to those paries regularly intervening in Intermountain's rate proceedings. XV. Intermountain requests that this matter be handled under modified procedure pursuant to Rules 201-204 of the Commission's Rules of Procedure. Intermountain stands ready for immediate consideration of this matter. APPLICATION - 9 WHREFORE, Intermountain respectfully petitions the Idaho Public Utilities Commssion as follows: a. That the proposed rate schedules herewith submitted as Exhibit No. 2 be approved without suspension and made effective as of October 1, 2009 in the maner shown on Exhbit No. 2. b. That this Application be heard and acted upon without hearng under modified procedure, and c. For such other relief as this Commission may determine proper herein. DATED at Boise, Idaho, this 19th day of August, 2009. INTERMOUNTAIN GAS COMPAN Morgan W. Richards, Jr. By Ji ~ w - R...l..9. IT Morgan W ~ clds, Jr. .. Attorney for Intermountain Gas Company h upply & Regulatory Affairs APPLICATION - 10 CERTIFICATE OF MAING I HEREBY CERTIFY that on this 19th day of August, 2009, I served a copy of the foregoing Case No. INT -G-09-02 upon: Paula Pyron Northwest Industral Gas Users 4113 Wolf Berr Cour Lake Oswego, OR 97035-1827 Chad Stokes Cable Huston et a1. 1001 SW Fifth Avenue, Suite 2000 Portland, Oregon 97204-1136 R. Scott Pasley J. R. Simplot Company POBox 27 Boise, ID 83707 Steven Gray J. R. Simplot Company POBox 27 Boise, ID 83707 Conley E. Ward, Jr. Givens, Pursley, Webb & Huntley 277 N. 6th St., Suite 200 POBox 2720 Boise, ID 83701 by depositing tre copies thereof in the United States Mail, postage prepaid, in envelopes addressed to said persons at the above addresses. APPLICATION - 11 Ri:cr; D. .. ) '- EXHIBIT NO.3 zon; AUG l 9 PM 3: I 0 CASE NO. INT -G-09-02 INTERMOUNTAIN GAS COMPAN PERTINENT EXCERPTS FROM INTERSTATE PIPELINES AND RELATED FACILITIES (16 pages) Exhibit No.3 Case No. INT-G-09-02 Intermountain Gas Company Page 1 of 16 iJlII':6f/.~wrllliamSi€~ NORTHWEST PIPELINE P.O. Box 58900 salt Lake City, UT 84158-0900 Phone: (801) 584-6851 FAX: (801) 584-7764 November 20, 2008 Ms. Kimberly D. Bose, Secretary Federal Energy Regulatory Commission 888 First Street, N.E. Washington, D.C. 20426 Re: Northwest Pipeline GP Docket No. RP09- 9' Dear Ms. Bose: Pursuant to Part 154 of-the regulations of the Federal Energy Regulatory Commission (Commission), Northwest Pipeline GP (Northwest) tenders for filing and acceptance the following tariff sheets as part of its FERC Gas Tariff: Second Revised Sheet NO.5 First Revised Sheet No. 5-C Third Revised Sheet No. 7 First Revised Sheet NO.8 First Revised Sheet No. 8.1 Northwest proposes to replace its 2008 (leap year) daily reservation and demand rates with 2009 non-leap year rates computed on the basis of 365 days. Statement of Natures Reasons and Basis for the Filng On June 1,1997, Northwest began billng its customers for reservation and demand charges using daily rates.1 In accordance with the rate sheets in Northwest's tariff, these rates are based on a year with 365 days. For leap years the rates are computed on the basis of 366 days and, accordingly, on November 8, 2007 (Docket No. RP08-61), Northwest fied revised tariff sheets to reflect daily reservation rates computed on the basis of 366 days, effective for calendar year 2008. With Commission acceptance of the November 8,2007 filng, the daily reservation rates currently listed in Northwest's Tariff reflect a 366 day-year and need to be adjusted back to a 365 day-year. 179 FERC 1f 61,259 (1997) and 80 FERC 1f 61,124 (1997). Ms. Kimberly D. Bose November 20,2008 Page 2 of 3 Exhibit No.3 Case No. INT -G-09-02 Intermountain Gas Company Page 2 of 16 Northwest now proposes to revise daily reservation rates on the basis of 365 days, to be effective for calendar years 2009,2010 and 2011. Northwest proposes to use the daily reservation rates approved by the Commission in Docket No. RP06-416-002 that are based on a 365-day year. Note that the "Expansion Shipper - 2009 Phase" rates on Sheet No. 7 are not being revised for leap year in this filng as they were previously updated in the Jackson Prairie Phase III ("Phase III") filing submitted on November 17, 2008 in Docket No. CP06-416. The instant filing and the Phase III filing both have an effective date of January 1, 2009; therefore, Sheet No.7 is now submitted as Third Revised Sheet NO.7 due to the pending status of the Phase II filng. Effective Date and Waiver Request Northwest requests that the proposed tariff sheets be made effective January 1, 2009. Northwest also requests that the Commission grant any waivers it may deem necessary for the acceptance of this filng. Procedural Matters Pursuant to the applicable provisions in Section 154 of the Commission's regulations, Northwest submits the following materials in connection with this tiing: · The proposed tariff sheets listed above. e A redlined version of the proposed tariff sheets. · A diskette containing the proposed tariff sheets in electronic form. Service Communications An original and five copies of this filing are being provided to the Commission. Copies of this filng have been served upon Northwest's customers and upon interested state regulatory commissions. All communications regarding this filng should be served bye-mail to: Lynn Dahlberg Manager, Certificates and Tariffs (801) 584-6851 Northwest Pipeline GP P.O. Box 58900 Salt Lake City, Utah 84158-0900 Iynn.dahlberg~williams.com Amy Harward Attorney (801) 584-6326 Northwest Pipeline GP P.O. Box 58900 Salt Lake City, Utah 84158-0900 amy.harward~williams.com The undersigned certifies that the contents of this filing are true and correct to the best of her knowledge and belief; that the paper and electronic versions of the submitted Exhibit No.3 Case No. INT-G-09-02 Intermountain Gas Company Page 3 of 16 Ms. Kimberly D. Bose November 20,2008 Page 3 of 3 tariff sheets contain the same information; and that she possesses full power and authority to sign this filng. Respectfully submitted, NORTHWEST PIPELINE GP 'Í\ Çì JIll :i ~ t0õ.~LQ,tr't.