20060816Application.pdf

EXECUTIVE OFFICES
INTERMOUNTAIN GAS COMPANY RECEIVED
555 SOUTH COLE ROAD. P.O. BOX 7608 . BOISE, IDAHO 83707 . [phone] . FAX: [phone]
2006 AUG 16 AM 9:
August 16 , 2006 IDAHO PUBLIC
UTiLITIES CO~.Hj)iSSiON
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-06-
Dear Ms. Jewell:
Enclosed for filing with this Commission is a signed original and seven copies of
Intermountain Gas Company s Application and supporting Workpapers for Authority to
change its Prices on October 1 , 2006.
Please acknowledge receipt of this filing by stamping and returning a photocopy of this
Application cover letter to us.
If you have any questions or require additional information regarding the attached
please contact me at 377-6168.
Ve~
irector
Gas Supply and Regulatory Affairs
MPM/blf
Enclosures
W. C. Glynn
P. R. Powell
M. E. Rich
M. W. Richards, Jr.
RECEIVED
2006 AUG I 6 AM 9: 19
INTERMOUNTAIN GAS COMPANY IDAHO PUBLIC
UTILITIES COMMISSION
CASE NO. INT-OG-
APPLICATION,
EXHIBITS,
AND
WORKP APERS
In the Matter of the Application of INTERMOUNTAIN GAS COMPANY
for Authority to Change Its Prices on October 1 2006
(October 1 , 2006 Purchased Gas Cost Adjustment Filing)
Morgan W. Richards, Jr.
ISB # 1913
804 East Pennsylvania Lane
Boise, Idaho 83706
Telephone [phone]
Attorney for Intennountain Gas Company
RECEIVED
2006 AUG 1 6 AM 9: 19
IDAHO PUBU(;
UTILITIES COMMISSION
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
In the Matter of the Application of
INTERMOUNTAIN GAS COMPANY
for Authori to Chan e Its Prices
Case No. INT-06-
APPLICATION
Intennountain Gas Company ("Intennountain ), an Idaho corporation 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 in effect October 1 , 2006 new rate schedules which will
decrease its annualized revenues by $1.6 million, pursuant to the Rules of Procedure of the Idaho
Public Utilities Commission ("Commission ). Because of changes in Intennountain s gas related
costs, as described more fully in this Application, Intennountain s earnings will not be decreased as
a result of the proposed changes in prices and revenues. Intennountain s current rate schedules
showing proposed changes are attached hereto as Exhibit No.1 and are incorporated herein by
reference. Intennountain s proposed rate schedules are attached hereto as Exhibit No.2 and are
incorporated herein by reference.
Communications in reference to this Application should be addressed to:
Paul R. Powell
Executive Vice President & Chief Financial Officer
Intennountain Gas Company
Post Office Box 7608, Boise, ID 83707
and
Morgan W. Richards, Jr.
Attorney
804 East Pennsylvania Lane, Boise, ID 83706
In support of this Application, Intennountain does allege and state as follows:
APPLICATION - 2
Intennountain is a gas utility, subject to the jurisdiction of the Idaho Public Utilities
Commission, engaged in the sale of and distribution of natural gas within 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.
Intennountain provides natural gas service to the following Idaho communities and counties
and adjoining areas:
Ada County - Boise, Eagle, Garden City, Kuna, Meridian, and Star;
Bannock County - Chubbuck, Inkom, Lava Hot Springs, McCammon, and Pocatello;
Bear Lake County - Georgetown, and Montpelier;
Bingham County - Aberdeen, Basalt, Blackfoot, Firth, Fort Hall, MorelandlRiverside, and Shelly;
Blaine County - Bellevue, Hailey, Ketchum, and Sun Valley;
Bonneville County - Ammon, Idaho Falls, lona, and Ucon;
Canyon County - Caldwell, Greenleaf, Middleton, Nampa, Panna, and Wilder;
Caribou County - Bancroft, Conda, Grace, and Soda Springs;
Cassia County - Burley, Declo, Malta, and Raft River;
Elmore County - Glenns Ferry, Hammett, and Mountain Home;
Fremont County - Parker, and S1. 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, Murtaugh, and Twin Falls;
Washington County - Weiser.
Intennountain s properties in these locations consist of transmission pipelines, a compressor
station, a liquefied natural gas storage facility, distribution mains, services, meters and regulators
and general plant and equipment.
II.
Intennountain seeks with this Application to pass through to each of its customer classes a
change in gas related costs resulting ITom: 1) an increase in costs billed Intennountain pursuant to
General Rate Cases filed by Northwest Pipeline Corporation ("Northwest" or "Northwest
Pipeline ) and Gas Transmission Northwest Corporation ("Gas Transmission Northwest" or
APPLICATION - 3
GTN"), 2) benefits included in Intennountain s flITll transportation and storage costs resulting
from Intennountain s management of its storage and finn capacity rights on pipeline systems
including Northwest Pipeline and GTN, 3) a decrease in Intennountain s Weighted Average Cost
of Gas ("W ACOG"), 4) an updated customer allocation of gas related costs pursuant to the
Company s Purchased Gas Cost Adjustment provision, and 5) the inclusion of temporary
surcharges and credits for one year relating to gas and interstate transportation costs ITom
Intennountain's deferred gas cost account. Exhibit No.3 contains pertinent excerpts ITom pipeline
and related facilities' tariffs. Intennountain also seeks with this Application to eliminate the
temporary surcharges and credits included in its current prices during the past 12 months, pursuant
to Case No. INT-05-2. The aforementioned changes would result in an overall price decrease to
Intennountain s RS-, RS-, GS-, and LV-1 customers, a price decrease to Intennountain s T-
customers, and an increase in Intennountain s T-2 Demand Charge and a decrease to the T-
Commodity Charge.
These price changes are applicable to service rendered under rate schedules affected by and
subject to Intennountain s Purchased Gas Cost Adjustment ("PGA"), initially approved by this
Commission in Order No. 26109, Case No. INT-95-, and additionally approved through
subsequent proceedings.
Exhibit No.4 summarizes the price changes in: 1) Intennountain s base rate gas costs and its
rate class allocation, and 2) adjusting temporary surcharges or credits flowing through to
Intennountain s direct sales and transportation customers. Exhibit No.s 3 and 4 are attached hereto
and incorporated herein by reference.
III.
The current prices of Intennountain are those approved by this Commission in Order
No. 29875, Case No. INT-05-
IV.
Intermountain s proposed prices incorporate all price changes impacting Intennountain
finn interstate transportation capacity including, but not limited to, any such changes
implemented by Northwest and GTN which have occurred since Intennountain s last PGA filing
in Case No. INT-05-2. Exhibit No., Lines 1 through 23 , details the proposed changes in
APPLICATION - 4
Intermountain s prIces resulting from adjustments to Intennountain s cost of interstate and
upstream capacity from its various suppliers.
On June 30, 2006, Northwest Pipeline Corporation filed a general system rate case with
the Federal Energy Regulatory Commission ("FERC") in Docket No. RP06-416-000. This filing
is the first general rate increase sought by Northwest in nearly ten years. The FERC suspended
the effective date of Northwest's proposed rates until January 1 , 2007, subject to refund and
conditions and the outcome of the FERC hearing. Intennountain s proposed prices have been
weighted to reflect this January 1 , 2007 effective date. Intennountain has representation at FERC
to intervene in Northwest's General Rate Case proceeding.
Intennountain 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
of GTN's proposed rates until January 1 2007, subject to refund and conditions and the outcome
of the FERC hearing. lntennountain s proposed prices have been weighted to reflect this January
, 2007 effective date. GTN's current rates are based on its last rate case, filed in 1994.
Intennountain has representation at FERC to intervene in GTN's General Rate Case proceeding.
Intennountain is party to certain agreements whereby Intennountain manages its storage
related assets in conjunction with a third party asset manager. Intennountain proposes to pass back
to its customers the benefits generated from these agreements as included on Exhibit No., Line
19.
The W ACOG reflected in Intennountain s proposed prices is $0.72400 per thenn, as shown
on Exhibit No., Line 24, Column (t). This compares to $0.73219 per thenn currently included in
the Company s tariffs.
As stated in the Company s Customer Notice, despite a 30% increase in crude oil
prices during this past year when the Company last changed its natural gas prices, the Company has
not increased in its Application the natural gas cost to its customers. Natural gas prices have been
moderated by historically high levels of natural gas stored in the nation s inventory; natural gas
production, which was shut-in after the impact of Hurricane Katrina, has now largely come back
APPLICATION - 5
on-line in the Gulf of Mexico and the outlook for the upcoming hurricane season is moderate as
compared to last season; and price induced domestic natural gas rig counts and production are up as
compared to a year ago.
The proposed W ACOG includes the benefits to Intennountain s customers generated by
Intermountain s management of significant natural gas storage assets whereby gas is procured
during the traditionally lower priced summer season for withdrawal and use during the winter when
prices would otherwise be substantially higher. Additionally, and in an effort to further stabilize the
prices paid by our customers during the upcoming winter storage withdrawal period, Intennountain
entered into hedging agreements to lock-in the price for 100% of the company s April 2006 to
October 2006 storage injections.
Intennountain also believes that the W ACOG proposed in this Application, subject to the
effect of actual supply and demand, will likely materialize during the upcoming PGA period
because Intennountain is planning to employ, in addition to those natural gas hedges already in
place for the high winter demand, cost effective financial instruments to secure those prices
embedded within the filed W ACOG when and if those pricing opportunities materialize in the
marketplace.
However, liquidity in the market is sustained by contrary opinions and natural gas prices
could indeed realize levels different from those included in this Application. Although current
commodity futures prices dictate the use of this $0.72400 per thenn W ACOG, Intennountain
continues to remain vigilant in monitoring natural gas prices and is committed to come before this
Commission prior to this winters heating season with an Application to further amend these
proposed prices, should these forward prices materially deviate from the $0.72400 per thenn.
Timely natural gas price signals and the accounting for any cost differences brought about
by these volatile markets, facilitated through the use of the PGA mechanism, enhances our
customers' ability to make timely and infonned energy use decisions and ensures they only pay the
actual cost of such supplies. It is important to continue to alert our customers in a timely manner to
these impending increases before their higher natural gas usage is before them. By employing the
use of customer mailings and various media resources, Intennountain will continue to educate its
customers regarding the wise and efficient use of natural gas, billing options available to help our
customers manage their energy budget, and pending natural gas unit price changes.
APPLICATION - 6
VI.
Pursuant to Case No. INT-05-, Intennountain has included temporary surcharges and
credits in its October 1 , 2005 prices for the principal reason of collecting or passing back to its
customers deferred gas cost charges and benefits, as outlined in Case No. INT -05-2. Line 29 of
Exhibit No.4 reflects the elimination of these temporary surcharges and credits.
VII.
Intennountain s PGA tariff includes provisions whereby Intennountain 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. Intennountain s proposed prices
include a fixed cost collection adjustment pursuant to these PGA provisions, as outlined on Exhibit
No., Line 24. The price impact of this adjustment is included on Exhibit No., Line No. 30.
Exhibit No.5 is attached hereto and incorporated herein by reference.
VIII.
Intennountain is party to certain agreements whereby Intennountain has released segmented
portions of its finn capacity rights when not needed to meet its customer needs. Intennountain
proposes to pass back to its customers the benefits generated from the capacity release agreements
totaling $3.5 million. Exhibit No., Line 1 , reflects the inclusion of the $3.5 million credit.
Intennountain proposes to pass back this amount via the per thenn credit as detailed on Exhibit
No.7. Exhibit No.s 6 and 7 are attached hereto and incorporated herein by reference.
IX.
Intennountain proposes to allocate deferred gas costs from its Account No. 186 balance
its customers through temporary price adjustments to be effective during the 12-month period
ending September 30 2007, as follows:
1) Intennountain has been deferring in its Account No. 186 fixed gas costs. The
credit amount shown on Exhibit No., Line 9 , Co!. (b) of$3.1 million is predominantly attributable
to the collection of interstate pipeline capacity costs and the true-up of expense issues previously
ruled on by this Commission. Intennountain proposes to collect or pass back these balances via the
per thenn surcharges and credits, as detailed on Exhibit No.8 and included on Exhibit No., Line
2. Exhibit No.8 is attached hereto and incorporated herein by reference.
APPLICATION - 7
2) Intennountain has been deferring in its Account No. 186 deferred gas cost debits
of $14.1 million, as shown on Exhibit No., Line 2, Co!. (b), attributable to Intennountain
variable gas costs since September 1, 2005. Intennountain proposes to collect this debit balance via
a per thenn surcharge, as shown on Exhibit No., Line 4, Co!. (b) and included on Exhibit No.
Line 3. Exhibit No.9 is attached hereto and incorporated herein by reference.
Intennountain has allocated the proposed price changes to each of its customer classes
based upon Intennountain s PGA provision. A straight cent-per-thenn price decrease was not
utilized for the T -1 tariff. No fixed costs are currently recovered in the tail block of Intennountain
1 tariff. Absent Williams' finn transportation TF-1 Commodity Charge, the proposed decrease
in the T -1 tariff is fixed cost related, and therefore, a cent per thenn decrease was made only to the
first two blocks of the tariff for these fixed costs.
XI.
The proposed increase to the T-2 tariff Demand Charge is fixed cost related, and therefore, a
cent per thenn increase was made to the T-2 Demand Charge for these fixed costs. Additionally, the
proposed decrease to the T-2 Commodity Charge incorporates the decrease in the Williams' finn
transportation TF -1 Commodity Charge.
XII.
Exhibit No.1 0 is an analysis of the overall price changes by class of customer. Exhibit No.
10 is attached hereto and incorporated herein by reference.
XIII.
The proposed overall price change herein requested among the classes of service of
Intennountain will not affect Intennountain s earnings, and is just, fair, and equitable.
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 Intennountain
customers through a Customer Notice and by a Press Release sent to daily and weekly newspapers
and major radio and television stations in Intennountain s service area. The Press Release and
Customer Notice are attached hereto and incorporated herein by reference. Copies of this
APPLICATION - 8
Application, its Exhibits, and Workpapers have been provided to those parties regularly intervening
in Intennountain s rate proceedings.
xv.
Intennountain requests that this matter be handled under modified procedure pursuant to
Rules 201-204 of the Commission s Rules of Procedure. Intennountain stands ready for immediate
consideration of this matter.
APPLICATION - 9
WHEREFORE, Intennountain 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 , 2006 in the manner shown on Exhibit No.
b. That this Application be heard and acted upon without hearing under modified procedure
and
For such other relief as this Commission may detennine proper herein.
DATED at Boise, Idaho, this 16th day of August, 2006.
INTERMOUNTAIN GAS COMPANY Morgan W. Richards, Jr.
By
Paul R. Powell
Executive Vice President & CFO
By
~.
\J .
~~~
Morgan W. . chards, Jr.
Attorney for Intennountain Gas Company
APPLICATION - 10
CERTIFICATE OF MAILING
I HEREBY CERTIFY that on this 16th day of August, 2006, I served a copy of the
foregoing Case No. INT -06-04 upon:
Paula Pyron
Northwest Industrial Gas Users
4113 Wolf Berry Court
Lake Oswego, OR 97035
Edward A. Finklea
Cable Huston Benedict Haagensen & Lloyd LLP
1001 SW Fifth Avenue, Suite 2000
Portland, Oregon 97204-1136
R. Scott Pasley
1. R. Simplot Company
PO Box 27
Boise, ID 83707
David Hawk
1. R. Simp10t Company
PO Box 27
Boise, ID 83707
Conley E. Ward, Jr.
Givens, Pursley, Webb & Huntley
277 N. 6th St., Suite 200
PO Box 2720
Boise, ID 83701
by depositing true copies thereof in the United States Mail, postage prepaid, in envelopes addressed
to said persons at the above addresses.
APPLICATION - 11
EXHIBIT NO.
