20080815Application.pdf

EXECUTIVE OFFICES
INTERMOUNTAIN GAS COMPANY
555 SOUTH COLE ROAD. P.O. BOX 7608. BOISE, IDAHO 83707. [phone]. FAX: [phone]
12: 55
August 15, 2008
Ms. Jean Jewell
Commission Secretary
Idaho Public Utilities Commission
472 W. Washington St.
P.O. Box 83720
Boise, 10 83720-0074
RE: Intermountain Gas Company
Case No. INT-G-08-03
Dear Ms. Jewell:
Enclosed for filing with this Commission are a signed original and seven copies of
Intermountain Gas Company's Application and supporting Workpapers for Authority to
Change Its Prices on October 1, 2008.
Please acknowledge receipt of this filing by time stamping and returning a photocopy of this
Application cover letter to us.
If you have any questions or require additional information regarding this Application,
please contact me at [phone].
MPM/sc
Enclosures
cc: W. C. Glynn
E. N. Book
12:56
INTERMOUNTAIN GAS COMPANH¡iii.
iJ~rtLi'fi E;,:;
CASE NO. INT -G-08-03
APPLICATION,
EXHIBITS,
AND
WORKAPERS
In the Matter of the Application of INTERMOUNTAIN GAS COMPAN
for Authority to Change Its Prices on October 1, 2008
(October 1, 2008 Purchased Gas Cost Adjustment Filing)
Stephen R. Thomas, ISB No. 2326
MOFFATT, THOMAS, BARTT, ROCK &
FIELDS, CHARTERED
Post Office Box 829
Boise, Idaho 83701
Telephone: [phone]
Facsimile: [phone]
MTBR&F 11-500.0340
Attorney for Intermountain Gas Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
In the Matter of the Application of
INTERMOUNTAI GAS COMPAN
for Authori to Chan e Its Prices
Case No. INT -G-08-03
APPLICATION
Intermountain Gas Company ("Intermountain"), an Idaho corporation with general offces
located at 555 South Cole Road, Boise, Idaho, hereby requests authority, pursuant to Idaho Code
Sections 61-307 and 61-622, to place in effect October 1, 2008 new rate schedules which wil
increase its anualized revenues by $54.3 millon, pursuant to the Rules of Procedure of the Idaho
Public Utilities Commission ("Commission"). Because of changes in Intermountain's gas related
costs, as described more fully in this Application, Intermountain's earngs will not be increased as
a result of the proposed changes 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.
Communications in reference to ths Application should be addressed to:
Michael P. McGrath
Director - Gas Supply & Regulatory Affairs
Intermountain Gas Company
Post Office Box 7608, Boisei ID 83707
and
Stephen R. Thomas
Moffatt, Thomas, Barett, Rock & Fields, Charered
Post Office Box 829
Boise, ID 83701
APPLICA nON - 2
In support of this Application, Intermountain does allege and state as follows:
I.
Intermountain is a gas utility, subject to the jursdiction of the Idaho Public Utilities
Commssion, engaged in the sale of and distrbution of natual gas withn 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, Morelandlverside, and Shelley;
Blaine County - Bellevue, Hailey, Ketchum, and Sun Valley;
Bonnevile 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 - Heybur, Paul, and Rupert;
Owyhee County - Bruneau, Homedale;
Payette County - Fruitland, NewPlymouth, and Payette;
Power County - American Falls;
Twin Falls County - Buhl, Filer, Hansen, Kimberly, Murugh, 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 through to each of its customer classes a
change in gas related costs resulting from: 1) a decrease in costs billed Intermountain pursuant to
APPLICATION - 3
the Settlement of the General Rate Case filed by Gas Transmission Nortwest Corporation ("Gas
Transmission Northwest" or "GTN"); 2) the procurement of discounted interstate transportation on
Northwest Pipeline GP ("Nortwest" or "Northwest Pipeline"); 3) benefits included in
Intermountai's firm transportation and storage costs resulting from Intermountain's management
of its storage and firm capacity rights on pipeline systems including Northwest Pipeline, GTN and
TransCanada's BC system; 4) an increase 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 provision and; 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. Exhibit NO.3 contains pertinent excerpts from pipeline and related facilities' tarffs.
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 Case No. INT-G-07-03. The
aforementioned changes would result in an overall price increase to Intermountain's customers.
These price changes are applicable to servce rendered under rate schedules affected by and
subject to Intermountain's Purchased Gas Cost Adjustment ("PGA"), intially approved by this
Commission in Order No. 26109, Case No. INT-G-95-1, and additionally approved though
subsequent proceedings.
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 through to
Intermountain's direct sales and transportation customers. Exhibit No.'s 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
No.s 30443 & 30599 and Case No.s IN-G-07-03 & INT-G-08-01.
N.
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 GTN which have occured since Intermountain's last PGA fiing
in Case No. INT-G-07-03.
APPLICATION - 4
Intermountain transports natural gas from Alberta on the Gas Transmission Northwest
system from the international border at Kingsgate to the interconnection with Northwest Pipeline
at Stanfield. On June 30, 2006, GTN filed a general system rate case with the Federal Energy
Regulatory Commission in Docket No. RP06-407-000. The FERC suspended the effective date
ofGTN's proposed rates until Januar 1,2007, subject to refud and conditions and the outcome
ofthe FERC hearng. Intermountain's prices as approved in Case No. INT-G-07-03 are reflective
of GTN's Januar 1, 2007 prices. The outcome of GTN's General Rate Case is now final
resulting in lower shipper prices which first became effective November 1, 2007 and as later
revised effective Januar 1, 2008. Intermountain proposes with this Application to incorporate
GTN's lower prices which became effective November 1, 2007 and as later revised January 1,
2008.
TransCanada's BC system, formally known as Alberta Natual Gas ("ANG") and now
known as Foothils Pipeline System ("Foothils") and its Alberta system also known as Nova Gas
Transmission ("Nova"), implemented price changes durng 2008. Foothills tarff prices decreased
effective April 1, 2008 largely reflecting a settlement stemming from the banptcy of a shipper
on the Foothills system while Nova's tarff prices increased relating to a revenue requirement
settlement with the Alberta Energy and Utilities Board. Also, Intermountain's capacity costs have
increased on these Canadian pipelines due to the tightening exchange rate between U.S. and
Canadian curencies.
Intermountain's review of the adequacy of its interstate transportation and storage
services is performed on an anual basis under design weather and certain load growth
assumptions. A summary of the methodology incorporated within this review was included in the
Company's Integrated Resource Plan, which is curently on fie with this Commission.
Intermountain's adequacy review included analyzing pipeline capacity which indicated a need to
procure additional Northwest Pipeline capacity in order to more closely align deliveries from
upstream pipelines with Intermountain's take-away rights on Northwest at its Stanfield
interconnect with GTN. Intermountain was able to obtain this capacity at a price equal to 85% of
Northwest's maximum TF-1 Rate generating an anual savings to Intermountain's customers of
approximately $595,000.
APPLICATION - 5
Rows 3 through 5 of Exhibit No. 4 includes the costs for this incremental discounted
capacity as well as the aforementioned price changes on GTN's and TransCanada's pipelines.
Intermountain continues to effectively manage its natural gas storage at Northwest's
Plymouth LNG and Jackson Prairie facilities, Questar Pipeline's Clay Basin facility and
Intermountain's use of the Aeco storage facility in Alberta, Canada. Rows 6 through 19 of
Exhibit No.4, Colum (h), contains over $600,000 in savings from the management of these
assets which include the benefits generated from certain asset management agreements with third
parties.
Exhibit No.4, Lines 1 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 WACOG reflected in Intermountain's proposed prices is $0.78484 per therm, as shown
on Exhibit No.4, Line 21, Colum (t). Ths compares to $0.63583 per therm curently included in
the Company's tarffs.
The world wide demand for all energy is at an all time high. This demand, when coupled
with constraints being placed on production, is drving the price of all energy to record highs.
The proposed WACOG 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 durng 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 significant portions of its underground storage and other winter "flowing" supplies.
Intermountain believes that the W ACOG proposed in this Application, subject to the effect
of actual supply and demand, wil likely materialize durg the upcoming PGA period.
Intermountain wil 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 withi the filed
W ACOG when and ifthose 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 ths Application. Although curent
APPLICATION - 6
commodity futues prices dictate the use of this $0.78484 per therm WACOG, Intermountain
continues to remain vigilant in monitoring natual gas prices and is committed to come before ths
Commssion prior to this winter's heating season with an Application to fuher amend these
proposed prices, should forward prices materially deviate from the $0.78484 per thermo
Timely natual gas price signals and the accounting for any cost differences brought about
by changes in the natual gas market, facilitated though the use of the PGA mechansm, enhance
our customers' ability to make timely and informed 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 will continue to educate its
customers regarding the wise and efficient use of natual gas, billng options available to help our
customers manage their energy budget, and pending natual gas unt price changes.
VI.
Pursuant to Case No. INT-G-07-03, Intermountain has included temporar surcharges and
credits in its October 1, 2007 prices for the principal reason of collecting or passing back to its
customers deferred gas cost charges and benefits, as outlned in Case No. INT-G-07-03. 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
wil be adjusted for updated customer class sales volumes and purchased gas cost allocations,
pursuant to the Company's approved cost of servce 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 Exhbit 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 over $9.0 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, other capacity releases on Northwest Pipeline and upstream releases
on the aforementioned Canadian pipelines. Intermountain proposes to pass back these credit
APPLICATION -7
amounts via the per therm credits, as detailed on Exhibit No. 7 and included on Exhibit No.6, Line
1. Exhibit No. ' s 6 and 7 are attached hereto and incorporated herein by reference.
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 30,2009, 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 $8.5 million is predominantly attbutable
to the collection of interstate pipeline capacity costs, the tre-up of expense issues previously ruled
on by this Commission, refuds attbutable to the Settlement of GTN's General Rate Case and
mitigating capacity release credits from Intermountain's upstream 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 deferrng in its Account No. 186 deferred gas cost
amounts of $18.0 milion, as shown on Exhibit No.9, Lines 2 though 18, CoL. (b), attbutable to
Intermountain's varable gas costs since October 1, 2007. Intermountain proposes to collect ths
balance via a per therm surcharge, as shown on Exhibit No.9, CoL. (b) and included 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 increase 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 unaccounted for
gas recovery as included on Exhibit No.9, the proposed increase in the LV-1 tarff is fixed cost
related, and therefore, a cent per therm increase relating to fixed costs was made only to the fist
two blocks of the LV-1 tarff.
XI.
Each block of the proposed LV-I, T-3 and T-4 tarffs include a unform cents per therm
increase for unaccounted for gas recovery as detailed on Exhibit No.9, Lines 13 through 20, CoL.
APPLICATION - 8
(b). The prices, including the proposed adjustment for each block of the T -3 and T -4 tarffs which
include the removal of existing temporar price changes, are outlined on Exhibit No.1, Page 1,
Lines 21 though 28.
Additionally, the LV-I, T-3 and T-4 tarffs were updated to reflect the elimination of the T-
1 and T-2 tarffs pursuant to Case No. INT-G-08-01 as approved by this Commssion in Order No.
