20180827Application and Exhibits.pdf

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Avista Corp.
141 1 East Mission P.O. Box 3727
Spokane, Washington 99220-0500
Telephone [phone]
Toll Free 800-727-9170
ri;i, 'l ;i-i i 'ilJLiCi ,i 'ilr:ri i-;,lh{l\{l$SION
August 24,2018
Diane Hanian
State of Idaho
Idaho Public Utilities Commission
472 W . Washington Street
Boise, Idaho 837 02-5983
Case No. AVU-G-18-0Tledvice No. l8-02-G
I.P.U.C. No. 27 - Natural Gas Service
Enclosed for electric filing with the Commission are the Original filing plus seven copies, and one
compact disc, of the following revised tariff sheets:
Twenty-Sixth Revision Sheet 150 canceling
Twentieth Revision Sheet 155 canceling
Twenty-Fifth Revision Sheet 150
Nineteenth Revision Sheet 155
The Company requests that the proposed tariff sheets be made effective November l, 2018. These tariff
sheets reflect the Company's annual Purchased Gas Cost Adjustment ("PGA"). If approved, the
Company's annual revenue will deuease by approximately $0.6 million or approximately 1.0%. The
proposed changes have no effect on the Company's earnings. Detailed information related to the
Company's request is included in the attached Application and supporting workpapers.
If the Company's request is approved, a residentialor small commercialcustomer using an average of 63
therms per month will see a decrease of $0.34 per month, or approximately 0.7%o. The present bill for 63
therms is $48.31 while the proposed bill is $47.97. The Company will issue a notice to its customers
through a bill insert in the September 2018 to October 2018 timeframe. A copy of the bill insert has been
included in the Company's filing.
If any questions regarding this filing, please contact Annette Brandon at [phone].
Patrick D
Director of Regulatory Affairs
BEFoRE THE rDAHo puBLIC urrlrrrEs coMMISSIofii'ri:lYEt)
?. ii l.:l 27 f,li 91 22
t!IN THE MATTER OF THE APPLICATION OF )
AVISTA UTILITIES FOR AN ORDER APPROVING )
A CHANGE IN NATURAL GAS RATES AND CHARGES )
Application is hereby made to the Idaho Public Utilities Commission for an Order approving a revised
schedule of rates and charges for natural gas service in the state of Idaho. The Applicant requests that
the proposed rates included in this Purchased Gas Cost Adjustment ("PGA") filing be made effective on
November 1,2018. If approved as filed, the Company's annual revenue will decrease by approximately
$0.6 million or about 1.0%. In support of this Application, Applicant states as follows:
The name of the Applicant is AVISTA CORPORATION, doing business as AVISTA UTILITIES
(hereinafter Avista, Applicant or Company), a Washington corporation, whose principal business office
is 141 1 East Mission Avenue, Spokane, Washington, and is qualified to do business in the state of ldaho.
Applicant maintains district offices in Moscow, Lewiston, Coeur d'Alene, and Kellogg, Idaho.
Communications in reference to this Application should be addressed to:
Patrick D. Ehrbar
Director of Regulatory Affairs
Avista Utilities
1411 E. Mission Avenue
Spokane, WA 99220-3727
Phone: [phone]
Fax: [phone]
Pat.ehrbar@avistacorp. com
il.
Attorney for the Applicant and his address is as follows:
David J. Meyer
Vice President and Chief Counsel for Regulatory
And Governmental Affairs
Avista Utilities
1411 E. Mission Avenue
Spokane, WA 99220-3727
Phone: [phone]
Fax: [phone]
David.meyer@avistaco{p.com
Case No. AVU-G-18-0_ (Advice No. l8-02-G)Page I of6
I
III.
The Applicant is a public utility engaged in the distribution of natural gas in certain portions of Northern
Idaho, Eastern and Central Washington, and Southwestern and Northeastern Oregon, and further
engaged in the generation, transmission, and distribution of electricity in Northern Idaho and Eastem
Washington.
ry
Twenty-Sixth Revision Sheet 150, which Applicant requests the Commission approve, is filed herewith
as Exhibit "A". Additionally, Twentieth Revision Sheet 155, which Applicant requests the Commission
approve, is also filed herewith as Exhibit "A". Also included in Exhibit "A" is a copy of Twenty-Fifth
Revision Sheet 150 and Nineteenth Revision Tariff Sheet 155 with the changes underlined and a copy
of Twenty-Fifth Revision Sheet 150 and Nineteenth Revision Tariff Sheet 155 with the proposed
changes shown by lining over the current language or rates.
V
The existing rates and charges for natural gas service on file with the Commission and designated as
Applicant's Tariff IPUC No. 27, which will be superseded by the rates and charges filed herewith, are
incorporated herein as though fully attached hereto.
u.
Notice to the Public of Applicant's proposed tariffs is to be given simultaneously with the filing of this
Application by posting, at each of the Company's district offices in Idaho, a Notice in the form attached
hereto as Exhibit "B" and by means of a press release distributed to various informational agencies, a
draft copy attached hereto in Exhibit "E". [n addition, Exhibit "E" to this Application also contains the
form of customer notice that the Company will send to its customers in its monthly bills in the September
- October timeframe.
VII.
The circumstances and conditions relied on for approval of Applicant's revised rates are as follows:
Applicant purchases natural gas for customer usage and transports it over Williams Northwest Pipeline,
Gas Transmission Northwest (GTN), TransCanada - Alberta, TransCanada - BC and Spectra Energy
Pipeline systems, and defers the effect of timing differences due to implementation of rate changes and
differences between Applicant's actual weighted average cost of gas ("WACOG") purchased and the
WACOG embedded in rates. Applicant also defers various pipeline refunds or charges and
miscellaneous revenue received from natural gas related transactions including pipeline capacity
releases.
VIII.
This filing reflects the Company's proposed annual PGA to: 1) pass through changes in the estimated
cost of natural gas for the November 2018 through October 2019 twelve-month period (Schedule 150),
and 2) revise the amortization rate(s) to refund or collect the balance of deferred gas costs (Schedule
155). Below is a table summarizing the proposed changes reflected in this filing.
Case No. AVU-G-18-0_ (Advice No. l8-02-G)Page 2 of 6
Sch.