~~ lynn Dahlberg Manager, Certificates and Tariffs Enclosure Northwest Pipeline GP FERC Gas Tariff Fourth Revised Volume No.1 Exhibit No.3 Case No. INT-G-09-02 Intermountain Gas Company Page 4 of 16 Second Revised Sheet No.5 Superseding First Sheet NO.5 STATEMENT OF RATES Effective Rates Applicable to Rate Schedules TF-1, TF-2, TI-l, TFL-1 and TIL-1 (Dollars per Dth) Rate Schedule and Type of Rate Base Tariff Rate Minimum Maximum ACA (2) Currently Effective Tariff Rate (3) Minimum Maximum Rate Schedule TF-l (4) (5)Reservation (Large Customer) System-Wide .00000 .37984 .00000 .3798415YearEvergreenExp..00000 .38101 .00000 .3810125YearEvergreenExp..00000 .36445 .00000 .36445Volumetric (Large Customer) System-Wide .00756 .03000 .00170 .00926 .0317015YearEvergreenExp..00369 .00369 .00170 .00539 .00539 25 Year Evergreen Exp..00369 .00369 .00170 .00539 .00539 (Small Customer)(6 ).00756 .67209 .00170 .00926 .67379 Scheduled Overrun .00756 .40984 .00170 .00926 .41154 ~ate Schedule TF-2 (4) (5)Reservation ,00000 .37984 .00000 .37984iVolumetric.00756 .03000 .00756 .03000Scheduled Daily Overrun .00756 .40984 .00756 .40984AnnualOverrun.00756 .40984 .00756 .40984 ate Schedule TI-1 Volumetric (7 ).00756 .40984 .00170 .00926 .41154 Scheduled Overrun .00756 .40984 .00170 .00926 .41154 ate Schedule TFL- 1 (4) (5)Parachute Lateral (9)Reservation .00000 .07377 .00000 .07377Volumetric.00000 . 00000 .00170 . 00170 .00170 Scheduled Overrun .00000 .07377 .00170 .00170 .07547 ate Schedule TIL-1 Parachute Lateral (9)Volumetric .00000 .07377 .00170 .00170 .07547 Scheduled Overrun .00000 .07377 .00170 .00170 .07547 Issued by: Laren M.Gertsch, Director Issued on: November 20, 2008 Effective: January i, 2009 Northwest I)ipeline GP FERC Gas Tariff Fourth Revised Volume No. i Exhibit No.3 Case No. INT-G-09-02 Intermountain Gas Company Page 5 of 16 Third Revised Sheet No.7 Superseding Second Revised Sheet No.7 STATEMENT OF RATES (Continued) Effective Rates Applicable to Rate Schedules SGS-2F and SGS-21 (Dollars per Dth) Rate Schedule and Type of Rate Currently Effective Tariff Rate (1) Minimum Maximum Rate Schedule SGS-2F (2) (3) (4) (5) Demand Charge Pre-Expansion Shipper Expansion Shipper 0.00000 0.00000 0.01551 0.08476 Capacity Demand Charge Pre-Expansion Shipper 0.00000 0.00056 Expansion Shipper - 2009 Phase o . 00000 0.00243 Volumetric Bid Rates Withdrawal Charge Pre-Expansion Shipper 0.00000 0.01551 Expansion Shipper 0.00000 0.08476 Storage Charge Pre-Expansion Shipper Expansion Shipper - 2009 Phase 0.00000 0.00000 0.00056 0.00243 Rate Schedule SGS-21 Volumetric 0.00000 0.00113 Footnotes (1) Shippers receiving service under these rate schedules are required to furnish fuel reimbursement in-kind at the rates specified on Sheet No. 14. :) Issued by: Laren M.Gertsch, Director Issued on: November 20, 2008 Effective: January i, 2009 STATEMENT OF RATES (Continued) Exhibit No.3 Case No. INT -G-09-02 Intermountain Gas Company Page 6 of 16 Second Revised Sheet No. 8.1 Superseding First Revised Slieet No. 8.1 I Northwest Pipeline GP FERC Gas Tariff Fourth Revised Volume No.1 Effective Rates Applicable to Rate Schedules LS-2F and LS-2I (Dollars per Dth) Rate Schedule and Tye of Rate Currently Effective Tariff Rate (1) Minimum Maximum Rate Schedule LS-2F (3) Demand Charge (2 )0.00000 0.03062 0.00000 0.00391 0.00000 0.03062 0.00000 0.00391 0.64110 0.64110 0.04184 0.04184 Capacity Demand Charge (2) Volumetric Bid Rates Vaporization Demand-Related Charge (2) Storage Capacity Charge (2) Liquefaction Vaporization Rate Schedule LS-21 Volumetric 0.00000 0.00783 Liquefaction Vaporization 0.64110 0.04184 0.64110 0.04184 ¡Footnotes iI (1) Shippers receiving service under these rate schedules are required to furnish fuel reimbursement in-kind at the rates specified on Sheet No. 14. (2) Rates are daily rates computed on the basis of 365 days per year, except that rates for leap years are computed on the basis of 366 days. I Issued by: Laren M.Gertsch, Director Issued on: January 21, 2009 Filed to comply with order of the Federal Energy Regulatory Commission, Docket No. RP06-416-000 , Issued March 30,2007 Effective: February 20, 2009 Northwest Pipeline GP FERC Gas Tariff Fourth Revised Volume No.1 Exhibit NO.3 Case No. INT-G-09-02 Intermountain Gas Company Page 7 of 16 Third Revised Sheet No. 14 Superseding Second Revised Sheet No. 14STATEMENT OF FUEL USE REQUIREMENTS FACTORS FOR REIMBURSEMENT OF FUEL USE Applicable to Transportation Service Rendered Under Rate Schedules Contained in this Tariff, Fourth Revised Volume No. 1 I~ The rates set forth on Sheet Nos. 5, 6, 7, 8 and 8.1 are exclusive of fuel use requirements. Shipper shall reimburse Transporter in-kind for its fuel use requirements in accordance wi th Section 14 of the General Terms and onditions contained herein. ! The fuel use reimbursement furnished by Shippers shall be as follows for the applicable Rate Schedules included in this Tariff: Ra te Schedule TF-l Rate Schedule TF-1 - Evergreen Expansion Incremental Surcharge (1) Rate Schedule TF-2 Rate Schedule TI-1 Rate Schedule TFL-l Parachute Lateral Rate Schedule TIL-l Parachute Lateral Rate Schedule SGS-2F Rate Schedule SGS-21 Rate Schedule LS-1 Rate Schedule LS-2F Rate schédule LS-2I Rate Schedule DEX-1 1.85%" 0.50% 1.85% 1. 85% 0.00% 0.00% 0.18% o .18%" 1. 72% 1. 72%" 1.72% 1.85% ,q \. + t The fuel use factors set forth above shall be calculated and adjusted as xplained in Section 14 of the General Terms and Conditions. Fuel reimbursement quantities to be supplied by Shippers to Transporter shall be Fetermined by applying the factors set forth above to the quantity of gas ominated for receipt by Transporter from Shipper for transportation, for injection into storage, or for deferred exchange, as applicable. ~ootnote ~'ii) In addition to the Rate Schedule TF-1 fuel use requirements factor, the vergreen Expansion Incremental Surcharge will apply to the quantity of gas ominated for receipt at the Sumas, SIPI or Pacific Pool receipt points under ~vergreen Expansion service agreements. I I Issued by: Laren M.Gertsch, Director Issued on: February 26, 2009 Effective: Aprill, 2009 FERC GAS TARIFF THIRD REVISED VOLUME NO. 1-A OF GAS TRASMISSION NORTHWEST CORPORATION FILED WITH THE FEDERAL ENERGY REGULATORY COMMISSION Communications Concerning This Tariff Should Be Addressed To: John A. Roscher, Director Rates and Regulatory Affairs Gas Transmission Northwest Corporation 1400 SW Fifth Avenue Suite 900 Portland, OR 97201 Telephone: (503) 833-4254 Facsimile: (503) 833 -4918 Exhibit No.3 Case No. INT-G-09-02 Intermountain Gas Company Page 8 of 16 Gas Transmission Northwest Corporation FERC Gas Tariff Third Revised Volume No. 1-A Exhibit No.3 Case No. INT-G-09-02 Intermountain Gas Company Page 9 of 16 Original Sheet No. 2 PRELIMINARY STATEMENT Gas Transmission Northwest