30599.
XII.
The proposed increase to the T -5 Tarff Demand Charge is fixed cost related and reflects the
removal of a fixed cost temporar credit curently included in the T-5 Demand Charge.
Additionally, the T -5 Commodity Charge includes a uniform cents per therm increase for
unaccounted for gas recovery as detailed on Exhibit No.9, Lines 13 through 20, CoL. (b) and also
outlned on Exhbit No.1, Page 1, Lines 29 through 32.
XIII.
Exhibit No. 10 is an analysis of the overall price changes by class of customer. Exhibit No.
lOis attached hereto and incorporated herein by reference.
XI.
The proposed overall price changes herein requested among the classes of service of
Intermountain reflects a just, fair, and equitable pass-though of changes in gas related costs to
Intermountain's customers.
XV.
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 through 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 intervenig
in Intermountain's rate proceedings.
APPLICATION - 9
XV.
Intermountain requests that ths matter be handled under modified procedure pursuant to
Rules 201-204 of the Commission's Rules of Procedure. Intermountain stands ready for imediate
consideration of this matter.
APPLICATION - 10
WHREFORE, Intermountain respectfully petitions the Idaho Public Utilities Commission
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, 2008 in the maner shown on Exhibit No.
2.
b. That this Application be heard and acted upon without hearing under modified procedure,
and
c. For such other relief as this Commssion may determine proper herein.
DATED at Boise, Idaho, this 15th day of August, 2008.
By
Stephen
Attorne
omas
or Intermountain Gas Company
INTERMOUNTAI GAS COMPAN
APPLICATION - 11
CERTIFICATE OF MAING
I HEREBY CERTIFY that on this 15th day of August, 2008, I served a coPY of the
foregoing Case No. INT -G-08-03 upon:
Paula Pyron
Nortwest Industral Gas Users
4113 Wolf Berr Cour
Lake Oswego, OR 97035-1827
Edward A. Finklea
Cable Huston Benedict Haagensen & Lloyd LLP
1001 SW Fifth Avenue, Suite 2000
Portland, Oregon 97204-1136
R. Scott Pasley
J. R. Simplot Company
PO Box 27
Boise, ID 83707
Steven Gray
1. 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 -12
EXHIBIT NO.3 54
CASE NO. INT -G-08-03
INTERMOUNTAIN GAS COMPANY
PERTINENT EXCERPTS FROM INTERSTATE PIPELINES AND RELATED
FACILITIES
(33 pages)
Williams Northwest Pipeline Corporation
("Northwest Pipeline" or "Northwest")
Applicable Filings, Tariffs and Rate Schedules
Exhibit NO.3
Case No. INT-G-08-03
Intermountain Gas Company
Page 1 of 33
Exhibit NO.3
Case No. INT -G-08-03
Intermountain Gas Company
Page 2 of 33
Willíåi6i€~
NORTHWEST PIPELINE
P.O. Box 58900
Salt lake City, UT 84158-0900
Phone: [phone]
FAX: [phone]
November 8,2007
Ms. Kimberly D. Bose, Secretary
Federal Energy Regulatory Commission
888 First Street, N.E.
Washington, D.C. 20426
Re: Northwest Pipeline GP
Docket No. RP07-
Dear Ms. Bose:
Pursuant to Part 154 of the regulations of the Federal Energy Regulatory Commission
(Commission), Northwest Pipeline GP (Northwest) tenders for filng and acceptance the
following tariff sheets as part of its FERC Gas Tariff:
Thirty-Third Revised Sheet NO.5
Eighth Revised Sheet No. 5-C
Sub Seventeenth Revised Sheet No. 7
Eighteenth Revised Sheet NO.8
Sixteenth Revised Sheet No. 8.1
Northwest proposes to change its daily reservation and demand rates to reflect 2008 leap
year rates computed on the basis of 366 days.
Statement of Nature, Reasons and Basis for the Filng
On June 1, 1997, Northwest began biling 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, except that such rates for leap years are computed on the
basis of 366 days. Since 2008 is a leap year, Northwest is filing revised tariff sheets to reflect
daily reservation rates to be effective for calendar year 2008 that are computed on the basis
of 366 days.
Northwest has derived the daily rates for 2008 by multipJying the daily reservation rates
approved by the Commission in Docket No. RP06-416-002 by 365 and dividing by 366.
Northwest verified that these proposed rates wil render the annual revenue accepted by the
Commission in Docket No. RP06-416-002.
1 79 FERC ,r 61,259 (1997) and 80 FERC ,r 61,124 (1997).
Exhibit NO.3
Case No. tNT -G-08-03
Intermountain Gas Company
Page 3 of 33
Ms. Kimberly D. Bose
November 8, 2007
Page 2 of3
Note that the "Expansion Shipper - 2008 Phase" rates on Sheet No. 7 are not being revised
for leap year in this filing because they were updated in the Jackson Prairie Phase II ("PhaseII" filing submitted on October 31,2007 in Docket No. CP04-416. The instant filing and the
Phase II filng both have an effective date of January 1, 2008; therefore, Sheet NO.7 is now
submitted as Substitute Seventeenth Sheet No. 7 due to the pending status of the Phase ilfilng. .
Effective Date and Waiver Request
Northwest requests that the proposed tariff sheets be made effective January 1, 2008.
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 filng:
· The proposed tariff sheets listed above.
· A redlined version of the proposed tariff sheets.
· A diskette containing the proposed tariff sheets in electronic form.
Service and Communications
An original and five copies of this filng are being provided to the Commission. Copies of
this filing 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
[phone]
Northwest Pipeline GP
P.O. Box 58900
Salt Lake City, Utah 84158-0900
Iynn.dahlberg~willams.com
Amy Harward
Attorney
[phone]
Northwest Pipeline GP
P.O. Box 58900
Salt Lake City, Utah 84158-0900
amy .harward~wiliams. com
Exhibit NO.3
Case No. INT-G-Q8-Q3
Intermountain Gas Company
Page 4 of 33
Ms. Kimberly D. Bose
November 8,2007
Page 3 of 3
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 tariff
sheets contain the same information; and that she possesses full power and authority to
sign this filng.
Respectfully submitted,
NORTHWEST PIPELINE GP~Lyn~berg
Manager, Certificates and Tariffs
Enclosures
Northwest Pipdine GP
FERC Gas Tariff
Fourth Revised Volume No. i
Exhibit NO.3
Case No. INT -G-08-03
Intermountain Gas Company
Page 5 of 33
Original Sheet No.5
STATEMENT OF RATES
Effective Rates Applicable to
Rate Schedules TF-l, TF-2, TI-l, TFL-l and TIL-l
(Dollars per Dth)
Rate Schedule and
Tye of Rate
Base
Tariff Rate
Minimum Maximum ACA (2)
Currently
Effective
Tariff Rate (3)
Minimum Maximum
IRate Schedule TF-l (4) (5)Reservation
(Large Customer)
System-Wide .00000 .37883 .00000 .37883
15 Year Evergreen Exp..00000 .37995 .00000 .37995
25 Year Evergreen Exp..00000 .36344 .00000 .36344Volumetric
(Large Customer)
System-Wide .00756 .03000 .00190 .00946 .03190
15 Year Evergreen Exp..00369 .00369 .00190 .00559 .00559
25 Year Evergreen Exp..00369 .00369 .00190 .00559 .00559
(Small Customer)(6 ).00756 .67209 .00190 .00946 .67399
Scheduled Overrun .00756 .40984 .00190 .00946 .41174
IRate Schedule TF-2 (4) (5)Reservation
Volumetric
Scheduled Daily Overrun
Annual Overrun
Rate Schedule TI- 1
Volumetric (7)
Scheduled Overrun
IRate Schedule TFL- 1 (4) (5)Parachute Lateral (9)
Reservation
Volumetric
Scheduled Overrun
IRate Schedule TIL-1
Parachute Lateral (9)
Volumetric
Scheduled Overrun
.00000
.00756
.00756
.00756
.00756
.00756
.00000
.00000
.00000
.00000
.00000
.37883
.03000
.40984
.40984
.00000
.00756
.00756
.00756
.37883
.03000
.40984
.40984
.41174
.41174
.07357
.00190
.07567
.07567
.07567
Issued by: Laren M.Gertsch, Director
Issued on: December 19, 2007 Effective: January 31, 2008
.40984
.40984
.00190
.00190
.00946
.00946
.07357
.00000
.07377
.00190
.00190
.00000
.00190
.00190
.07377
.07377
.00190
.00190
.00190
.00190
Exhibit NO.3
Case No. INT-G-08-03
Intermountain Gas Company
Page 6 of 33
Northwest Pipeline GP
FERC Gas Tariff
Fourth Revised Volume No. i
Original Sheet No. 7
STATEMENT OF RATES (Continued)
Effective Rates Applicable to Rate Schedules SGS-2F and SGS-2I
(Dollars per Dth)
Rate Schedule and
Tye of Rate
Currently EffectiveTariff Rate (1)
Minimum Maximum
Rate Schedule SGS-2F (2) (3)
Demand Charge
Pre-Expansion Shipper 0.00000 0.01547
Interim Best-Efforts Withdrawal Charge
Expansion Shipper 0.00000 0.01547
Capacity Demand Charge
Pre-Expansion Shipper
Expansion Shipper - 2008 Phase
0.00000
0.00000
0.00056
0.00264
Volumetric Bid Rates
Withdrawal Charge
Pre-Expansion Shipper 0.00000 0.01547
Storage Charge
Pre-Expansion Shipper
Expansion Shipper - 2008 Phase
0.00000
0.00000
0.00056
0.00264
Rate Schedule SGS-2I
Volumetric 0.00000 0.00113
Footnotes
(1) Shippers recei ving 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: December 19, 2007 Effective: January 3 i, 2008
Northwest Pipeline GP
FERC Gas Tariff
Fourth Revised Volume No. i
Exhibit NO.3
Case No. INT-G-08~03
Intermountain Gas Company
Page 7 of 33
Qriginal Sheet No.8
STATEMENT OF RATES (Continued)
Effective Rates Applicable to Rate Schedule LS- 1
(Dollars per Dth)
Tye of Rate
Currently Effective
Tariff Rate (1)
Demand Charge (2 )
Capacity Charge (2)0.03054
0.00390
Liquefaction
Vaporization 0.64110
0.04184
Footnotes
(1).Shippers recei ving service under this rate schedule are required to
furnish fuel reimbursement in-kind at the rate 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.
Issued by: Laren M.Gertsch, Director
Issued on: December 19, 2007
Filed to comply with order of the Federal Energy Regulatory Commission,
Docket No. RP06-416-00 , Issued March 30,2007
Effective: January 3 I, 2008
118 FERC 11 61.272 (2007)
Northwest Pipeline GP
FERC Gas Tanff
Fourth Revised Volume No. i
Exhibit NO.3
Case No. INT-G-08-03
Intermountain Gas Company
Page 8 of 33
Onginal Sheet No. 8.1
STATEMENT OF RATES (Continued)
Effective Rates Applicable to Rate Schedules LS-2F and LS-2I
(Dollars per Dth)
Rate Schedule and
Type of Rate
Currently Effective
Tariff Rate (1)
Minimum Maximum
Rate Schedule LS-2F (3)
Demand Charge (2)0.00000 0.03054
0.00000 0.00390
0.00000 0.03054
0.00000 0.00390
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-2I
Volumetric 0.00000 0.00783
Liquefaction
Vaporization 0.64110
0.04184
0.64110
0.04184
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.