Commodity Demand
Change
Amortization TotalRateTotal
Sch.150
Overall
Pe rce nt
Chanqe
-0.8,
-0.8,h
-0.3,4
1.7V"
-2.2.4
Service
General
No. per therm per therm Chanse Der therm
Change
per therm
131 $ 0.006s4 $- $ 0.006s4 $- $ 0.00654
146 $$$$ (0.0026s) $ (0.0026s)
General
Lg General
Interruptftrle
IX.
Commoditv Costs
As shown in the table above, the estimated WACOG change is a slight increase of $0.00654 per therm.
The proposed WACOG, including the revenue conversion factor, is $0.17025 per therm compared to the
present WACOG of $0.16371 per therm included in rates. The overall reduction in the WACOG is
generally the result ofthe continued high natural gas production levels and an abundance ofnatural gas
in storage.
The Company's natural gas Procurement Plan ("Plan") uses a diversified approach to procure natural
gas for the coming PGA year. While the Plan generally incorporates a more structured approach for the
hedging portion of the portfolio, the Company exercises flexibility and discretion in all areas of the plan
based on changes in the wholesale market. The Company typically meets with Commission Staff semi-
annually to discuss the state of the wholesale market and the status of the Company's Plan. In addition,
the Company communicates with Staff when it believes it makes sense to deviate from its Plan and/or
opportunities arise in the market.
Avista has been hedging natural gas on both a periodic and discretionary basis throughout 2017-2018
for the forthcoming PGA year. Approximately 32%o of estimated annual load requirements for the PGA
year (November 2018 through October 2019) will be hedged at a fixed-price derived from the
Company's Plan. These volumes are comprised of: 1) volumes hedged for a term of one year or less,
and 2) volumes from prior multi-year hedges. Through July, the hedge volumes for the PGA year have
been executed at a weighted average price of $2.50 per dekatherm ($0.250 per therm).
The Company used a 30-day historical average of forward prices and supply basins (ending July 31,
2018) to develop an estimated cost associated with index purchases. The estimated monthly volumes to
be purchased by basin are multiplied by the 30-day average forward price for the corresponding month
and basin. These index purchases represent approximately 68% of estimated annual load requirements
for the coming year. The annual weighted average price for these volumes is $1.50 per dekatherm
($0.150 per therm).
Case No. AVU-G-l 8-0_ (Advice No. l8-02-G)Page 3 of6
lll $ 0.00654 $
x.
Demand Costs
Demand costs reflect the cost of pipeline transportation to the Company's system, as well as fixed costs
associated with natural gas storage. As shown in the table above, demand costs are expected to decrease
for residential customers by approximately $0.00918 per therm. This reduction is primarily due to the
pricing of Canadian pipeline costs in U.S. dollars rather than Canadian dollars.l
K.
Schedule 155 / Amortization Rate Change
As shown in the table above, the proposed amortization rate change for Schedule l0l and Schedule 1 1 1
is a decrease of $0.00283 per therm. The current rate applicable to Schedule 101 and Schedule I I 1 is
$0.08862 per therm in the rebate direction; the proposed rate is $0.09145 per therm also in the rebate
direction. This rate is comprised of the following components:
Rate Schedule 155
Idaho Earnings Test
Temporary Tax Benefits
Total
($7,935,767)($ 65,212)($ s79.410)
($8,580,449)
The first balance is related to the previous year's residual amortization balance and deferrals in Rate
Schedule 155. The Company was able to replace the present rebate due, in part, to a combination of
lower actual natural gas prices versus the embedded WACOG, as well as through optimization efforts
(both storage as well as fixed transportation contract) resulting in a deferral balance of approximately
$7.9 million.2
The second balance included in this filing is related to the Idaho Earnings test deferral (Rate Schedule
197) approved in Case No. AVU-G-I5-01, Order No. 33437. This amount represents the residual
balance remaining from the deferral of earnings sharing.
The third balance included in this filing is related to the Temporary Tax Benefits agreed to as part of the
Settlement Stipulation in Case No. GNR-U-I8-01 which states at page 11, part (a) "The parties agree
that the Company will include the Natural Gas Temporary Tax Benefit of $544,000 as an adjustment
within the Purchase Gas Adjustment (PGA) effective November 1, 2018".
I In previous years, due to the U.S and Canadian currency being close to par, in Company used Canadian dollars in setting
the demand rate for Transcanada- AB (NOVA system), Transcanad-BC (Foothills system) and Spectra -Westcoast. The
actual costs, however, were recorded in U.S. Dollars at the actual exchange rate on the date of payment.
2 Included in this $7.9 million is$12,233.26 related to the residual balance of the Idaho Holdback (transferred in November
2017). ln Case No. AVU-G-12-07, Order No. 32769, approximately $1.55 million of the existing PGA deferral balance
was approved to offset increases related to the GRC. This amount was amortized from November 2013 through December
2014, with a rebate of 512,233.26 remaining. After correspondence with Staff, we transferred this remaining balance into
the PGA account amortization in order to fully pass it back to customers.
Case No. AVU-G-18-0_ (Advice No. l8-02-G) Page 4 of 6
xII
If approved as filed, the Company's annual revenue will decrease by approximately $0.06 million or
about 1.0o/o effective November 1,2018. Residential or small commercial customers using an average
of 63 therms per month would see a decrease of $0.34 per month, or approximately 0.7oh. The present
bill for 63 therms is $48.31 while the proposed bill is $47 .97 .
xIII
Exhibit "C" attached hereto contains support workpapers for the rates proposed by Applicant contained
in Exhibit "A".
XIV
Avista requests that the rates proposed in this filing be approved to become effective on November 1,
2018, and requests that the matter be processed under the Commission's Modified Procedure rules
through the use of written comments. Avista stands ready for immediate consideration on its
Application.
XV
WHEREFORE, Avista requests the Commission issue its Order finding its proposed rates to be just,
reasonable, and nondiscriminatory and to become effective for all natural gas service on and after
November 1,2018.
Dated at Spokane, Washington, this 24th day of August 2018.
A UTILITIES
D. Ehrbar
Director of Regulatory Affairs
Case No. AVU-G-18-0_ (Advice No. 18-02-G)Page 5 of6
VERIFICATION
STATE OF WASHINGTON )
)
)County ofSpokane
Patrick D. Ehrbar, being first duly swom on oath, deposes and says: That he is Director of
Regulatory Affairs of Avista Utilities and makes this verification for and on behalf of Avista
Corporation, being thereto duly authorized;
That he has read the foregoing filing, knows the and believes the same to be true.