Corporation (GTN) is a natural gas company which owns and operates a natural gas pipeline system extending from the International Boundary in the vicinity of Kingsgate, British Columbia, through parts of Idaho, Washington and Oregon to the California boundary. GTN offers open access transportation service under Part 284 of the Commission' s regulations in Third Revised Volume No. 1-A of this FERC Gas Tariff. These services include transportation services authorized by the Federal Energy Regulatory Commission as listed in the Table of Contents. Prior to January 1, 1998, GTN was known as "Pacific Gas Transmission Company" or "PGT." References to Pacific Gas Transmission Company or PGT within GTN's existing Service Agreements or similar documents shall be deemed to refer to GTN. The transportation of natural gas is undertaken by GTN only under written service agreements acceptable to GTN after consideration of its commitments, delivery capacity, and other pertinent factors. This FERC Gas Tariff is filed in compliance with Part 154, Subpart E, Title 18 of the Code of Federal Regulations. Issued by: John A Roscher, Director of Rates & Regulatory AffairsIssued on: October 7,2003 Effective on: October 6,2003 Gas Transmission Northwest Corporation FERC Gas Tariff Third Revised Volume No. 1-A Exhibit No.3 Case No. INT-G-09-02 Intermountain Gas Company Page 10 of 16 Sixteenth Revised Sheet No. 4 Superseding Fifteenth Revised Sheet No. 4 STATEMENT OF EFFECTIVE RATES AND CHARGES FOR TRASPORTATION OF NATURAL GAS Rate Schedules FTS-1 and LFS-1 RESERVATION DAILY MILEAGE (a) (Dth-MILE) DAILY NON-MILEAGE (b) (Dth) DELIVERY ( c) (Dth-MILE) FUEL (d) (Dth) MAIMUM MINIMU MAIMUM MINIMUM MAIMUM MINIMUM MAIMUM MINIMUM BASE 0.000463 0.000000 0.036632 0.000000 0.000016 0.000016 0.0050%0.0000% STF (e)(e)0.000000 (e)0.000000 0.000016 0.000016 0.0050%o . 0000% EXTENSION CHARGES MEDFORD E-1 (f)0.003290 0.000000 0.005498 0.000000 0.000026 0.000026 E-2(g) (1) 0.008298 0.000000 (WWP) 0.000000 0.000000 E-2(h) (1) 0.002972 0.000000 (Diamond 1) 0.000000 0.000000 E-2(h) (1) 0.001166 0.000000 (Diamond 2) 0.000000 0.000000 COYOTE SPRINGS E-3(i) 0.001412 0.000000 0.001420 0.000000 0.000000 0.000000 OVERRUN CHARGE (j ) SURCHARGES ACA (k)0.001700 0.001700 Issued by: John A Roscher, Director, Rates & Regulatory AffairsIssued on: November 21, 2008 Effective on: January 1, 2009 Exhibit No.3 Case No. INT -G-09-02 Intermountain Gas Company Page 11 of 16 NOVA Gas Transmission Ltd. GAS TRANSPORTATION TARIFF OF NOVA GAS TRANSMISSION LTD. Effective Date: April 29, 2009 NOVA Gas Transmission Ltd. Exhibit No.3 Case No. INT -G-09-02 Intermountain Gas Company Page 12 of 16 Table of Rates, Tolls and Charges TABLE OF RATES, TOLLS & CHARGES Service Rates, Tolls and Charges 1.Rate Schedule FT-R Refer to Attachment" 1" for applicable FT -R Demand Rate per month & Surcharge for each Receipt Point Average Firm Service Receipt Price (AFSRP)$183.99/l03m3 2.Rate Schedule FT-RN Refer to Attchment "i" for applicable FT-RN Demand Rate per month & Surcharge for each Receipt Point 3.Rate ScheduleFT-D FT-D Demand Rate per month $4.87/GJ 4.Rate Schedule STFT STFT Bid Price.Minimum bid of 100% of FT-D Demand Rate 5.Rate Schedule FT-DW FT -DW Bid Prce.Minimum bid of 125% of FT -D Demand Rate 6.Rate Schedule FT-A FT-A Commodity Rate $0.50/103m3 7.Rate Schedule FT-P Refer to Attchment "2" for applicable FT -P Demand Rate per month 8.Rate Schedule LRS Contract Term Effective LRS Rate ($/i03m3/day) 1-5 years 10.28 6-10 years 8.59 15 years 7.71 20 years 6.84 9.Rate Schedule LRS-2 LRS-2 Rate per month $50,000 10. Rate Schedule LRS-3 LRS-3 Demad Rate per month $129.55/103m3 11. Rate Schedule IT-R Refer to Attchment "1" for applicable IT-R Rate & Surcharge for each Receipt Point 12. Rate Schedule IT-D IT-D Rate $0.1759/GJ 13. Rate Schedule FCS The FCS Charge is determned in accordance with Attchment "1" to the a~plicableSchedule of Servce i9 i; 14. Rate Schedule PT Schedule No PTRate PTGas Rate 9006-01000-0 $60.50/d 1.0103m3/d 9009-01001-1 $660.00/d 50.0 103m3/d 15. Rate Schedule OS Schedule No.Charge 2008333534 $212.00 /month 2009367515 $45.00 /month 2009367513 $90.00 /month 2009227545 $9.00 /month 2009367511 $6.00 /month 2009367517 $5.00 /month 2009367518 $48.00 /month 2009367514 $146.00 /month 2009369554 $350.00 /month 2009367512 $1,671.00 /month 2009367516 $18.00 /month 2009367441 $43.00 /month 2009367265 $169.00 /month 2009367442 $88.00 /month 2009376113 $185.00 /month 2009367266 $9.00 /month 2003004522 $83,333.00 /month 16. Rate Schedule CO2 Tier CO2 Rate ($/1 03m3) 1 553.44 2 438.58 3 294.62 Effective Date: April 29, 2009 revised pursuant to NEB Order AO-I-TGI-01-2009 Foothills Pipe Lines Ltd. Exhibit No.3 Case No. INT-G-09-02 Intermountain Gas Company Page 13 of 16 Page 1 PHASE I GAS TRASPORTATION TARFF OF FOOTHILLS PIPE LINES LTD. This Gas Transportation Tariff is subject to the National Energy Board Act, is available for inspection during normal business hours and is also available electronically at ww.transcanada.com. Communications concerning this Gas Transportation Tariff should be addressed to: Foothils Pipe Lines Ltd. 450 First Street S.W. Calgary, Alberta T2P 5Hl Attention: Greg Szuch TARIFF - PHASE I Effective Date: Aprill, 2007 Foothills Pipe Lines Ltd. Exhibit No.3 Case No. INT-G-09-02 Intermountain Gas Company Page 14 of 16 Page 1 TABLE OF EFFECTIVE RATES 1. Rate Schedule FT, Firm Transportation Service Demand Rate ($/GJlKonth) Zone 6 0.0088209313 Zone 7 0.0073370959 Zone 8* 0.0092889366 Zone 9 0.0127867269 2. Rate Schedule OT, Overrun Transportation Service Commodity Rate ($/GJ/K) Zone 6 0.0003190035 Zone 7 0.0002653416 3. Rate Schedule IT, Interruptible Transportation Service Commodity Rate ($/GJ/Km) 0.0003359287Zone 8* Zone 9 0.0004624241 *For Zone 8, Shippers Haul Distance shall be 170.7 km. TARIF - PHASE I Effective Date: January 1,2009 Exhibit No.3 Case No. INT-G-09-02 Intermountain Gas Company Page 15 of 16 FERC GAS TARIFF FIRST REVISED VOLUME NO. 1 (SUPERSEDES ORIGINAL VOLUME NOS. 1, 1-A, 2 AND 2-A) of QUESTAR PIPELINE COMPANY Filed with FEDERAL ENERGY REGULATORY COMMISSION Communications regarding this tariff should be addressed to: L. Bradley Burton, Director, Federal Regulatory Affairs Questar Pipeline Company 180 East 100 South P. O. Box 45360 Salt Lake City, Utah 84145-0360 Telephone: (801) 324-2459 FAX: (801) 324-5834 Questar Pipeline Company FERC Gas Tariff First Revised Volume No. i Exhibit