(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.
(3) Rates are also applicable to capacity release service. (Section 22 of
the General Terms and Conditions describes how bids for capacity release
will be evaluated.) The Vaporization Demand-Related Charge and Storage
Capacity Charge are applicable to Replacement Shippers bidding for
capacity released on a one-part volumetric bid basis.
Issued by: Laren M.Gertscb, Director
Issued 00: December 19, 2007
Filed to comply witb order of the Federal Energy Regulatory Commission,
Docket No. RP06-416-00 , Issued March 30,2007
Effective: January 3 I, 2008
118 FERC ,r 61,272 (2007)
Northwest Pipeline GP
FERC Gas Tariff
Fourth Revised Volume No. i
Exhibit No.3
Case No. INT -G-08-03
Intermountain Gas Company
Page 9 of 33
STATEMENT OF FUEL USE REQUIREMENTS FACTORS
FOR REIMBURSEMENT OF FUEL USE
First Revised Sheet No. 14
Superseding
Original Sheet No. i 4
Applicable to Transportation Service Rendered Under
Rate Schedules Contained in this Tariff, Third Revised Volume No. 1
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 with Section 14 of the General Terms and
Conditions contained herein.
The fuel use reimbursement furnished by Shippers shall be as follows for
the applicable Rate Schedules included in this Tariff:
Rate Schedule TF- 1
Rate Schedule TF-1 - Evergreen Expansion
Incremental Surcharge (1)
Rate Schedule TF- 2
Rate Schedule TI-1
Rate Schedule TFL- 1
Parachute Lateral
Rate Schedule TIL- 1
Parachute Lateral
Rate Schedule SGS-2F
Rate Schedule SGS-2I
Rate Schedule LS-1
Rate Schedule LS-2F
Rate Schedule LS-2I
Rate Schedule DEX-l
1. 99%
0.50%
1.99%
1.99%
0.00%
0.00%
0.27%
0.27%
2.03%"
2.03%
2.03%
1. 99%
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
determined by applying the factors set forth above to the quantity of gas
nominated for receipt by Transporter from Shipper for transportation, for
injection into storage, or for deferred exchange, as applicable.
Footnote
(1) In addition to the Rate Schedule TF-1 fuel use requirements factor, the
Evergreen Expansion Incremental Surcharge will apply to the quantity of gas
nominated for receipt at the Sumas, SIPI or Pacific Pool receipt points under
Evergreen Expansion service agreements.
Issued by: Laren M.Gertsch, Director
Issued 00: February 25, 2008 Effective: April i, 2008
TransCanada Pipelines Alberta System or
Nova Gas Transmission ("Nova or NGTL")
Applicable Filings, Tariffs and Rate Schedules
Exhibit NO.3
Case No. INT-G-08-03
Intermountain Gas Company
Page 10 of 33
Exhibit NO.3
Case No. INT -G-08-03
Intermountain Gas Company
Page 11 of 33
TransCanada
450 First Street SW.
Calgary, Alberta np 5H1
Direct Phone: [phone]
Fax: [phone]
Email: norm_bowman~ranscanada.com
November 20, 2007
Alberta Energy and Utilities Board
640 - 5th Avenue S.W.
Calgary, Albert
T2P 3G4
Filed Electronically
Attention: Mr. Wade Vienneau
Manager - Calgary Offce, Utilties Branch
Re: NOVA Gas Transmission Ltd. ("NGTL")
Application for 2008 Interim Rates, Tolls and Charges
NGTL applies to the Albert Energy and Utilities Board ("Board") under Division 3 of the
Public Utilities Board Act, and under Part 4 and 5 of the Gas Utilities Act, for approval of
interim rates, tolls, and charges for services on the Albert System, effective January 1,2008
("2008 Interim Rates").
NGTL currently provides services under 2007 final rates, tolls and charges approved by the
Board in Order U2007 -76 ("2007 Final Rates"). The 2007 Final Rates are effective until
December 31, 2007.
In Decision 2005-057, the Board approved the 2005 - 2007 Revenue Requirement Settlement
("the Settlement"), which provides for the determination of interim and final rates, tolls and
charges for the period of the Settlement. Each year's revenue requirement was calculated based
on certain costs fixed pursuant to the Settlement and a forecast of remaining costs that wil flow
through, adjusted for appropriate deferral account balances. This forecast revenue requirement,
together with a forecast of firm transportation contract demand quantity and throughput, was
used to calculate rates using the approved rate design in place at the time (EUB Decision 2006~
010).
The 2008 Interim Rates are based on:
. the 2007 final revenue requirement of$I,159.5 milion, adjusted for deferral account
balances, determined in accordance with the Settlement (Attachment A);
. forecast 2008 contract demand quantities and throughput (Attachment B);
. an illustrative rate calculation (Attachment C) which uses the rate design approved by the
Board in Decision 2006-010.
Exhibit NO.3
Case No. INT -G-08-03
Intermountain Gas Company
Page 12 of 33
Page 2
November 20, 2007
Mr. W. Vienneau
A comparison of 2007 and 2008 rates, tolls and charges is provided in Attchment D. A table of
the 2008 Interim Rates is provided in Attchment E. The C02 Management Service rates for
2008 are based on the current methodology approved by the Board in Decision 2002-084 as
amended by Order U2006-204. The C02 Management Service is currently under review and any
changes will be incorporated in 2009.
The proposed 2008 average interim rates for FT -R and FT -D services wil be $0. 155/Mcf and the
proposed 2008 average interim export rate wil be $0.311Mcf. These rates are approximately
6.9% higher than the 2007 average annual rates.
As the Board is aware, NGTL is currently in discussions with its shippers to negotiate its revenue
requirement, or components of it, for a term of not more than three years, commencing January 1,
2008. NGTL is preparing a General Rate Application that it intends to file in the fourth quarter
2007 in the event it is not able to negotiate a settlement. NGTL wil fie for 2008 Final Rates to be
determined in accordance with the terms of a new settlement, or in accordance with the 2008
General Rate Application as approved by the Board.
NGTL wil notify its shippers and the members of the Tolls, Tariff, Facilities and Procedures
Committe of the availability of this application on TransCanada's Albert System Website at
the address below.
htt://ww.transcanada.comlAlbertregulatory_info/activeJates_services_filings.htm
All notices and communications regarding this matter should be directed to Linda Angus by
e-mail at linda_angusiêtranscanada.com and alberta_systemiêtranscanada.com, or by phone at
920-7163.
Yours trly,
NOVA Gas Transmission Ltd.
a wholly owned subsidiary of TransCanada PipeLines Limited
Original Signed By
Norm Bowman
Director, Regulatory Services
Attachments
cc: Tolls, Tariff, Facilities and Procedures Committee, via e-mail
Alberta System Shippers
Exhibit NO.3
Case No. INT -G-08-03
Intermountain Gas Company
Page 130f 33
NOVA Gas Transmission Ltd.2008 Interim Rates
Attachment E
Page 1 of 19
Service Rates, Tolls and Charges
1.Rate Schedule FT-R Refer to Attachment "1" for applicable FT-R Demand Rate per month & Surcharge for
each Receipt Point
Average Firm Service Receipt Price (AFSRP)$ 168.24/io3m3
2.Rate Schedule FT-RN Refer to Attachment" l" for applicable FT -RN Demand Rate per month & Surcharge
for each Receipt Point
3.Rate Schedule FT-D FT-D Demand Rate per month $4.451GJ
4.Rate Schedule STFT STFT Bid Price.Minimum bid of 100% ofFT-D Demand Rate
5.Rate Schedule FT-DW FT-DW Bid Price.Minimum bid of 125% of FT -D Demand Rate
6.Rate Schedule FT-A FT-A Commodity Rate $0.48/io3m3
7.Rate Schedule FT-P Refer to Attachment "2" for applicable FT-P Demand Rate per month
8.Rate Schedule LRS Contract Term Effective LRS Rate ($/I03m3/day)
1-5 years 10.08
6-10 years 8.42
15 years 7.55
20 years 6.71
9.Rate Schedule LRS-2 LRS-2 Rate per month $50,000
io.Rate Schedule LRS-3 LRS- 3 Demand Rate per month $ 129.55!l03m3
l1.Rate Schedule IT-R Refer to Attachment" 1" for applicable IT -R Rate & Surcharge for each Receipt Point
12.Rate Schedule IT-D IT-D Rate $0.1606/GJ
13.Rate Schedule FCS The FCS Charge is determned in accordance with Attachment "1" to the applicable
Schedule of Service
14.Rate Schedule PT Schedule No PT Rate PTGas Rate
9006-01000-0 $67.22/d 1.0 io3m3/d
15.Rate Schedule as Schedule No.Charge
2003034359-2 $899.00 1 month
2007262666-1 $434.00 1 month
2006253651-1 $11.00 1 month
2007262711-1 $6.00 1 month
2007262709-1 $303.00 1 month
2007262728-1 $859.00 1 month
2007262705-1 $1,220.00 1 month
2007263949-1 $46.00 1 month
2007262175-1 $438.00 1 month
2007262669-1 $95.00 1 month
2007262602-1 $4.00 1 month
200726270 I-i $9.00 1 month
2007262727-1 $17.00 1 month
2007262698-1 $43.00 1 month
2007262609-1 $7.00 1 month
2007262668.1 $19.00 1 month
2007262697-1 $1,760.00 1 month
2007263948-1 $90.00 1 month
2003004522-2 $83,333.00 1 month
16. Rate Schedule CO2 Tier CO, Rate ($/I03m3)
I 630.10
2 503.07
3 349.65
TARIFF Effective Date: .
NOVA Gas Transmission Ltd.
Exhibit NO.3
Case No. INT-G-08-03
Intermountain Gas Company
Page 14 of 33
2008 Interim Rates
Attachment 1
Page 1
Receipt
Point
Number
1337
1631
1613
1424
1890
3880
1526
1681
3868
2000
2109
2200
1075
1208
1103
5026
1851
1469
1573
2136
1567
1770
2708
2734
1326
1368
1009
1116
1098
1297
1792
3943
1275
1649
2744
1100
1296
1181
1122
1398
1339
1497
1329
1393
1330
2761
2085
2066
1197
1334
1382
1231
1198
2143
2222
2132
1459
TARIFF
Receipt Point Name
ABEE
ACADIA EAST
ACADIA NORTH
ACADIA VALLEY
ACADIA VALLEY WEST
AECO INTERCONNECTION
AKUINU RIVER
AKUINU RIVER W.
ALBERTA MONTANA BORDER
ALBERTA-B.C. BDR (CHART ACC
ALDER FLATS
ALDER FLATS S.