SIGNED AND SWORN to before me this 24th day of August 2018, by Patrick D. Ehrbar
tJr)
EDE
o
pOTARY
PUBL\G NOTARY PUBLIC in and for the State of
Washington, residing at Spokane.
,ll11 il ,6-0q-JNCommission Expires
Case No. AVU-G-18-0_ (Advice No. l8-02-G)Page 6 of6
bhb,t D*jrrl
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that I have served Avista Corporation dba Avista Utilities'Advice filing
ADV 18-02-G (Tariff IPUC No. 27 Natural Gas Service) by mailing a copy thereof, postage
prepaid to the following:
Diane Hanian, Secretary
ldaho Public Utilities Commission
472 W . Washington Street
Boise, lD 83720-5983
Edward A. Finklea
Alliance of Western Energy Consumers
545 Grandview Drive
Ashland, OR 97520
Chad Stokes
Cable Huston Benedict Haagensen &
Lloyd, LLP
1001 SW Sth, Suite 2000
Portland, OR 97204-1136
Curt Hibbard
St. Joseph Regional Medical Center
PO Box 816
Lewiston, ID 83501
Dated at Spokane, Washington this 24th day of August 2018.
Paul Kimball
Senior Regulatory Analyst
AVISTA UTILITIES
Case No. AVU-G-18-0 4
EXHIBIT "A"
Proposed Tariff Sheets
August 24,2018
AVISTA CORPORATION
d/b/a Avista Utilities
SCHEDULE 150
PURCHASE GAS COST ADJUSTMENT - IDAHO
APPLICABLE:
To Customers in the State of ldaho where Company has natural gas service
available.
PURPOSE:
To pass through changes in costs resulting from purchasing and transporting
naturalgas, to become effective as noted below.
RATE:
(a)The retail rates of firm gas Schedules 101, 'l 1'1 and 112 are to be increased
by 26.6650 per therm in all blocks of these rate schedules.
(b)The rates of intenuptible Schedules 131 and 132 are to be increased by
17.025i, per therm.
The rate for transportation under Schedule 146 is to be decreased by
0.0006 pertherm.
WEIGHTED AVERAGE GAS COST:
The above rate changes are based on the following weighted average cost of gas
pertherm as of the effective date shown below:Demand Commodity Total
Schedules '101 9.640C 17.0250, 26.665f
Schedules 111 and 112 9.6400 17.0250, 26.6650
Schedules 131 and 132 0.0006 17.025i, 17.025i,
The above amounts lnclude a gross revenue factor.
Demand Commodity Total
Schedules 101 9.584C 16.926P 26.510i,
Schedules 111 and 112 9.5846 16.9260 26.510$
Schedules 131 and 132 0.0000 16,926i, 16.926(,
The above amounts do not include a gross revenue factor.
BALANCING ACCOUNT:
The Company will maintain a Purchase Gas Adjustment (PGA) Balancing Account
whereby monthly entries into this Balancing Account will be made to reflect differences
between the actual purchased gas costs collected from customers and the actual
purchased gas costs incurred by the Company. Those differences are then collected from
or refunded to customers under Schedule 155 - Gas Rate Adjustment.
(c)
lssued August24,2018 Effective November 1,2018
l.P.U.C. No.27
Twenty-Sixth Revision Sheet 150
Replacing
Revision Sheet 150 150
v
Patrick Ehrbar - Director of Regulatory Affairsq*bL
AVISTA CORPORATION
d/b/a Avista Utilities
SCHEDULE 150
PURCHASE GAS COST ADJUSTMENT - IDAHO
APPLICABLE:
To Customers in the State of ldaho where Company has natural gas service
available.
PURPOSE:
To pass through changes in costs resulting from purchasing and transporting
naturalgas, to become effective as noted below.
RATE:
(a)The retail rates of firm gas Schedules 101, 111 and 112 are to be increased
by 26€29d per therm in all blocks of these rate schedules.
(b)The rates of interruptible Schedules 131 and 132 are to be increased by
#371+ per therm.
(c)The rate for transportation under Schedule 146 is to be decreased by
0.0006 per therm.
WEIGHTED AVERAGE GAS COST:
The above rate changes are based on the following weighted average cost of gas
per therm as of the effective date shown below:Demand Commodity Total
Schedules l0l
Schedules lll and 112
Schedules l3l and 132
The above amounts include a gross revenue factor.
Demand Commodity Total
Schedules l0l
Schedules lll and 112
Schedules 131 and 132 0.0000 W
The above amounts do not include a gross revenue factor.
BALANCING ACCOUNT:
The Company will maintain a Purchase Gas Adjustment (PGA) Balancing Account
whereby monthly entries into this Balancing Account will be made to reflect differences
between the actual purchased gas costs collected from customers and the actual
purchased gas costs incurred by the Company. Those differences are then collected from
or refunded to customers under Schedule 155 - Gas Rate Adjustment.
lssued August 24,2018 Effective November 30, 2018
Twenty-Fifth Revision Sheet 150
LP.U.C. No.27
Replacing
ourth Revision Sheet 150 150
By
Avista Utilities
Patrick Ehrbar - Director of Regulatory Affairs
AVISTA CORPORATION
d/b/a Avista Utilities
SCHEDULE 150
PURCHASE GAS COST ADJUSTMENT - IDAHO
APPLICABLE:
To Customers in the State of ldaho where Company has natural gas service
available.
PURPOSE:
To pass through changes in costs resulting from purchasing and transporting
natural gas, to become effective as noted below.
RATE (a) The retail rates of firm gas Schedules 101, 1 1 1 and 112 are to be increased
by 26.6651 per therm in all blocks of these rate schedules.
(b)The rates of interruptible Schedules 131 and 132 are to be increased by
17.0250, per therm.
(c)The rate for transportation under Schedule 146 is to be decreased by
0.0000 per therm.
WEIGHTED AVERAGE GAS COST:
The above rate changes are based on the following weighted average cost of gas
per therm as of the effective date shown below:Demand Commodity Total
Schedules 101 9.640d 17.025d 26.665d
Schedules 111 and 112 9.640d 17.025d, 26.665d
Schedules 131 and 132 0.0000 17.025d 17.025d,
The above amounts include a gross revenue factor.