CASE NO. INT-OG-
INTERMOUNTAIN GAS COMPANY
CURRENT TARIFFS
Showing Proposed Price Changes
(8 pages)
RECEIVED
2006 AUG '6 AM 9: 20
IDAHO PUBlIC-UTILITIES COMMISSION
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 1 of 8
COMPARISON OF PROPOSED OCTOBER 1, 2006 PRICES
TO OCTOBER 1 2005 PRICES
October I, 2005 Proposed
Line Prices per Proposed October 1,2006
No.Rate Class INT-05-Adjustment Prices
(a)(b)(c)(d)
RS-
April- November 1.25501 (0.00058)25443
December - March 1.14245 (0.00058)1.14187
RS-
April- November 1.10648 (0.00100)1.1 0548
December - March 07285 (0.00100)1.07185
GS-
April - November
Block I 1.13515 (0.01209)1.12306
Block 2 1.11342 (0.01209)1.10133
Block 3 1.09240 (0.01209)08031
December - March
Block 1 08430 (0.01209)1.07221
Block 2 1.06310 (0.01209)1.05101
Block 3 04264 (0.01209)1.03055
CNG Fuel 1.04264 (0.01209)03055
LV-I (1)
Block 1 88912 (0.00025) (2)88887
Block 2 85063 (0.00025) (3)85038
Block 3 77051 00916 (4)77967
Block 1 12929 (0.01110) (2)11819
Block 2 09080 (0.01110) (3)07970
Block 3 01068 (0.00169) (4)00899
Demand Block 1 70931 12103 83034
Demand Block 2 90773 12103 1.02876
Commodity Charge 00653 (0.00169)00484
Over-Run Service 04912 (0.00169)04743
(1) The LV -1 Adjustment is calculated by taking the figures in Lines 22 - 24, Col ( c), plus removal
of the TF-1 Commodity Charge change, plus the change in the W ACOG, plus removal of the
temporary variable surcharge from 1NT -05-2 of $0.03171, plus the temporary variable
debit on Exhibit 9, Line 4, Col (b)
(2) See Workpaper No., Line 13, Col (e)
(3) See Workpaper No., Line 20, Col (e)
(4) See Workpaper No., Line 21 , Col (e)
I.P.C. Gas Tariff
Second Revised Volume No.
(Supersedes First Revised Volume No.
Thirty-SOOR Seventh Revised Sheet No. 01 (Page 1 of 1)
Name
of Utility Intermountain Gas Company
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 2 of 8
IDAHO PUBLIC UTILITIES COMMISSION'APPROVED EFFECTIVE
Rate Schedule RS-
RESIDENTIAL SERVICE SEP 30 '05 OCT 1- '
~V\. 'O- d-.Q'615
~ m - SECRETARY-
AVAILABILITY:
Available to individually metered consumers not otherwise specifically provided for, usingnatural gas for residential purposes.
RATE:
Monthly minimum charge is the customer charge.
For billinQ Deriods endinQ ADrii throuQh November
Customer Charge - $2.50 per bill
Commodity Charge - $1.25501 $1.25443 per therm
For billina Deriods endina December throuah March
Customer Charge - $6.50 per bill
Commodity Charge - $1.14245 $1.14187 per therm
Includes:
Temporary purchased gas cost adjustment of $0.06562 $0.03422
Weighted ayerage cost of gas of $0.73219 $0.72400
PURCHASED GAS COST ADJUSTMENT:
This tariff is subject to an adjustment for cost of purchased gas as provided for in the
Company s Purchased Gas Cost Adjustment Provision.
SERVICE CONDITIONS:
All natural gas service hereunder is subject to the General Service Provisions of the
Company s Tariff, of which this rate schedule is a part.
Issued by: Intermountain Gas Company
By: Paul R. Powell Title: Executive Vice President & Chief Financial Officer
Effective: October 1 2006
I.P.C. Gas Tariff
Second Revised Volume No.
(Supersedes First Revised Volume No.
Thirty-SOOR Seventh Revised Sheet No. 02
Name
of Utility
(Page 1 of 1)
Intermountain Gas Company
Exhibit No.
Case No. INT -O6-04 '
Intermountain Gas Company
Page 3 of 8
IDAHO PUBLIC UTILITIES COMMISSION-APPROVED EFFECTIVE
Rate Schedule RS-
MULTIPLE USE RESIDENTIAL SERVICE
SEP 30 '05 OCT 1- '
~~. 0.1\). d.-Q'615
.n. . SECRETARY.
AVAILABILITY:
Available to individually metered consumers using gas for several residential purposes
including both water heating and space heating.
RATE:
Monthly minimum charge is the customer charge.
For billinQ Deriods endinQ ADrii throuQh November
Customer Charge - $2.50 per bill
Commodity Charge - $1.10648 $1.10548 per therm
For billinQ Deriods endinQ December throuQh March
Customer Charge - $6.50 per bill
Commodity Charge $1.07286 $1.07185 per therm
Includes:
Temporary purchased gas cost adjustment of $0.04838 $0.02786
Weighted average cost of gas of $0.73219 $0.72400
PURCHASED GAS COST ADJUSTMENT:
This tariff is subject to an adjustment for cost of purchased gas as provided for in the
Company s Purchased Gas Cost Adjustment Provision.
SERVICE CONDITIONS:
All natural gas service hereunder is subject to the General Service Provisions of the
Company s Tariff, of which this rate schedule is a part.
Issued by: Intermountain Gas Company
By: Paul R. Powell Title: Executive Vice President & Chief Financial Officer
Effective: October 1, 2OOa 2006
LP.C. Gas Tariff
Second Revised Volume No.
(Supersedes First Revised Volume No.Thirty-~ Ninth Revised Sheet No. 03 (Page 1 of 2)
Name
of Utility
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 4 of 8
Intermountain Gas Company IDAHO PUBLIC UTILITIES COMMISSION'APPROVED EFFECTIVE
Rate Schedule GS-
GENERAL SERVICE
SEP 30 '05 OCT 1- '
~V\. o.~- d-q~l 5
~ ~
. SEORErARY.
AVAILABILITY:
Available to individually metered customers whose requirements for natural gas do not exceed000 therms per day, at any point on Company s distribution system. Requirements in excess of
000 therms per day may be served under this rate schedule upon execution of a one-year written
service contract.
RATE:
Monthly minimum charge is the customer charge.
For billinQ periods endinQ April throuQh November
Customer Charge - $2.00 per bill
Commodity Charge - First 200 therms per bill CID $1.13515*$1.12306*
Next 1,800 therms per bill CID $1.11342*$1.10133*
Over 2 000 therms per bill CID $1.09240*$1.08031 *
For billinQ periods endinQ December throuQh March
Customer Charge - $9.50 per bill
Commodity Charge - First 200 therms per bill CID $1.08430*$1.07221*
Next 1,800 therms per bill $1.06310*$1.05101*
Over 2,000 therms per bill $1.04264*$1.03055*
Includes:
Temporary purchased gas cost adjustment of $0.04984 $0.02520
Weighted average cost of gas of $0.73219 $0.72400
Issued by: Intermountain Gas Company
By: Paul R. Powell Title: Executive Vice President & Chief Financial OfficerEffective: October 1 -2008 2006
LP.C. Gas Tariff
Second Revised Volume No.
(Supersedes First Revised Volume No.Thirty-EigAtR Ninth Revised Sheet No. 03 (Page 2 of 2)
Name
of Utility
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 5 of 8
Intermountain Gas Company IDAHO PUBLIC UTILITIES COMMISSION-APPROVED EFFECTIVE
Rate Schedule GS-
GENERAL SERVICE (Continued)
SEP 30 '05 OCT 1- '
~V\. ~. d-q~15~m~ . SECRETARY.
For separately metered deliveries of gas utilized solely as Compressed Natural Gas Fuel in
vehicular internal combustion engines.
Customer Charge - $9.50 per bill
Commodity Charge - $1.04264 $1.03055 per therm
Includes:
Temporary purchased gas cost adjustment of $9.94984 $0.02520
Weighted average cost of gas of $9.73219 $0.72400
PURCHASED GAS COST ADJUSTMENT:
This tariff is subject to an adjustment for cost of purchased gas as provided for in the
Company s Purchased Gas Cost Adjustment Provision.
SERVICE CONDITIONS:
1. Any GS-1 customer who leaves the GS-1 service will pay to Intermountain Gas Company,
upon exiting the GS-1 service, all gas and transportation related costs incurred to serve
the customer during the GS-1 service period not borne by the customer during the time the
customer was using GS-1 service. Any GS-1 customer who leaves the GS-1 service will
have refunded to them, upon exiting the GS-1 service, any excess gas commodity or
transportation payments made by the customer during the time they were a GS-
customer.
2. All natural gas service hereunder is subject to the General Service Provisions of the
Company s Tariff, of which this rate schedule is a part.
Issued by: Intermountain Gas Company
By: Paul R. Powell Title: Executive Vice President & Chief Financial Officer
Effective: October 1 2006
I.P.C. Gas Tariff
Second Revised Volume No.
(Supersedes First Revised Volume No.
Forty-SOOA Seventh Revised Sheet No. 04 (Page 1 of
Name
of Utili
Exhibit No.
Case No. INT -O6-
Intermountain Gas Gompany
Page 6 of 8
Intermountain Gas Compan IDAHO PUBLIC UTILITIES COMMISSION"APPROVED EFFECTIVE
Rate Schedule LV-
LARGE VOLUME FIRM SALES SERVICE
SEP 30 '05 OCT 1- '
~V\. tO. d-q~lS~m~ . SECRETARY
AVAILABILITY:
Available at any mutually agreeable delivery point on the Company s distribution system to any
existing customer receiving service under the Company s rate schedules LV-, T-1, or T-2, or any new
customer whose usage does not exceed 500,000 therms annually, upon execution of a one-year
minimum written service contract for firm sales service in excess of 200,000 therms per year.
MONTHLY RATE:
Commodity Charge:
First 250,000 therms per bill (fY $0.88912*$0.88887*Next 500,000 therms per bill (fY $0.86063*$0.85038*
Amount Over 750,000 therms per bill (fY $0.77061**$0.77967**
The above prices include weighted average cost of gas of $0.73219 $0.72400
Includes temporary purchased gas cost adjustment of $0.03032 $0.03084
**
Includes temporary purchased gas cost adjustment of $0.03171 $0.04906
PURCHASED GAS COST ADJUSTMENT (PGA):
This tariff is subject to an adjustment for cost of purchased gas as provided for in the Company
Purchased Gas Cost Adjustment Provision.
SERVICE CONDITIONS:
1. All natural gas service hereunder is subject to the General Service Provisions of the
Company s Tariff, of which this Rate Schedule is a part.2. Any LV-1 customer who exits the LV-1 service at any time (including, but not limited to, the
expiration of the contract term) will pay to Intermountain Gas Company, upon exiting the LV-1 service,
all gas and/or interstate transportation related costs to serve the customer during the LV-1 contract
period not borne by the customer during the LV-1 contract period. Any LV-1 customer will have
refunded to them, upon exiting the LV-1 service, any excess gas and/or interstate transportation related
payments made by the customer during the LV-1 contract period.3. In the event that total deliveries to any customer within the last three contract periods met or
exceeded the 200,000 therm threshold, but the customer during the current contract period used less
than the contract minimum of 200,000 therms, an additional amount shall be billed. The additional
amount shall be calculated by billing the deficit usage below 200,000 therms at the T -1 Block 1 rate. The
customer s future eligibility for the LV-1 Rate Schedule will be renegotiated with the Company.
Issued by: Intermountain Gas Company
By: Paul R. Powell Title:
Effective: October 1, 2OO€i 2006
Executive Vice President & Chief Financial Officer
I.P.C. Gas Tariff
Second Revised Volume No.
(Supersedes First Revised Volume No.
Thirty Second Third Revised Sheet No. 05 (Page 1 of 2)
Name
of Utilitv Intermountain Gas Company
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Pa!;le 7 of 8
IDAHO PUBLIC UTILITIES COMMISSION" .APPROVED EFFECTIVE
Rate Schedule T-
FIRM TRANSPORTATION SERVICE
SEP 30 '05 OCT 1- '
~~. C.I\). d-q~15
~ m . SECRETARY.
AVAilABILITY:
Available at any mutually agreeable delivery point on the Company s distribution system to any existing
customer receiving service under the Company s rate schedules lV-1, T-1, or T-2, upon execution of a one
year minimum written service contract for firm transportation service in excess of 200,000 therms per year.
MONTHLY RATE:
Commodity Charge:
Block One:
Block Two:
Block Three:
First 250,000 therms transported $0.12929*$0.11819*
Next 500,000 therms transported $0.09080*$0.07970*
Amount over 750,000 therms transported $0.01068 $0.00899
Includes temporary purchased gas cost adjustment of $(0.00139)$(0.01822)
PURCHASED GAS COST ADJUSTMENT:
This tariff is subject to an adjustment for cost of purchased gas as provided for in the Company
Purchased Gas Cost Adjustment Provision.
SERVICE CONDITIONS:
1. All natural gas service hereunder is subject to the General Service Provisions of the Company s Tariff, of
which this Rate Schedule is a part.
2. The customer shall negotiate a Maximum Daily Firm Quantity (MDFQ) amount, which will be stated in and
will be in effect throughout the term of the service contract. The MDFQ shall not exceed the customer
historical maximum daily usage, as agreed to by the Company.
In the event the Customer requires daily usage in excess of the MDFQ, and subject to the availability of
firm interstate transportation to service Intermountain s system, all such usage may be transported and
billed under either secondary rate schedule T -3 or T -4. The secondary rate schedule to be used shall be
predetermined by negotiation between the Customer and Company, and shall be included in the service
contract. All volumes transported under the secondary rate schedule are subject to the provisions of the
applicable rate schedule T -3 or T -4.
Issued by: Intermountain Gas Company
By: Paul R. Powell Title: Executive Vice President & Chief Financial Officer
Effective: October 1 2006
Name
of Utility Intermountain Gas Company
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 8 of 8
IDAHO PUBLIC UTILITIES COMMISSION"APPROVED EFFECTIVE
LP.C. Gas Tariff
Second Revised Volume No.
(Supersedes First Revised Volume No.
Thirteonth Fourteenth Revised Sheet No.1 0 (Page 1 of 2)
SEP 30 '05 OCT 1- '
?~. o.t0- d-q~15~ m~ . SECRETARY.
Rate Schedule T-
FIRM TRANSPORTATION SERVICE WITH MAXIMUM DAILY DEMANDS
AVAILABILITY:
Available at any mutually agreeable delivery point on the Company s distribution system to anyexisting T -2 customer whose daily contract demand for nonammonia therms on any given day meets orexceeds a predetermined level agreed to by the customer and the Company upon execution of a one-yearminimum written service contract for firm transportation service in excess of 200,000 therms per year.
MONTHLY RATE:
Firm Service
Demand Charge:
Firm Daily Demand -
First 15,000 therms
Amount over 15,000 therms
Commodity Charge:
For Firm Therms Transported
Over-Run Service
Rate Per Therm
$1.70931*$1.83034*
$0.90773*$1.02876*
$0.00653 $0.00484
Commodity Charge:
For Therms Transported In Excess Of MDFQ:$0.04912 $0.04743
Includes temporary purchased gas cost adjustment of $(0.08920)$(0.15687)
PURCHASED GAS COST ADJUSTMENT:
This tariff is subject to an adjustment for cost of purchased gas as provided for in the CompanyPurchased Gas Cost Adjustment Provision.
SERVICE CONDITIONS:
All natural gas service hereunder is subject to the General Service Provisions of the Company s Tariffof which this Rate Schedule is a part.
The customer shall nominate a Maximum Daily Firm Quantity (MDFQ), which will be stated in and willbe in effect throughout the term of the service contract.
The monthly Demand Charge will be equal to the MDFQ times the Firm Daily Demand rate. Firmdemand relief will be afforded to those T -2 customers paying both demand and commodity charges
for gas when, in the Company s judgment, such relief is warranted.
The actual therm usage for the month or the MDFQ times the number of days in the billing month,
whichever is less, will be billed at the applicable commodity charge for firm therms.
Issued by: Intermountain Gas CompanyBy: Paul R. Powell Title: Executive Vice President & Chief Financial Officer
Effective: October 1 , 2OOa 2006
INTERMOUNTAIN GAS CO.
CASE NO. INT-O6-
EXHIBIT NO.
(PROPOSED TARIFFS)
HAS BEEN SCANNED
SEP ARA TEL Y
EXHIBIT NO.
RECE\VEO
200G ~UG '6 ~M 9: 22
IDAHO PUBPC
UTILITIES COMf.~\SSION
CASE NO. INT-O6-
INTERMOUNTAIN GAS COMPANY
PERTINENT EXCERPTS FROM INTERSTATE PIPELINES AND RELATED
FACILITIES
(49 pages)
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 1 of 49
Williams Northwest Pipeline Corporation
Northwest Pipeline " or "Northwest"
Applicable Tariffs/Rate Schedules
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 2 of 49
.JI~~"r"I"lamS
NORTHWEST PIPELINE
o. Box 58900
Salt Lake City, lIT 84158-0900
Phone: [phone]
FAX: [phone]
To: All Shippers on Northwest Pipeline Corporation s Transmission System
and Affected State Regulatory Commissions
On June 30, 2006, Northwest Pipeline Corporation filed a general system rate case with
the Federal Energy Regulatory Commission. The attached is an abbreviated copy of
the rate case filing. Please distribute to interested people within your organization.Upon request; Northwest will send a full copy of this filing to you or others within your
organization.
Requests for full copies should be directed to Barbara Odland as follows:
Barbara Odland
Northwest Pipeline Corporation
O. Box 58900
Salt lake City, Utah 84158-0900.