ALDERSON
ALDERSON NORTH
ALDERSON SOUTH
ALGAR LAKE
AMISKSOUTH
ANDREW
ANSELL
ANTE CREEK S.
ARMENA
ARMSTRONG LAKE
ASSUMPTION
ASSUMPTION #2
ATHABASCA
ATHABASCA EAST
ATLEE-BUFFALO
A TLEE-BUFFALD E
ATLEE-BUFFALO S
ATMORE
ATUSIS CREEK E
ATUSIS CREEK INTERCONNECTI
BADGER EAST
BADGER NORTH
BALLATER #2
BANTRY
BANTRY N.E
BANTRYNW.
BANTRY NORTH
BAPTISTE
BAPTISTE SOUTH
BARICH
BASHAW
BASHAWB
BASSANO SOUTH
BASSET LAKE
BASSET LAKE S.
BASSET LAKE W.
BAXTER LAKE
BAXTER LAKE B
BAXTER LAKE NW
BAXTER LAKE S.
BAXTER LAKE W.
BAY TREE
BEAR CANYON W.
BEAR RIVER
BEAUVALLON
FT-R Demand
Rate per Month
($/103m3)
254.84
122.14
122.77
174.14
81.64
81.64
254.84
254.84
99.78
81.64
101.9
99.32
86.93
88.89
86.97
254.84
242.57
176.09
137.74
254.84
254.84
254.84
254.84
254.84
254.84
245.63
81.64
81.64
81.64
231.27
81.64
81.64
81.64
99.77
254.84
81.64
81.64
81.64
81.64
254.84
254.84
254.84
127.77
127.82
99.48
254.84
254.84
254.84
254.84
254.84
254.84
254.84
254.84
254.84
240.25
254.84
254.84
FT -RN Demand
Rate per Month
($/103m3)
280.32
134.35
135.05
191.55
89.80
89.80
280.32
280.32
109.76
89.80
111.31
109.25
95.62
97.78
95.67
280.32
266.83
193.70
151.51
280.32
280.32
280.32
280.32
280.32
280.32
270.19
89.80
89.80
89.80
254.40
89.80
89.80
89.80
109.75
280.32
89.80
89.80
89.80
89.80
280.32
280.32
280.32
140.55
140.60
109.43
280.32
280.32
280.32
280.32
280.32
280.32
280.32
280.32
280.32
264.28
280.32
280.32
IT-R Rate
per Day
($/103m3)
9.61
4.61
4.63
6.57
3.08
3.08
9.61
9.61
3.76
3.08
3.82
3.74
3.28
3.35
3.28
9.61
9.15
6.64
5.19
9.61
9.61
9.61
9.61
9.61
9.61
9.26
3.08
3.08
3.08
8.72
3.08
3.08
3.08
3.76
9.61
3.08
3.08
3.08
3.08
9.61
9.61
9.61
4.82
4.82
3.75
9.61
9.61
9.61
9.61
9.61
9.61
9.61
9.61
9.61
9.06
9.61
9.61
Effective: January 1,2008
(Amended February 28, 2008)
Exhibit NO.3
Case No. INT -G-08-03
Intermountain Gas Company
Page 15 of 33
1856 SPOTTED CREEK SPTCK 157.80 150.29 142.78 165.32 5.67 i'L
1857 LINDEN llNDN 85.72 81.64 77.56 89.80 3.08 ML
1858 POE POEXX 134.01 127.63 121.25 140.39 4.81 NE
1859 HUMMOCK LAKE HUMLK 113.02 107.64 102.26 118.40 4.06 i'L
1860 LACOMBE LAKE LACOM 108.77 103.59 98.41 113.95 3.91 i'L
1862 ELNORA EAST # 2 ELNE2 226.46 215.68 204.90 237.25 8.13 i'L
1863 CESSFD-BURf W # 2 CSBW2 112.36 107.01 101.66 117.71 4.03 NE
1864 DAVEY LAKE DAVEY 90.05 85.76 81.47 94.34 3.23 i'L
1865 NOSEHILL CK NORTH NOSCN 148.47 141.40 134.33 155.54 5.33 PR
1866 HIGHLAND RANCH HIGHL 134.96 128.53 122.10 141.38 4.85 i'L
1867 RUMSEY NORTH #2 RUMN2 245.13 233.46 221.79 256.81 8.80 i'L
1868 FERINTOSH SOUTH FTOHS 247.08 235.31 223.54 258.84 8.87 i'L
1869 TORRINGTON E #2 TORE2 85.72 81.64 77.56 89.80 3.08 i'L
1870 BIG VAllEY BIGVL 224.08 213.41 202.74 234.75 8.05 i'L
1871 SHARPLES SHARP 90.64 86.32 82.00 94.95 3.25 i'L
1872 LITTlE BOW llTLB 85.72 81.64 77.56 89.80 3.08 i'L
1873 MALMO MALMO 191.67 182.54 173.41 200.79 6.88 i'L
1874 LAVESTA LAVST 119.01 113.34 107.67 124.67 4.27 i'L
1875 GALT ISLAND GALT!113.53 108.12 102.71 118.93 4.08 i'L
1876 CHAPEL ROCK CHAPR 85.72 81.64 77.56 89.80 3.08 i'L
1877 DUVERNAY DUVER 195.97 186.64 177.31 205.30 7.04 NE
1878 JOffRE EAST JOFFE 151.45 144.24 137.03 158.66 5.44 i'L
1879 KERSEY #2 KERS2 85.72 81.64 77.56 89.80 3.08 i'L
1880 GOOSEQUILL WEST GQUiW 123.24 117.37 111.50 129.11 4.43 i'L
1881 PORTERS BUTTE PORTS 85.72 81.64 77.56 89.80 3.08 i'L
1882 KEIVERS LAKE KVRLK 85.72 81.64 77.56 89.80 3.08 i'L
1884 LAMERTON SOUTH LAMRS 128.56 122.44 116.32 134.68 4.62 i'L
1885 ROSEGLEN ROSEG 94.69 90.18 85.67 99,20 3.40 i'L
1886 JARVIS BAY JRBAY 130.83 124.60 118.37 137.06 4.70 i'L
1887 LAMERTON#2 LAMR2 186.72 177.83 168.94 195.61 6.71 i'L
1888 MUNSON #2 MUNS2 246.40 234.67 222.94 258.14 8.85 i'L
1890 ACADIA VALLEY WEST ACDVW 85.72 81.64 77.56 89.80 3.08 NE
1891 FAWCETT R W #3 FAwn 267.58 254.84 242.10 280.32 9.61 NE
1944 ZAMA LAKE SUMI'lARY ZAMSM 267.58 254.84 242.10 280.32 9.61 PR
1945 WATRl/WATR2 SUM WATSH 85.72 81.64 77.56 89.80 3.08 i'L
1947 BRAZEAU - BRAZEAU EAST SUMMARY BRZHB 134.53 128.12 121. 71 140.93 4.83 i'L
1949 RIMBEY.WESTEROSE SUMMARY RIMGL 126.33 £20.31 114.29 132.34 4.54 i'L
1958 EMPRESS BORDER EMPRS 85.72 81.64 77.56 89.80 3.08 I'lL
1963 COUSINS B & C SALES (SUMMARYj COUBC 136.71 130.20 123.69 143.22 4.91 i'L
2000 ALBERTA.B.C. BDR (CHART ACCOUNTING)ALTBC 85.72 81.64 77.56 89.80 3.08 i'L
2003 COLEMAN COLEM 85.72 81.64 77.56 89.80 3.08 t1L
2005 WILDCAT HILLS WCATH 85.72 81.64 77.56 89.80 3.08 i'L
2007 EAST CALGARY ECALY 87.50 83.33 79.16 91.66 3.14 i'L
2008 CROSSFIELD CROSF 86.15 82.05 77.95 90.26 3.09 i'L
2010 MINNEHIK-BK LK MNBUK 126.92 120.88 114.84 132.97 4.56 i'L
2012 WINDfAll WINDF 161.82 154.11 146.40 169.52 5.81 PR
2013 KAYBOB KABOB 200.13 190.60 181.07 209.66 7.19 PR
2014 WILLESDEN GREEN WILSG 95.41 90.87 86.33 99.96 3.43 i'L
2016 FERRIER FERIR 136.08 129.60 123.12 142.56 4.89 i'L
2018 CARSON CREEK CARCK 220.23 209.74 199.25 230.71 7.91 PR
2019 WILSON CREEK WLNCK 161.07 153.40 145.73 168.74 5.78 i'L
2020 KAYBOB SOUTH KBOBS 181.07 172.45 163.83 189.70 6.50 PR
2022 JUDY CREEK JDCRK 267.58 254.84 242.10 280.32 9.61 PR
2026 QUIRK CREEK QUIRK 85.72 81.64 77.56 89.80 3.08 i'L
2027 KAYBOB 11-36 K1136 197.57 188.16 178.75 206.98 7.09 PR
2028 SIMONETTE SIMET 228.92 218.02 207.12 239.82 8.22 PR
2029 WASKAHIGAN WASKA 167.77 159.78 151.79 175.76 6.02 PR
2030 STURGEON LAKE S STLKS 251. 79 239.80 227.81 263.78 9.04 PR
2031 GOLD CREEK GLDCK 180.71 172.10 163.50 189.31 6.49 PR
2032 BURNT TIMBER BURNT 99.31 94.58 89.85 104.04 3.57 i'L
2034 VIRGINIA HILLS VIRGH 267.58 254.84 242.10 280.32 9.61 PR
2035 KAYBOB SOUTH #3 KBOB3 153.02 145.73 138.44 160.30 5.49 PR
2036 JUMPiNG POUND W JUMPW 8572 81.64 77.56 89.80 3.08 I'lL
2037 GILBY WEST GLBYW 139.74 133.09 126.44 146.40 5.02 I'lL
2040 LEAFLAND LFLND 182.56 173.87 165.18 191.26 6.56 I'L
2043 BELLOY BELOY 267.58 254.84 242.10 280.32 9.61 PR
2044 DUNVEGAN DNVEG 233.70 222.57 211.44 244.83 8.39 PR
2046 PiONEER PiDER 134.01 127.63 121.25 140.39 4.81 i'L
2047 HOTCHKISS HDTKI 267.58 254.84 242.10 280.32 9.61 PR
2049 ETA LAKE ETALK 136.13 129.65 123.17 142.62 4.89 i'L
2053 KEG RIVER KëGRV 267.58 254.84 242.10 280.32 9.61 PR
Page 9 of 14
Exhibit NO.3
Case No. INT-G-08-03
Intermountain Gas Company
Page 16 of 33
TransCanada Pipelines Foothills Pipeline System
("Foothills")
formerly Alberta Natural Gas ("ANG")
Applicable Filings, Tariffs and Rate Schedules
Exhibit NO.3
Case No. INT-G-08-03
Intermountain Gas Company
Page 17 of 33
t( ~ TransCanada
450 - 1st Street S.W.