Demand Commodity Total
Schedules 101 9.5840, 16.926i, 26.510$
Schedules 111 and 112 9.5840, 16.9260, 26.5100,
Schedules 131 and 132 0.000d 16.926$ 16.9260,
The above amounts do not include a gross revenue factor.
BALANCING ACCOUNT:
The Company will maintain a Purchase Gas Adjustment (PGA) Balancing Account
whereby monthly entries into this Balancing Account will be made to reflect differences
between the actual purchased gas costs collected from customers and the actual
purchased gas costs incurred by the Company. Those differences are then collected from
or refunded to customers under Schedule 155 - Gas Rate Adjustment.
lssued August 24,2018 Effective November1,2018
l.P.U.C. No.27
lssued by
By
Twenty-Sixth Revision Sheet 150
Replacing
ifth Revision Sheet 150 150
Avista
Patrick Ehrbar - Director of Regulatory Affairs
AVISTA CORPORATION
d/b/a Avista Utilities
SCHEDULE 155
GAS RATE ADJUSTMENT - IDAHO
AVAITABLE:
To Customers in the State of ldaho where Company has natural gas service
available.
PURPOSE:
To adjust gas rates for amounts generated by the sources listed below
MONTHLY RATE:(a) The rates of firm gas Schedules 101 and 111 are to be
decreased by 9.145C per therm in all blocks of these rate schedules.(b) The rate of intenuptible gas Schedule 131 is to be decreased by
0.0000 pertherm.(c) The rate of transportation gas Schedule 146 is to be decreased by 0.2650,
per therm.
SOURCES OF MONTHLY RATE:
Changes in the monthly rates above result from amounts which have been
accumulated in the Purchase Gas Adjustment (PGA) Balancing Account as
described in Schedule 150 - Purchase Gas Cost Adjustment.
SPECIAL TERMS AND CONDITIONS:
The above Monthly Rate is subject to the provisions of Tax Adjustment Schedule
158.
lssued August 24,20'18 Effective November1,2018
l.P.U.C. No.27
Twentieth Revision Sheet 155
Canceling
Nineteenth Revision Sheet 155
Patrick Ehrbar, Director of Regulatory Affairs
155
By
Vg/*l-^-
AVISTA CORPORATION
d/b/a Avista Utilities
SCHEDULE 155
GAS RATE ADJUSTMENT - IDAHO
AVAILABLE:
To Customers in the State of ldaho where Company has natural gas service
available.
PURPOSE:
To adjust gas rates for amounts generated by the sources listed below
MONTHLY RATE:(a) The rates of firm gas Schedules 101 and 111 are to be
decreased by 8€{t2# per therm in all blocks of these rate schedules.(b) The rate of interruptible gas Schedule 131 is to be decreased by
0.0000 per therm.
SOURCES OF MONTHLY RATE:
Changes in the monthly rates above result from amounts which have been
accumulated in the Purchase Gas Adjustment (PGA) Balancing Account as
described in Schedule 150 - Purchase Gas Cost Adjustment.
SPECIAL TERMS AND CONDITIONS:
The above Monthly Rate is subject to the provisions of Tax Adjustment Schedule
1 58.
lssued August 30,2017 Effective November1,2017
Nineteenth Revision Sheet 155
l.P.U.C. No.27
Canceling
hteenth Revision Sheet 155 155
By 7 .Kelly Nonruood, Vice President, State & Federal Regulation
ru/a.r"J
AVISTA CORPORATION
d/b/a Avista Utilities
SCHEDULE 155
GAS RATE ADJUSTMENT - IDAHO
AVAILABLE:
To Customers in the State of ldaho where Company has natural gas service
available.
PURPOSE:
To adjust gas rates for amounts generated by the sources listed below
MONTHLY RATE:(a) The rates of firm gas Schedules 101 and 111 are to be
decreased bV 9.145i, per therm in all blocks of these rate schedules.(b) The rate of interruptible gas Schedule 131 is to be decreased by
0.0000 per therm.(c) The rate of transportation qas Schedule 146 is to be decreased bv 0.265d
Per therm.
SOURCES OF MONTHLY RATE:
Changes in the monthly rates above result from amounts which have been
accumulated in the Purchase Gas Adjustment (PGA) Balancing Account as
described in Schedule 150 - Purchase Gas Cost Adjustment.
SPECIAL TERMS AND CONDITIONS:
The above Monthly Rate is subject to the provisions of Tax Adjustment Schedule
1 58.
lssued August 24,2018 Effective November1,2018
l.P.U.C. No.27
Twentieth Revision Sheet 155
Canceling
Nineteenth Revision Sheet 155 155
by
By Patrick Ehrbar, Director of Regulatory Affairs
EXHIBIT "B"
Notice of Public Applicant's Proposed Tariffs
August 24,2018
AVISTA UTILITIE,S
Case No. AVU-G- 18-0 .l
Important Notice for Idaho Natural Gas Customers
(September/October 2018)
Proposed Natural Gas Rate Adjustment to be Effective Nov. 1, 2018
Avista has filed an annual natural gas rate request with the Idaho Public Utilities Commission
(Commission), with a requested effective date of Nov. 1,2018. This annual filing has no impact on the
company's earnings, and is not related to the proposed acquisition of Avista by Hydro One.
The rate request is the annual Purchased Gas Cost Adjustment (PGA). The PGA is filed each year to
balance the actual cost of wholesale natural gas purchased by Avista to serve customers with the amount
included in rates. This includes the natural gas commodity cost as well as the cost to transport natural gas
on interstate pipelines to Avista's local distribution system. If approved, Avista's request is designed to
decrease natural gas revenues by $0.6 million or 1.0 percent. The primary drivers for the requested rate
reduction include continued low natural gas commodity costs due to the continued high production levels
of natural gas and a reduction in the cost to transport natural gas to Avista's distribution system.
Customer Bills - If approved, residential natural gas customers in Idaho using an average of 63 therms per
month would see their monthly bills decrease from $48.31 to$47.97, a decrease of $0.34 per month, or
approximately 0.7 percent. The proposed natural gas rate change would be effective Nov. 1,2018. The
requested natural gas rate changes by rate schedule are:
General Service - Firm - Schedule l0l - Residential & Small Commercial
Large General Service - Firm - Schedules I I I & I l2 - Commercial
Transportation Service - Schedule l0l
Overall
-0.7%
-1.9Yo
-1.9%
-1.0%
Customer Bills Resulting from all Annual Natural Gas Adjustments - In addition to the filing discussed
above, the Company previously made its annual Fixed Cost Adjustment (FCA) filing on June 29, 2018 with
the same proposed effective date of Nov. 1,2018. If the FCA and PGA filings are approved, residential
natural gas customers in Idaho using an average of 63 therms per month would see their monthly bills
decrease from S48.31 to $45.93, a decrease of $2.38 per month, or approximately 4.9 percent.