No.3 Case No. INT-G-09-02 Intermountain Gas Company Page 16 of 16 Twenty-Third Revised Sheet No. 6 Superseding Twenty-Second Revised Sheet No. 6 STATEMENT OF RATES Base Rate Schedule/ Type of Charge (a) Tariff Rate (bl $ Annual Charge Adjustment 4/ (c) $ CurrentlyEffective~ (d) $PEAKING STORAGE Monthly Reservation Charge Maximum ?./ Minimum Usage Charge Inj ection Withdrawal 2.87375 0.00000 2.87375/Dth O.OOOOO/Dth 0.03872 0.03872 0.03872/Dth 0.03872/Dth CLAY BASIN STORAGE Firm Storage Service - FSS Monthly Reservation Charge Deliverability Maximum 3./ Minimum Capacity Maximum Minimum Usage Charge Injection Withdrawal Authorized Overrun Charge Maximum Minimum Interruptible Storage Service - iss Usage Charge Inventory l/ Maximum Minimum Injection Withdrawal 2.85338 0.00000 2.85338/Dth O.OOOOO/Dth 0.02378 0.00000 0.02378/Dth O.OOOOO/Dth 0.01049 0.OL781 0.00170 0.01219/Dth 0.0178l/Dth 0.30315 0.01781 0.00l70 0.00170 0.30485/Dth 0.0195l/Dth 0.05927 0.00000 0.01049 0.01781 0.00170 0.05927/Dth O.OOOOO/Dth 0.01219/Dth 0.01781/Dth OPTIONAL VOLUMETRIC RELEASES ~/ Peaking Storage Service - PKS Maximum 3./ Minimum Firm Storage Service - FSS Maximum ~/ Minimum Storage Usage Charges Applicable Peaking Storage Service - PKS, Inj ection Withdrawal Clay Basin Storage Service - FSS, Injection Withdrawal 3.40890 0.00000 3.40890/Dth O.OOOOO/Dth 0.57068 0.00000 to Volumetric Releases l/ 0.57068/Dth O.OOOOO/Dth 0.03872 0.03872 0.03872/Dth 0.03872/Dth 0.01049 0.0178l 0.00170 0.01219/Dth 0.01781/Dth PARK AN LOAN SERVICE - PALl Daily Charge Maximum Minimum Delivery Charge 0.303l5 0.00000 0.02830 0.00l70 0.30315/Dth O.OOOOO/Dth 0.03000/Dth FUEL REIMBURSEMENT - 2.0% (0.2% utility and L.8% compressor fuel) for Rate Schedule PALl Issued by: Issued on: R. Allan Bradley, January 23, 2009 President and CEO Effective on:February 25,2009 EXIBITNOS.4-10 CASE NO. INT-G-09-02 INTERMOUNTAIN GAS COMPAN (7 pages) C1...."E.nRE .11::1,/ :;) 2009 AUG 19 PH 3: t 0 IDAHO pi 11,s'",¡r'N UTILITIES CO I . ti.Uì, IN T E R M O U N T A I N G A S C O M P A N Y Su m m a r y o f G a s C o s t C h a n g e s An n u a l T h e n n s l 10 / 1 / 2 0 0 8 To t a l A n n u a l An n u a l T h n n s l 10 1 1 / 2 0 0 9 To t a l A n n u a l Co s t o f S e r v i c e A l l o t i n o f G a s C o s t A d j u s t m e n t 0 1 li n e Bil l i n g D e e r m i n a n t s Pri c e s Co s t Bi l l n g D e t e r m i n a n t s Pr i c e s Co s t An n u a l No . De i p t i o n IN T . G - l 8 - D 3 IN T - G - l 8 - 3 IN T . G - l 8 - IN T . G o O 0 2 IN T - G 0 2 IN T - G . 0 9 - l 2 Dif f e r e n c e RS . 1 RS . 2 GS . 1 LV . 1 (a ) (h ) (c ) (d ) (e ) (I ) (g ) (h ) (i ) (j (k -r 1 DE M A N D C H A R G E S : 2 Tr a n s p o a t i o n : 3 NW P T F . 1 D e m a n d 1 ( F u D R a t e ) ( ~ 62 5 , 8 8 , 1 0 0 $ 0,0 3 9 2 7 $ 24 , 5 7 8 , 5 2 4 62 5 , 5 8 , 8 0 $ 0, 0 3 9 5 2 $ 24 , 7 2 0 , 0 1 6 $ 14 1 , 4 9 2 $ 16 , 5 3 9 $ 76 , 8 4 $ 47 , 6 3 7 $ 47 6 4 NW P T F . l D e m a n d 1 ( D i s c o u n t e d ) ( 3 ' 32 4 , 9 2 5 , 2 6 0 0, 0 2 6 6 4 8, 6 5 , 4 3 7 33 , 8 0 , 2 5 0 0, 0 2 6 8 6 8,9 6 5 , 8 9 2 30 , 4 5 36 , 1 7 1 16 8 , 0 5 10 4 , 1 8 7 1,0 4 1 5 Up s t e a m C a p a c t y ( 4 ' 1,2 6 5 , 7 9 5 , 0 6 0 0, 0 1 1 8 1 15 , 1 8 9 , 4 9 3 1,2 8 4 , 9 9 1 , 5 4 0,0 1 2 1 9 15 , 6 6 2 , 5 4 47 3 , 0 5 55 , 2 9 4 25 6 , 9 0 0 15 9 , 2 6 7 1,5 9 2 6 Sto r a g e : 7 SG 8 - 1 8 De m a n d 30 3 , 3 7 0 ( ~ 0, 0 0 1 5 5 17 1 , 2 9 9 ( ~ 30 3 , 3 7 0 ( ~ 0,0 0 1 5 5 17 1 , 7 4 2 ( ~ 44 52 24 1 14 9 9 Ca p a c i t y D e m a n d 10 , 9 2 0 , 9 9 0 ( " 0, 0 0 0 0 6 22 3 , 2 2 5 ( ~ 10 , 9 2 0 , 9 9 0 ( " 0,0 0 0 0 6 22 3 , 2 2 5 ( 6 ' 10 TF ~ 2 R e s e r v a t i o n 10 , 9 2 0 , 9 9 0 ( " 0,0 3 7 8 8 41 3 , 6 8 7 10 , 9 2 0 , 9 9 0 ' " 0,0 3 7 9 8 41 4 , 7 7 9 1,0 9 2 12 8 59 2 36 11 TF . 2 R e d e l i v e r y C h a r g e 10 , 9 2 0 , 9 9 0 ( " 0,0 0 3 0 32 , 7 6 3 10 , 9 2 0 , 9 9 0 ( " 0, 0 0 3 0 32 , 7 6 3 12 LS 13 De m a n d 1, 1 3 3 , 0 0 0 ( " 0,0 0 3 0 5 1, 2 6 1 , 3 1 2 ( 6 ' 1, 1 3 2 , 0 0 0 ( ~ 0,0 0 3 0 6 1,2 8 4 , 3 3 1 (~ 3,0 1 9 35 1, 6 4 0 1,0 1 6 10 14 Ca p a c i t y 10 , 9 5 5 , 2 0 0 ( " 0,0 0 0 3 9 1 , 5 5 , 4 7 3 ( ~ 10 , 9 6 2 , 2 3 5 ( " 0,0 0 0 3 9 1, 5 6 , 4 7 4 ( 0 ' 1, 0 0 1 11 7 54 33 7 3 15 Liq u e f a c t i o n 10 , 9 5 5 , 2 0 0 ( " 0,0 8 4 1 1 70 2 , 3 3 10 , 9 6 2 , 2 3 5 ' " 0,0 8 4 1 1 70 2 , 7 8 9 45 1 53 24 4 15 2 2 16 Va p o r i z a t i o n 10 , 9 5 5 , 2 0 0 ( " 0,0 4 1 8 4 45 , 3 6 6 10 , 9 6 2 , 2 3 5 ( " 0.0 4 1 8 4 45 , 6 6 0 29 4 34 16 0 99 1 17 TF - 2 R e s e r v a t i o n 10 , 9 5 5 , 1 5 0 ( ~ 0,0 3 7 8 8 41 4 , 9 8 1 10 , 9 6 2 , 2 3 5 ( ~ 0,0 3 7 9 8 41 6 , 3 4 1,3 6 16 0 74 0 46 0 5 18 TF . 2 R e d e l i v e r y C h a r g e 10 , 9 5 5 , 2 0 0 ( " 0, 0 0 3 0 32 , 8 6 6 10 , 9 6 2 , 2 3 5 ( " 0,0 0 3 0 0 32 , 8 8 7 21 2 12 7 19 Oth e r S t o r a g e F a c i l t i e s (6 8 7 , 8 6 1 ) m (8 0 , 4 0 2 ) (3 7 3 , 5 5 ) (2 3 1 , 5 8 ) (2 , 3 1 5 ) 20 CD M M O I l T Y C H A R G E S : 21 To t a l P r o d u c e / S u p p l i e r P u r c h a s e s I n c l u d i n g S t o a g e 30 5 , 2 3 2 , 3 0 3 0, 6 7 4 8 2 i " 20 5 , 9 7 6 , 8 6 3 30 5 , 2 3 2 , 3 0 3 0.9 6 0 0 15 1 , 3 9 5 , 2 2 2 (5 4 , 5 8 1 , 6 4 1 ) (5 , 7 7 3 , 8 9 7 ) (2 9 , 9 4 4 , 3 7 6 ) (1 8 , 3 8 , 5 5 2 ) (4 7 6 , 8 1 6 ) 22 TO T A L A N N U A L C O S T I l F F E R E N C E $ (5 4 , 3 3 7 , 8 1 6 ) $ (5 , 7 4 5 , 3 9 6 ) $ (2 9 , 8 1 1 , 9 6 3 ) $ (1 8 , 3 0 4 , 4 8 1 ) $ (4 7 5 , 9 9 6 ) 23 No r m a l i z e d S a l e s V o l t m e s ( 1 / 1 / 0 8 . 1 2 1 3 1 / 0 8 ) 32 , 2 8 8 , 8 7 9 16 7 , 4 5 , 3 9 9 10 2 , 8 2 1 , 5 8 2,6 6 6 , 4 6 24 Av e r g e B a s e R a t e C h a n g e $ (0 , 1 7 9 4 ) $ (0 , 1 7 8 0 3 ) $ (0 , 1 7 8 0 2 ) $ (0 , 1 7 8 5 1 ) 25 Ot h r P e r n e n t C h a n g e s P r o p o s e d : 26 El i m i n a t i o n o f T e m p o r a r C r e d i t s a n d S u r c h a r g e s f r o m C a s N o . I N T - G - 0 8 - 3 0, 0 1 2 1 5 (0 , 0 0 4 1 3 ) 0,0 0 5 1 8 (0 , 0 4 1 8 5 ) 27 Ad j u s m e n t t o F i x e d C o s t C o l l e c t i o n R a t e ( s e e E x i b i t 5 , L i n e 2 4 ) 0, 0 0 2 4 5 0, 0 0 7 8 9 0,0 1 2 4 3 (0 . 0 0 5 2 2 ) 28 To t a l P e r m a n e n t C h a n g e s P r o p o s e ( L i n e s 2 4 t h r o u g h 2 7 ) : (0 , 1 6 3 3 ) (0 , 1 7 4 2 7 ) (0 , 1 6 0 4 1 ) (0 , 2 2 5 5 ) 29 Te m p o r a r y S u r c h a r g e ( C r e d i Q P r p o s e d ( E x h i b i t N o . 