[phone]
nwpratecase(Q)william s. com
If you have any questions concerning this rate case filing, please give Barbara or me acall.
d!: Jan Caldwell
Manager, Cost of Service/Rate Design
Northwest Pipeline Corporation
[phone]
nwpratecase(Q)wi Ilia m s. co m
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 3 of 49
IJII.~"rrllilSmS
June 30, 2006
NORTHWEST PIPEUNE
o. Box 58900
Salt Lake City, UT 84158-0900
Phone: (801) 5s+noo
FAX: [phone]
Ms. Magalie R. Salas, Secretary
Federal Energy Regulatory Commission
888 First Street, N.
Washington, D.C. 20426
Re:Northwest Pipeline Corporation
Docket No. RP06-
Dear Ms. Salas:
Pursuant to Section 4 of the Natural Gas Act, 15 U.C. ~ 717c, and Part 154 of the
regulations of the Federal Energy Regulatory Commission ("Commission ), 18 CFR 154,
Northwest Pipeline Corporation. ("Northwest") tenders for filing as part of its FERC Gas
Tariff, Third Revised Volume No., an original and twelve copies of certain revised tariff
sheets to reflect a general rate increase and pro forma Sheet No.5, together with
supporting rate case statements and schedules. The revised tariff sheets, which are
enumerated herein and included in the filing, are proposed to be effective August 1 , 2006.
Statement of Nature, Reasons and Basis for the Filing':'" 18 CFR 154.7(a)(6)
I. Overview
This general rate case filing reflects various revisions to the rates for jurisdictional
transportation and storage services contained in Northwest's Tariff along with supporting
statements and schedules as required by the Commission s regulations. As background,
this filing represents the first general rate increase that Northwest has filed since its Docket
No. RP96-367 rate application, which was filed approximately ten years ago. Following a
period of several years of "pancaked" rate case filings, Northwest entered into a Settlement
Agreement in Docket No. RP96-367 with its customers which, among other things, was
intended to help Northwest avoid filing repeated rate increases and provide rate stability for
its customers.
In the ten years since the Settlement Agreement, many circumstances have
changed that necessitate increases in the jurisdictional rates reflected in this filing to permit
Northwest the opportunity to recover its cost of service. As shown in Statement G of this
filing, revenues at current rates are inadequate to recover Northwest's cost of service and
result in a revenue deficiency of approximately $119.1 million.
In compliance with 18 CFR 154.7(aX6), the following table compares the cost of
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 4 of 49
Ms. Magalie R. Salas
June 30, 2006
Page 2 of 7
service, rate base and throughput underlying this filing with the same information
underlying the most recently Commission-approved just and reasonable rates. For "the
last rates found just and reasonable by the Commission," Northwest is using the cost of
service, rate base and throughput in the Settlement Agreement approved in Docket No.
RP96-367, and increasing such amounts by the incrementally priced expansion projects
and cost of service projects which were certificated by the Commission after the March 1
1997 effective date of the Oocket No. RP96-367 rate case.
Annual
Throughput
Cost of Service Rate Base (Dth)
RP96-367 $265,722,093 $812,305,958 723,000 000
Evergreen Expansion 960,705 180,588,786 85,794 583
Cost of Service Projects 570,826 21,419,552
Last Rates" Approved $313,253,624 014 314 296 808,794 583
This Filing $441,4 78 087 506,923 947 801 353,958
The cost of service underlying this filing utilizes a base period for the twelve months
ended March 31, 2006, adjusted for known and measurable changes through December
31, 2006, which, as shown above, results in an increase in Northwest's cost of service of
approximately $128.2 million4/ over the cost of service underlying the last rates found just
and reasonable by the Commission. The major reasons for the increased cost of service
are:
a) an increase of approximately $12.1 million included in the Certificate Application
filed in Docket No. CP06-45 for the incrementally priced Parachute Lateral Project,
which is anticipated to be placed in service on November 1 , 2006;
11 Excludes approximately $2.3 million cost of service and approximately $8.7 million rate base
related to the Tumwater and Olympia projects since Northwest was fully reimbursed for these
two projects following the effective date of the Docket No. RP96-367 settlement.
The Cost of Service Projects include the Berwick (Docket No. CPO3-196), Centralia (Docket
No. CPO3-196), and Elmore (Docket No. CPO2-240) laterals and the Columbia Gorge 1999
Expansion (Docket No. CP98-554). The cost of service and rate base for Berwick, Centralia and
Elmore are updated to reflect the current annual cost of service calculations pursuant to Section
21 of the General Tenns and Conditions of Northwest's Tariff.
31 Includes the cost of service, rate base, and throughput related to the proposed incrementally
priced Parachute Lateral Project.
41 This amount is higher than the revenue deficiency shown on Statement G of $119.1 million
due primarily to the $12.1 million cost of service associated with the Parachute Lateral, partially
offset by other minor differences, including throughput, and minor cost variances associated with
each calculation.
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 5 of 49
Ms. Magalie R. Salas
June 30, 2006
Page 3 of 7
b) an increase of approximately $61.6 million included in the Certificate in Docket No.
CP05-32 for the rolled-in Capacity Replacement Project, which is anticipated to be
placed in service on November 1 , 2006;
c) an increase of approximately $21.8 million included in the Certificate in Docket No.
CP01-438 for the rolled-in Rockies Displacement Project, net of approximately
$16.7 million in escrow funds which were used to partially offset the capital cost of
the project;
d) an increase of approximately $7.1 million included in the Certificate in Docket No.
CP02-4 for the rolled-in portion of the Sumas-Chehalis and Columbia Gorge
displacement facilities constructed as part of the Evergreen Expansion Project;
e) an increase of approximately $16.9 million related to the increase in the rate of
return and associated income taxes (i.e. pre-tax return) on the approximately $1.507
billion rate base included in this filing;
f) an increase of approximately $13.9 million related to operation and maintenance
expenses, including administrative and general expenses, ("O&M"), in addition to
the O&M costs included in the total project costs enumerated above, including
approximately $5.9 million associated with a required accounting change to expense
pipeline assessment costs; and
g) a reduction of approximately $5.2 million related to the net effect of various other
changes reflected in this filing, including normal rate base decline as a result of
depreciation partially offset by additional reliability and integrity-related
expenditures.
II. Cost of Service
The cost of service in this filing, as indicated above and supported by the Statement
P testimony of various Northwest witnesses submitted with the filing, is $441,478,087which consists of the following cost components:
O&M Expenses
Depreciation and Amortization
Taxes Other Than Income Taxes
Federal and State Income Taxes
Return
Revenue Credits
Total Cost of Service
$106,272,899
87,366,078
16,925,100
68,737 002
165,158,867
(2,981,859)
$441,478,087
Exhibit No.
Case No. INT -O6-
Intermountain Gas Company
Page 6 of 49
Ms. Magalie R. Salas
June 30 , 2006
Page 4 of 7
Northwest is requesting an overall after tax rate of return of 10.96 percent (15.47percent pre-tax), including a rate of return on equity of 13.6 percent. Consistent with
Commission policy, Northwest has used its projected capital structure as of the end of the
test period comprised of debt capital of 45 percent and common stock equity of 55 percent.
The evidence in this rate proceeding supports a depreciation rate of 2.93 percentapplied to transmission plant (exclusive of the facilities associated with the EvergreenExpansion 15 and 25 year contracts and the Cost of Service Projects), and a net negative
salvage rate of 0.94 percent for a combined rate of 3.87 percent. However, Northwest is
making a market adjustment to its net negative salvage rate as applied to such
transmission plant to reduce it to 0.31 percent, but only to the extent that the combination
of depreciation and net negative salvage rates would otherwise exceed 3.24 percent.Northwest has proposed certain other changes to the depreciation and net negativesalvage rates as shown on Statement H-2 page 2 of this filing.
III. Other Proposed ChanQes
Northwest is proposing in this proceeding a two-part straight-fixed variable ("SFY'rate design for the Rate Schedule TF-1 (Large Customer) rates (but will maintain the
levelized rate methodology for the Evergreen Expansion shippers and a one-partvolumetric rate for Rate Schedule TF-1 (Small Customer)). While SFV rate design is a
change from the rates that were implemented in the settlement of Northwest's last rate
case in Docket No. RP96-367, SFV rates are consistent with the Commission s directivesin Order No. 636 and with the rate design the Commission approved in Northwest's last
litigated rate proceeding in Docket No. RP95-409.
The rate for service under Rate Schedule LS-21 associated with interruptible storage
service at Northwest's Plymouth LNG storage facility is modified to provide for the inclusion
of liquefaction and vaporization charges. Currently, a shipper under Rate Schedule LS-only pays a daily volumetric inventory charge. Northwest proposes to revise Rate
Schedule LS-21 to reflect liquefaction and vaporization charges similar to such chargesunder Rate Schedules LS-1 and LS-2F.
IV. Tariff Sheets - 18 CFR 154.7(a)(5)
Appendix A contains the following revised tariff sheets which are being submitted in
the instant filing:
Thirty-First Revised Sheet No.
Third Revised Sheet No. 5-
Sixth Revised Sheet No. 5-
First Revised Sheet No. 5-
Fourteenth Revised Sheet No.
Fifteenth Revised Sheet No.
Seventeenth Revised Sheet No.
Fifteenth Revised Sheet No. 8.
Fifth Revised Sheet No. 91
Third Revised Sheet No. 91-
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 7 of 49
Ms. Magalie R. Salas
June 30, 2006
Page 5 of 7
Proposed Sheet Nos. 5 through 8.1 are submitted to revise Northwest's
Statement of Rates in its tariff to reflect the overall increase in Northwest's jurisdictionalrates and to reflect new liquefaction and vaporization rates under Rate Schedule LS-
on Sheet No. 8.
Sheet No. 91 is submitted to revise Rate Schedule LS-21 to provide for liquefactionand vaporization charges associated with interruptible storage services at Northwest'sPlymouth LNG storage facility. Sheet No. 91-A is submitted due to pagination.
f .,;c
Northwest's certificate application in Docket No. CP06-45 for the construction and
operation of the Parachute Lateral project anticipates an in-service date for the Parachute
Lateral prior to January 1 , 2007 and the anticipated costs associated with the Parachute
lateral project are reflected in the test period adjustments. Pro forma tariff sheets includedin the certificate filing include recourse rates associated with service on the Parachute
Lateral, and Northwest incorporates these pro forma tariff sheets by reference in the instant
filing. Since Northwest is requesting an effective date of August 1 , 2006 for the proposedtariff sheets submitted in the instant filing, the recourse rates for the Parachute Lateral
project are not reflected on the proposed tariff sheets. Therefore, pro forma Sheet No.al.sois submitted to show both the rates on proposed Thirty-First Revised Sheet No.
submitted herewith and the rates for the Parachute lateral project under the newParachute lateral Rate Schedules TFl-1 and TIL-1. When Northwest submits a motion
December 2006 to move into effect on January 1 , 2007 the tariff sheets in the instant filing,
following an anticipated five month suspension period, Northwest will file Substitute Thirty-First Revised Sheet No.5 to include the Parachute lateral rates.
Proposed Effective Date and Waiver Request - 18 CFR 154.7(a)(3), (6), (8) and (9)
Pursuant to Section 154.7(a)(9) ofthe Commission s regulations, Northwest herebymoves that the proposed tariff sheets be made effective August 1 , 2006, or at the end ofany suspension period which may be imposed by the Commission. Although Northwest
has requested an effective date of August 1 , 2006 , Northwest anticipates this filing will be
suspended for the full five month period, with an effective date of January 1, 2007. For thereasons discussed above, Northwest requests that a waiver of Section 154.7(a)(9) or154.206 of the Commission s regulations be granted, as necessary, and that thesuspension order include a statement that Northwest may file Substitute Thirty-First
Revised Sheet No.5 reflecting the anticipated Parachute lateral rates as shown on pro
forma Sheet No.5 when Northwest files a motion, pursuant to Section 154.206 of theCommissions regulations, to place the suspended rates into effect.
Material Submitted 18 CFR 154.7(a)(1)
In accordance with Section 154.7(a)(1) of the Commission s regulations, thefollowing material is submitted herewith:
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 8 of 49
Ms. Magalie R. Salas
June 30, 2006
Page 6 of 7
i. a proposed form of notice for the instant filing suitable for publication in the Federal
Register, and a diskette copy of such notice in accordance with 18 CFR 154.209;
ii. the revised tariff sheets and pro forma Sheet No., and, pursuant to 18 CFR 154.4
a diskette copy of such sheets;
iii. a "red lined" version of both the revised tariff sheets and pro forma Sheet No.
pursuant to 18 CFR 154.201(a);
iv. documentation in the form of workpapers or otherwise, sufficiently detailed to
support the changes proposed herein in accordance with to 18 CFR 154.201 (b);
v. Statements A through J, L, M, 0, P and related schedules in accordance with Part
154 of the Commission s regulations;
vi. the Statement of Northwest's Chief Accounting Officer pursuant 18 CFR 154.308;and
vii. a compact disk ("CD") containing Northwest's electronic version of its filing herein
pursuant to 18 CFR 154.4.
Service and Communications - 18 CFR 154.2(d) and 154.208
An original and twelve copies of this filing are being provided to the Commission.
Abbreviated copies of this filing have been served upon Northwest's customers and upon
affected state regulatory commissions. Within two business days of receiving a request for
a complete copy from Northwest's customers and/or interested state regulatory
commissions, Northwest will serve a full copy of this filing to the requesting parties.
All communications regarding this filing should be served upon:
Laren M. Gertsch*
Director, Rates and Regulatory
[phone]
Northwest Pipeline Corporation
O. Box 58900
Salt Lake City, Utah 84158-0900
nwpratecaseCWwill iam s. com
Steven W. Snarr
General Counsel
[phone]
Northwest Pipeline Corporation
O. Box 58900
Salt Lake City, Utah 84158-0900
steven. w .snarrCWwillia ms. com
* Designated to receive service pursuant to 18 CFR 385.203.
Ms. Magalie R. Salas
June 30, 2006
Page 7 of 7
Jan M. Caldwell
Manager, Cost of Service/Rate Design
[phone]
Northwest Pipeline Corporation
O. Box 58900
Salt lake City, Utah 84158-0900
nwpratecase(tYwi II iam s. com
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 9 of 49
Gary K. Kotter
Manager, Certificates and Tariffs
[phone]
Northwest Pipeline Corporation
O. Box 58900
Salt lake City, Utah 84158-0900
nwpratecase(tYwill ia m s. co m
Questions regarding this filing should be directed to Laren M. Gertsch.
To the best of my knowledge and belief, the tariff sheets and statements and
schedules are true and correct and contain the same information as the diskette and
compact disk containing the tariff sheets and statements and schedules.
Respectfully submitted,
L r n M. Gertsch
Di ctor, Rates and Regulatory
Enclosures
Exhibit No.
Case No. INT -O6-
Intermountain Gas Company
Page 10 of 49
Northwest Pipeline Corporation
FERC Gas Tariff .
Third Revised Volume No.Thirty-First Revised Sheet No.
Superseding
Thirtieth Revised Sheet No.
STATEMENT OF RATES
Effective Rates Applicable to Rate Schedules TF-1, TF-2 and TI-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-1 (4) (5)
Reservation
(Large CUstomer)
System-Wide 00000 43712 00000 4371215 Year Evergreen Exp.00000 41621 00000 4162125 Year Evergreen Exp.00000 39748 00000 39748
Volumetric
(Large CUstomer)
System-Wide 00756 00756 00180 00936 0093615 Year Evergreen Exp.00369 00369 00180 00549 0054925 Year Evergreen Exp.00369.00369 00180 00549 00549
(Small CUstomer)(6)00756 88180 00180 00936 88360
Scheduled Overrun 00756 44468 00180 00936 44648
~te Schedule TF-2 (4) (5)
Reservation 00000 43712 00000 43712Volumetric00756007560075600756Scheduled Daily Overrun 00756 44468 00756 44468Annual Overrun 00756 44468 00756 44468
Rate Schedule TI-1
Volumetric (7)
Scheduled Overrun
00756
00756
44468
44468
00180
00180
00936
00936
44648
44648
(SSlled by: Laren M.Gertsch, Director
IsSlled 00: Juoe30, 2006 Effective: ~ugust 2006
Exhibit No.
Case No. (NT -O6-
Intermountain Gas Company
Page 11 of 49
Northwest Pipeline Corporation
FERC Gas Tariff
Third Revised Volume No. 1 Third Revisec:l Sheet No. 5-B
Superseding
Second Revised Sheet No. 5-B
STATEMENT OF RATES (Continued)
Effective Rates Applicable to Rate Schedules TF-1, TF-2 and TI-1 (Continued)
(Dollars per Dth)
Wootnotes (Continued)
(3 )The currently effective tariff rate is
and the applicable surcharges. To the
the maximum currently effective tariff
applied on a non-discriminatory basis,
No. 497.
the sum of the base tariff rate
extent Transporter discounts
rate, such discounts will be
subj ect to the policies of Order
Shippers receiving service under these rate schedules are required to
furnish fuel reimbursement in-kind at the rates specified on SheetNo. 14.