The Company's applications are proposals, subject to public review and a Commission decision. Copies of
the applications are available for public review at the offices of both the Commission and Avista, and on
the Commission's website (www.puc.idaho.sov). Customers may file with the Commission written
comments related to the Company's filings. Customers may also subscribe to the Commission's RSS feed
(http://www.puc.idaho.gov/rssfeeds/rss.htrn) to receive periodic updates via e-mail about the case. Copies
of rate filings are also available on our website, www.m.vavista.com/rates.
If you would like to submit comments on the proposed rate change, you can do so by going to the
Commission website or mailing comments to:
Idaho Public Utilities Commission
P.O. Box 83720
Boise, lD 83720-0074
To assist customers in managing their energy use and energy bills, Avista offers services such as energy
efficiency programs and rebates, comfort level billing, payment arrangements and Customer Assistance
Referral and Evaluation Services (CARES). To learn more, visit www.myavista.com.
AVISTA UTILITIES
Case No. AVU-G-I8-0ji
EXHIBIT "C"
Workpapers
August 24,2018
Title Description Page Number
Total Revenue Chanee' !A1 Change in Revenue as a result of filing 2
Rate Schedule 150 Chanse'!A1 Rate Schedule 150 Change 3
Rate Schedule 155 Change !A1 Rate Schedule 155 Chanee 4
lnput!At Commoditv lnDuts 5
CommoditylAl Commodity WACOG Calculation 6
Volumes!A1 Volumes 7
lnput - Demand Contracts'!A1 Demand Calculation 8
lnput - Amortization Balances'!A1 Amortization Input 9
Amortization !A1 Amortization Calculation 10
Conversion Factor'!A1 Revenue Conversion Factor 11
GRI Funding GRI Funding 12
Lost and Unaccounted for Gas Lost and Unaccounted for Gas 13
Tab: lndex Page 1 of 13
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1
2
3
4
5
5
7
8
9
10
11
12
13
t4
15
15
t7
18
19
20
Avista utilities
State of ldaho
Summary of Changes
Rate Schedule 150
GRF:1.005873
(no customers)
(no customers)
(no customers)
(no customers)
Present
Change
Proposed
Schedule 101
schedule 111
Schedule 112
Schedule 131
Schedule 132
Rate Schedule 101
Rate Schedule 111
Rate Schedule 112
Rate Schedule 131
Rate Schedule 132
(no customers)
(no customers)
Rate
Rate
Schedule 101
schedule 111
Schedule 112
Schedule 131
Schedule 132
150
Rate Sch 150 Total
Demand
So.1M97
S0.10497
S0.10497
s0.00000
s0.00000
50.26773
s0.26773
50.26773
5o.16276
5o.t6276
s0.16926
s0.16925
s0.15925
s0.16925
s0.16926
s0.09s84
50.09s84
50.09s84
50.00000
s0.00000
s0.25s10
s0.25s10
50.26s10
S0.15925
s0.16926
50.006s0
50.006s0
s0.005s0
s0.005s0
50.006s0
(So.oo913)
(50.00913)
(So.oos13)
So.ooooo
s0.00000
(So.oo253l
So.oosso
s0.006s0
Rate Sch 150
Commodity
s0.16275
s0.15276
5o.15275
s0.16276
s0.16276
Total schedule
150
s0.25929
s0.25929
50.26929
S0.16371
S0.15371
s0.17025
So.uo2s
So.1702s
s0.1702s
s0.17025
s0.09640
s0.09540
s0.09540
s0.00000
s0.00000
s0.2565s
s0.2555s
s0.2555s
So.17o2s
s0.17025
s0.005s4
s0.005s4
s0.006s4
s0.006s4
s0.005s4
(s0.00e18)
(So.ooe18)
(s0.00918)
s0.00000
So.ooooo
s0.006s4
s0.005s4
Rate Sch 150
Demand
50.10ss8
50.10ss8
s0.10ss8
50.00000
s0.00000
Rate Sch 150
Commodity
50.15371
50.16371
50.16371
s0.15371
S0.16371
Tab: Rate Schedule 150 change Page 3 of 13
Rate chedule 150
Summarv of Chanres Without Revenue Sensitive Costs With Revenue Scnsitive Costs
Avista Utilities
State of ldaho
Summary of Changes
Rate Schedule 155 - Amortization
L
2
3
4
5
5
7
8
9
10
11
t2
13
L4
15
15
t7
18
19
20
20
Total schedule 150
(So.082o2)
(So.082o2)
s0.00000
50.00000
s0.00000
s0.00000
(So.oeoe2)
(S0.08576)
s0.00000
s0.00000
So.ooooo
(so.oo263)
(so.oo8so)
(So.oo474)
So.ooooo
s0.00000
So.ooooo
(So.oo253)
Total schedule 150
(50.08862)
(s0.08862)
s0.00000
s0.00000
s0.00000
So.ooooo
(So.0914s)
(So.0914s)
s0.00000
So.ooooo
So.ooooo
(So.oo25s)
(So,oo283)
(50.00283)
So,ooooo
s0,00000
So.ooooo
(5o,oo26s)
Present
Change
Rate Schedule 101
Rate Schedule 111
Rate Schedule 112
Rate Schedule 131
Rate Schedule 132
Rate Schedule 146
Rate Schedule 101
Rate schedule 111
Rate Schedule 112
Rate Schedule 131
Rate Schedule 132
Rate Schedule 145
(no customers)
(no customers)
Rate Schedule 101
Rate schedule 111
Rate Schedule 112
Rate Schedule 131
Rate Schedule 132
Rate Schedule 145
(no customers)
(no customers)
(no customers)
(no customers)
Proposed
Tab: Rate Schedule 155 Change Page 4 of 13
summeil of Chanees
Without Revenue
Sensitive
wlth Revenue
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Avista utilities
WA Gas Operations
Demand cost calculation (per Therm)
Line No.Description Estimated Exoense Allocator
Allocation
Percentase ldaho Allocation
1
2
3
4
5
5
7
8
9
10
11
L2
13
L4
1.5
16
17
18
19
20
2L
22
23
24
25
Northwest Pipeline Corporation (NwP) S t6,294,068 lD System Allocated
2,614,309 lD System Allocated
ID
30.90%
30.90%
s 5,O34,867
807,821TCPL - Gas Transmission Northwest
Total Fixed Oomestic Transportation Costs
Transcanada - AB (NOVA system)
TransCanada - BC (Foothills Pipe Line Ltd.)