Calgary, Alberta T2P 5H1
Tel: [phone]
Fax: [phone]
Email: murray-sondergard(gtranscanada.com
March 14, 2008
National Energy Board
444 Seventh Avenue S.W.
Calgary, Alberta
T2P OX8
Filed Electronically
Attention: Ms. Claudine Dutil-Berry, Secretary
Dear Madam:
Re: Foothils Pipe Lines Ltd. ("Foothils")
Statement of Rates and Charges effective April!, 2008
Pursuant to Section 60(1)(a) of the National Energy Board Act, Foothills encloses for filing revised rates
and charges for transporttion service on Foothills Zone 8. Attachment 1 provides the revised 2008 Zone
8 Transporttion Rates on an annual basis. Attachment 2 provides the 2008 Revised Rates inclusive of an
adjustment to account for rates in place from January 1, 2008 to March 31, 2008. Foothils intends the
2008 Revised Rates to be effective April 1, 2008.
The rates and charges are based on the methodology approved by the Board in Decision TG-8-2004 as
amended by Order TG-03-2007.
Foothills is filing these rates now as a result of a settlement following the bankrptcy of Calpine
Corporation, a shipper on TransCanada's B.C. System now incorporated into Foothills Zone 8. AB a
result of the settlement, Calpine has paid to Foothills a total of $44.4 milion. Foothils intends to refund
the settlement amount plus carring charges to Zone 8 shippers over 2008 and 2009. This results in an
adjustment to Foothills Zone 8 2008 FT Service Revenue Requirement, provided to the Board in Foothills
November 30, 2007 filing, of $23.5 milion.
The Foothils Zone 8 full haul demand rate will decrease from $0.0918/GJ to $0.0568/GJ.
Attachment 3 to this letter is a black-lined copy of the relevant section of the Tariff illustrating the 2008
rates.
Attachment 4 to this letter is a clean copy of the relevant section of the Tariff incorporating the revised
rates.
March 14,2008
Page 2
Ms. C. Dutil-Berry
Exhibit NO.3
Case No. tNT -G-08-03
Intermountain Gas Company
Page 18 of 33
Foothils will notify its shippers and interested parties of the filing pursuant to Order TG-6-81, and will
also post a copy of this Application on TransCanada's Foothills System website at:
http://www.transcanada.comI oothils/regulatory /reg_ fiings/index.html
On March 4, 2008 Foothills provided notice to shippers and interested parties ofthe rate reduction and its
intention to file the revised rates. Foothils understands that any par that is opposed to the rates and
charges will advise the Board accordingly.
Please direct all notices and communications regarding this filing to Greg Szuch bye-mail at
greg_szuchCftranscanada.com or by phone at [phone].
Yours trly,
Foothils Pipe Lines Ltd.
a wholly owned subsidiary of TransCanada PipeLines Limited
Original Signed by
Muray Sondergard,
Director, Regulatory Services
EncIs.
cc: Interested Parties - TG-6-81
Foothils Finn and Interruptible Shippers
REVENUE REQUIREMENT
Foothils Pipe lines ltd.
Exhibit No.3
Case No. INT-G-08-03
Intermountain Gas Company
Page 19 of 33
Attachment 1
Summary
REVISED ZONE 8 TRANSPORTATION RATES
Schedule Amount $000
Estimated Costs of Service:
Operating & Maintenance
Return on Rate Base
Depreciation & Amortization
Taxes: Income and Other
Special Charge
Fuel Tax
Sub-Total
Adjustments:
Previous (Over) Under
G&A Settlement Savings 1
Total Revenue Requirement
Other Service Revenue
SIFT Revenue
Interruptible/Overrun Revenue
SGS Revenue
Calpine Settement 2
FT Service Revenue Requirement
A
B
C
o
Zone 8
19,056
17,798
17,637
15,643
555
3,000
73,689
E 9,277
(833)
82,132
(2,798)
(190)
(23,500)
55,644
BILLING DETERMINANTS
FT Contract MOQ (T J/d)
Maximum Haul Distance (Km)
Total FT MOQ x Distance
F 2,319.79
170.70
395,989F
Estimated STFT MDQ (T J/d)
Estimated Interruptible/Overrun Deliveries (T J)
Estimated SGS Deliveries (T J)
116.67
2,636
TRANSPORTATION RATES'
Effective Rates
Demand Rate ($/GJ / Km / Month)
Overrun Service ($/GJ / Km)
Interruptible Rate ($/GJ / Km)
Full Haul Rates (100% load Factor)
Demand Rate ($/GJ)
Overrun Service ($/GJ)
Interruptible Rate ($/GJ)
0.0117099104
nfa
0.0004223246
0.0655371051
nfa
0.0720908092
. Numbers may not add up to totals due to rounding.
Note(s):
1. Forecasted Shippers' Savings with respect to Foothills' General & Administrative Expenses Settement Agreement dated January
as approved in Board Order TG-2-2003, as amended November 3, 2006 and approved in Board Order TG-03-2007.
2. 2008 portion of Calpine Settlement refund.
3. 2008 revised annual rates. See Attachment 2 for the 2008 revised rates effective April 1, 2008.
Exhibit NO.3
Case No. INT-G-08-03
Intermountain Gas Company
Page 20 of 33
FoothiUs Pipe Lines Ltd.Revised 2008 Rates
Attachment 2
Page 1 of 1
Revised 2008 Rates efective April i, 2008
2008
Current Effecve 208 Re 200 Re Efecve
RJte i AiWlI RJte i Adjusment Forma 3 Ra 4IT De Rate ($/GJlKtl)0.0164032716 0.011709104 -((0.011709104 x 12). (0.016432716 x 3)Y9 0.0101454567
IT !nrrtible Rate ($/GJIK)0.005915934 0.00223246 =f(0.00223246 x 12). (0.005915934 x 3)V9 0.0036590 1 7
Fu Haul Raes (100% Load Factor)
IT Ded Ra ($/GJ)0.0918045397 0.0655371051 "1(0.0655371051 x 12). (0.0918045397 x 3))/9 0.0567812935
IT lntenutible Rate ($/GJ)0.100849934 0.07209092 =f(0.072098092 x 12) . (0.100849934 x 3)V9 0.0624594\45
i. 2008 I1tes in effect from Janua \ to Ma 3 l, 208
2. 2008 resed anual rat ar cacute as an anual 12 moth I1te
3. ((2008 revi anuall1 x \2) - (200 curnt effective I1te x 3))/9
4. 2008 revise 11!e are to be in effect for 9 moths from Apl i to Deem 31, 2008
Foothills Pipe Lines Ltd.
TABLE OF EFFECTIVE RATES
1. Rate Schedule FT, Firm Transportation Service
Demand Rate
($/GJ/KmMonth)
Zone 6 0.0067213026
Zone 7 0.0073436317
Zone 8* 0.01640327160101454567
Zone 9 0.0094198745
2. Rate Schedule OT, Overrun Transportation Service
Commodity Rate
($/GJ/Km)
Zone 6 0.0002424076
Zone 7 0.0002648523
3. Rate Schedule IT, Interruptible Transportation Service
Commodity Rate
($/GJ/Km)
Zone 8* 0.00059159340003659017
Zone 9 0.0003397332
*For Zone 8, Shippers Haul Distance shall be 170.7 km.
Exhibit NO.3
èase No. INT-G-08-03
Intermountain Gas Company
Page 21 of 33
Attachment 3
Page 1
TARIFF - PHASE I Effective Date: January April 1,2008 I
Foothills Pipe Lines Ltd.
TABLE OF EFFECTIVE RATES
1. Rate Schedule FT, Firm Transportation Service
Demand Rate
($/GJ/KmMonth)
0.0067213026Zone 6
Zone 7 0.0073436317
0.0101454567
0.0094198745
Zone 8*
Zone 9
2. Rate Schedule OT, Overrun Transportation Service
Commodity Rate
($/GJ/Km)
0.0002424076Zone 6
Zone 7 0.0002648523
3. Rate Schedule IT, Interruptible Transportation Service
Commodity Rate
($/GJ/Km)
Zone 8* 0.0003659017
Zone 9 0.0003397332
*For Zone 8, Shippers Haul Distance shall be 170.7 km.
Exhibit NO.3
Case No. INT-G-08-03
Intermountain Gas Company
Page 22 of 33
Attachment 4
Page i
T ARlFF - PHASE I Effective, Date: April i, 2008
Exhibit NO.3
Case No. INT-G-08-03
Intermountain Gas Company
Page 23 of 33
TrasCda - Cust Exes" Pnng & Tolls - Be Systm
TransCanada's - Foothils-BC Transportation Rates
2008 Final Rates Effective January 1, 2008
FT Firm Service (A/BC to Kingsgate)
lI Interruptible Service (A/BC to Kingsgate)
1. For information purposes, the maximum Shipper's Haul Distance used in the Shipper's monthly cliarge for Service calcuiation is
170.7 krn.
2. Rates are payable in Canadian doHafs and G.1 units are used for billing purposes. ~.1cf and M~'lbtu units are provided for
information purposes only.
3. Conversion Factors below have been used to calculate tiie rates provided for information purposes:
Cdn$/US$
ç/GJ to -t/i'lMBtu
ç/GJ to q:/Mcf
1.01 - subject to change (updated Dec 11/07ì
x 1.055056
at a heat value of 37.8 M.1/m3
4. Rates do not include G.S.T.
5. Inquiries regarding the BC System may be directed to:
ß.CI,f.eNewnerry at 403.920.5579
Dan Morrison at 403.920.6139
Other information for TransCanada's Be System:
Current Archives
.. Fuel Rates. & Heating Values
.. AS Border Heat Values
. Rates: 2007 'Ii 2006'1 i 2005 'Ii
2004 'I
.. Fuel Rates & Heating Values
. A13SQn:terHeatY_alwes 'I
IQ
Gas Transmission Northwest ("GTN")
Applicable Tariffs and Rate Schedules
Exhibit NO.3
Case No. INT-G-08-03
Intermountain Gas Company
Page 24 of 33
FERC GAS TARIFF
THIRD REVISED VOLUME NO. 1-A
OF
GAS TRASMISSION NORTHWEST CORPORATION
FILED WITH THE
FEDERA ENERGY REGULATORY COMMISSION
Communications Concerning This Tariff
Should Be Addressed To:
John A. Roscher i Director
Rates and Regulatory Affairs
Gas Transmission Northwest Corporation
1400 SW Fifth Avenue
Suite 900
Portland, OR 97201
Telephone: [phone]
Facsimile: [phone]
Exhibit NO.3
Case No. INT-G-08-03
Intermountain Gas Company
Page 25 of 33
Exhibit NO.3
Case No. INT-G-08-03
Intermountain Gas Company
Page 26 of 33
Gas Transmission Northwest Corporation
FERC Gas Tariff
Third Revised Volume No. 1-A
First Revised Sheet No. 1
Superseding
Original Sheet No. 1
TABLE OF CONTENTS
Third Revised Volume No. 1-A Sheet No.