A "Facility Cost-of-Service Charge," as defined in Section 21 of the
General Terms and Conditions, is payable in addition to all other rates
and charges if such a charge ~s included in Exhibit C to a Shipper'
Transportation Service Agreement.
In addition to the reservation rates and surcharges shown on Sheet
No.5, Shippers who contract for Columbia Gorge Expansion proj ectcapacity are subject to a Facilities Reservation Surcharge pursuant to
Section 3.4 of Rate Schedule TF-1. The Facilities Charge used in. deriving the Columbia Gorge Expansion Project Facilities Reservation
Surcharge has a minimum rate of $0 and a maximum rate during the
indicated months or calendar years as follows:
August 1,2006 -October 1,2006 $0.18523
November 1, 2006 - December 1,2006 $0.17819
Year Rate Year Rate Year Rate2007$0.16990 2013 $0.12704 2019 $0.096342008$0.16286 2014 $0.11979 2020 $0.091692009$0.15605 2015 $0. ~1396 2021 $0.087532010$0.14880 2016 $0.10926 2022 $0.083122011$0.14155 2017 $0.10515 2023 $0.078722012$0.13393 2018 $0.10075 2024 $0.07410
January 1,2025 - March 31,2025 $0.07300
Issued by: Laren M.Gertsch, Director
Issued on: June 30, 2006 Effective: August 1, 2006
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 12 of 49
. Northwest Pipeline Corporation
FERC Gas Tariff
Third Revised Volume No.Sixth Revised Sheet No. s.:c
Sliperseding
Fifth Revised Sheet No. 5-C
STATEMENT OF RATES (Continued)
Effective Rates Applicable to Rate Schedules TF-1,TF-2 and TI-1. (Continued)
(Dollars per Dth)
~ootnotes (Continued)
(4)All reservation rates are daily rates computed on the basis of 365 days
per year, except that such rates for leap years are computed on the
basis of 366 days.
For Rate Schedule TF-1, the 15-Year and 25-Year Evergreen Expansion
reservation and volumetric rates apply to Shippers receiving service
under Rate Schedule TF-1 Evergreen Expansion service agreements. The"System-Wide reservation and volumetric rates apply to Shippers receiving
service under all other Rate Schedule TF-1 service agreements.
For Rate Schedule TF-1, the 15-Year and 25-Year Evergreen Expansion
maximum base tariff reservation rates are comprised of $0.41094 and$0.39221 for transmission costs and $0.00527 and $0.00527 for storage
costs, respectively. The System-Wide maximum base tariff reservation
rates for Rate Schedule TF-1 "and the maximum base tariff reservation
rates for Rate Schedule TF-2 are comprised of $0.43185 for transmission
costs and $0.00527 for storage costs.
For Rate Schedule TF-1 (Large Customer), the maximUm base tariff
volumetric rates applicable to Shippers receiving service under Rate
Schedule TF-1 Evergreen Expansion service agreements are comprised of
$0.00344 for transmission costs and $0.00025 for storage costs. The
maximum base tariff volumetric rates for all other services under Rate
Schedule TF-1 (Large Customer) and "for services under Rate Schedule TF-2
are comprised of $0.00731 for transmission costs and $0.00025 forstorage costs.
(5)Rates for Rate Schedules TF-1 and TF-2 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
reservation rate is the comparable volumetric bid reservation charge
applicable to Replacement Shippers bidding for capacity released on a
one-part volumetric bid basis.
Issued by: Laren M.Gertsch. Director
Issued on: June 30, 2006 Effective:. August 1, 2006
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 13 of 49
Northwest Pipeline Corporation
FERC Gas Tariff
Third Revised Volume No.First Revised Sheet No. 5-D
Supeneding
Ori2inal Sheet No. 5-D
STATEMENT OF RATES (Continued).
Effective Rates Applicable to Rate Schedules TF-1, TF-2 and TI-1 (Continued)
(Dollars per Dth)
Footnotes (Continued)
(6)Rate Schedule TF-1 (Small Customer) one-part volumetric rate is basedupon a. 50% load factor, and the maximum base tariff rate is comprised of
$0.87101 for transmission costs and $0.01079 for storage costs.Transporter will not transport gas for delivery for Smal~ CUstomerssubject to this Rate Schedule TF~l under any interruptible Service
Agreement or under any capacity release Service Agreement unless such
Small CUstomer has exhausted, its daily levels of firm serviceenti tlement for that day.
(7)Rate Schedule TI-1 maximum base tariff volumetric rate is comprised of
$0.43916 for transmission costs and $0.00552 for storage costs.
(8 )Applicable to Rate Schedules TF-1, TF-2 and TI-1 pursuant15.5 of the General Terms. and Conditions.Section
Issued by: Laren M.Gertsch, Director
Issued on: June 30, 2006 Effective: August 1, 2006
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 14 of 49
Northwest Pipeline Corporation
FERC GaS Tariff
Third RevisCd Volume No. 1 Fifteenth Revised Sheet No.
Superseding
Fourteenth Revised Sheet No.
STATEMENT OF RATES (Continued)
Effective Rates Applicable to Rate Schedules SGS-2F and SGS-2I
(Dollars per Dth)
Rate Schedule and
Type of Rate
Currently EffectiveTariff Rate (1)
Minimum Maximum
Rate Schedule SGS-2F (2)
Demand Charge
Capacity Demand Charge 00000
00000
0 . 01634
00060
Volumetric Bid Rates
Withdrawal Charge
Storage Charge
00000
00000
01634
00060
Rate Schedule SGS-2I
Volumetric 00000 00120
Footnotes
(1)Shippers receiving service under these rate schedules are requ~red 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 exceptthat rates for leap years are computed on the basis of 366 days.
Rates are also applicable to capacity release service. (Section 22 ofthe General Terms and Conditions describes how bids for capacity release
will be evaluated.
) ,
The Withdrawal Charge and Storage Charge are
applicable to Replacement Shippers bidding for capacity released on a
one-Part volumetric bid basis.
Issued by: Laren M.Gertsc:h, Director
Issued on: June 30 2006 Effective: August 1, 2006
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 15 of 49
Northwest PipeliBe Corporation
FERC Gas Tariff
Third Revised Volume No.Seventeenth Revised Sheet No.
Superseding
Sixteenth Revised Sheet No.
STATEMENT OF RATES (Continued)
Effective Rates Applicable to Rate Schedule LS-1
(Dollars per Dth)
. Type of Rate
Currently Effective
Tariff Rate (1)
Demand Charge (2)
Capacity Charge (2)031'
00403
Liquefaction
Vaporization 64110
04184
Footnotes
( 1)Shippers receiving service under this rate ~chedule 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 r~tes for leap years are computed on the basi~ of 366 days.
Issued by: Laren M.Gertsch, Director
Issued on: June 30, 2006 Effective: August 1, 2006
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 16 of 49
TransCanada Alberta System
(or Nova Gas Transmission - "Nova
Applicable Tariffs/Rate Schedules
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 17 of 49
NOVA Gas Transmission Ltd.Table of Rates, Tolls and Charges
TABLE OF RATES, TOLLS & CHARGES
Service Rates, Tolls and Charges
Rate Schedule Ff-Refer to Attachment "I" for applicable Ff-R Demand Rate per month & Surcharge for
each Receipt Point
Aver!me Finn Service Receipt Price (AFSRP)$141.4211~m
Rate Schedule Ff-Refer to Attachment "1" for applicable Ff -RN Demand Rate per month & Surcharge
for each ReceiDt Point
Rate Schedule Ff-Ff -D Demand Rate per month (Apr - Oct)$14 1.4211 03
Ff-D Demand Rate Der month (effective November 1 2006) 74/GI
Rate Schedule STFr STFr Bid Price.Minimum bid of 100% ofFf-D Demand Rate
Rate Schedule Ff-Ff-DW Bid Price.Minimum bid of 125% ofFf-D Demand Rate
Rate Schedule Ff-Ff-A Commodity Rate 48/103
Rate Schedule Ff-Refer to Attachment "2" for applicable Ff -P Demand Rate per month
Rate Schedule LRS Contract Tenn Effective LRS Rate ($/lO'/day)
5 years
10 years
15 years 726
20 years
Rate Schedule LRS-LRS-2 Rate Der month $50 000
10. Rate Schedule LRS-LRS-3 Demand Rate per month (Ian - April)$196.32110'
LRS-3 Demand Rate per month (effective May 1,2006)$ 129.55/103
11. Rate Schedule IT-Refer to Attachment "I" for applicable IT-R Rate & Surcharl!:e for each Receipt Point
12. Rate Schedule IT~D IT-D Rate (Apr - Oct)12110-'mIT-D Rate (effective November 1 2006)1354/GI
13. Rate Schedule FCS The FCS Charge is detennined in accordance with Attachment "I" to the applicable
Schedule of Service
14. Rate Schedule PT Schedule No PT Rate PT Gas Rate
9005-01000-$ 164.911d 0 l~m
9006-01000-15.05/d 1.0 103
15. Rate Schedule OS Schedule No.Charge
2003004522-$ 83 333./ month
2003034359-899./ month
2004168619-437./ month
2006222805-/ month
2006222973-856./ month2006222974-1 66./ month
2006223044-1 171.00 / month
2006223045-576./ month
2006223046-294./ month
2006223047-68./ month
2006224148-92./ month
2006224149-536./ month
2006224337-66./ month
2006224475-111.00 / month2006224607-588./ month
16. Rate Schedule CO2 Tier CO2 Rate ($/103
674.
532.41
390.43
TARIFF Effective Date: April I , 2006 as per BOO Order U21 006-
(Amended April 6, 2006)
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 18 of 49
Transcanada Alberta System Web site Page 1 of 1
" ).
TransCanada
" .,
In burlnes to rJeJMer
TransCanada Home ~ Gas Transmission II- Alberta System
Border Heat Values, Empress, McNeill & A/BC
Empress Border McNeill Border Alberta/BC Border
Posted Actual Posted Actual Posted Actual HVDate(MJ/m3)(MJ/m3)(MJ/m3)(MJ/m3)(MJ/m3)(MJ/m3)
July 37.40 37.37.2006
June 37.45 37.38.2006
May 37.37.44 37.37.37.37.2006
Apr 37.45 37.41 37.45 37.37.37.2006
Mar 37.45 37.40 37.45 37.37.37.2006
Feb 37.37.41 37.45 37.46 37.37.2006
Jan 37.37.37.37.46 37.37.2006
Border Archives
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 19 of 49
TransCanada BC System
(or Alberta Natural Gas ANG"
Applicable Tariffs/Rate Schedules
TransCanada B.C. System Gas Transportation Service Documents
Exhibit No.
Case No. INT-06-
Intermountain Gas Company
Page 20 of
TAB 3 , Page 2
RATES STATEMENT AND CALCULATION METHODOLOGY
Statement of Effective Rates and Charges
Effective Rates
FS-1 Firm Service
Demand Rate (cents/GJlKm/Month*1.2454355541
IS-1 Interruptible Service
Commodity Rate (cents/GJIKm*0450404091
* Total distance of pipeline is 170.7 kIn
Company Use Gas
Shipper s Share of Company Use Gas shall be determined pursuant to Section 10.of the
General Terms and Conditions.
Effective Date: January 1 , 2006
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 21 of 49
~~ !,:~~~da
TransCanada Home; Gas Transmission i' Customer Express
Pricing & Tolls - BC System
TransCanada s - BC System Rates
2006 Interim Rates Effective Jan 1, 2006
Service Tariff Rate Information P
tj:/GJ/d
(Cdn)
ct:/Mcf/d
(Cdn)
F-.S::.l Firm Service (A/BC to Kingsgate)
FS-1 Rate 1. 2454355541 (-t/GJ/Month/Km)7.4
15:-1 Interruptible Service (A/BC to Kingsgate)
IS-1 Rate 0450404091 ((\:/GJ/Km) "
* The IS-1 Interruptible Service Commodity Rate is calculated by taking the FS"l Firm Service Demand Rate and multiplying by 110%
For information purposes, the maximum Shipper s Haul Distance used in the Shipper s monthly charge for Serv
170.7 km.
2. Rates are payable in Canadian dollars and GJ units are used for billing purposes. Mcf and MMbtu units a
information purposes only.
3. Conversion Factors below have been used to calculate the rates provided for information purposes:
Cdn$/US$
tj:fGJ to q:/MMBtu
1.15 - subject to change (updated Mar 2/06)
x 1.0550564. Posted commodity rate is based on Effective Heating Value Forecast of 37.8 MJ/m35. Rates do not include G5.
6. Inquiries regarding the BC System may be directed to:
Bruce Newberry at 403.920.5579
Scott Yule at 403.920.5558
Other information for TransCanada s BC System:
Current
.. Fu.e.LRa.te.
~....&'.
He.g.ttngVaJue~
. AB.BQrderHeatJ/glues
Archives
.. Rates: 2005 '1112004
.. Eue). RaJe~8t.tte(:!ting\!gJues
. AB BmderHeqtVqlues '1l
Disclaimer:Th/!! priCing aM toll~ InfOrMUtiOl1 Im::lud.ed em this w-ebslta is intended to be us&! fof' plaunlng pU\"(l.os~ tmlr and irtthrnTrall.SCamida endeavelJrS to maintain the. information in such a way that Is accurate and It may not provIdeaa:urate rGSults. Use of this infonnation IS.;rt userS sole risk and TransCanad,a shan not be Uab1e fur U$er's use of I"ellion any results obtained from it.
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 22 of 49
TransCanada B.C. System Website Page 1 of 1
~).
TransCanada
" ..,
IB to deJiYer
TransCanada Home" Gas Transmission " BC System
Current Fuel Rates & Heating Values
Fuel Rate Effective July 1, 2006
Fuel Rate and MJ value on TransCanada s B.C. System for
July, 2006
Please be advised that effective July 1 , 2006 at 08:00 the fuel rate
on TransCanada s B.C. System will change to 10/0.
If you have any questions please contact Leslie Leroux at
403.920.2625
For the period of July 1, 2006, until further notice, a fuel rate of
006444% per GJ/km will be in effect. For scheduling purposes this
rate is converted to 0.0104% per GJ/Mile. Applicable rates for the
most common paths are provided here:
Current Fuel Rates
Exhibit No.
Case No. INT O6-
Intermountain Gas Company
Page 23 of 49
Gas Transmission Northwest ("GTN"
- formerly PGT -
Applicable Tariffs/Rate Schedules
Exhibit No.
Case No. INT -O6-
Intermountain Gas Company
Page 24 of 49
June 30, 2006
Gas Transmission Northwest Corporation
1400 SW Fifth Avenue, Suite 900
Portland, Oregon 97201
Ms. Magalie R. Salas
Secretary
Federal Energy Regulatory Commission
888 First Street, N.
Washington, D.C. 20426
John A. Roscher
Director, Rates & Regulatory Affairs
tel [phone]
fax [phone]
email John Roscher(gjTransCanada .com
web www.gastransmissionnw.com
Re:Gas Transmission Northwest Corporation
Docket No. RP06-
Dear Secretary Salas:
Pursuant to Section 4(e) of the Natural Gas Act, as amended
/ ("
NGA") and Subpart D
of Part 154 of the regulations of the Federal Energy Regulatory Commission ("FERC" or
Commission / Gas Transmission Northwest Corporation ("GIN") hereby submits for filing
and acceptance the revised tariff sheets listed on Appendix A to be included in its FERC Gas
Tariff, Third Revised Volume No. I-A. The tariff sheets are proposed to become effective on
August 1, 2006. GIN anticipates, however, that the rates proposed herein will be subject to a
five-month suspension period and placed into effect on January 1 2007.
Statement of Nature. Reasons and Basis
The purpose of this filing is to restate GIN's rates for service on its interstate
transportation system. GIN's system extends approximately 612 miles from the International
Boundary at Kingsgate, British Columbia, to the Oregon-California border, where
interconnects with Tuscarora Gas Transmission Company and Pacific Gas & Electric Company.
GIN utilizes this pipeline to provide firm and interruptible transportation service to numerous
shippers serving the Pacific Northwest, California, and Nevada markets. GIN also interconnects
with facilities of Northwest Pipeline near Spokane and Palouse, Washington, and Stanfield
Oregon.
GIN's current rates for service were established more than 10 years ago by settlement in
Docket No. RP94-149.Since that time, the market in which GIN operates has undergone
1/15 u.S.c. ~ 717c(e).
/18 c.F.R. ~~ 154.301 - 315 (2005).
See Pacific Gas Transmission Co.76 FERC ~ 61 246 (1996), reh'g sub nom, PG&E Gas
Transmission, Northwest Corp.82 FERC ~ 61 289 (1998).