6 , L i n e 4 , C o l s ( b ) . ( e ) ) (0 , 0 7 6 0 4 ) (0 , 0 6 6 7 5 ) (0 , 0 5 4 9 ) (0 , 0 6 0 4 4 ) 30 Pr o p s e d A v e r a g e P e r T h e r C h a n g e i n I n t e r m o n t a i n G a s C o m p a n y T a r i f $ (0 , 2 3 9 3 8 ) $ (0 , 2 4 1 0 2 ) $ (0 , 2 1 9 9 0 ) $ (0 , 2 8 6 2 ) (1 ) S e e W o r k a p e r N o . 5 , U n e 8 '" S e e W o r k a p e r N o , 1 ~, S e e W o r k p a p e r N o , 2 i" S e e W o r k p a p e r N o , 3 (5 ) R e p r e s e n t s N o n - A d d i t i v e D e m a n d C h a r g e D e t e r m i n a n t s i~ P r i c e R e f l e c t s D a i t y C h a r g e ; A n n u a l C h a r g e ( C o i u m n ( d ) & ( g ) ) e q u a l s P r i c e ( C o l u m n ( c ) & ( Q ) t i m e s A n n u a l T h e r m s i l l n g D e t e r m i n a n t s ( C o l u m n ( b ) & ( e ) ) t i m e s 3 6 5 , A c t u a l P r i c e s i n c l u d e 6 d e m m a l s , mS e e W o r k p a p e r N o , 4 , L i n e 3 1 , C o l u m n ( e ) i" S e e I N T . ~ 8 - 4 -o - o m Q) ~ Q ) X CO C D ( / : : CD . . C D õ ' 3 z - . o . . o c 0 Z -: J . 0 S" Z . 5. - i ' ¡ G) ø Q) i (/ 0 o e p 00 3 N "0 Q) :J-. IN T E R M O U N T A I N G A S C O M P A N Y Su m m a r y o f F i x e d G a s C o s t C h a r g e s An n u a l T h e r m s l 10 / 1 / 2 0 0 8 An n u a l Co s t o f S e r v i c e A l l o c a t i o n o f G a s C o s t A d j u s t m e n t ( 1 ) li n e Bi l l n g D e t e r m i n a n t s Pr i c e s Co s t No . De s c r i p t i o n IN T - G - 0 S - 0 3 IN T - G - 0 8 . 0 3 IN T - G - 0 8 - 0 3 RS - l RS - 2 GS - l LV . l (a ) (b ) (c ) (d ) (e ) (I ) (g ) (h ) 1 DE M A N D C H A R G E S : 2 Tr a n s p o r t t i o n : 3 NW P T F - l D e m a n d 1 ( F u l l R a t e ) 62 5 , 8 8 0 , 1 0 0 $ 0. 0 3 9 2 7 $ 24 , 5 7 8 , 5 2 4 $ 2,8 7 2 , 9 1 0 $ 13 , 3 4 7 , 8 3 4 $ 8, 2 7 5 , 0 7 3 $ 82 , 7 0 7 4 NW P T F - l D e m a n d 1 ( D i s c o u n t e d ) 32 4 , 9 2 5 , 2 6 0 0. 0 2 6 6 4 8, 6 5 6 , 4 3 7 1,0 1 1 , 8 2 5 4, 7 0 1 , 0 4 2 2, 9 1 4 , 4 4 1 29 , 1 2 9 5 Up s t r e a m C a p a c i t y 1,2 8 5 , 7 9 5 , 0 6 0 0. 0 1 1 8 1 15 , 1 8 9 , 4 9 3 1, 7 7 , 4 5 4 8,2 4 8 , 9 4 3 5, 1 1 3 , 9 8 3 51 , 1 1 3 6 Sto r a g e : 7 SG S - l 8 De m a n d 30 3 , 3 7 0 0. 0 0 1 5 5 17 1 , 2 9 9 ( 2 ) 20 , 0 2 3 93 , 0 2 7 57 , 6 3 57 6 9 Ca p a c i t y D e m a n d 10 , 9 2 0 , 9 9 0 0, 0 0 0 0 6 22 3 , 2 2 5 ( 2 ) 26 , 0 9 2 12 1 , 2 2 7 75 , 1 5 5 75 1 10 TF - 2 R e s e r v a t i o n 10 , 9 2 0 , 9 9 0 0. 0 3 7 8 8 41 3 , 6 8 7 48 , 3 5 5 22 4 , 6 6 0 13 9 , 2 8 0 1, 3 9 2 11 TF - 2 R e d e l i v e i y C h a r g e 10 , 9 2 0 , 9 9 0 0.0 0 3 0 0 32 , 7 6 3 3, 8 3 0 17 , 7 9 2 11 , 0 3 1 11 0 12 LS - l 13 De m a n d 1,1 3 3 , 0 0 0 0.0 0 3 0 5 1, 2 6 1 , 3 1 2 ( 2 ) 14 7 , 4 3 1 68 4 , 9 8 0 42 4 , 6 5 7 4,2 4 4 14 Ca p a c i t y 10 , 9 5 5 , 2 0 0 0. 0 0 0 3 9 1, 5 5 9 , 4 7 3 ( 2 ) 18 2 , 2 8 2 84 6 , 9 0 1 52 5 , 0 4 2 5,2 4 8 15 Liq u e f a c t i o n 10 , 9 5 5 , 2 0 0 0. 0 6 4 1 1 70 2 , 3 3 8 82 , 0 9 4 38 1 , 4 1 9 23 6 , 4 2 2,3 6 3 16 Va p o r i z a t i o n 10 , 9 5 5 , 2 0 0 0. 0 4 1 8 4 45 8 , 3 6 6 53 , 5 7 7 24 8 , 9 2 5 15 4 , 3 2 2 1,5 4 2 17 TF - 2 R e s e r v a t i o n 10 , 9 5 5 , 1 5 0 0. 0 3 7 8 8 41 4 , 9 8 1 48 , 5 0 6 22 5 , 3 6 4 13 9 , 7 1 5 1,3 9 6 18 TF - 2 R e d e l i v e i y C h a r g e 10 , 9 5 5 , 2 0 0 0, 0 0 3 0 0 32 , 8 6 6 3, 8 4 2 17 , 8 8 11 , 0 6 5 11 1 19 Ot h e r S t o r a g e F a c i l t i e s 3,9 5 5 , 8 9 1 46 2 , 3 9 2 2,1 4 8 , 3 2 2 1, 3 3 1 , 8 6 5 13 , 3 1 2 20 To t a l F i x e d G a s C o s t C h a r g e s $ 57 , 6 5 0 , 6 5 5 $ 6,7 3 8 , 6 1 3 $ 31 , 3 0 8 , 2 8 4 $ 19 , 4 0 9 , 7 6 4 $ 19 3 , 9 9 4 21 No r m a l i z e d S a l e s V o l u m e s ( I N T - G - 0 9 - 0 2 E s t i m a t e d V o l u m e s ) 32 , 8 4 2 , 3 9 3 17 1 , 0 0 8 , 2 6 8 10 5 , 2 3 1 , 3 8 7 2,6 0 8 , 5 8 1 22 Fix e d C o t C o l l e c t i o n p e r T h e r m ( L i n e 2 0 d i v i d e d b y L i n e 2 1 ) $ 0, 2 0 5 1 8 $ 0. 1 8 3 0 8 $ 0, 1 8 4 4 5 $ 0.0 7 4 3 7 23 Cu r r e n t F i x e d C o s t C o l l e c t i o n p e r T h e r m $ 0. 2 0 2 7 3 $ 0, 1 7 5 1 9 $ 0, 1 7 2 0 2 $ 0,0 7 9 5 9 - 24 Dif f e r e n c e ( L i n e 2 2 m i n u s L i n e 2 3 ) $ 0. 0 0 2 4 5 $ 0. 0 0 7 8 9 $ 0. 0 1 2 4 3 $ (0 , 0 0 5 2 2 ) (1 ) S e e W o r k p a p e r N o . 5 , L i n e 8 (2 ) P r i c e R e f l e c t s D a i l y C h a r g e ; A n n u a l C h a r g e ( C o l u m n ( d ) ) e q u a l s P r i c e ( C o l u m n ( c ) ) t i m e s A n n u a l T h e r m s ( C o l u m n ( b ) ) t i m e s 3 6 5 . -o - ( ) m Ql ; a Q l X CC ( l C / : : (I ~ ( I õ ' .. ~ z ; : o c : 0 Z -: J . 0 .. o o Z . 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IN T E R M O U N T A I N G A S C O M P A N Y Pr o p o s e d T e m p o r a r y S u r c h a r g e s ( C r e d i t s ) - F i x e d C o s t s De f e r r e d Ac c o u n t 1 8 6 0 Es t i m a t e d Co s t o f S e r v i c e A l l o c a t i o n o f D e f e r r e d G a s C o s t s ( 2 ) Li n e Se p t . 3 0 , 2 0 0 9 No . De s c r i p t i o n Ba l a n c e (1 1 RS - 1 RS - 2 GS - 1 LV - 1 (a ) (b ) (c ) (d ) (e ) (t ) 1 Fix e d C o s t s : 2 Fr o m I N T - G - 0 8 - 0 3 ( A c c o u n t s 1 8 6 0 . 2 0 5 0 - 2 0 9 0 ) $ 15 6 , 2 2 9 $ (3 5 , 4 3 3 ) $ 52 , 6 9 8 $ 13 8 , 2 7 6 $ 68 8 3 Fi x e d C o s t C o l l e c t i o n A d j u s t m e n t ( A c c o u n t s 1 8 6 0 . 2 2 0 0 ) (3 1 8 , 6 1 7 ) (2 1 3 , 3 9 1 ) (3 9 6 , 2 8 6 ) 31 7 , 5 6 6 (2 6 , 5 0 6 ) 4 Ca p a c i t y R e l e a s e s & P u r c h a s e s ( A c c o u n t 1 8 6 0 . 2 3 2 0 ) (9 6 4 , 4 0 7 ) (1 1 2 , 7 2 7 ) (5 2 3 , 7 3 9 ) (3 2 4 , 6 9 6 ) (3 , 2 4 5 ) 5 In t e r e s t ( A c c o u n t s 1 8 6 0 . 2 4 3 0 ) 21 , 6 4 7 2, 5 3 0 11 , 7 5 6 7, 2 8 8 73 6 Ma r k e t S e g m e n t a t i o n ( A c c o u n t 1 8 6 0 . 2 5 3 0 ) (8 , 8 3 6 , 9 0 7 ) (1 , 0 4 4 , 3 7 2 ) (4 , 8 0 0 , 0 0 5 ) (2 , 9 6 2 , 2 1 1 ) (3 0 , 3 1 9 ) 7 Am o r t i z a t i o n o f 1 8 6 0 . 2 5 3 0 ( A c c u n t s 1 8 6 0 . 2 5 4 0 - 1 8 6 0 . 2 5 5 0 ) 9, 2 0 0 , 4 9 9 1, 0 4 1 , 4 1 6 4, 9 6 3 , 7 7 3 3, 1 6 3 , 8 6 4 31 , 4 4 6 8 To t a l F i x e d C o s t s $ (7 4 1 , 5 5 6 ) $ (3 6 1 , 9 7 7 ) $ (6 9 1 , 8 0 3 ) $ 34 0 , 0 8 7 $ (2 7 , 8 6 3 ) 9 No r m a l i z e d S a l e s V o l u m e s ( 1 / 1 / 0 8 - 1 2 1 3 1 / 0 8 ) 32 , 2 8 8 , 8 7 9 16 7 , 4 5 5 , 3 9 9 10 2 , 8 2 1 , 5 6 5 2, 6 6 6 , 4 6 0 10 Pr o p o s e d T e m p o r a r y S u r c h a r g e ( C r e d i t ) ~ F i x e d C o s t s $ (0 . 0 1 1 2 1 ) $ (0 . 0 0 4 1 3 ) $ 0. 0 0 3 3 1 $ (0 . 0 1 0 4 5 ) (1 ) S e e W o r k p a p e r N o . 6 (2 ) S e e W o r k p a p e r N o . 5 , L i n e 8 "' - ( ) m Ql ; a Q l X (Q C D e n : : CD ' C D õ ' .- g z ; : o c : 0 Z -: : . 0 .