Preliminary Statement 2
Map 3
Statement of Effective Rates and Charges for
Transportation of Natural Gas 4
Rate Schedules:
FTS-1 Firm Transportation Service 30
LFS-1 Limited Firm Transportation Service 45
ITS-1 Interruptible Transportation Service 60
USS-1 Unbundled Sales Service 65
PS-1 Parking Service 67
AIS-1 Authorized Imbalance Service 71
Transportation General Terms and Conditions 100
Form of Service Agreements:
FTS-1 Firm Transportation Service 250
Electronic Signature for
Capacity Release 259
ITS-1 Interruptible Transportation Service 270
PS-1 Parking Service 280
AIS-1 Authorized Imbalance Service 290
LFS-1 Limited Firm Transportation Service 320
Issued by: John A Roscher, Director of Rates & Regulatory Affairs
Issued on: August 4, 2004 Effective on: September 3, 2004
Exhibit NO.3
Case No. tNT -G-08-03
Intermountain Gas Company
Page 27 of 33
Gas Transmission Northwest Corporation
FERC Gas Tariff
Third Revised Volume No. 1-A
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 CorporationFERC Gas Tariff substitute Thirteenth Revised Sheet No. 4Third Revised Volume No. I-A Superseding
Substitute Twelfth Revised Sheet No. 4
Exhibit NO.3
Case No. INT-G-08-03
Intermountain Gas Company
Page 28 of 33
STATEMENT OF EFFECTIVE RATES AND CHAGES FOR
TRASPORTATION OF NATURL GAS
Rate Schedules FTS-l and LFS-l
RESERVATION
DAILY
MILEAGE (a)
(Dth-MILE)
DAILY
NON-MILEAGE (b)
(Dth)
DELIVERY (c)
(Dth-MILE)
FUEL (d)
(Dth)
MAIMUM MINIMUM 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%0.0000%
EXTENSION CHARGES
MEDFORD
E-l (f)0.003290 0.000000 0.005498 0.000000 0.000026 0.000026
E-2 (g) (1) 0.007382 0.000000
(WWp)
0.000000 0.000000
E-2 (h) (1) 0.002964 0.000000
(Diamond 1)
0.000000 0.000000
E-2 (h) (1) 0.001163 0.000000
(Diamond 2)
0.000000 0.000000
COYOTE SPRINGS
E-3(i) 0.0014120.0000000.0014200.000000 0.000000 0.000000
OVERRUN CHARGE (j )
SURCHARGES
ACA (k)0.001900 0.001900
Issued by: John A Roscher, Director of Rates & Regulatory AffairsIssued on: February 14, 2008 Effective on: January I, 2008
Filed to comply with order of the Federal Energy Regulatory Commission, Docket
No. RP06 -407 -008, issued January 7 ( 2008, 22 FERC ~ 61,012
Gas Transmission Northwest Corporation
FERC Gas Tariff
Third Revised Volume No. I-A
Exhibit NO.3
Case No. INT-G-08-03
Intermountain Gas Company
Page 29 of 33
substitute Sixth Revised Sheet No. 5
Superseding
Substitute Fifth Revised Sheet No. 5
STATEMENT OF EFFECTIVE RATES AND CHARGES FOR
TRASPORTATION OF NATURAL GAS (a)
Rate Schedule ITS - 1
MILEAGE (n)
(Dth-Mile)
NON-MILEAGE (0)
(Dth)
DELIVERY (c)
(Dth-Mile)
FUEL (d)
(Dth-Mile)
MAIMUM MINIMUM MAIMUM MINIMUM MAIMUM MINIMUM MAIMUM MINIMUM
BASE (e) 0.000000 (e)0.000000 0.000016 0.000016 0.0050i 0.0000%
EXTENSION CHARGES
MEDFORD
E- 1 (Medford) (f)
0.003290 0.000000 0.0054980.000000 0.0000260.000026
COYOTE SPRINGS
E-3 (Coyote Springs)
0.001412 0.000000
(i)
0.001420 0.000000 0.0000000.000000
SURCHAGES
ACA (k)
0.001900 0.001900
(Continued)
Issued by: John A Roscher, Director of Rates & Regulatory AffairsIssued on: February 14, 2008 Effective on: November I, 2007
Filed to comply with order of the Federal Energy Regulatory Commission, Docket
No. RP06-407-008, issued January 7,2008,22 FERC' 61,012
Gas Transmission Northwest Corporation
FERC Gas Tariff
Third Revised Volume No. 1-A
Exhibit NO.3
Case No. INT -G-08-03
Intermountain Gas Company
Page 30 of 33
substitute Ninth Revised Sheet No. 6
Superseding
Substitute Eighth Revised Sheet No. 6
STATEMENT OF EFFECTIVE RATES AND CHAGES
FOR TRASPORTATION OF NATUR GAS
Notes:
(a)The mileage component shall be applied per
transported by GTN for delivery to shipper
and delivery points in Shipper's contract.
Sheet 3 for receipt and delivery point and
pipeline
based on
Consult
milepost
mile to gas
the primary receipt
GTN' s sys tem map on
designations.
(b) The non-mileage component is applied per Shipper i s MDQ at Primary
Point (s) of Delivery on Mainline Facilities.
(c) The delivery rates are applied per pipeline mile to gas transported by
GTN for delivery to shipper based on distance of gas transported.
Consult GTN's system map on Sheet No. 3 for receipt and delivery point
and milepost designations.
(d) Fuel Use: Shipper shall furnish gas used for compressor station fuel,
line loss, and other utility purposes, plus other unaccounted-for gas
used in the operation of GTN's combined pipeline system in an amount
equal to the sum of the current fuel and line loss percentage and the
fuel and line loss percentage surcharge in accordance with Paragraph 37
of this tariff, multiplied by the distance in pipeline miles transported
from the receipt point to the delivery point multiplied by the
transportation quantities of gas received from Shipper under these rate
schedules. The current fuel and line loss percentage shall be adjusted
each month between the maximum rate of 0.0050% per Dth per pipeline mile
and the minimum rate of 0.0000% per Dth per mile. The fuel and line
loss percentage surcharge is 0.0000% per Dth per pipeline mile. No fuel
use charges will be assessed for backhaul service. Currently effective
fuel charges may be found on GTN's Internet website under II Informational
Postings. II
Issued by: John A Roscher, Director of Rates & Regulatory AffairsIssued on: February 14, 2008 Effective on: February 1, 2008
Filed to comply with order of the Federal Energy Regulatory Commission, Docket
No. RP06-407 008, issued January 7, 2008, 22 FERC ~ 61,012
Questar Pipeline Company ("Questar")
Applicable Tariffs and Rate Schedules
Exhibit NO.3
Case No. INT~G-08-03
Intermountain Gas Company
Page 31 of 33
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
Exhibit NO.3
Case No. INT -G-08-03
Intermountain Gas Company
Page 32 of 33
Communications regarding this tariff should be addressed to:
L. G. Wright, Director, Regulatory Affairs
Questar Regulated Services Company
180 East 100 South
P.O. Box 4536 a
Salt Lake City, Utah 84145-0360
Telephone: [phone]
FAX: [phone]
Questar Pipeline Company
FERC Gas Tariff
First Revised Volume No. i
Base
Rate Schedule/
Tye of Charge
(a)
PEAING STORA
Monthly Reservation Chrge
Maximum
Minimum
Usage ChargeInjection
Withdrawal
CLA BAIN STORAE
Firm Storage Service - FSS
Monthly Reservation Chrge
Oeliverability
Maimum
Minimum
Capacity
Maximum
Minimum
Usage Charge
Injection
Withdrawal
Authorized Overru Charge
Maximum
Minimum
Interruptible Storage Service - ISS
Usage Charge
Inventory 1/
Maximum
Minimum
Injection
Withdrawal
OPTION VOLUMTRIC RELEES ~/
Peaking Storage Service - PKS
Maximum
Minimum
Firm Storage Service - FSS
Maimum
Minimum
Storage Usage Charges Aplicable
Peaking Storage Service - PKS,Injection
Withdrawal
Clay Basin Storage Service - FSS,
Injection
Withdrawal
STATEM OF RATES
Anual
Tariff
Rate
(b)
$
2.87375
0.00000
0.03872
0.03872
2.85338
0.00000
0.02378
0.00000
0.01049 .