Ms. Magalie R. Salas
June 30, 2006
Page 2 of 12
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 25 of 49
significant, fundamental changes, including an increase in pipeline capacity into GTN's major
market in California as well as an increase in pipeline capacity out of GTN's major supply area
in the Western Canada Sedimentary Basin ("WCSB"). The changing competitive landscape has
left GTN with substantial unsubscribed capacity as a result of capacity turnback and shipper
defaults, and GTN has been forced to drastically discount the price of capacity to meet
competitive demands. As further described in the testimony filed herein, GTN anticipates that
during the test period, it will have approximately 450 000 Dth per day of unsubscribed long-term
capacity as the result of capacity turnback and/or defaults by customers. Also, as described in
the testimony, GTN does not anticipate that it will be able to sell its unsubscribed capacity at or
near GTN's tariff rate for the foreseeable future. In fact, for 290 days of the base period, GTN'
capacity was worth less than zero the cost of transporting gas on GTN and upstream
pipelines exceeded the difference between the price of gas in the supply and market areas.
As a result of the turnback of capacity and persistently poor market conditions, GTN is
compelled to file to increase its rates to reflect the heightened risks it now faces and to allow
GTN a fair opportunity to recover its costs and earn a fair return. To address the unique risks
presented to the pipeline and its shippers by this level of capacity turnback and default, GTN
proposes that it share with its shippers the costs associated with unsubscribed mainline capacity
on a 10 percent/90 percent basis, respectively. GTN's proposal honors the Commission
objective that l,ipelines not shift 100 percent of the costs associated with turnback capacity to
their shippers.
To the extent that GTN's efforts to remarket its unsubscribed capacity are successful
GTN proposes to share revenues generated from such unsubscribed mainline capacity sales with
its shippers on a 25 percent/75 percent basis, respectively, after all costs allocated to long-term
firm, short-term firm, seasonal and interruptible capacity services have been recovered. GTN
will share revenues associated with mainline capacity sales regardless of their source, be it from
long-term fIrm, short-term firm, seasonal, or interruptible capacity sales. Therefore, maximum
rate, long-term firm shippers' ultimate cost responsibility will be reduced by the sale of GTN'
unsubscribed capacity. By allowing GTN to retain 25 percent of the revenue from unsubscribed
capacity sales, GTN will have an ongoing incentive to sell its unsubscribed capacity for the
benefit of itself and its shippers.
GTN is also proposing a series of other changes designed to increase recovery of costs
and reduce the burden on long-term firm shippers, including charging a market-based rate for
full-haul interruptible transportation; implementing hub service rates that are similar to a 100
percent load factor interruptible transportation rate; and implementing a flexible service proposal
designed to allow increased recovery of revenue from short-haul services. These proposals are
addressed in greater detail below and in the testimony. Again, these services will inure to the
benefit oflong-term firm shippers through GTN's revenue sharing proposal.
The enclosed Statement P, in Volumes 3 of this filing, contains the prepared direct
testimony and exhibits supporting GTN's proposed rate increase and tariff changes. A list of
1/ See Natural Gas Pipeline Co. of America 73 FERC 'il61 050, at 61 129 (1995) (citing El Paso
Natural Gas Co.72 FERC 'il61 083 , at 61,441 (1995)).
Ms. Magalie R. Salas
June 30, 2006
Page 3 of 12
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 26 of 49
GTN's witnesses is set forth below, along with a brief summary of the principal topics addressed
in each witness s testimony.
Witness Testimony
Jeffrey R. Rush Overview of GTN'system and major
components of the rate case filing.
Amy Leong Overall cost of service consisting of operations
and maintenance expenses, depreciation and
amortization, return allowance, income taxes
and taxes other than income taxes, rate base
and return, capital structure, cost of debt, and
regulatory assets and liabilities.
John A. Roscher Cost classification and rate design, treatment of
turnback capacity, roll-in of 1998 and 2002
expansions discount adjustments, market-
based IT rate propqsal and flexible services
rate proposal.
Benjamin K. Johnson Billing determinants and revenues, including
Statement G, hub service rate design, and
elimination of IT discount floor.
Kenneth W. Nichols Revisions to creditworthiness tariff provisions.
Walter W. Haessel WCSB gas supply projections to support the
economic life of GTN' s system.
Dan A. King Cost analysis of retiring and removing
facilities to support net negative salvage rate
and pipeline integrity costs.
Edward H. Feinstein Depreciation rates.
Leslie Ferron-Jones Commercial risk environment and turnback
capacity issues.
Steven H. Levine Business risk analysis, including analysis of
proxy pipeline group.
Paul R. Moul Range of return on equity.
Paul R. Carpenter Market power analysis in support of GTN'
market-based IT rate proposal.
Ms. Magalie R. Salas
June 30, 2006
Page 4 of 12
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 27 of 49
Barry E. Sullivan Consistency of GTN's market-based IT rate
proposal with Commission policy.
Reasons for Proposed Rate Increase
GTN's cost-of-service and rate calculations are based upon the costs and throughput
levels for the base period (twelve months ended March 31, 2006) as adjusted for known and
measurable changes through the test period ending December 31 , 2006. As a result of the
changes proposed herein, GTN's maximum recourse full-haul unit rate for service under Rate
Schedule FTS-1 will increase from $0.262787 per Dth to $0.449854 per Dth. However, as
discussed above, under GTN's revenue sharing mechanism, the rate paid by long-tenn finn
shippers could be significantly reduced if GTN is successful in remarketing unsubscribed
capacity.
In compliance with section 154.7(a)(6) of the Commission s regulations, the following
table compares the cost-of-service, rate base, and throughput contained in this filing with the
same infonnation underlying GTN's last rates found to be just and reasonable by the
Commission:
Mainline Cost-of-Service
Mainline Rate Base
Mainline Throughput
This Filing
$294 608 644
$868 221,495
327 067 816 932 Dth-mi
Prior Rates 5
$206 019 324
$951 237,958
367 128 864 763 Dth-mi
The proposed rates also incorporate an increase in return on equity, reflecting the
increased business and financial risks GTN now faces. As detailed in the testimony of GTN
Witness Amy Leong, GTN's proposed rates include an overall cost of capital of 11.33 percent.
Witness Leong establishes GTN's overall cost of service for the twelve-month base period
ending March 31 , 2006, adjusted for known and measurable changes for the test period ending
December 31 , 2006, as $303.5 million. This cost of service is based on GTN's actual capital
structure of37.01 percent debtJ62.99 percent equity and a transmission depreciation rate of2.
percent. GTN Witness Leong supports the use of GTN's own capital structure, which confonns
to FERC's policy in that GTN issues its own non-guaranteed debt, has its own debt ratings
separate from its parent, and has a common equity ratio in line with others previously approved
by the Commission.
In addition, GTN Witness Paul R. Moul supports an appropriate return on common
equity in the range of 13.0 to 15.0 percent. Based upon the investment risks unique to GTN, as
detailed in the testimony of GTN Witnesses Moul, Steven H. Levine, and Leslie Ferron-Jones
GTN has justified a rate of return on equity of 14.5 percent.
See supra.
Ms. Magalie R. Salas
June 30, 2006
Page 5 of 12
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 28 of 49
The following table summarizes GIN's overall rate of return:
Capitalization Ratio Cost Weighted Cost
Long-Term Debt 37.01%96%20%
Equity 62.99%14.13%
Overall Rate of
Return
11.33%
GIN Witnesses demonstrate that GIN has above-average business risk relative to the
relevant pipeline proxy group. GIN faces above-average supply risk due to its heavy
dependence on gas supplies sourced from the WCSB, a basin where production has flattened out
and is projected to remain flat or decline in the coming years. GIN also faces above-averagemarket risk in its primary destination market in California because WCSB gas supplies
transported to California via GIN compete with Rocky Mountain and San Juan gas suppliestransported to California via numerous pipelines. Indeed, since 2001 , there have been several
expansions of pipeline capacity to California, which have resulted in excess interstate pipeline
capacity to the state.
As a result of the competitive conditions in GIN's supply and market areas, GIN'pipeline capacity has been devalued significantly. GIN Witness Ferron-Jones describes howGIN has had difficulty selling its unsubscribed capacity even at sharply discounted rates due to
these conditions.
As supported by GIN Witnesses Edward H. Feinstein, Walter W. Haessel and Dan A.
King, GIN's rates also reflect an increase in the depreciation rate of GIN's transmission plant to
76 percent and the establishment of a negative salvage rate of 0.74 percent.
Other Rate-Related Proposals
Market-Based, Full-Haul IT Rate Proposal
Consistent with Commission policy and Commission cases approving or otherwise
addressing market-based rates for transportation fl.GIN is proposing to charge market-basedrates for full-haul interruptible transportation ("IT") service from the International Boundary
near Kingsgate, British Columbia, to Malin, Oregon. GIN Witness Dr. Paul R. Carpenter
provides a market power analysis that concludes that GIN lacks market power over full-haul IT
See K N Interstate Gas Transmission Co.76 FERC ~ 61 134 (1996); Rendezvous Gas
Services, LLC, 112 FERC ~ 61 141 , at 61 792-94 pp. 26-40 (2005); Koch Gateway, 61 FERC ~
013 (1996).
Ms. Magalie R. Salas
June 30, 2006
Page 6 of 12
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 29 of 49
service from Kingsgate to Malin, and thus the Commission can appropriately approve GTN'
request to charge market-based rates for such service. Just as importantly, GTN is not filing for
authority to charge market-based rates for IT services at any other delivery points on its system.
After careful consideration, GTN has determined that customers at these other receipt and
delivery points do not have the same quality of good alternatives available to them. GTN will
continue to provide all other customers (at all other delivery points) with IT service at a capped
cost-based IT tariff rate.
Roll-In of 1998 and 2002 Expansion Projects
GTN is proposing to roll in the costs associated with the 1998 and 2002 expansions. The
1998 Expansion benefits from de minimis capital costs of only $6 million and easily meets the
roll-in threshold of the Commission s 1995 Policy Statement / even after taking into account all
changed circumstances. The rate impact of rolled-in treatment for the proposed expansion is
below the 5 percent threshold established by the Commission. GTN's roll-in analysis
demonstrates that there are rate reductions and system benefits associated with the 1998
Expansion.
The 2002 Expansion meets the roll-in test as set forth in the 1999 Policy Statemen1.
Consistent with Commission policy,/ GTN calculated a rolled-down, stand-alone rate for the
2002 Expansion, utilizing all maximum rate post-expansion long-term finn capacity sales and
permanent capacity releases, with the exception of those expected to terminate or default during
the test period. The resulting rolled-down 2002 Expansion rate is lower than the filed-for
mainline system rate without the 2002 Expansion costs and volumes. As such, the 2002
Expansion qualifies for rolled-in treatment under the 1999 Policy Statement because with roll in
existing shippers will not subsidize the expansion. GTN is also proposing to roll in fuel costs
associated with the 2002 Expansion. GTN demonstrates that pipeline capacity sales and
permanent releases since the inception of the roll-down mechanism warrant a rolling in of the
2002 Expansion fuel costs. Rolling-down the overall incremental fuel rate yields a current rate
expressed on a full-haul basis, of 1.14 percent, well below the roll-in threshold of 2.45 percent.
Flexible Services Rate Proposal
GTN is proposing to facilitate the recovery of unsubscribed capacity costs by
allowing GTN to apply higher rates to new contracts for services not sold on an annual, uniform
MDQ basis. Such services would include seasonal long-term firm, variable MDQ long-tenn
firm, short-term finn and interruptible transportation other than full-haul (collectively referred to
as "flexible services
).
GTN proposes to set the maximum rate for flexible services equal to 2.
times the maximum reservation component of the recourse rate that applies to long-tenn finn
uniform MDQ shippers, plus the delivery component applicable to long-term firm, unifonn
Pricing Policy for New and Existing Facilities Constructed by Interstate Natural Gas
Pipelines 71 FERC ~ 61 914 (1995).
Certificate of New Interstate Natural Gas Pipeline Facilities 88 FERC ~ 61 225 (1999),
clarified 90 FERC ~ 61 128 (2000).
PG&E Gas Transmission, Northwest Corp.82 FERC ~ 61 289, at 62 123 n.29 (1998).
._.._---~_.-------------
Ms. Magalie R. Salas
June 30, 2006
Page 7 of 12
Exhibit No.
Case No. INT -06-
Intermountain Gas Company
Page 30 of 49
MDQ shippers. These flexible service rates can be assessed at any time during the year and
revenues nom flexible services will be shared on an annual basis to the extent that overall
pipeline revenues for mainline service exceed what would have been collected had the maximum
recourse rates for long-term, uniform MDQ shippers applied to all mainline volumes transported
during the annual period. GTN proposes that revenues above this threshold be shared among
GTN and its shippers on a 25 percent/75 percent basis, consistent with the revenue sharing
percentage GTN is proposing for unsubscribed capacity sales.
Hub Service Rates
Consistent with Commission precedent j GTN is also proposing to charge a
postagestamp rate for hub services which is similar to a 100 percent load factor IT rate. By
approving this proposal, the Commission will level the playing field for pipelines serving
western markets by allowing GTN the opportunity to charge similar rates for similar services.
Summary of Proposed Tariff Chan!!es
GTN is also proposing to implement the following tariff changes reflected on the revised
tariff sheets in Appendix A, to be effective August 1 , 2006:
Revised Base Rates
As explained above, GTN is updating its cost-of-service and proposing to increase its
base transportation rates (maximum recourse rates) for Rate Schedule FTS-l. In addition, GTN
is seeking authorization to charge market-based rates for full-haul interruptible transportation
service under Rate Schedule IT nom one receipt point (Kingsgate) to one delivery point (Malin).
As noted, GTN is also requesting authorization to implement a flexible service rate proposal that
will allow GTN to set the maximum rate for new sales of seasonal long-term firm, variable MDQ
long-term firm, short-term firm, and interruptible transportation other than full-haul at levels
higher than their respective maximum recourse rates, subject to a cap of 2.5 times the maximum
reservation component of the recourse rate that applies to long-term firm, uniform MDQ
shippers, plus the delivery component applicable to such long-term firm, uniform MDQ shippers.
Creditworthiness
As detailed in the testimony of GTN Witness Kenneth W. Nichols, GTN proposes to
make four tariff changes related to credit provisions:
First, GTN proposes to modify General Terms and Conditions ("GT&C") ~ 18.1(e) to
allow GTN to consider a shipper s credit quality when evaluating bids and awarding capacity in
an open season for long-term firm capacity based on specific, objective criteria that will be
posted prior to the commencement of each open season. As explained by GTN Witness Nichols
this change is necessary given GTN's unique experience with non-creditworthy shippers, and is
Mojave Pipeline Co.79 FERC ~ 61 347 (1997).
Ms. Magalie R. Salas
June 30, 2006
Page 8 of 12
Exhibit No.
Case No. INT -O6-
Intermountain Gas Company
Page 31 of 49
also consistent with FERC's Policy Statement on Creditworthiness Issues for Interstate Natural
Gas Pipelines. il
Second, GTN proposes to modify GT&C ~ 18.3(A)(2)(b) and ~ 18.3(D)(3) of its Tariff to
give GTN the discretion to determine whether to allow a shipper to replace its original credit
assurance with an alternative assurance. This proposal would prevent a shipper from using a
superior form of credit assurance to secure capacity in an open season and then substituting an
inferior form of security thereafter.
Third, GTN proposes to clarify GT&C ~ 18.3(A)(2)(b)(i) and ~ 18.3(D)(3)(a) to ensure
that GTN has the authority to request additional assurances when a shipper provides GIN with a
guarantee and the guarantor has become noncreditworthy or no longer has a sufficient credit
limit.
Fourth, GTN is proposing to eliminate its current strict "10 percent of tangible net worth
test" for establishing shipper credit limits in GT&C ~ 18.3(A)(2)(b) and to replace it with a more
flexible approach that considers a shipper s specific circumstances in determining credit limits.
Reservation of Capacity for Future Expansions
GTN is proposing to revise GT &C ~ 32 to permit GTN to reserve unsubscribed firm
capacity, or capacity under existing or expiring firm transportation agreements that are not
subject to the right of flIst refusal ("ROFR"), for use in connection with a future expansion
project. GTN will only be permitted to reserve capacity for a future expansion project for which
an open season has been held or will be held within one year of posting the capacity as reserved.
Capacity may only be reserved for up to one year prior to GTN's filing a certificate application
for the proposed expansion, and thereafter until the expansion is placed into service. GIN
submits that its proposed tariff revisions with respect to the reservation of capacity for future
expansions are consistent with the caRacity reservation tariff provisions that the Commission hasapproved for several other pipelines.