- Q ) Z . :5 " - ; ( X G) 6 Ql i en 0 () e p 00 3 N "0Ql:: -o Exhibit No, 9 Case No. INT-G-09-02 Intermountain Gas Company Page 1 of 1 INTERMOUNTAIN GAS COMPANY Proposed Temporary Surcharges (Credits). Variable Costs Line No.Description (a) Amount (b) 1 Account 1860 Variable Amounts Which Apply to RS.1, RS.2, GS.1, and LV.1: 2 Account 1860 Variable Costs (1)$(12,659,176) 3 Normalized Sales Volumes (1/1/08 - 12/31/08)305,232,303 4 Proposed Temporary Surcharge (Credit). Variable Costs $(0.04147) 5 Lost and Unaccounted For Gas Amounts Which Apply to RS.1, RS.2, and GS.1: 6 Lost and Unaccounted For Gas Amounts from INT-G-08-03 (Account 1860-2120) (2)$1,996,095 7 Lost and Unaccounted For Gas Amortization (Account 1860-2130) (3)(2,032,178) 8 (Over)/Under Collection of Lost and Unaccounted For Gas from INT-G-08-03 (36,083) 9 Lost and Unaccounted For Gas INT-G-09-02 (4)(606,648) 10 Total Lost and Unaccounted For Gas Amounts Which Apply to RS-1, RS-2, and GS-1 $(642,731) 11 Normalized Sales Volumes (1/1/08 -12131/08)302,565,843 12 Proposed Temporary Surcharge (Credit) . Lost and Unaccounted For Gas Costs $(0.00212) 13 Lost and Unaccounted For Gas Amounts Which Apply to LV.1, T.3, T.4, and T.5: 14 Lost and Unaccounted For Gas Amounts from INT-G-08-03 (Account 1860-2120) (5)$665,365 15 Lost and Unaccounted For Gas Amortization (Account 1860-2140) (6)(715,977) 16 (Over)/Under Collection of Lost and Unaccounted For Gas from INT-G-08-03 (50,612) 17 Lost and Unaccounted For Gas INT-G-09-02 (7 (203,420) 18 Total Lost and Unaccounted For Gas Amounts Which Apply to LV-1, T-3, T-4 and T-5 $(254,032) 19 Normalized Sales Volumes (1/1/08 - 12/31/08)225,852,844 20 Proposed Temporary Surcharge (Credit). Lost and Unaccounted For Gas Costs $(0.00112) (1) See Workpaper No.6, Page 1, Line 17, Column (D (2) See Workpaper No.6, Page 1, Line 19, Column (c) (3) See Workpaper NO.6, Page 1, Line 25, Column (d) (4) See Workpaper NO.6, Page 1, Line 40, Column (d) plus Line 46, Column (e) (5) See Workpaper No.6, Page 1, Line 20, Column (c) (6) See Workpaper NO.6, Page 1, Line 29, Column (d) (7) See Workpaper No.6, Page 1, Line 41, Column (d) plus Line 50, Column (e) IN T E R M O U N T A I N G A S C O M P A N Y An a l y s i s o f A n n u a l i z e d P r i c e C h a n g e b y C l a s s o f S e r v i c e No r m a l i z e d V o l u m e s f o r T w e l v e M o n t h s E n d e d D e c e m b e r 3 1 , 2 0 0 8 Av e r a g e P r i c e s E f f e c t i v e pe r C a s e N o . l N T - G - 0 8 . 0 3 & I N T - G - 0 8 - 0 4 Co m m i s s i o n O r d e r N o s . 3 0 6 4 9 & 3 0 6 7 6 Pr o p o s e d Ad j u s t m e n t s E f f e c t i v e 10 / 1 / 2 0 0 9 Pr o p o s e d A v e r a g e P r i c e s Ef f e c t i v e 1 0 / 1 / 2 0 0 9 li n e No . An n u a l Th e r m s l C D V o l s . (b ) De s c r i p t i o n (a ) $J h e r m (d ) Re v e n u e (c ) Re v e n u e (e ) $/ T h e r m (f ) Re v e n u e (g ) $/ T h e r m (h ) Ga s S a l e s : 2 RS - 1 R e s i d e n t i a l 32 , 2 8 8 , 8 7 9 $ 38 , 2 9 6 , 2 2 5 $ 1. 1 8 6 0 5 $ (7 , 7 2 9 , 3 1 2 ) $ (0 . 2 3 9 3 8 ) $ 30 , 5 6 6 , 9 1 3 $ 0. 9 4 6 6 7 3 RS - 2 R e s i d e n t i a l 16 7 , 4 5 5 , 3 9 9 18 1 , 4 3 9 , 5 9 9 1.0 8 3 5 1 (4 0 , 3 6 0 , 1 0 0 ) (0 . 2 4 1 0 2 ) 14 1 , 0 7 9 , 4 9 9 0. 8 4 2 4 9 4 GS - 1 G e n e r a l S e r v i c e 10 2 , 8 2 1 , 5 6 5 10 4 , 9 2 7 , 3 5 1 1.0 2 0 4 8 (2 2 , 6 1 0 , 4 6 2 ) (0 . 2 1 9 9 0 ) 82 , 3 1 6 , 8 8 9 0. 8 0 0 5 8 5 LV - 1 L a r g e V o l u m e 2. 6 6 6 . 6 0 2, 2 9 4 . 8 6 2 0. 8 6 0 6 4 (7 6 2 , 6 6 1 ) (0 . 2 8 6 0 2 ) 1. 5 3 2 . 2 0 1 0. 5 7 4 6 2 6 To t a l G a s S a l e s 30 5 . 2 3 2 . 3 0 3 32 6 . 9 5 8 . 0 3 7 1. 0 7 1 1 8 (7 1 , 4 6 2 . 5 3 5 ) (0 . 2 3 4 1 3 ) 25 5 . 9 5 . 5 0 2 0.8 3 7 0 5 7 T - 3 T r a n s p o r t a t i o n 62 , 2 2 8 , 1 6 2 1, 3 0 6 , 1 6 9 0. 0 2 0 9 9 (2 6 9 , 4 4 8 ) (0 . 0 0 4 3 3 ) 1, 0 3 6 , 7 2 1 0.0 1 6 6 6 8 T - 4 T r a n s p o r t a t i o n 13 8 , 8 4 6 , 0 4 1 6, 4 2 5 , 7 9 5 0. 0 4 6 2 8 (6 0 1 , 2 0 3 ) (0 . 0 0 4 3 3 ) 5, 8 2 4 , 5 9 2 0. 0 4 1 9 5 9 T- 5 T r a n s p o r t a t i o n ( D e m a n d ) 66 0 , 8 4 0 55 6 , 7 7 8 0. 8 4 2 5 3 - - 55 6 , 7 7 8 0. 8 4 2 5 3 10 T- 5 T r a n s p o r t a t i o n ( C o m m o d i t y ) 22 , 1 1 2 , 1 8 1 12 5 . 3 7 6 0. 0 0 5 6 7 (9 5 , 7 4 6 ) (0 . 0 0 4 3 3 ) 29 , 6 3 0 0. 0 0 1 3 4 11 To t a l T - 5 (1 ) 22 . 1 1 2 1 8 1 68 2 . 1 5 4 0. 0 3 0 8 5 (9 5 . 7 4 6 ) (0 . 0 0 4 3 3 ) 58 6 . 4 8 0. 0 2 6 5 2 12 To t a l T r a n s p o r t a t i o n 22 3 . 1 8 6 . 3 8 4 8. 1 4 , 1 1 8 0. 0 3 7 7 0 (9 6 6 , 3 9 7 ) (0 . 0 0 4 3 3 ) 7. 4 4 7 . 7 2 1 0. 0 3 3 3 7 13 To t a l 52 8 4 1 8 6 8 7 $ 33 5 3 7 2 1 5 5 $ 06 3 4 6 7 $ 17 4 2 8 9 3 2 ) $ 10 1 3 7 0 Z l $ 26 2 9 4 3 2 2 3 $ 04 9 7 6 0 Ii ) D e m a n d v o l u m e s r e m o v e d f r o m t h e $ / t e r m c a l c u l a t i o n s Pe r c e n t Ch a n g e (i ) -2 0 . 1 8 % -2 2 . 2 4 % -2 1 . 5 5 % -3 3 . 2 3 % -2 1 . 8 6 % -2 0 . 6 3 % -9 . 3 6 % 0.0 0 % -7 6 . 3 7 % -1 4 . 0 4 % -1 1 . 4 9 % -2 1 . 6 0 % "U - ( ) m Ql a Q l X co C D e n : : CD - ' C D f r .. g z : : o C 0 Z -: : . 0 .. ~ ~ ~ øø Ql i en 0 () e p 00 3 I ' "0 Ql ::-. WORKAPERNOS.1-8 CASE NO. INT -G-09-02 INTERMOUNTAIN GAS COMPAN (9 pages) RECEIVED 2009 AUG I 9 PH 3: " IDAHO PUBLIC "TI'll"'C:'" i"'r.~j-,I' . r'U ' , L. . _. ;,¡¡lo '~Sl¡ ii"- "'...v..v 'Hl_. .\J....t,..j¡~ Workpaper No.1 Case No. INT-G-09-02 Intermountain Gas Company Page 1 of 1 INTERMOUNTAIN GAS COMPANY Summary of Northwest Pipeline TF-' Full Rate Demand Costs Line INT -G-08-03 INT -G-08-03 INT -G-08-03 No.Transportation Annual Therms Prices Annual Cost (a)(b)(c)(d) 1 TF-1 Demand 1 Contract #1 412,537,600 $0.038979 $16,080,303 2 TF-1 Demand 1 Contract #2 25,550,000 0.051407 1,313,449 3 TF-1 Demand 1 Contract #3 73,000,000 0.038313 2,796,849 4 TF-1 Demand 1 Contract #4 23,542,500 0.037883 891,861 5 TF-1 Demand 1 Contract #5 54,750,000 0.038313 2,097,637 6 TF-1 Demand 1 Contract #6 36,500,000 0.038313 1,398,425 7 Total Annual Cost 625,880,100 $0.039270 $24,578,524 Line INT -G-09-02 INT-G-09-02 INT -G-09-02 No.Transportation Annual Therms Prices Annual Cost (a)(b)(c)(d) 8 TF-1 Demand 1 Contract #1 412,537,600 $0.039065 $16,115,781 9 TF-1 Demand 1 Contract #2 25,550,000 0.055264 1,411,995 10 TF-1 Demand 1 Contract #3 73,000,000 0.038414 2,804,222 11 TF-1 Demand 1 Contract #4 23,542,500 0.037984 894,238 12 TF-1 Demand 1 Contract #5 54,450,700 0.038414 2,091,669 13 TF-1 Demand 1 Contract #6 36,500,000 0.038414 1,402,111 14 Total Annual Cost 625,580,800 $0.039515 $24,720,016 15 Total Annual Cost Difference (Row 