Spectra - Westcoast Energy lnc
Total Fixed Canadlan Transportation Costs
Total Fixed Pipeline Charges
Demand Costs
Demand Volumes
Demand Rate
5 $
L8,9O4377
4,68f,428 lD System Allocated
2,239,692 lDSystemAllocated
983,722 lD System Allocated
$5,U2,688
L,446,56L
692,065
303,970
I 30.90%
3090%
30.90%
s
s s
5 s
s 7,90,U2
26,8Lt,219
s 2,M2,595
8,285,2Uss
s 26,BLt,2L9 s 8,285,2U
86,447,889S o.o9s84
RCF: 1.0058730
Proposed WACOG without Revenue Sensitive Costs 5
sProposed WACOG with Revenue Sensitive Costs
0.09584
0.m640
lnput - Demand Contracts Bof13
Avista Utilities
State of ldaho
Schedule 155 - Temporary Refunds/Charges
Amortization
Acct 191000
Est. Balance
Ar 6/30/18
Line
No.
Current
Deferrals
(Acct 191010)
At 6/30/L8
ldaho
Gas Earnings Test
Deferral*
6/30120L8
(\44,r82.35l.
(18,14s.s1)
(587.44],
0.00
0.00
0.00
(2,3s6,31)
Temporary
Tax Benefits*
6/3O120L8
Total
for Amortization
1 Schedule 101
2 Schedule 111
3 Schedule 112
4 Schedule 121
5 Schedule 122
6 Schedule 132
7 Schedule 146
8 Total
192,503.11
82,s01.33
(120.01)
0.00
0.00
0.00
(s,624,872.97l,
(2,4tO,6s9.84],
(L75,L47.971
0.00
0.00
0.00
0.00
(47s,115.38)
(95,544.75)
(2,9s4.99)
0.00
0.00
0.00
(s,794.LO\
(s,9s1,568.s9)
(2,44L,848.77')
(178,810.3s)
0.00
0.00
0.00
(8,1s0.41)
274,884.43 (8,2LO,68O.721 (65,27L.6L1 (s79,4LO.221 (8,580,478.12)
9
10
Amortization Only
Large Customers
5 (8,40L,667.77l.
$ (178,810.3s)
s (8,s80,478.12)
*the balance remaining in the ldaho Earnings Test Deferral and the Temporary Tax Benefits at L0l3Ll2OlSwill be tranferred
into account 191000.
lnput - Amortization Balances Page: 9 of 13
Avista Utilities
ldaho Gas Operations
Development of Amortization Rate
Rate Schedule: 101-131
Balance June 30, 2018
J u l-18
Aug-18
Sep-18
Oct-18
RCF:1.00587
Line
No.
1
2
3
4
5
6
7
8
9
10
77
72
13
74
15
16
77
18
19
20
18
Sales Therms Amortization
2,257,385
2,250,631 s
2,654,040 s
6,011,179 s
238,774.48
198,898.21
199,184.19
233,847.49
885,275.24
7,271,372.76
7,162,348.23
897,068.24
802,148.96
522,693.72
320,667.93
205,233.97
187,381.50
187,563.99
279,077.39
(6,001)
(s,s40)
(4,67tl,
(3,68s)
(2,830)
12,lzsl
(1,s7s)
(L,224r,
(1,006)
(844)
(688)
(s1e)
lnterest
7.N%
Balance
(7,93s,796)
(7,7O3,s96l
(7,511,035)
(7,318,0271
(7,090,181)
(7,090,181)
(6,21O,4461
(s,003,745)
(3,84s,082)
(2,gs1,8441
(2,1s0,820)
(7,629,7O2\
(1,310,258)
(1,106,030)
(919,493)
(732,617l,
(s14,059)
(6,s14)
(6,337)
5
5
s
)
s
(6,176)
Beginning Balance
Nov-18
Dec-18
Jan-19
Feb-19
Mar-19
Apr-19
May-19
Jun-19
Jul-19
Aug-19
Sep-19
Oct-19
r0,793,407
74,769,229
14,777,522
70,937,789
9,779,979
6,372,752
3,909,631
2,502,243
2,284,583
2,286,&8
2,671,024
s
S
S
)
)
s
S
s
)
)
s
s
s
s
5
s
5
s
S
s
s
S
s
Rate Schedule 101, 111 (no customers 131)
Amortization Rate S (0.08202) (7,090,181)
lnterest Rate S (0.00029) (24,660)
Rate Before RCF S (0.08231)
Tariff Rate S (0.08279)
(7,114,84t1
Summary
Rate Schedule 101
Rate Schedule 111
Rate Schedule 146
Earnings Test/fax Total
(0.08231) s (0.00861) s
(0.08231) s (0.0044s) s- s (0.00263) s
PGA
s
s
s
(0.09092)
(0.08676)
(0.00263)
Tab: Amortization Page: 10 of 13
AVISTA UTILITIES
Revenue Conversion Factor
Idaho - Natural Gas System
TWELVE MONTHS ENDED DECEMBER 31,2016
(Final Settlement - per Stipulation)
Line
No.Description Factor
I Revenues 1.000000
2
J
Expenses:
Uncollectibles 0.003s64
Commission Fees 0.002275
4
5
6
7
8
Idaho State Income Tax
Total Expenses
Net Operating Income Before FIT
Federal Income Tax@35%
REVENUE CONVERSION FACTOR
REVENUE GROSS UP:
(zeroed out
for PGA)0.000000
0.005839
0.994161
0.198699
0.795460
(l/r-.0s839)1.005873
Tab: RCF (Conversion Factor)
Page: 11 of L3
Avista Utilities
state of ldaho
Voluntary GRI Funding
Previous Pipeline Rate (PerTherm)
Current Pipeline Rate (PerTherm)
Reduction in Pipeline Funding Rate (PerTherm)
Monthly Rate (Daily Rate x 365 DayslL2 Months)
NWP Demand Billing Determinants
Estimated Transportation Volumes (Therms)
GRI Funding Shortfall
ldaho Percentage
Total ldaho GRI Funding Shortfall
Northwest PipelineTF-1 TF-1
Reservation Volumetric
Transcanada - GTN Pipeline
TF-1 TF-1
Reservation Volumetric
Total
s0.00086 s0.00088 s0.00086 s0.00088
50.00076 S0.0007s 50.00075 S0,0007s
s0.00010 50.00013 s0.00010 s0.00013
s0.00304 s0.00304
558,085,000 0
00
30.01% 3057% 30.01% 30.57%
s14,000 s3,000 s9,000 s6,000 s32,000
Set the GRI Funding at the 11/1/99 Level.