Open Seasons for Expansion Capacity and ROFR Capacity
GTN Witness Roscher describes how GTN's currently-effective ROFR procedures have
exposed GTN and it long-term shippers to the risk of prospective capacity turnback. For
example, in 2001 an open season for ROFR capacity generated contract extensions of 2 to 5
years while contemporaneous open seasons for GTN's 2002 Expansion Project generated
binding bids for terms ranging from 10 to 52 years.GTN awarded the expansion capacity to
See Policy Statement on Creditworthiness for Interstate Natural Gas Pipelines and Order
Withdrawing Rulemaking Proceeding, 111 FERC ~ 61 412 (2005).
See Texas Gas Transmission, LLC, 111 FERC ~ 61 380 (2005); Dominion Transmission, Inc.
111 FERC ~ 61 135 (2005); Tennessee Gas Pipeline Co.84 FERC ~ 61 304 (1998), reh'g and
clarification 86 FERC ~ 61 066 (1999).
See Exh. GTN-6 at 41-45.
Ms. Magalie R. Salas
June 30, 2006
Page 9 of 12
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 32 of 49
two shippers for contract terms of 52 and 40 years./ According to Mr. Roscher, shippers and
potential shippers have been reluctant to bid on ROFR capacity because of the uncertainty
inherent in the ROFR shipper s right to retain the capacity by matching the highest bid.
In order to promote allocative efficiency, rationalize demand for expansion capacity with
existing capacity and reduce the risk of prospective capacity tumback, GTN is proposing to add a
new ~ 33.11 to its ROFR procedures that will permit GTN to hold one open season for an
expansion project and a shipper s ROFR capacity when GTN has announced an expansion
project and a shipper has notified GTN of its intent to exercise its right of first refusal. Under the
proposed ~ 33., in order to continue to receive transportation service following the expiration
of its contract term, a ROFR shipper may be required to match the lowest acceptable bid that
meets the minimum terms and conditions of the expansion open season.
GTN submits that this matching requirement is consistent with the Commission
allocative efficiency principle that holds that pipeline capacity should be allocated to shippers
that value the capacity most as reflected by the NPV of their bids. If an expansion shipper places
greater value on the existing capacity than the ROFR shipper, then the existing capacity should
be used to satisfy this new demand. By satisfying new demand with existing capacity, GTN'
proposal also rationalizes capacity by reducing the pipeline s need to construct additional
capacity. Finally, GTN's proposal would benefit GTN and its shippers by reducing the risk of
prospective capacity tumback. Allocating ROFR capacity and expansion capacity in one open
season would mitigate the risk of future capacity tumback by ensuring that the longest possible
term for the capacity is obtained.
Finally, GTN submits that its proposal to require the ROFR shipper to match the
minimum terms and conditions in the expansion open season is consistent with Commission
precedent. In Kern River Gas Transmission Co., for example, the Commission relied on its
earlier decision in Tennessee Gas Pipeline Co. to find that "if a pipeline has already announced
an expansion project, the Commission will allow the pipeline to impose the same minimum
terms and conditions on the posting of unsubscribed capacity that it anticipates it will impose in
the future expansion project open season."lQ/ Thus, in these cases the Commission has endorsed
the concept that, when the pipeline has announced an expansion project, in allocating expired
capacity, the pipeline may impose the same minimum terms and conditions that it will use to
allocate the expansion capacity.
ROFR Notice Period When Expansion Project is Proposed
Under the ROFR procedures set forth in GT&C ~ 33, in order to exercise the ROFR, a
shipper must notify GTN one year prior to the primary election date whether it elects to
See id. at 44.
See id. at 43-44.
105 FERC ~ 61 114, at P 14 (2003) (citing Tennessee 84 FERC at 62 347, in which the
Commission permitted the pipeline to impose the same minimum terms and conditions in the
posting of "expired contract capacity" that it received from shippers "as a result of an expansion
open season
Ms. Maga1ie R. Salas
June 30, 2006
Page 10 of 12
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 33 of 49
terminate or not to terminate its service agreement. If the shipper elects not to terminate its
contract, then the ROFR process will be triggered and the shipper will be permitted to retain its
capacity if it agrees to match any acceptable bid that may be received by GTN. In light of its
proposal to rationalize the allocation of ROFR capacity with allocation of expansion of capacity,
GTN is also proposing to revise its ROFR procedures to provide that, when GTN has proposed
an expansion the sizing of which could be affected by the shipper s decision on whether or not to
exercise its ROFR to continue service, GTN may notify a shipper that its election to terminate or
not to terminate its service agreement must be provided up to 36 months prior to the expiration
date of the shipper s term of service. GTN's proposed language with respect to the 36-month
notice requirement is virtually identical to language that the Commission has approved for
Northern Border Pipeline Company.
Materials Submitted
Consistent with the relevant provisions of Sections 154., 154.201 et seq.and 154.301
of the Commission s regulations, GTN is submitting the original and 12 copies of this filing
comprised of the following:
1) Transmittal Letter including Statement of Nature, Basis and Reasons for Filing;
2) A Form of Notice for this filing suitable for publication in the Federal Register
including one diskette containing a copy of the Form of Notice;
3) A certificate of service;
4) Statement of Authorized Accounting Representative pursuant to 9 154.308 of the
Commission s regulations;
5) Appendix A -- List of Revised Tariff Sheets in clean and marked versions;
6) Statements A - 0; and
7) Statement P -- Prepared Direct Testimony/Exhibits.
Electronic Filine Requirement
Pursuant to Section 154.4 of the Commission s regulations, this filing includes a disk
containing all statements and schedules contained in this filing in electronic media in the same
fonnat generated by the spreadsheet software used in developing the statements.
See Northern Border, FERC Gas Tariff, First Rev. Vol. 1 , Rate Schedule T-1 9 5., Third
Rev. Sheet No. 102A.
Ms. Maga1ie R. Salas
June 30, 2006
Page 11 of 12
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 34 of 49
Proposed Effective Date and Motion to Place Rates Into Effect
The revised tariff sheets filed herein have a proposed effective date of August 1 , 2006.
Because this filing reflects a rate increase, however, GTN expects the Commission to suspend
the effectiveness of the tariff sheets until January 1 2007. Pursuant to section 154.7(a)(9), GTN
hereby moves to place the tariff sheets set forth in Appendix A into effect August 1 , 2006. In the
event the Commission elects to accept and suspend the tariff sheets, GTN will file a separate
motion pursuant to section 154.206 to place the tariff sheets into effect at the end of the
suspension period.
Requests for Waivers
Pursuant to section 154.7(a)(7), GTN respectfully requests that the Commission grant all
waivers necessary to allow the tariff sheets to become effective as proposed herein, including
any necessary waivers of Parts 154, 284 and 385, as well as any other rule, policy,
pronouncement or order.
Postine and Certification of Service
In accordance with section 154.2(d) of the Commission s regulations, GTN has made
copies of this filing available for public inspection, during regular business hours, in a
convenient form and place at GTN's main offices located at 1400 SW 5th Avenue, Suite 900
Portland, Oregon 97201. In addition, GTN has posted a complete copy of the filing on its
internet web site http://www.gastransmissionnw.com. Finally, GTN is serving copies of this
filing on interested state regulatory commissions, GTN's affected customers, and other interested
parties. Such service meets or exceeds the requirements of section 154.208 ofthe Commission
regulations.
Ms. Magalie R. Salas
June 30, 2006
Page 12 of 12
Communications
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 35 of 49
All correspondence and communications concerning this filing should be addressed to the
following:
Carl M. Fink
Associate General Counsel
John A. Roscher
Director, Rates and Regulatory Affairs
Gas Transmission Northwest Corporation
Suite 900
1400 SW 5th Avenue
Portland, OR 97201
[phone]
e-mail: John - Roscher~transcanada.com
Lee A. Alexander
Kevin 1. Lipson
Stefan M. Krantz
Hogan & Hartson LLP
555 Thirteenth Street, N.
Washington, D.C. 20004-1109
[phone]
e-mail: LAA1exander~hh1aw .com
Denotes person designated to receive official service pursuant to Rule 203 of the
Commission s Rules of Practice and Procedure.
The undersigned hereby certifies that he has read this filing and knows (i) the contents of
the paper copies and electronic media; (ii) that the paper copies contain the same information
contained on the electronic media; (iii) that the contents as stated in the copies and on the
electronic media are true to the best of his knowledge and belief; and (iv) that he possesses full
power and authority to sign this filing.
Respectfully submitted
John A. Roscher
Director, Rates and Regulatory Affairs
Gas Transmission Northwest Corporation
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 36 of 49
UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION
Gas Transmission Northwest Corporation Docket No. RPO6-
NOTICE OF PROPOSED CHANGES IN FERC GAS TARIFF
Take notice that on June 30, 2006, Gas Transmission Northwest Corporation ("GTN") tendered
for filing as part of its FERC Gas Tariff, Third Revised Volume No. I-, revised tariff sheets listed
below. GTN proposes that the tariff sheets become effective on August 1 , 2006.
Ninth Revised Sheet No.
Fourth Revised Sheet No.
Eighth Revised Sheet No.
Fourth Revised Sheet No. 12
Sixth Revised Sheet No. 100
Second Revised Sheet No. 108
Second Revised Sheet No. 109
First Revised Sheet No. 129
First Revised Sheet No. 130
Second Revised Sheet No. 133
First Revised Sheet No. 133A
Second Revised Sheet No. 134
Second Revised Sheet No. 135
First Revised Sheet No. 135A
Second Revised Sheet No. 136
First Revised Sheet No. 136A
Second Revised Sheet No. 137
Second Revised Sheet No. 138
Second Revised Sheet No. 139
First Revised Sheet No. 140
Third Revised Sheet No. 141
First Revised Sheet No. 141A
First Revised Sheet No. 210
Original Sheet No. 210A
Third Revised Sheet No. 211
Original Sheet No. 211A
Third Revised Sheet No. 212
Fourth Revised Sheet No. 213
Second Revised Sheet No. 214
GTN states that the purpose of this filing is to effectuate an increase in the base tariff rates
applicable to GTN'sjurisdictional services and to implement certain related tariff revisions. G1N
further states that the filing is necessary to allow GTN an opportunity to recover its costs and earn a fair
return in light of the increased risks that GTN now faces as a result of significant capacity turnback on
its system and its inability to remarket such capacity at or near its maximum recourse rate.
GTN states that a copy of this filing has been served upon its customers and interested state
regulatory commissions.
Any person desiring to intervene or to protest this filing must file in accordance with Rules 211
and 214 of the Commission s Rules of Practice and Procedure (18 CFR g 385.211 and g 385.214).
Protests will be considered by the Commission in determining the appropriate action to be taken, but
will not serve to make protestants parties to the proceeding. Any person wishing to become a party must
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 37 of 49
file a notice of intervention or motion to intervene, as appropriate. Such notices, motions, or protests
must be filed in accordance with the provisions of Section 154.210 of the Commission s regulations (18
9 154.210). Anyone filing a motion to intervene or protest must serve a copy of that document
on the Applicant. Anyone filing an intervention or protest on or before the intervention or protest date
need not serve motions to intervene or protests on persons other than the Applicant.
The Commission encourages electronic submission of protests and interventions in lieu of paper
using the "eFiling" link at http://www.ferc.gov. Persons unable to file electronically should submit an
original and 14 copies of the protest or intervention to the Federal Energy Regulatory Commission, 888
First Street, N., Washington, D.C. 20426.
This filing is accessible on-line at http://www.ferc.gov, using the "eLibrary" link and is available
for review in the Commission s Public Reference Room in Washington, D.C. There is an
eSubscription" link on the web site that enables subscribers to receive email notification when a
document is added to a subscribed docket(s). For assistance with any FERC Online service, please
emai1 FERCOnlineSupport(~Jerc.gov, or call [phone] (toll free). For TTY, call [phone].
Comment Date: 5:00 pm Eastern Time on (DATE).
Magalie R. Salas
Secretary
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 38 of 49
STATEMENT OF AUTHORIZED ACCOUNT REPRESENTATIVE
RATE FILING OF GAS TRANSMISSION NORTHWEST CORPORATION
OF JUNE 30, 2006
TO THE FEDERAL ENERGY REGULA TORY COMMISSION:
, Gregory A. Lohnes, Chief Financial Officer for Gas Transmission Northwest
Corporation, do hereby represent that the cost statements and supporting data submitted as part
of the above-mentioned filing by Gas Transmission Northwest Corporation, together with
working papers required therein, which purport to reflect the books of the Company, do, in fact
set forth the results shown by such books.
Gregory A. Lohnes
Chief Financial Officer
Gas Transmission Northwest Corporation
Dated:June 22 2006
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 39 of 49
APPENDIX A
REVISED TARIFF SHEETS
Gas Transmission Northwest Corporation
FERC Gas Tariff
Third Revised Volume No. I-A
Exhibit No.
Case No. INT-06-
Intermountain Gas Company
Page 40 of 49
Ninth Revised Sheet No.
Superseding
Eighth Revised Sheet No.
STATEMENT OF EFFECTIVE RATES AND CHARGES FOR
TRANSPORTATION OF NATURAL GAS
Rate Schedules FTS-l and LFS-
RESERVATION
DAILY DAILY
MILEAGE (a)NON - MILEAGE (b)DELIVERY (c)FUEL (d)
(Dth-MILE)(Dth)(Dth-MILE)(Dth)
MAX I MUM MINIMUM MAX I MUM MINIMUM MAX I MUM MINIMUM MAX I MUM MINIMUM
BASE 000616 000000 049918 000000 000037 000037 0050%0000%
STF(e)001540 000000 124795 000000 000037 000037 0050%0000%
EXTENSION CHARGES
MEDFORD
E-l (f)003917 000000 014747 000000 000024 000024
2 (g) 0.189234
(WWP)
000000 000000 0.000000
2 (h) 0.090388 0.000000
(Diamond 1)000000 0.000000
2(h) 0.035477 0.000000
(Diamond 2)
000000 0.000000
COYOTE SPRINGS
3 (i) 0.001878 0.000000 0.003652 0.000000 000000 000000
OVERRUN CHARGE
(j)
SURCHARGES
ACA (k)001800 001800
Issued by: John A Roscher, Director of Rates & Regulatory Affairs
Issued on: June 30, 2006 Effective on: August 1, 2006
Gas Transmission Northwest Corporation
FERC Gas Tariff
Third Revised Volume No. 1-A
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 41 of 49
Fourth Revised Sheet No.
Superseding
Third Revised Sheet No.
STATEMENT OF EFFECTIVE RATES AND CHARGES FOR
TRANSPORTATION OF NATURAL GAS (a)
Rate Schedule ITS-1
MILEAGE (n)NON-MILEAGE (0)FUEL (d)
(Dth-Mile)(Dth)(Dth)
MAX I MUM MINIMUM MAXIMUM MINIMUM MAX I MUM MINIMUM
BASE 001577 000037 124795 000000 0050%0000%
EXTENSION CHARGES
MEDFORD
E-1 (Medford)(f)
003941 000024 014747 000000
COYOTE SPRINGS
E-3 (Coyote Springs)(i)
001878 0 . 000000 003652 000000
SURCHARGES
ACA (k)
001800 001800
(Continued)
Issued by: John A Roscher, Director of Rates & Regulatory Affairs
Issued on: June 30, 2006 Effective on: August 1, 2006
Gas Transmission Northwest Corporation
FERC Gas Tariff
Third Revised Volume No. 1-
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 42 of 49
Eighth Revised Sheet No.
Superseding
Seventh Revised Sheet No.
STATEMENT OF EFFECTIVE RATES AND CHARGES
FOR TRANSPORTATION OF NATURAL GAS
Notes:
(a) The mileage component shall be applied per
transported by GTN for delivery to shipperand deli very 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 system map on
designations.
(b) The non-mileage component is applied per Shipper r 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 pointand 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 lineloss percentage surcharge is 0.0000% per Dth per pipeline mile. No fuel
use charges will be assessed for backhaul service. The incremental fuel
surcharge, initially established for Shippers utilizing capacity
constructed as part of GTN' s 2002 Pipeline Expansion proj ect at
000854% per Dth per pipeline mile, shall be adjusted downward as new
long-term Shippers take capacity that is subj ect to the incremental fuel
surcharge pursuant to Paragraph 38 of GTN's General Terms andConditions. Currently effective fuel charges, including GTN's currently
effective incremental fuel surcharge, may be found on GTN's Internetwebsite under "Informational Postings.
(e) Maximum reservation rates for Short-Term Firm service under Rate
Schedule FTS-1 are equal to two and one-half times the applicable non-
mileage and mileage FTS-1 Base Reservation components.
(f) Applicable to firm service on GTN's Medford Extension.
(Continued)
Issued by: John A Roscher, Director of Rates & Regulatory Affairs
Issued on: June 30, 2006 Effective on: August 1, 2006
Gas Transmission Northwest Corporation
FERC Gas Tariff
Third Revised Volume No. 1-A
Exhibit No.