14 minus Row 7)$141,492 (1) (1) See Exhibit 4, Line 3, Column (h) Workpaper No.2 Case No. INT-G-09-02 Intermountain Gas Company Page 1 of 1 INTERMOUNTAIN GAS COMPANY Summary of Northwest Pipeline TF-' Discounted Demand Costs Line INT -G-08-03 INT -G-08-03 INT-G-08-03 No.Transportation Annual Therms Prices Annual Cost (a)(b)(c)(d) 1 TF-1 Demand 1 Contract #1 43,680,000 $0.037883 $1,654,729 2 TF-1 Demand 1 Contract #2 28,470,000 0.022730 647,123 3 TF-1 Demand 1 Contract #3 29,404,400 0.020637 606,819 4 TF-1 Demand 1 Contract #4 54,750,000 0.015911 871,127 5 TF-1 Demand 1 Contract #5 36,500,000 0.022730 829,645 6 TF-1 Demand 1 Contract #6 36,500,000 0.026518 967,907 7 TF-1 Demand 1 Contract #7 95,620,860 0.032201 3,079,087 8 Total Annual Cost 324,925,260 $0.026641 $8,656,437 Line INT -G-09-02 INT -G-09-02 INT -G-09-02 No.Transportation Annual Therms Prices Annual Cost (a)(b)(c)(d) 9 TF-1 Demand 1 Contract #1 43,680,000 $0.037984 $1,659,141 10 TF-1 Demand 1 Contract #2 28,470,000 0.022790 648,831 11 TF-1 Demand 1 Contract #3 29,404,400 0.020691 608,406 12 TF-1 Demand 1 Contract #4 54,750,000 0.015953 873,427 13 TF-1 Demand 1 Contract #5 36,500,000 0.022790 831,835 14 TF-1 Demand 1 Contract #6 36,500,000 0.026589 970,499 15 TF-1 Demand 1 Contract #7 104,495,850 0.032286 3,373,753 16 Total Annual Cost 333,800,250 $0.026860 $8,965,892 17 Total Annual Cost Difference (Row 16 minus Row 8)$309,455 (1) (1) See Exhibit 4, Line 4, Column (h) Workpaper No.3 Case No. INT-G-09-02 Intermountain Gas Company Page 1 of 1 INTERMOUNTAIN GAS COMPANY Summary of Upstream Capacity Costs line INT-G-08-03 INT-G-08-03 INT-G-08-03 No.Transportation Annual Therms Prices Annual Cost (a)(b)(c)(d) 1 Upstream Agreement #1 190,501,320 $0.015280 $2,910,860 2 Upstream Agreement #2 155,624,370 0.005945 925,187 3 Upstream Agreement #3 155,025,220 0.016505 2,558,691 4 Upstream Agreement #4 300,643,200 0.015281 4,594,129 5 Upstream Agreement #5 292,803,000 0.005941 1,739,543 6 Upstream Agreement #6 191,197,950 0.015487 2,961,083 7 Total Annual Cost $15,689,493 8 Estimated Upstream Capacity Release Credits $(500,000) 9 Total Annual Cost Including Capacity Release Credits $15,189,493 line INT -G-09-02 INT-G-09-02 INT-G-09-02 No.Transportation Annual Therms Prices Annual Cost (a)(b)(c)(d) 10 Upstream Agreement #1 189,697,800 $0.016724 $3,172,506 11 Upstream Agreement #2 155,624,370 0.005449 847,997 12 Upstream Agreement #3 155,025,220 0.016505 2,558,691 13 Upstream Agreement #4 300,643,200 0.016724 5,027,957 14 Upstream Agreement #5 292,803,000 0.005445 1,594,312 15 Upstream Agreement #6 191,197,950 0.015487 2,961,083 16 Total Annual Cost $16,162,546 17 Estimated Upstream Capacity Release Credits $(500,000) 18 Total Annual Cost Including Capacity Release Credits $15,662,546 19 Total Annual Cost Difference (Row 18 minus Row 9)$473,053 (1) (1) See Exhibit 4, Line 5, Column (h) Workpaper No.4 Case No. INT-G-09-02 Intermountain Gas Company Page 1 of 1 INTERMOUNTAIN GAS COMPANY Summary of Other Storage Facility Costs INT -G-08-o3 Line Montly INT -G-oø.03 INT -G-oS-3 INT -G-08-o3 No.Storage Facilities Billng Determinant Prices Monthly Cost Annual Cost (a)(b)(c)(d)(e) 1 Demand Costs - 2 Clay Basin i Reservation 266,250 (1)$0.285338 $75,971 $911,652 3 Clay Basin II Reservation 221,840 (1)0.28538 63,299 759,588 4 Clay Basin ILL Reservation 213,010 (1)0.265338 60,780 729,360 5 Clay Basin i Capacity 31,950,000 (2)0,002378 75,977 911,724 6 Clay Basin II Capacity 26,625,000 (2)0,002378 63,314 759,768 7 Clay Basin ill Capacity 25,560,000 (2)0,002378 60,782 729,384 8 AECODemand 26,064,970 (2)0,001865 48,611 291,666 9 Total Demand Costs 110,199,970 (3)$448,734 $5,093,142 10 Cycling Costs - 11 Clay Basin i & II Cycling Costs 58,575,000 $0.001165 $68,222 $818,663 12 Clay Basin ill Cycling Costs 25,560,000 0,001156 29,539 35,462 13 Total Cycling Costs 84,135,000 $97,761 $1,173,125 14 Storage Demand Charge Credit $(2,310,376) 15 Total Costs Including Storage Credit $3,955,891 INT -G-09-02 Line Montly INT -G-09-o2 INT -G-09-2 INT -G-09-o2 No.Storage Facilities Biling Determinant Prices Monthly Cost Annual Cost (a)(b)(c)(d)(e) 16 Demand Costs - 17 Clay Basin I Reservation 266,250 (1)$0,285338 $75,971 $911,652 18 Clay Basin II Reservation 221,840 (1)0.285338 63,299 759,588 19 Clay Basin ILL Reservation 213,010 (1)0.285338 60,780 729,360 20 Clay Basin i Capacity 31,950,00 (2)0,002378 75,977 911,724 21 Clay Basin II Capacity 26,625,00 (2)0,002378 63,314 759,768 22 Clay Basin ILL Capacity 25,560,000 (2)0,002378 60,782 729,384 23 AECO Demand (4) 24 Total Demand Costs 84,135,000 (3)$400,123 $4,801,476 25 Cycling Cost - 26 Clay Basin i & II Cycling Costs 58,575,000 $0.000679 $39,766 $477,195 27 Clay Basin ILL Cycling Costs 25,560,000 0,000673 17,200 206,402 28 Total Cycling Costs 84,135,000 $56,96 $683,597 29 Estimated Storage Demand Charge Credit $(2,217,043) 30 Total Costs Including Storage Credit $3,268,030 31 Total Annual Cost Difference Including Storage Credit (Row 30 minus Row 15)$(687.861) (5) (1) Charge Based on Maximum Daily Withdrawal (2) Charge Based on Maximum Contractual Capacity (3) Non Additive Billng Determinants; Includes only Capacity Volumes (4) Reflects a March 31, 209 contract tennination, (5) See Exhibit 4, Une 19, Column (h) Workpaper No.5 Case No. INT-G-09-02 Intermountain Gas Company Page 1 of 1 INTERMOUNTAIN GAS COMPANY Peak Day Analysis for Demand Allocators Line Peak Firm Sales Total No.Description RS.'RS.2 GS.'LV-'Peak Sales (a)(b)(c)(d)(e)in DEMAND ALLOCATORS PER CASE NO. INT-G.08.03: 2 Peak Day Thenns 442,643 2,034,413 1,255,491 12,850 3,745,397 3 Percent of Total ~~~~100.0000% 4 PROPOSED DEMAND ALLOCATORS PER CASE NO.INT-G.09-02 : 5 Peak Day Usage Per Customer 7.12 9.67 42.87 6 January 2009 Actal Customers 62,688 214,451 29,989 307,128 7 INT.G-09-02 Peak Day Thenns (Line 5 mulitplied by Line 6)446,339 2,073,741 1,285,628 12,850 (1)3,818,558 8 Percent ofT otal ~~~~100.0000% (1) Contract Demand Thenns INTERMOUNTAIN GAS COMPANV Anysis of Accunt 186 Surcrg (Crert)Estni septmber 30, 209 UfO im Denpton lal ACCOUNT 1860 VARIABLE AMOUNTS, Ne cuulatve De Ga Baanc in 1862010 as of iON10 Am in 1860.200 as of 61Est Th Saes 711 tlgh 9IAmioRat Est Amn in 186.200 at 9~Esma Bala in 186.210 at 9~ 8 Deer Gas Co From Proutrsupier in 186.2180 at 1lY1O 9 Oe Ga Cos Fro PrucupJîin 186.2180tth 6I 10 Esma De Co in 1860.2180frm 7/1 itgh 9~ 11 Estma Baan in 180.2180 at 910/ 12 Daly Ga Exc Sales Deered in 180.2240 