Tab:GRl Page: 12 of 13
12 IIIONTHS ENDED TOTAL
LOSS & UNACCOUNTEO FOR GAS
BY DELIVERY POINT. THERMS
IDAHO
lD SPO-CDA area
lD LEWIS-CLARK area
Bonners
Genesee
Kellogg
Moscow
Pinehurst-Kingston
Sandpoint
Smelterville-Page
IDAHO TOTAL
't22,057,324 121,755,487
DELIVERY
55,220,996
65,836,328
REVENUE
54,947,548
66,807,938
LOSS +/-
273,48
28,390
o/o OF
PURCHASE
0.50
0.04
301,837 0.25
180
,t47,097,624 146,490,005
2,925,260
272,750
4,7'.|4,250
7,39't,730
861,1 10
8,365,020
5,439,646
254,800
5,055,520
7,3U,622
551,107
5,771,858
(2,514,385)
,17,950
(341,2701
57,108
310,003
2,593,162
(85.95)
6.58
(7.241
0.77
36.00
31.00
35.9115
607,619
Lost and Uaccounted For Gas 13 of 13
0.41
AVISTA UTILITIES
Case No. AVU-G-I8-0+
EXHIBIT "D"
Pipeline Tariffs
August 24,2018
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Gas Transmission Northwest l,[.C
I:ERC Gas'Iariff
Fourth Revised Volume No. l-A
PART 4
S]'A'I'EMENT OF RA'TES
v.2.0.0 Superseding v. 1.0.0
STATEMENT OF RATES
Issued: April I 1.201 I
ljlltctive: April.t. 201 I
[)ocket No. RPI l-1986-000
Acccpted: May -1. 201 I
Attachment D - Pipeline Tariff Sheets Page 2 ot 45
(ias Transmission Northucst LLC
FtiRC Gas'l'arilf
Irourth Rcvised Volume No. l-A
DAILY
MILEACE (aI
(Dth-MILE)
BASE 0.000434 0.000000
STF (e) (e) 0.000000
EXTT.]NSION CHARGES
MEDFORD
E.l (0 0.001759 0.000000
E-2 (h) 0.002972 0.000000
lDiamond I )
E-2 (h) 0.001r66 0.000000
(Diamond 2)
COYOTE SPRINGS
E-3 (i) 0.001282 0.000000
CARTY LATERAL
E4 tP) --
OVERRTJN C'IIARGI: (i)
SURCHARGES
ACA (k)
Issued: rr-ovcmher 27. 201 7
lilfective: Januarv l. 2018
P,\RT 4.I
{.1 - Statenrcnt ol'Rates
l"l'S-1. t.l'S-1. and FHS Rates
v. 1 7.0.0 Superseding v. 1 5.0.0
STATEMEN]' Ot.' EF I. ECI-IVE RA'IES AN D C] HA RGES FOR
TRAn-SPORTATION OF NATLIRAI- C;AS
Rate Schedules FTS-I. t-FS-1. and FHS
For Rate Schedules FTS-I and LFS-l:
RESERVATION
Ma.r. Min. Max. Min.
0.03.13e3 0.000000
DAILY
NON-MILEACE (b)
lDth)
(r.') (),000000
DELIVERY (c)
(Drh-MILE)
Ma,r. Min.
0.0000 t6 0.000016
0.0000t6 0.000016
FUEL (d)
(Drh-MILE)
Max. Min.
0.0050o/o 0.0000%
0.0050% 0.000070
0.0046-lt 0.000000 0.(xxnl6
0.000000
0.(m0016
0.0000(x)
0.(x)(x)00 0.(xxx)00
0.0{)l:8.1 0.(xxxx)0 (}.(ru(xxxr 0.(xx)(xx)
0. 166-t75 0.00()00(l 0.000000 0.00{)000
(k) (k)
Docket No. RP I 8- l 8,1-(XX)
Acceptcd: Decemher 18. 201 7
Attachment D - Pipeline Tariff Sheets Page 3 of 45
(ias'l'ransnrission North\\est l.l,C
I-'t-:RC' Gas'l'aritf
Fourth Rcvised Volume n\o. l-A
Pn R'r +.1
-[. ] - Statenrent of Rates
FTS-1. LFS-1. and F['lS Rates
v. 1 7.0.0 Superseding v. 1 5.0.0
For Rate Sclredule FHS:
The Mainline and Extension Rcscrvation rates shorvn above for Rate Schedules F''l'S-l and
l.tS-l shall also be applicable to service under Rate Schedule FllS. except that the Mileage and
Non-Mileage Conrponents shall he adjusted to reflect tlre expeditetl hours of gas tlow ("HF)
utilizing the follou'ing fbrmulas. rounded to 6 decimal places:
(a) Mileage Reservation Component : t'-I'S-l M x Milcs x (l.l/l IF)
(h) Non-Mileage Rcservation Component = F'IS-lNM x (24l[-tF)
whcre:
FT'S-IM =
I.'TS.INMMilcs =
Applicable t;'l'S- I Mileage Rescnation Charge
Applicable FTS-l Non-Mileage Reservation Charge
Distance. in pipeline rniles. f'rom the l)rimur.v Point(s)
of Receipt to the Primar] Point(s) of Dclircrl' as sct
lbrth in Shippcr' s Contrd
MDQ/MilQl-t t-'
lssued: Novemher ?7. 2017
Etlectivc: January l. 3018
l)ocket No. R l' I tl- I 8-l-0(X)
Acccptcd: De'ccmbc'r 18. 201 7
Attachment D - Pipeline Tariff Sheets Page 4 of 45
Cias Transmissiott Northwest l.l.C
IrERC Gas'faritT
l"ourth Reviscd Volume No. l-A
PART.I.2
-1.2 - Statement ol Ratcs
l'l'S-l and IHS Rates
v.8.0.0 Superseding r'.6.0.0
STATEMEN OF EFFECTIVE RATES AND CHARGES T.'OR
TRANSPORI'A'rION OF NATURAL GAS (a)
Rate Schedule l'IS- |
BASTJ
MILEAGE (n)
(Dth-Mile)
Mar. Min.