Case No. INT O6-
Intermountain Gas Company
Page 43 of 49
Fourth Revised Sheet No. 12
Superseding
Third Revised Sheet No. 12
STATEMENT OF EFFECTIVE RATES AND CHARGES
FOR TRANSPORTATION OF NATURAL GAS FOR
PARKING AND AUTHORIZED IMBALANCE SERVICES
($/Dth)
Rate Schedule
and Type of Charge
Base Tariff Rate
Minimum Maximum
PS-1 Parking Service:353377/d
AIS-1 Authorized
Imbalance Service:353377/d
Notes:
(Continued)
Issued by: John A Roscher, Director of Rates & Regulatory AffairsIssued on: June 30, 2006 Effective on: August 1, 2006
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 44 of 49
Questar Pipeline Company
(for Clay Basin Storage)
Applicable Tariffs/Rate Schedules
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 45 of 49
FERC GAS TARIFF
FIRST REVISED VOLUME NO.
(SUPERSEDES ORIGINAL VOLUME NOS. 1, 1-A, 2 AND 2-A)
QUESTAR PIPELINE COMPANY
Filed with
FEDERAL ENERGY REGULATORY COMMISSION
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 45360
Salt Lake City, Utah 84145-0360Telephone: [phone]FAX: [phone]
Questar Pipeline Company
FERC Gas Tariff
First Revised Volume No.
Exhibit No.
Case No. INT O6-
Intermountain Gas Company
Page 46 of 49
Nineteenth Revised Sheet No.
Superseding
Eighteenth Revised Sheet No.
STATEMENT OF RATES
Base
Rate Schedule/
Type of Charge
(a)
Annual
Tariff
Rate
(b)
Currently
Charge
Adjustment
(c)
Effective
Rate
(d)
PEAKING STORAGE
Monthly Reserva tion
Maximum
Minimum
Usage Charge
Injection
Wi thdrawal
Charge
87375
00000
87375/Dth
OOOOO/Dth
03872
03872
03872/Dth
03872 /Dth
CLAY BASIN STORAGE
Firm Storage Service - FSS
Monthly Reserva tion Charge
De liverabilit y
Maximum
Minimum
Capacity
Maximum
Minimum
Usage Charge
Injection
wi thdrawal
Authorized Overrun Charge
Maximum
Minimum
Interruptible Sto rage Servic e - ISS
Usage Charge
Inventory 1/
Maximum
MinimumInjection
wi thdrawal
85338
00000
85338/Dth
OOOOO/Dth
02378
00000
02378/Dth
OOOOO/Dth
01049
01781
00180 01229/Dth
01781/Dth
30315
01781
00180
00180
30495/Dth
o. 01961/Dth
05927
00000
01049
01781
00180
05927/Dth
OOOOO/Dth
01229/Dth
017B1/Dth
OPTIONAL VOLUMETR IC RELEASES
Peaking Storage Service - PK
Maximum
Minimum
Firnt Storage Serv ice - FSS
Maximum
Minimum
Storage Usage Cba rges Applic able
Peaking Storage Service - PK
Injection
wi thdrawal
Clay Basin Storage Service - FSS,
Inj ection
Withdrawal
40890
00000
40890/Dth
OOOOO/Dth
57068
00000
to Volumetric Releases ~/
57068/Dth
OOOOO/Dth
03872
03872
03872 /Dth
03872 /Dth
01049
01781
00180 01229/Dth
01781jDth
PARK AND LOAN SERVICE - PAL
Daily Charge
Maximum
Minimum
Delivery Charge
30315
00000
02830 00180
30315/Dth
OOOOO/Dth
O. 03010/Dth
FUEL REIMBURSEMENT - 2.0% (0.2% utility and 1.8% compressor fuel) for Rate Schedule PALl
Issued by: R. Allan Bradley,
Issued on: August 10, 2005
President and COO
Effective on: October 2005
Questar Pipeline Company
FERC Gas Tariff
First Revised Volume No.
Exhibit No.
Case No. INT O6-
Intermountain Gas Company
Page 47 of 49
Eleventh Revised Sheet No. 6A
Superseding
Tenth Revised Sheet No. 6A
FOOTNOTES
!/Applied to the average monthly working gas balance.
~/Released capacity may be sold at a volumetric rate. Shippers releasing
capacity on a volumetric basis must specify a rate between the maximum and
minimum volumetric rate stated on this Statement of Rates and notify Questar
of the criteria by which bids are to be evaluated.
l/Storage usage charges are applicable to storage services that are
released at a volumetric rate and will be billed to the replacement shipper
according to ~ 18.2 of the General Terms and Conditions of Part 1 of thistariff.
i/The annual charge adjustment (ACA) as specified by the Commission will
be billed according to ~~ 4 (f) and 3 (d) of Rate Schedule FSS and ISS,
respectively, and ~ 17 of the General Terms and Conditions of Part 1 of thistariff.
NOTE: The monthly rates stated on Questar 1 s Statement of Rates may be
converted to a daily rate by multiplying the monthly base tariff rate times
the number of months in the rate period and dividing the result by the numberof days in the rate period. The result is rounded to the fourth decimalplace.
Issued by: R. Allan Bradley, President and COO
Issued on: June 23, 2005 Effective on: July 25, 2005
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 48 of 49
Niska Gas Storage for AECO Storage
- ("
AECO"
- formerly Encana -
Applicable Tariffs/Rate Schedules
ENCANA~
-~~..,,~' '=;;
-P
1/-
Exhibit No.
Case No. INT-O6-
Intermountain Gas Company
Page 49 of 49
At:COGas Stotagt PartnershiP
Ben Ledene
1800, 855 -Z-SStrE:etSW Tel (403) 64~92PO BoX2850 Fax [phone]
Calgary AB T2P2S5 Ben.Led8(l~n:ana:Com
April 25, 2006
Duke Energy Marketing limited Partnerhlp
257 East 200 South, Suite 1000
Salt lake City, UT 84 11 1
United States
Attention:Jim McArthur
Director. Gas Marketing
Dear Sir/Madam:
RE:Natural Gas storage Agreamelit Firm SeiViC~foraReselVedliweritolyof2750T J date(iasof
May 1, ,1994 (he ~StorageAgreemennOOf.\.vOOhPll~eEriergyiMarketing limit~ Partn~$hip(formerlyGraI1dVatl~y G as ,Comptu)y) and: '~COGas StOfc;lgePartriei'i;hip '(s~SSor in interestto EnC8na GasStor8ge,abusihess unit ofEriGan~(Midstr~m &JlitaikeUrig).
The Commodity, RatearidlheDemaoo Rate ofthe$t~geAgr~ement are rndexedea,::hApr~ 1stinaccordanre with the fOrmulas given t:)n ScheduleS. A~iWI(rii ~tthat:tQ~tr~~t,.~peqiyely;Thei!1(lexfqrthe,Cotrimooity Rate 'is'G~I'2006)JG~1(1~93). ,BaslXf.OO,, ~'4e1i6iJiOiiofGAI.apl (19S3)"i$ !i8tJown in the
=fi~ ~::~:r.~~W;~'t~~~~~i~~be
The DemafujRate indaxin the$t~g~Agr~~~nt isgI'!JgQ06)1PPj.(1$9~). ~~eCI' QI1 t!ie d.e.flnIJloo of~ ~ 1
2~~~ ~:3 t~~ffi~n~' ~ f: D~:A~~\~ ~~c~~~; ~~l ~ j 6
:~~$~
~=e
p=;
AlS9. ~per SCotian 2~89fthe~t~Agreernelit.'no~~'ishe.repyQiventhat' ~ffectiye,AprU1,2006.
~dal"la Corporation m axitnurn daQy iOjet:;U'm8nd . withdro~lreqQire~J$fr()mllieSt()rage Facitityare ,~sfQll()Ws:
Mciximum JnjeptionRateisOT J/ciqy
Maximum WilhdrawaIRateis:OTJ/di;ty
If yQuhave any'questjons'reg~dl"Jth~e, ma1:ters plea$e~n meal(~)645.3092~
7lLBen ~edooe
AdyjSor.Mc1rket ' Devel~nt
r-..; i,~~ Ei:IC:i;,& CCi'1iQc~tj(n
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EXIllBIT NOS. 4-
CASE NO. INT -G-06-
INTERMOUNTAIN GAS COMPANY
(7 pages)
RECEIVED
2006 AUG 16 AM 9: 23
IDAHO PUBLIC
UTILITIES COMMISSION
IN
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DE
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C
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Tr
a
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1

(
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R
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Up
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p
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L
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To
t
a
l
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(b
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(c
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(d
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(e
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1
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15
4
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30
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3
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1
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56
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15
3
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01
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3
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00
4
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07
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4
6
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No
r
m
a
l
i
z
e
d

S
a
l
e
s
/
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D

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o
l
s
.

(
1
0
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1
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0
4

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9
/
3
0
/
0
5
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Pr
o
p
o
s
e
d

P
r
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c
e

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d
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t

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r

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r
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r
e
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t
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d

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f
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o
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t

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m
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t
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d
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O
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p
t
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3
0
,
2
0
0
6
No
.
De
s
c
r
i
p
t
i
o
n
Ba
l
a
n
c
e

(
1
)
RS
-
RS
-
GS
-
(a
)
(b
)
(c
)
(d
)
(e
)
(f
)
(g
)
Fi
x
e
d

C
o
s
t
s
:
Fr
o
m

I
N
T
-
05
-
2
(
A
c
c
o
u
n
t
s

1
8
6
0
.
20
5
0

-

2
0
9
0
)
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2
5
86
3
)
10
6
44
2
(2
9
7
95
2
)
(1
1
3
,
4
6
3
)
(2
1
06
4
)
17
4
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
.
22
0
0
-
22
1
0
)
51
5
54
5
)
(2
5
54
8
)
(4
5
9
,
51
0
)
(6
8
5
25
5
)
(3
1
4
61
1
)
(3
0
62
1
)
St
a
t
o
l
!

R
e
v
e
n
u
e

D
e
f
e
r
r
a
l

(
A
c
c
o
u
n
t

1
8
6
0
.
22
6
0
)
(1
8
0
82
3
)
(2
1
37
0
)
(9
4
31
8
)
(5
5
72
2
)
(6
,
76
3
)
(2
,
65
0
)
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
.
23
2
0
)
(9
8
6
,
30
5
)
(1
1
6
56
5
)
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1
4
,
4
5
9
)
(3
0
3
93
6
)
(3
6
,
89
1
)
(1
4
,
4
5
4
)
In
t
e
r
e
s
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Exhibit No.
Case No. INT O6-
Intermountain Gas Company
Page 1 of
INTERMOUNTAIN GAS COMPANY
Proposed Temporary Surcharges (Credits) - Variable Costs
Description
(a)
Amount
(b)
Account 1860 Amounts Which Apply to RS-1, RS-, GS-, and LV-
Account 1860 Variable Costs (1)
Normalized Sales/CD Vols. (10/1/04 - 9/30/05)
Proposed Temporary Surcharge(Credit) - Variable Costs
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RECEIVED
2006 AUG 16 AM 9: 23
IDAHO PUBLIC
UTILITIES COMMISSION
NEWS RELEASE
and
CUSTOMER NOTICE
NEWS RELEASE Contact: Mike Huntington
Vice President
Marketing & External Affairs
[phone]August 16, 2006
Today, Intermountain Gas Company ("Intermountain ) filed its annual purchased gas cost adjustment application
with the Idaho Public Utilities Commission ("IPUC"). This type of application is filed each year to ensure that the costs that
Intermountain is incurring on behalf of its customers are properly reflected in its sales price. In its application
Intermountain requests permission to adjust its prices to reflect the prices of natural gas supplies that it expects to incur.
William C. "Bill" Glynn , President of Intermountain Gas Company, said
, "
Despite increases in some other energy
prices like crude oil that has increased 30% during the past year, the Company expects to be able to manage its natural
gas purchases such that it will not need to raise customer prices for this next winter season." Commenting further Glynn
said
, "
The forces behind this expectation include the increase in natural gas production resulting from additional drilling,
the return of Gulf Coast production which was shut-in from hurricane Katrina, and purchasing and pricing strategies the
Company has employed , including the use of significant summer storage injections for winter deliveries.
Glynn , however, went on to say, "We are pleased to be able to offer this additional price stability, however
Intermountain continues to urge all its customers to be conscious of their energy usage and use it wisely. Helpful tips on
ways to do that and how to request government payment energy assistance are provided through bill inserts and on the
Company s website (www.intqas.com). We also have a number of programs to help our customers level out their energy
bills over the year, and stabilize the potential impact that cold weather will have during periods of higher natural gas
usage.
If approved as filed, all residential and commercial customer s unit prices will be essentially unchanged for natural
gas used this next year and the Company s total net revenue will decrease by approximately $1.6 million (.5%). The
proposed effective date is October 1 2006. This proposal is subject to public review and approval by the IPUC. A copy
of Intermountain s application is available at the offices of both the Idaho Public Utilities Commission and the Company.
CUSTOMER NOTICE Contact: Mike Huntington
Vice President
Marketing & External Affairs
[phone]August 16, 2006
Today, Intermountain Gas Company ("Intermountain ) filed its annual purchased gas cost adjustment application
with the Idaho Public Utilities Commission ("IPUC"). This type of application is filed each year to ensure that the costs that
Intermountain is incurring on behalf of its customers are properly reflected in its sales price. In its application
Intermountain requests permission to adjust its prices to reflect the prices of natural gas supplies that it expects to incur.
William C. "Bill" Glynn , President of Intermountain Gas Company, said
, "
Despite increases in some other energy
prices like crude oil that has increased 30% during the past year, the Company expects to be able to manage its natural
gas purchases such that it will not need to raise customer prices for this next winter season." Commenting further Glynn
said
, "
The forces behind this expectation include the increase in natural gas production resulting from additional drilling,
the return of Gulf Coast production which was shut-in from hurricane Katrina, and purchasing and pricing strategies the
Company has employed , including the use of significant summer storage injections for winter deliveries.
Glynn , however, went on to say, "We are pleased to be able to offer this additional price stability, however
Intermountain continues to urge all its customers to be conscious of their energy usage and use it wisely. Helpful tips on
ways to do that and how to request government payment energy assistance are provided through bill inserts and on the
Company s website (www.intqas.com). We also have a number of programs to help our customers level out their energy
bills over the year, and stabilize the potential impact that cold weather will have during periods of higher natural gas
usage.
If approved as filed, all residential and commercial customer s unit prices will be essentially unchanged for natural
gas used this next year and the Company s total net revenue will decrease by approximately $1.6 million (.5%). The
proposed effective date is October 1 , 2006. This proposal is subject to public review and approval by the IPUC. A copy
of Intermountain s application is available at the offices of both the Idaho Public Utilities Commission and the Company.
WORKP APER NOS. 1-
CASE NO. INT -G-06-
RECEIVED
200& AUG I 6 AM 9: 25
IDAHO PUBUl~
UTILITIES COMMISSION
INTERMOUNTAIN GAS COMPANY
(8 pages)
Work paper No.
Case No. INT-O6-
Intermountain Gas Company
Page 1 of
INTERMOUNTAIN GAS COMPANY
Northwest Pipeline TF-1 Full Rate Demand Workpaper
Line INT-05-INT-05-INT-05-
No.Trans ortation Annual Therms Prices Annual Cost
(a)(b)(c)(d)
TF-1 Demand 1 Contract #1 412 537 600 028615 804 763
TF-1 Demand 1 Contract #2 550 000 028615 731 113
TF-1 Demand 1 Contract #3 000 000 028615 088 895
TF-1 Demand 1 Contract #4 542 500 028615 673 669
TF-1 Demand 1 Contract #5 54,750 000 028615 566 672
TF-1 Demand 1 Contract #6 500 000 028615 044,448
Total Annual Cost 625 880 100 028615 909 560
Line INT-06-INT-06-INT-06-
No.Trans ortation Annual Therms Prices Annual Cost
(a)(b)(c)(d)
TF-1 Demand 1 Contract #1 412 537 600 040362 650 843
TF-1 Demand 1 Contract #2 550 000 040224 027 723
TF-1 Demand 1 Contract #3 000 000 040027 921 971
TF-1 Demand 1 Contract #4 542 500 039691 934,425
TF-1 Demand 1 Contract #5 750 000 039906 184 854
TF-1 Demand 1 Contract #6 500,000 039992 1,459 708
Total Annual Cost 625 880 100 040362 179 524
Total Annual Cost Difference (Row 14 minus Row 7)269,964 (1)
(1) See Exhibit 4, Line 3, Column (h)
Workpaper No.