at 61Ml 13 Int Defe In 186 at iON10 14 IntDein1860.23tt6l 15 Esat Int frm 7/1 tlh9l916 EstmatBaancinl86.2at9l0A 17 ESTIMATED ACCOUNT 1860 VARIBLE BAlACE AT 91301 18 ACCOUNT 1860 lOST AND UNACCOUNTED FOR AMOUNTS, 19 Co CumWd De Gas Baanc in 186.2120 as d lB!1J0 20 lrdusbal Cumulail Def Gas 8a in 1860.2120 as of 101110 21 Ne cuulat Derr Ga Balan in 1862120 as of 10/iV 22 Co Amo in 1860.2130 as of 6l923 EslmaTh Sa 71 tlYh 9J9 24 AmornRa 25 EsmafAminl86.2130at9l 26 Indu Amoriz in 186.2140 as of6/927 Esmate Th saies 7/1 ttug 91928 AmörRa 29 EsatAminl860.2140at9l 3D Estat Balane in 186(.2120 at 9/ 31 Lost &Unaur For Ga Del in 186.2150 at 1lY10 32 Tot Los & Una For Ga ttu¡o 6~33 Estma los & Una For Ga 7/1 thgh QI9 34 Estma Tot los & Unnt Ftt Ga at9l 35 Ba RaCoec of los & UnacrtFttGalhhßl 36 Esma Base Rat Colle of lo & Unaccnt For Ga 7/1 tth 9/ 37 Esma Ba Rat Colle of lo & Unant RiGBat9l38 Esmatlo&UnacntFttDe(TotIeBaRaCo1~1J0tl9l) 39 Esmat BaIMC in 1860.2150 at QI 40 ce Alloc of lo & Unant For Ga Defer 41 Indus Allocio of lost& Unacounted FttGa De 42 Estmat Baanc in 186.2150 at 9101 43 Co los & Unaun For Int De in 186.2420 at 1~110 44 Calo& Unant Fa-Int De in 1860.242 throh 6'9 45 Esat Co Inl fr 7/1 thh9l46 Estat Baan in 1860.2420 at 9/ 47 Indual lost & Unaccll For Int Defe in 1B623 at 1onlO 48 Indus lo & Unacc ForlntDein 1860.23 tti, 6~ 49 Estma Indusballo & UII Ftt Int fr 71 thh 9I 50 Esma Bala in 186.23& at 91 (8,694.43 (8,263.35 29.99 (1,104.17) ~,45,60'.84) 828.801,161,649.14 1,40,06 0.0367 52,815.90 1,215,2984 16,712.64 3,756,40.10 10,788,983 0.0238 25,719.81 4,031,83.55 (27,nO.74)2,99314.33 12,02,9480.03 38,423,29 3,35,966.88 693.80 $1,561.48 627,68o.oon 48,31 2,738.59 156,229.02 51 ESTIMATED ACCOUNT 1860 lOST AND UNACCOUNTEO FOR BALANCE AT 913109 52 ACCOUNT 186 FIXED AMOUNTS, 53 Net cuulat De Ga Bala in 1862050 at 10110 54 R8-1.DeGas Btin 1860.20 at 1~1108 55 AmonfoRS1 in 186.20l at 6~956 Esmat RS1 Ther Sas 7/1 thh 9I9 57 R8-1AmRe. 58 EstRS1Bainl860.206at9J 59 R8-2 De Ga Baanc in 1860.2070 at 1011108 60 Amo fo R8-2 in 1860.2070at6J61 Esma RS2 Th Sales 7/1 thh 9J 62 R8-2AmatooRa 63 Estma RS2 Balance in 1860.2070 at 9~ 64 GS1 Def Ga Ba in 1880.20 at 10/110 65 Amio fo GS1 in 186.2080 at6l66 Estma Th sa 7/1 tl 9J67 Gs1AiRae 68 Estma Gs1 Baanc in 1860.2080 at 9I 69 Indusl De Ga Banc in 186.20 at 101110 70 Ama1nfalV.1in1860.209at6l 71 Estma LV.1 Bl 1 &21l sales 7/1 tmh!ß 72 lV.1AmatonRa73 Esma Indusl Bae in 186,200 at 9/ 74 Estat cuulatve Baance in 186.Z0 at 91Ml Workpaper No.6 Case No. INT-G-09-02 Intermountain Gas Company Page 1 of 2 (8,781.98 Del Del Aii'"~Tota(b ie --(e)(l 699,486.63 (9,20,627.18)8,185,5270 (318,617.45 (9,407.04 (9,407.04) INTERMUNTAIN GAS COMPANY Anasis of Acount 186 Sureharges (Credit) Estimated Septmbe 30, 200 Uno!j Deript (a) Fix Co Coleon Deered in 186.22 at 10110FIX Co Co De in 186.22 thgh 6l9EsFixCosCoIlecDeferfr711thugh9l9 Estmat Baanc ki 180.2200 at 9101 Ca Releaas Deer in 186.230 .10/10C8 ReIse De in 186.230ttgh 6JEsat Caac Releaur De fr 7/1 tth 9l Estat Balanc in 186.232 at 9J 9 Int in 186143 at 111110 10 Int Def in 1860243 lth 6/911 Estmalrtfr7/1tlh9l12 Esma Bala in 186.243 at 9101 13 Mat Senton Deer in 186.2530 at 10/.114 Maret Se Defer in 1860.253 ttrh 6/ 15 EstrnatDein186.2fr711Ihh9J9 16 EsmatBatiiin186.25at9l 17 R8-1Amin186.25at6/18 EstatRS.l Th8alesfrm 7/1 tlTh9l0919 R8-1AmaRat 20 EstmaR8-1Amin1860.254at9J 1,402,068 0.0321 21 R8-2Amocnin1860.25atôJ 22 Estma RS2 Th Sa fr 7/1 tlrh 9I 23 RS.2AmoonRa24 Estmat RS2Amoron in 186.25 at9l 10,788,983 0.029 25 QS1 Amatnin 1860.25at 6I9 26 EsmatGS1 Th Sa fr 711 thh9/9 27 081 Amorn Rat 28 EsmatGS1Amain186.2at9l 12,02,940.03 29 Estmat Co Amorizon in 186.25 at 9J 30 LV-1Anin1860.255el6l31 Estma LV-1 Bloc 1&2 tJsaie fr 7/1 tlT 9I32 LV-1AmcRa 33 Estin LV-1 Amoio in 18602550 at 9~9 62,68 0.01165 34 Esma Indstl Aiio in 1860.25 at 9/30 35 Estma Balanc in 180.2530 at 9101 36 ESTMATEO ACCOUNT 1860 FlED BALACE AT 91310 '" TOTAL DEFERRED ACCOUNT 186 BALANCE Workpaper No.6 Case No. INT-G-09-02 Intermountain Gas Company Page 2 of2 Workpaper No.7 Case No. INT-G-09-02 Intermountain Gas Company Page 1 of 1 INTERMOUNTAIN GAS COMPANY Analysis of LV-' Tariff Block " Block 2, and Block 3 Adjustments Line No.Description (a) LV-1 Therm Sales (1/1/08 -12/31/08) 2 Blocks 1 and 2 Therm Sales 3 Percent Therm Sales betwen Blocks 1 and 2 4 Proposed Adjustment to LV-1 Tariff (1) 5 LV-1 Therm Sales (1/1/08 -12/31/08) 6 Annualized Adjustment (Line 4 multiplied by Line 5) 7 Annualized Adjustment (Line 4 multiplied by Line 5) 8 Percent Annualized Sales included in Block 1 and Block 2 9 Adjustment to Block 1 and 2 (Line 7 multiplied by Line 8) 10 Block 1 and 2 Therms 11 Price Adjustmentlherm Block 1 and 2 (Line 9 divided by Line 10) 12 WACOG Commodity Charge Change (2) 13 Total Price Adjustmentlherm Block 1 and Block 2 14 Price Adjustmentlherm Block 3 (3) 15 WACOG Commodity Charge Change (2) 16 Eliminate INT-G-08-03 Variable Temporary 17 Total Price Adjustmentlherm Block 3 Block'Block 2 Block 3 Therm Sales Therm Sales ThermSales (b)(c)(d) 2,666,460 0 0 2,666,60 0 100.000%0.000% (1) See Exhibit NO.4; Line 30, Column (I) minus the difference of Line 21, Column (f) minus Line 21, Column (c) (2) See Exhibit No.4; Line 21, Column (f minus Line 21, Column (c) (3) See Exhibit NO.6, Line 3, Column (e) Total (e) 2,666,460 2,666,460 100.000% $(0.10720) 2,666,460 $(285,845) $(285,845) 100.000% $(285,845) 2,666,60 $ $ (0.10720) (0.17882) (0.28602) $(0.04259) (0.17882) (0.05427) (0.27568)$ Workpaper No.8 Case No. INT -G-09-02 Intermountain Gas Company Page 1 of 1 INTERMOUNTAIN GAS COMPANY Analysis of Lost and Unaccounted for Gas ("L&U") Line No.Description (a) Detail (b) Amount (c) 1 Lost and Unaccounted for Gas INT-G-09-02 (Therms) 2 3 Projected Oct 08 - Sep 09 L&U (Therms) Estimated Oct 08 - Sep 09 Sales 1 2,414,773 531,960,560 4 Oct 08 - Sep 09 L&U Factor (line 2 divided by line 3)0.454% 5 Lost and Unaccounted for Gas INT -G-09-02 (Dollars) 6 Lost & Unaccounted for Gas (1860~2150) 2 $1,544,745 7 Estimated Oct 08 - Sep 09 Sales 1 531,960,560 8 L&U rate per therm embedded in base rates $0.00182 9 Oct 08 - Sep 09 Collection of Lost & Unaccounted for Gas 968,168 10 Projected L&U (Over)/Under Collection (Line 6 minus Line 9)$576,577 1 Estimated Oct 08 - Sep 09 Sales (Therms) RS-1 RS-2 GS-1 Industrial Total Sales 32,794,951 169,525,601 105,810,539 223,829,469 531,960,560 2 See Workpaper No.6, Page 1, Line 34, Column (c)