0.01781
0.30315
0.01781
0.05927
0.00000
0.01049
0.01781
3.40890
0.00000
0.57068
0.00000
to Volumtric Releases l/
PAR AN LO SERVICE - PALl
Daily Charge
Maximum
Minimum
Delivery Charge
0.03872
0.03872
0.01049
0.01781
0.30315
0.00000
0.02830
Exhibit NO.3
Case No. INT-G-08-03
Intermountain Gas Company
Page 33 of 33
Twenty-First Revised Sheet No. 6
Superseding
Twentieth Revised Sheet No. 6
Currently
Charge
Adjustment 4/
(c)
$
0.00190
0.00190
0.00190
0.00190
0.00190
FUL REIMURSEM - 2.0% (0.2% utility and 1.8% compressor fuel) for Rate Schedule PALl
0.00190
Issued by: R. Allan Bradley,
Issued on: August 29, 2007
Effective~
(d)
$
2.87375/0th
O.OOOOO/Oth
0.03872/Dth
0.03872/0th
2.85338/0th
O.OOOOO/Oth
0.02378/0th
O.OOOOO/Oth
0.01239/0th
0.01781/0th
0.30505/0th
0.01971/0th
0.05927/0th
O.OOOOO/Oth
0.01239/0th
0.01781/0th
3.40890/0th
O.OOOOO/Oth
0.57068/0th
O.OOOOO/Oth
0.03872/0th
0.03872/0th
0.01239/0th
0.01781/0th
O.30315/0th
O.OOOOO/Oth
0.03020/0th
President and CEO
Effective on: October i, 2007
EXHIT NOS. 4-10
CASE NO. INT -G-08-03
INTERMOUNTAI GAS COMPAN
(7 pages)
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Case No. INT-G-08-03€Intermountain Gas Company
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Case No. INT -G-08~03
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Exhibit NO.9
Case No. INT-G-08-03
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)$15,378,923
3 Normalized Sales Volumes (10/1/06 - 9/30107)301,173,117
4 Proposed Temporary Surcharge(Credit) . Variable Costs $0.05106
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-07-03 (Account 1860-2120) (2)$1,199,834
7 Lost and Unaccounted For Gas Amortization (Account 1860-2130) (3)(1,336,458)
8 (Over)/Under Collection of Lost and Unaccounted For Gas from INT-G-07-03 (136,624)
9 Lost and Unaccunted For Gas INT-G-08-03 (4)2,127,002
10 Total Lost and Unaccounted For Gas Amounts Which Apply to RS-1, RS-2, and GS-1 $1,990,378
11 Normalized Sales Volumes (10/1/06 - 9/30107)298,508,602
12 Proposed Temporary Surcharge(Credit) . Lost and Unaccounted For Gas Costs $0.00667
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-07 -03 (Account 1860-2120) (5)$399,945
15 Lost and Unaccounted For Gas Amortization (Account 1860-2140) (6)(438,619)
16 (Over)/Under Collection of Lost and Unaccounted For Gas from INT-G-07-03 (38,674)
17 Lost and Unaccounted For Gas INT-G-08-03 (7)709,756
18 Total Lost and Unaccounted For Gas Amounts Which Apply to LV-1, T-3, T-4 and T-5 $671,082
19 Normalized Sales Volumes (10/1106 - 9/30107)208,817,575
20 Proposed Temporary Surcharge(Credit) . Lost and Unaccounted For Gas Costs $0.00321
(1) See Workpaper No.6, Page 1, Line 17, Column (f)
(2) See Workpaper No.6, Page 1, Line 19, Column (d) times core allocation of 75% per Order No. 30443
(3) See Workpaper No.6, Page 1, Line 23, Column (d)
(4) See Workpaper No.6, Page 1, Line 32, Column (e) times core allocation of 75% per Order No. 30443, plus Line 36, Column (e)
(5) See Workpaper No.6, Page 1, Line 19, Column (d) times industrial allocation of 25% per Order No. 30443
(6) See Workpaper No.6, Page 1, Line 27, Column (d)
(7) See Workpaper No.6, Page 1, Line 32, Column (e) times industrial allocation of 25% per Order No. 30443, plus Line 40, Column (e)
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CASE NO. INT-G-08-03
5.-........b
INTERMOUNTAIN GAS COMPAN
(9 pages)
Workpaper NO.1
Case No. INT-G-08-03
Intermountain Gas Company
Page 1 of 1
INTERMOUNTAIN GAS COMPANY
Summary of Northwest Pipeline TF.1 Full Rate Demand Costs
Line INT.G.07.03 INT.G.07.03 INT.G.07.03
No.Transportation Annual Therms Prices Annual Cost
(a)(b)(c)(d)
1 TF-1 Demand 1 Contract #1 412,537,600 $0.038844 $16,024,611
2 TF-1 Demand 1 Contract #2 25,550,000 0.038414 981,478
3 TF-1 Demand 1 Contract #3 73,000,000 0.038414 2,804,222
4 TF-1 Demand 1 Contract #4 23,542,500 0.037984 894,238
5 TF.1 Demand 1 Contract #5 54,750,000 0.038414 2,103,167
6 TF-1 Demand 1 Contract #6 36,500,000 0.038414 1,402,111
7 Total Annual Cost 625,880,100 $0.038681 $24,209,827
Line INT .G.08.03 INT .G.08.03 INT.G.08.03
No.Transportation Annual Therms Prices Annual Cost
(a)(b)(c)(d)
8 TF-1 Demand 1 Contract #1 412,537,600 $0.038979 $16,080,303
9 TF-1 Demand 1 Contract #2 25,550,000 0.051407 1,313,449
10 TF-1 Demand 1 Contract #3 73,000,000 0.038313 2,796,849
11 TF.1 Demand 1 Contract #4 23,542,500 0.037883 891,861
12 TF-1 Demand 1 Contract #5 54,750,000 0.038313 2,097,637
13 TF.1 Demand 1 Contract #6 36,500,000 0.038313 1,398,425
14 Total Annual Cost 625,880,100 $0.039270 $24,578,524
15 Total Annual Cost Difference (Row 14 minus Row 7)$368,697 (1)
(1) See Exhibit 4, Line 3, Column (h)
Workpaper NO.2
Case No. INT-G-08-03
Intermountain Gas Company
Page 1 of 1
INTERMOUNTAIN GAS COMPANY
Summary of Northwest Pipeline TF.1 Discounted Demand Costs
Line INT.G.07.03 INT.G.07.03 INT.G.07.03
No.Transportation Annual Therms Prices Annual Cost
(a)(b)(c)(d)
1 TF-1 Demand 1 Contract #1 43,680,000 $0.037980 $1,658,966
2 TF-1 Demand 1 Contract #2 28,470,000 0.022790 648,831
3 TF-1 Demand 1 Contract #3 29,404,400 0.020690 608,377
4 TF-1 Demand 1 Contract #4 22,650,000 0.037980 860,247
5 TF-1 Demand 1 Contract #5 36,500,000 0.022790 831,835
6 TF-1 Demand 1 Contract #6 36,500,000 0.026590 970,535
7 TF-1 Demand 1 Contract #7
8 Total Annual Cost 197,204,400 $0.028289 $5,578,791
Line INT .G.08.03 INT .G.08.03 INT .G.08.03
No.Transportation Annual Therms Prices Annual Cost
(a)(b)(c)(d)
9 TF-1 Demand 1 Contract #1 43,680,000 $0.037883 $1,654,729
10 TF-1 Demand 1 Contract #2 28,470,000 0.022730 647,123
11 TF-1 Demand 1 Contract #3 29,404,400 0.020637 606,819
12 TF-1 Demand 1 Contract #4 54,750,000 0.015911 871,127
13 TF-1 Demand 1 Contract #5 36,500,000 0.022730 829,645
14 TF-1 Demand 1 Contract #6 36,500,000 0.026518 967,907
15 TF-1 Demand 1 Contract #7 95,620,860 0.032201 3,079,087
16 Total Annual Cost 324,925,260 $0.026641 $8,656,437
17 Total Annual Cost Difference (Row 16 minus Row 8)$3,077,646 (1)
(1) See Exhibit 4, Line 4, Column (h)
Workpaper NO.3
Case No. INT-G-08-03
Intermountain Gas Company
Page 1 of 1
INTERMOUNTAIN GAS COMPANY
Summary of Upstream Capacity Costs
Line INT.G.07.03 INT .G-07 .03 INT.G.07-03
No.Transportation Annual Therms Prices Annual Cost
(a)(b)(c)(d)
1 Upstream Agreement #1 199,158,600 $0.013629 $2,714,333
2 Upstream Agreement #2 155,624,370 0.007413 1,153,643
3 Upstream Agreement #3 155,025,220 0.021966 3,405,284
4 Upstream Agreement #4 300,325,650 0.013629 4,093,138
5 Upstream Agreement #5 292,197,100 0.007408 2,164,596
6 Upstream Agreement #6 191 ,172,400 0.018662 3,567,659
7 Total Annual Cost $17,098,653
8 Estimated Upstream Capacity Release Credits $(500,000)
9 Total Annual Cost Including Capacity Release Credits $16,598,653
Line INT .G.08.03 INT -G.08.03 INT .G.08.03
No.Transportation Annual Therms Prices Annual Cost
(a)(b)(c)(d)
10 Upstream Agreement #1 190,501,320 $0.015280 $2,910,860
11 Upstream Agreement #2 155,624,370 0.005945 925,187
12 Upstream Agreement #3 155,025,220 0.016505 2,558,691
13 Upstream Agreement #4 300,643,200 0.015281 4,594,129
14 Upstream Agreement #5 292,803,000 0.005941 1,739,543
15 Upstream Agreement #6 191,197,950 0.015487 2,961,083
16 Total Annual Cost $15,689,493
17 Estimated Upstream Capacity Release Credits $(500,000)
18 Total Annual Cost Including Capacity Release Credits $15,189,493
19 Total Annual Cost Difference (Row 18 minus Row 9)$(1,409,160) (1)
(1) See Exhibit 4, Line 5, Column (h)
Workpaper NO.4
Case No. INT-G-08-03
Intermountain Gas Company
Page 1 of 1
INTERMOUNTAIN GAS COMPANY
Summary of Other Storage Facilty Costs
INT.G-07-03
Line Monthly INT.G.07.03 INT -G-07 .03 INT.G.07-03
No.Storage Facilties Biling 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)0.285338 63,299 759,588
4 Clay Basin ill Reservation 213,010 (1)0.285338 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)0.001747 45,536 546,32
9 Total Demand Costs 110,199,970 (3)$445,659 $5,347,908
10 Cycling Costs .
11 Clay Basin i & II Cycling Costs 58,575,000 $0.000877 $51,362 $616,340
12 Clay Basin ILL Cycling Costs 25,560,000 0.000878 22,448 269,378
13 AECO Cycling Costs 26,064,970 0.002192 57,129 685,542
14 Total Cycling Costs 110,199,970 $130,939 $1,571,260
15 Storage Demand Charge Credit $(2,404,586)
16 Total Costs Including Storage Credit $4,514,582
INT.G.08.03
Line Monthly INT -G.08.03 INT .G-08.03 INT.G-08.03
No.Storage Facilties Biling Determinant Prices Monthly Cost Annual Cost
(a)(b)(c)(d)(e)
17 Demand Costs.
18 Clay Basin i Reservation 266,250 (1)$0.285338 $75,971 $911,652
19 Clay Basin II Reservation 221,840 (1)0.285338 63,299 759,588
20 Clay Basin ill Reservation 213,010 (1)0.285338 60,780 729,360
21 Clay Basin i Capacity 31,950,000 (2)0.002378 75,977 911,724
22 Clay Basin II Capacity 26,625,000 (2)0.002378 63,314 759,768
23 Clay Basin II Capacity 25,560,000 (2)0.002378 60,782 729,384
24 AECODemand 26,064,970 (2)0.001865 48,611 291,666 (4)
25 Total Demand Costs 110,199,970 (3)$448,734 $5,093,142
26 Cycling Costs.
27 Clay Basin i & II Cycling Costs 58,575,000 $0.001165 $68,222 $818,663
28 Clay Basin II Cycling Costs 25,560,000 0.001156 29,539 354,462
29 AECO Cycling Costs (4)
30 Total Cycling Costs 84,135,000 $97,761 $1,173,125
31 Estimated Storage Demand Charge Credit $(2,310,376)
32 Total Costs Including Storage Credit $3,955,891
33 Total Annual Cost Difference Including Storage Credit (Row 32 minus Row 16)$(558,691) (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 April 1 , 2009 contract termination.