Case No. INT-O6-
Intermountain Gas Company
Page 1 of
INTERMOUNTAIN GAS COMPANY
Northwest Pipeline TF-1 Discounted Demand Workpaper
Line INT-05-INT-05-INT-05-
No.Trans ortation Annual Therms Prices Annual Cost
(a)(b)(c)(d)
TF-1 Demand 1 Contract #1 680 000 027760 212 557
TF-1 Demand 1 Contract #2 28,470 000 016656 474 196
TF-1 Demand 1 Contract #3 29,404,400 014724 432 950
TF-1 Demand 1 Contract #4 650 000 027760 628,764
TF-1 Demand 1 Contract #5 500 000 016656 607 944
TF-1 Demand 1 Contract #6 500 000 019432 709 268
Total Annual Cost 197 204,400 020617 065 679
Line INT-06-INT-06-INT-06-
No.Trans ortation Annual Therms Prices Annual Cost
(a)(b)(c)(d)
TF-1 Demand 1 Contract #1 680 000 035650 557 192
TF-1 Demand 1 Contract #2 28,470 000 023810 677 871
TF-1 Demand 1 Contract #3 29,404,400 021090 620 139
TF-1 Demand 1 Contract #4 650 000 037270 844 166
TF-1 Demand 1 Contract #5 500 000 023810 869 065
TF-1 Demand 1 Contract #6 500 000 027780 013 970
Total Annual Cost 197 204,400 028308 582,403
Total Annual Cost Difference (Row 14 minus Row 7)516 724 (1)
(1) See Exhibit 4, Line 4 , Column (h)
Workpaper No.
Case No. INT-O6-
Intermountain Gas Company
Page 1 of
INTERMOUNTAIN GAS COMPANY
Upstream Capacity Workpaper
Line INT-05-INT-05-INT-05-
No.Trans ortation Annual Therms Prices Annual Cost
(a)(b)(c)(d)
Upstream Agreement #1 198 089 150 012756 526 825
Upstream Agreement #2 155 624 370 005498 855,623
Upstream Agreement #3 155 025 220 013122 034 241
Upstream Agreement #4 193 282 100 012756 2,465 506
Upstream Agreement #5 273 100 300 005254 1,434 869
Upstream Agreement #6 144 193 020 013161 897 724
Total Annual Cost 214,788
Estimated Upstream Capacity Release Credits
Total Annual Cost Including Capacity Release Credits 10,403 983
(810 805)
Line INT-06-INT-06-INT-06-
No.Trans ortation Annual Therms Prices Annual Cost
(a)(b)(c)(d)
10 Upstream Agreement #1 197 567 200 012525 2,474 529
Upstream Agreement #2 155 624 370 006641 033 501
12 Upstream Agreement #3 155 025 220 019310 993 537
13 Upstream Agreement #4 192 891 550 012525 2,415 967
14 Upstream Agreement #5 189 573,700 006637 258 201
15 Upstream Agreement #6 163 572,400 017131 802 159
16 Total Annual Cost 977 894
17 Estimated Upstream Capacity Release Credits (500 000)
18 Total Annual Cost Including Capacity Release Credits 12,477 894
19 Total Annual Cost Difference (Row 18 minus Row 9)073 911 (1)
(1) See Exhibit 4, Line 5 , Column (h)
Workpaper No.
Case No. INT-O6-
Intermountain Gas Company
Page 1 of
INTERMOUNTAIN GAS COMPANY
Other Storage Facilities
INT-05-
Line Monthly INT-05-INT-05-INT-05-
No.Stora e Facilities Billinq Determinant Prices Monthly Cost Annual Cost
(a)(b)(c)(d)(e)
Demand Costs.
Clay Basin I Reservation 266 250 (1)285340 972 911 664
Clay Basin II Reservation 221 840 (1)285340 63,300 759,600
Clay Basin III Reservation 213 010 (1)60,780 729,360
Clay Basin I Capacity 950 000 (2)002378 977 911,724
Clay Basin II Capacity 625 000 (2)002378 314 759 768
Clay Basin III Capacity 25,560 000 (2)60,782 729,384
AECO Demand 064 970 (2)001432 37,325 447,900
Total Demand Costs 110 199,970 (3)437,450 249,400
Cycling Costs -
Clay Basin I & II Cycling Costs 575,000 001581 594 111 126
Clay Basin III Cycling Costs 25,560 000 35,468 425,611
AECO Cycling Costs 26,064,970 001536 023 480 272
Total Cycling Costs 639,970 168 085 017 009
Storage Demand Charge Credit 351 942)
Total Costs Including Storage Credit 914,467
INT-06-
Monthly INT-06-INT-06-INT-06-
Stora e Facilities Billinq Determinant Prices Monthly Cost Annual Cost
(a)(b)(c)(d)(e)
Demand Costs.
Clay Basin I Reservation 266 250 (1)285338 971 911 652
Clay Basin II Reservation 221 840 (1)285338 63,299 759,588
Clay Basin III Reservation 213,010 (1)285338 780 729,360
Clay Basin I Capacity 950 000 (2)002378 75,977 911 724
Clay Basin II Capacity 625,000 (2)002378 314 759,768
Clay Basin III Capacity 560 000 (2)002378 782 729 384
AECO Demand 064 970 (2)001634 590 511 080
Total Demand Costs 110 199 970 (3)442 713 312 556
Cycling Costs -
Clay Basin I & II Cycling Costs 58,575 000 001196 060 840,715
Clay Basin III Cycling Costs 25,560,000 001187 339 364 062
AECO Cycling Costs 064 970 002227 58,039 696,465
Total Cycling Costs 110 199 970 158,438 901 242
Estimated Storage Demand Charge Credit 393 273)
Total Costs Including Storage Credit 820,525
Total Annual Cost Difference Including Storage Credit (Row 32 minus Row 16)093 942) (4)
(1) Charge Based on Maximum Daily Withdrawal
(2) Charge Based on Maximum Contractual Capacity
(3) Non Additive Billing Determants; Includes only Capacity Volumes
(4) See Exhibit 4, Line 19, Column (h)
Workpaper No.
Case No. INT-O6-
Intermountain Gas Company
Page 1 of
INTERMOUNTAIN GAS COMPANY
Peak Day Analysis for Demand Allocators in Case No. INT-O6-
Firm
Line Core Total Transportation Total Firm Total
No.Descri tion RS-RS-GS-Core Transportation Peak
(a)(b)(c)(d)(e)(I)
(g)
(h)(i)
DEMAND ALLOCA TORS PER CASE NO. INT-O5-
Peak Day Therms 446 782 820 855 151 783 419,420 126,412 070 181,482 600 902
Percent of Total 1? 40750%5056664%31 96596%94.96010%351056%1 5?934'10 03990%1000000%
PROPOSED DEMAND ALLOCATORS PER CASE NO.INT O6.04:
Peak Day Therms (Line 2) 446 782Customers Embedded v,;thin Line 2 61 967
Peak Day Usage Per Customer (Line 5 divided by Line 6)7.21
820855 151,783 3,419 420
175928 029 263 924
10.44.
189 378 169 277 143
960 062 157 978 562 147 140 552 070 195 622 (1)757 769
5? 160?6%3061557%94.79420%374030%1 46550%20580%1000000%
January 2006 Actual Customers 596
INT-G-06-04 Peak Day Therms (Line 7 muiitpiied by Line 8)444 107
Percent olTota!1161637%
(1) FY07 Forecast Contract Therms
Detail Detail Amounl Sub-Total Total
(b)(c)(d)(e)
730 036.
439685.43)
454611
03171 648615.
088301.14)
(358264.75)
652733.
729873.
939145.30)
13,443462.
589.
821916.
186 536.43
051042.
136239.
INTERMOUNTAIN GAS COMPANY
Analysis of Account 1860 Surcharges (Credits)
Estimated September 30 2006
Line
Description
(e)
ACCOUNT 1860 VARIABLE AMOUNTS:
Net Cumulative Deferred Gas Balance in 1860.2010 as of 1011105
Amorlrzalron In 1860.2020 as of 6130106
Eslrmated Therm Sales 711lhrou9h 9130106
Amorlrzalron Rate
Eslrmated Amortizalron In 1860.2020 at 9130106
Estimated Balance In 1860.2010 at 9130106
Deferred Gas Costs From ProducerslSuppliers In 1860.2180 al 1011105
Deferred Gas Costs From Producers/Suppliers In 1860.2180 Ihrou9h 6130106
Eslrmated Deferred Costs in 1860.2180 from 711lhrou9h 9130/06
Estimated Balance in 1860.2180 al 9130106
Daily Gas Excess Sales Deferred in 1860.2240 at 6130106
Interest Deferred In 1860.2340 al 1011105
Deferred Interestin 1860.2340 Ihrough 6130106
Eslrmaled Inleresl from 7/1lhrou9h 9130/06
Estimated Balance In 1860.2340 al 9130106
ESTIMATED ACCOUNT 1860 VARIABLE BALANCE AT 9/30/O6
ACCOUNT 1860 FIXED AMOUNTS:
NelCumulative Deferred Gas Balance In 1860.2050al 1011105
RS-1 Delerred Gas Balance in 1860.2060 at 10/1/05
Amortizalron for RS-1 In 1860.2060 at 6/30/06
Eslrmated RS-1 Therm Sales 7/1lhrough 9/30/06
RS-1 Amortizalron Rate
Eslrmaled RS-1 Balance in 1860.2060 aI9/30/06
912.78)
354959.76)
628360
04208 441.39
(7,309.82)
616 637.03)
979480
02489 248389.
924.76
313609.11)
268189
02612 242085.
984.
(45630.50)
823806
00276 (13313.70)
165210
03519 813.
RS-2 Deferred Gas Balance in 1860.2070 a110/1/05
Amorlrzalron for RS-2 In 1860.2070 at 6/30106
Eslrmaled RS-2 Therm Sales 7/1lhrough 9/30/06
RS-2 Amorlrzalron Rate
Eslrmated RS-2 Balance in 1860.2070 af 9/30/06
GS-1 Deferred Gas Balance In 1860.2080 all 0/1105
Amorllzalron for GS-1 In 1860.2080 a16130106
Eslrmated Therm Sales 7/1lhrough 9/30/06
GS-1 Amorlrzalron Rate
Eslrmated GS-1 Balance in 1860.2080 at 9/30/06
Industrial Deterred Gas Balance in 1860.2090 aI10/1/05
Amortizalron for T-1 & T-2 in 1860.2090 at 6130/06
Eslrmated T-1 Block 1 & 2 Therm Sales 7/1lhrough 9130106
1 Amorlrzalron Rate
Eslrmaled T-2 Contract Demand Volumes 7/1lhrou9h 9130/06
2 Amortizalron Rate
Eslrmated Industrial Balance In 1860.2090 at 9/30/06
Estimaled Cumulative Balance in 1860.2050 al9130106
Workpaper No.
Case No. INT-O6-
Intermountain Gas Company
Page 1 of 2
536702.
385313.93)
872 336.11)
(2,554769.45)
(52145.87)
(325862.84)
INTERMOUNTAIN GAS COMPANY
Analysis of Account 1860 Surcharges (Credits)
Estimated September 30, 2006
Line
Description
(a)
Detail
(b)
Fixed Cost Collection Deferred In 1860.2200 at 10/1/05
Fixed Cosl Coilection Deferred in 1860.2200 through 6/30/06
Estimated Fixed Cosl Collection Deferred from 7/1 through 9/30/06
Estimated Balance In 1660.2200 at 9/30106
T -4 Exit Fee Adjustment Deferred In 1860.2210 at 1011/05
4 Exil Fee Adjustment Deferred in 1860.2210 through 6/30/06
Estimaled T-4 Exil Fee Adjustment Deferred from 7/1 through 9/30/06
Estimated Balance In 1860.2210 at 9/30/06
Statoll Revenue Deferred in 1860.2260 at 10/1/05
Statoil Revenue Deferred in 1860.2260 through 6/30/06
Estimated Staloil Revenue Deferred from 7/1 through 9/30/06
Estimated Balance in 1660.2260 at 9/30/06
Capacity Released/Purchased Deferred in 1860.2320 at 6/30/06
Interest Deferred in 1860.2420 at 10/1/05
Deferred Interest in 1860.2420 through 6/30/06
Estimaled Inleresl from 7/1 through 9130106
Estimated Balance In 1660.2420 at 9/30/06
Interestin1660.2430at10/1/05
Deferred Interest in 1860.2430 through 6/30/06
Estimated Inleresl from 711 through 9/30/06
Estimated Balance In 1860.2430 at 9/30/06
Market Segmentation Deferred in 1860.2530 at 10/1/05
Market Segmenlation Deferred in 1860.2530 through 6/30/06
Estimated Deferral in 1860.2530 from 7/1 through 9/30/06
Estimated Balance in 1860.2530 aI9/30/06
RS-1 AmorUzation in 1860.2540 aI6/30/06
Estimaled RS-1 Therm Sales from 7/1 through 9/301O6
RS-1 Amortization Rate
Estimated RS-1 AmorUzation in 1860.2540 at 9/30/06
628360
00817
RS-2 AmorUzation in 1860.2540 at 6/30/06
Estimated RS-2 Therm Sales from 7/1 through 9/30106
RS-2 AmorUzation Rate
Estimated RS-2 AmorUzation in 1860.2540 at 9/30/06
979480
00822
GS-1 AmorUzation in 1860.2540 at 6/30106
Estimated GS Therm Sales from 7/1 through 9/30/06
GS-1 AmorUzation Rale
Estimaled GS-1 AmorUzation in 1860.2540 alg/30/06
268,189
00799
Estimated Core Amortization in 1860.2540 at 9/30/06
1 Amortization in 1860.2550 aI613O/06
Estimated T-1 Block 1&2 Therm Sales from 7/1 through 9/30/06
1 AmorUzation Rate
Estimated T-1 AmorUzation in 1860.2550 at 9/30106
823806
00415
2 AmorUzation in 1860.2550 at 6130106
Estimaled T-2 Con~acl from 7/1 through 9/30/06
2 AmorUzation Rale
Estimated T-2 Amortization in 1860.2550 at 9130106
165210
05401
Estimaled Indus~ial Amortization in 1860.2550 at 9130106
Estimated Balance in 1660.2530 at 9/30/06
ESTIMATED ACCOUNT 1860 FIXED BALANCE AT 9/30/06
TOTAL DEFERRED ACCOUNT 1860 BALANCE
Workpaper No.
Case No. INT-O6-
Intermountain Gas Company
Page 2 of 2
Detail Amount Sub.Total Total
(c)(d)(e)
281454.
(7,205535.42)
416,474.
507606.04)
036.88)
(4,427.57)
474.52)
(7,938.97)
34.
(180857.67)
(180823.17)
(986304.81)
(157.38)
160.
(169.29)
(166.59)
157.
(136190.96)
(54959.88)
(169993.60)
(21363.19)
829308.28)
616475.
467146.47)
268624.45
133.
273758.
216627.
031.
298658.
714193.
052.
788246.
360663.
190.
018.
114209.
039.
922.
962.
150171.07
687.
135008.17)
001231.
Workpaper No.
Case No. INT-06-
Intermountain Gas Company
Page 1 of
INTERMOUNTAIN GAS COMPANY
1 Tariff Block 1, Block 2, and Block 3 Adjustment
Line
No.Description
(a)
Industrial Therm Sales (10/1/04 - 9/30/05)
Blocks 1 and 2 Therm Sales
Percent Therm Sales between Blocks 1 and 2
Proposed Adjustment to T -1 Tariff (1)
Industrial Therm Sales (10/1/04 - 9/30/05)
Annualized Adjustment (Line 4 multiplied by Line 5)
Annualized Adjustment (Line 4 multiplied by Line 5)
Percent Annualized Sales included in Block 1
Adjustment to Block 1 (Line 7 mulitplied by Line 8)
Block 1 Therms
Price AdjustmenUTherm Block 1 (Line 9 divided by Line 10)
Northwest Pipeline TF-1 Commodity Charge Change (2)
Total Price AdjustmenUTherm Block 1
Annualized Adjustment (Line 4 multiplied by Line 5)
Percent Annualized Sales included in Block 2
Adjustment to Block 2 (Line 14 multiplied by Line 15)
Block 2 Therms
Price AdjustmenUTherm Block 2 (Line 16 divided by Line 17)
Northwest Pipeline TF-1 Commodity Charge Change (2)
Total Price AdjustmenUTherm Block 2
Total Price AdjustmenUTherm Block 3
Block 1 Block 2 Block 3
Therm Sales Therm Sales Therm Sales
(b)(c)(d)
188 505 733,450
188 505 5,733,450
78.703%21.297%
(1) See Exhibit No., Line 33, Col. (I) minus the difference of Line 22, Col. (f) minus Line 22, Col. (c)
(2) See Exhibit No., Line 22, Col. (f) minus Line 22, Col. (c)
Total
(e)
921 955
921 955
100.000%
(0.00941)
921 955
(253 336)
(253 336)
78.703%
(199 383)
188 505
(0.00941)
(0.00169)
01110
(253 336)
21.297%
(53 953)
733,450
(0.00941)
(0.00169)
(0.01110)
00169