(5) See Exhibit 4, Line 19, Column (h)
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Workpaper NO.6
Case No. INT-G-08-03
Intermountain Gas Company
Page 1 of 2
INTERMOUNTAIN GAS COMPAN
Analysis of Account 1860 Surcharges (Credits)
Estimatd Sepember 30, 2008
Line!'Description Oetell Oeteil Amount Sub-Totel Totel
(.)(b)(c)(d)(.)(f
ACCOUNT 1860 VARIABLE AMOUNTS:
Net Cumulative Deferre Gii Balance in 1860.2010 as of 10/1107 (1,478,527.72)
Amortzation in 1860.2020 as of6J8 1,249,504.41
Estimated Therm Sales 7/1 through 9130108 22,117,231
Amortzation Rate 0.00507 112,134.36
Estmated Amortizatin in 1860.2020 at 9130108 1,361,638.77
Estimalo Balanc. in 1860.2010 at 9130/08 (116,88.95)
8 Deferred Gas Costs From Proucel'/Suppliers In 1860.2180 at 1011/07 (168,720.04)
9 Deferr Gas Costs From ProducersSuppliers in 1860.2180 through 6J3 14,812,595.62
10 Esllmaled Deferrd Costs in 1860.2180 II1m 71 thl1ugh 9110 649,424.70
11 Estimalo Balance In 1860.2180 at 9130/08 15,293,30.28
12 Daily Gas Exc... Sales Deferr.d In 1860.2240 al 6130108
13 Inte..st Deferrd In 1860.2340 at 10/1/07 29,103.62
14 Inlerel Deterr in 186.2340 thl1ugh 6J 80,440.55
15 Esllmaled Interest fl1m 71 through 91108 92,967.43
16 Estimaled Balance In 1860.2340 et9130/0I 202,511.80
17 ESTIMATED ACCOUNT 1860 VARIABLE BALCE AT 9/30/08 15,378,922.93
18 ACCOUNT 1860 LOST AND UNACCOUNTED FOR AMOUNTS:
19 Net Cumulative Deerred Gai Balanee in 1860.2120 ai of 10/1/07 1,599,779.00
20 Core Amortzation in 1860.2130 as of 6101 (1,246,11.81)
21 Estimated Therm Sales 7/1 through 91010 21,697,898
22 Amortizatn Rate (0.0015)(90,046.28)
23 Estimated Amortzation in 1860.2130 at 9I (1,336,458.09)
24 Industrial Amortization in 1860.2140 as of 6110 (353,254.93)
25 Esimated Thenn Sales 7/1 thl1ugh 91310 44,693,225
26 Amortization Rate (0.00191)(85,364.06)
27 Estimated Amortzatin in 1860.2140 at 91310 (438,618.99)
28 Estimalo Balanco in 1860.2120 at 9/3018 (175,298.08)
29 Lost & Unaccounte For Gas Deferral in 1860.2150 at 1011/07 749,593.05
30 Lost & Unaccunted For Gas Deferrl.in 1860.2150 through 613108 1,322,042.41
31 Estimated Deterr Costs In 1860.2150 frm 7/1 thl1ugh 91310 711,99.59
32 Estimated Balance in 1860.2150 at 9130108 2,783,626.05
33 Core L&U Interest Deferred in 1860.2340 at 1011107 2,08.25
34 Core L&U Interet Deferr in 1860.2340 thl1ugh 610108 29,148.87
35 Estimated Core Interest from 7/1 through 9110 8,04.28
36 Estimalo Belanc.ln 1860.234 at 9130/08 39.282.40
37 Indusllal L&U Inle..st Deferrd In 1880.2360 et 10/1/07 1,293.41
38 Industral L&U Interest Deterrd In 1860.2360 thl1ugh 6130108 9,695.68
39 Estimate Industrial L&U Interest frm 7/1 through 91310 2,860.71
40 Estimalo Balance in 1860.2360 et 9/30/08 13,849.80
41 ESTIMATED ACCOUNT 1860 LOST AND UNACCOUNTED FOR BALANCE AT 9/30/08 2,661,460.17
42 ACCOUNT 1860 FIXED AMOUNTS:
43 Net Cumulative Deferre Gas Balance in 1860.2050 at 10/1101 ($3,939,492.15)
44 R5-1 Deferr Gas Balance In 1860.2060 allO/1107 1,049.70
45 Amortzation for RS-1 in 1860.2060 at 61310 273,486.70
46 Estimated RS-1 Thenn Sales 7/1 thl1ugh 9130108 736,939
47 R8-1 Amorttion Rate 0.00788 5,807.08
48 Estimated RS~ 1 Balance in 186.206 at 9~3 280,343.48
49 RS.2 Deferr Gas Balance in 1880.2070 at 1011107 12,369.44
50 Amortiztin for R5-21n 1860.2070 a161018 2,06,548.66
51 Estimaled R5-2 Thenn Sales 7/1 through 9~10,598,100
52 RS~2 Amortization Rate 0.01228 130,144.67
53 Esllmate R5-2 Balanc in 1860.2070 al 9130108 2,212,06.77
54 G5-1 Deferr Gas Balance In 1860.2080 at 1011107 (19,410.12)
55 Amortizaiion for GS.1 in 186.2080 at 613108 1,527,520.50
56 Estimate Thenn Sales 7/1 through 9130108 10,362,859
57 G8-1 Amorttion Rate 0.01509 156,375.54
58 Eslimate GS-l Balance m 1860.2080 at 91310 1,664,48.92
59 Induslrtal Deferrd Gas Balance in 1860.2090 at 10/110 (10,691.55)
60 Amort~atlonforLV.l, T-1, T-2, & T-5ln 1860.20 al6I108 $202,476.63
61 Estimate LV-11T-1 Blood & 2 Thenn Saies 71 through 913108 1,736,733
62 LV~1fT~1 Amortizatin Rate 0.00588 10,211.99
63 Estimated T-2I.. Contrac Demand Volumes 7/1 through 9110 165,210
64 T ~2I -5 Amortzation Rate 0.15365 25,384.52
65 Estimated Industrial Balanc in 1860.2090 at 9130108 227,381.59
66 Estimated Cumulative Balance In 1860.2050 at 9130108 444,781.61
Workpaper NO.6
Case No. INT-G-08-03
Intermountain Gas Company
Page 2 of2
INTERMOUNTAIN GAS COMPANY
Analysis of Account 1860 Surcharges (Credits)
Estimated Septmber 30, 2008
Une~Description Detail Detail Amount Sub-Total Total
Ie)(b)Ic)(d)(0)in
Fixed Coet Collection Dorrd in 1880.2200 - 2260 al 1011/07 (447,17225)
F~ed Cost Collecn Deferr In 186.2200 - 2260 llrough 6110 ($15,241,533.22)
Estimate F~ed Cost Collectkin Deferr lrom 71 through 91310 8,250,767.96
Esllate Balancoln 1860.2200 - 2260 ot 9130106 (7,437,937.51)
Copaclty Roleand/Purchasod Delorro In 1660.2320 at 10/1107 (280,524.03)
Capacity ReleasePurcase Defened in 186.2320 Ihrough 610108 (891,913.83)
Estimafed Capacty ReleasdlPurcas Delened from 7Illrough 91018 (514,656.11)
Estimatad Balance In 1860.2320 at 9130108 (1,687,093.97)
9 Intarost Defarred In 1860.2420 at 10/1107 128.39
10 Interest Delened in 1880.2420 through 61108 (1,270.18)
11 Estimate Interest frm 7/1 through 913010 316.71
12 Estimated Balance in 1860.2420 at 9130108 (825.08)
13 Intaresl In 1860.2430 at 10/1/07 4,846.47
14 Interest Defened in 1860.2430 through 610108 (100,660.76)
15 Estimated Interest frm 711 through 9ßOI0 (61,831.5)
16 Estimate Balance In 1860.2430 al 9130108 (157,645.44)
17 MlrketSegmentation Deferre In 1860.2530 at 10/1101 0.86
18 Markt Segmentation Deferrd in 186.253 through 610108 (2,543,639.20)
19 Estimatd Deferrl in 1860.2530 from 7/1llrough 913018 (860,601.84)
20 Estimated Balanc in 1860.2530 at 91310 (3.404,240.18)
21 R8-1 Amortiztkin in 1860.2540 at 6130108 410,360.00
22 Estimated RS-l Therm Saleslrom 7/1 through 913010 736,939
23 R8-1 Amorttion Rate 0.01161 8,555.86
24 Estimated RS-l Amortzatin in 1860.2540 at 91018 418,915.86
25 RS.2 Amortzatkin in 1860.2540 at 61108 1,945,923.04
26 Estimated RS-2 Therm Saies from 7/1llrough 913018 10,598,100
27 RS-2 Amortzatkin Rate 0.01138 120,606.38
28 Estimated R8-i Amortization in 1660.2540 at 918 2,066,529.42
29 GS-l Amortizatin in 1860.2540 at 610108 1,05,912.78
30 Estimafed GSl Therm Sales frm 7/1llrough6l10 10,362,859
31 GS-1 Amortizan Rate 0.01054 109,224.53
32 Estimated GS-l Amortzatkin in 186.2540 at 913010 1.163.137.31
33 Estimate Core Amortizatin in 1860.2540 at 913010 3,648,582.59
34 LV-If-l Amortizatkin in 186.2550 at 6~38 88,423.81
35 Estimated LV-1fT-1 Bloc 1 &2 Therm Sales from 7/1 through 9130108 1,736,733
36 LV-11T-l Amortizan Rafe 0.00430 7,467.95
37 Estimated LV-11T-1 Amorttkin in 186.2550 at 9110 95,891.6
38 T-2I.5 Amortizatkin in 1860.2550 at 6110 35,907.92
39 Estimate T-2I -I Contra from 7/1 through 91310 165,210
40 T.2f-5Amortzatin Rate 0.07245 11,969.46
41 Estimated T-2I -I Amortiztkin in 1860.2550 at 9130108 47,87738
42 Estimated Industral Amorttkin in 1860.2550 at 91310 143,769.14
43 Esll,tad B,lanco in 1860.2530,19/30108 388,111.55
44 ESTIMATED ACCOUNT 1860 FIXED BALANCE AT 9/30/08 (8,450.608.84)
45 TOTAl DEFERRED ACCOUNT 1860 BALNCE 9.589,n4.26
INTERMOUNTAIN GAS COMPANY
Analysis of LV.1 Tariff Block 1, Block 2, and Block 3 Adjustments
Line
No.Description
(a)
Block 1
Therm Sales
(b)
LV-1 Therm Sales (10/1/06 - 9/30/07)2,664,515
2 Blocks 1 and 2 Therm Sales 2,664,515
3 Percent Therm Sales between Blocks 1 and 2 100.000%
4 Proposed Adjustment to LV-1 Tariff (1)
5 LV-1 Therm Sales (10/1/06 - 9/30/07)
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)
1 0 Block 1 and 2 Therms
11 Price AdjustmenUTherm Block 1 and 2 (Line 9 divided by Line 10)
12 WACOG Commodity Charge Change (2)
13 Total Price AdjustmenUTherm Block 1 and Block 2
14 Price AdjustmenUTherm Block 3 (3)
15 WACOG Commodity Charge Change (2)
16 Total Price AdjustmenVTherm Block 3
Block 2
Therm Sales
(c)
0.000%
(1) See Exhibit NO.4; Line 30, Col. (i) minus the difference of Line 21, Col. (0 minus Line 21, Col. (c)
(2) See Exhibit NO.4; Line 21, Col. (0 minus Line 21, Col. (c)
(3) See Exhibit NO.6, Line 3, Col. (e)
Workpaper NO.7
Case No. INT-G-08-03
Intermountain Gas Company
Page 1 of 1
Block 3
Therm Sales
(d)
o
o
Total
(e)
o 2,664,515
2,664,515
100.000%
$0.05881
2,664,515
$156,700
$156,700
100.000%
$156,700
2,664,515
$
$
0.05881
0.14901
0.20782
$
$
0.05427
0.14901
0.20328
Workpaper NO.8
Case No. INT -G-08-03
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.08.03
2
3
Intermountain Estimated FY08 Sales 1
L&U rate per therm embedded in base rates 2
559,313,840
$0.00182
4 FY08 Collection of L&U Gas $1,017,951
5
6
Projected FY08 L&U (Therms)
WACOG/Therm 2
4,800,000
$0.63583
8 Projected L&U (Over)/Under Collection (Line 7 minus Line 4)
$3,051,984
$2,034,033
7 Projected FY08 L&U
1 Estimated FY08 Sales (Therms)
RS-1
RS-2
GS-1
Industrial
Total Sales
35,731,041
179,971,737
111,884,740
231,726,322
559,313,840
2 Per INT-G-07-03