(e) 0.000000
NON-MILEAGE (o) DEI-IVERY (c)(Dth) (Dth-Mile)
Mar. Min. Max. Min.
(e) 0.000000 0.000016 0.000016
F'UEL (d)
(Dth-Mile)
Max. Min.
0.0050% 0.0000%
EXTENSION CHARGES
MEDFORD
E-l (Medford) tl)
0.0027-59 0.000000
COYOTE SPRINGS
E-3 (Co1'otc Springs) (i)
0.001282 0.000000
CARTY LATERAL
E-.1 (Carty Lateral) (p)
SURCHARGES
ACA (K)
0.0046.1r
0.001283
0. r 66475
(k)
0.000000
0.000000
0.000000
(k)
0.000026
0.000000
0.000000
0.000026
0.000000
0.000000
Issued: November 27. 2017
l:ll'ectil'e: Januarl, l. 2018
Docket No. I{P l8- 184-000
Acceptcd: Decembcr 18. 201 7
Atlachment D - Pipeline Tariff Sheets Page 5 of 45
(ias'lransnrission Northwest l.l.('
I-'ERC Gas Taril'l'
Fourth Rcvised Volume No. l-A
PARl'1,2
-1.3 - Statenrcrrt ol'Ratcs
ITS-l and IllS Rates
v.8.0.0 Superseding v.6.0.0
Ratc' Schedule Il IS
BASI]
MILEACE (n)
tDth-Mile)
Mru, Min.
(e) 0.000000
NON-MILEAGE (o)
(Drh)
Ma.r. Min.
(e) 0.000000
DELIVERY (c)
(Dlh-tvlile)
lvlax, Min.
0.000016 0.00001fi
FUEL (d)
(Drh-Mile)
IvJax. Min.
0.0050% 0.0000%
EXI'ENSION CHARCES
MEDFORD
E-l (Medford) (f)
0.0066:3 0.0000{)0
COYOTE SPRINCS
E-3 (Cryote Springs)(i)
0.003077 0.000000
CARI'Y LA'TERAL
E-+ (Cart) l"ateral) (p)
0.01 I r38
0.003079
0.(xx)(xx)
0.000000
0.000016 0.000026
0.000000 0.000000
0.199-i.10 0.0000(m 0.0(xxxxt 0.(xxxx)0
SURCHARGES
ACA (K)(k) (k)
Issued: November 27.2017
Eflective: January l. 2018
I)ocket No. RPI 8- I 8-l-000
;\ccepted: Deccmber 2tt- l0l 7
Attachment D - Pipeline Tariff Sheets Page 6 of 45
Cas I'ransmission Northwest LLC
I"llRC Gas Tariff
Fourth Revised Volume No. l-A
lssuecl: November 27. 20 l7
Etlectivc: January l. 20ltt
PART 4.3
,4.3 - Statement of Rates
Footnotes to Statement of Effective Rates and Charges
v. I 5.0.0 Superseding v. I 3.0.0
Dockct No. RI'18- 184-000
Accepted: Deccnrber 28. 3017
STATEMEN OF Et.'FEC]TIVE RATES AND CHARGES
I.'OR'I'RANSPORTATION OF NATIJRAI, GAS
Notes:
(a) The mileage component shall be applied per pipeline milc to gas trat'rsported by C'lN for
delivery to shipper based on the primary receipt and delivery points in Shippe/s contract.
Consult GTN's system map in Section 3 for rcceipt and delivery point and milepost
designations.
(b) The non-mileage component is applied per Shippe/s MDQ at Primary Point(s) of Delivery
on Mainline Facilities.
(c) '[he delivery rates are applied per pipeline mile kr gas transported by CTN ltrr delivery to
shipper based on distance of gas transported. Consult GTN's system map in Section 3 lbr
receipt and delivery point and milepost designations.
(d) Fuel Use: Shipper shall tirrnish gas used ftrr conrpressor station tuel. line loss. and other
utilit.v* purposes. plus other unaccounted-for gas used in the oJxration rlf G'fN's cornbined
pipeline sy'stem in an amount equal to the sum of the currenl lucl and line loss percentage
and the fuel and line loss percentage surcharge in accordance with Section 6.38 ol'this
tarilT. multiplied b-"- the distance in pipeline miles transported from the receipt point to the
delivery fnint multiplied by the transportation quantities of gas received lrom Shipper
under these rate schedules, The current fuel and line loss percentage shall be ad.iusted each
month between the maximum rate of 0.0050% per Dth per pipeline nrile and the minimum
rate of 0.0000% per Dth per mile. Thc tucl and line loss percentrge surcharge is 0.0002%
per Dth per pipeline mile. No tuel use charges rvill be assessed t'or backhaul service.
Currently eft'ective luel charges may be lbund on C'l-N's lnternet website under
"lnlbrmational Postings. "
(e) Seasonal recourse rates apply to short-term tirrn (STF) servicc under Ratc Schedules FTS-l
and FllS (i.e.. tirm service that has a term of less than one year and that docs not include
multiple-year seasonal service) and l'[ Service under Rate Schedulcs l1'S-l and IHS. By
March I of each year GTN may designate up to fcrur (4) months as peak months during a
twelve-month period beginning on June I of the sarne year through May 3l of the followin,q
year. All other months rvill be considercd 6f1'-peak months. Reservation rate conrponents
that apply to S'IF service and pcr-unit-rate ITS-l and IHS servicc are as fbllows (delivcry
charges and applicablc surcharges continue to appl.v):
Attachment D - Pipeline Tariff Sheets Page 7 of 45
(ias Transmission Northrvcst l.l.('
FERC Cas Tariff
Irourth Revised Volunre No. l-A
l"or S'l'F and ITS- I :
PAR'l'4.-3
{.-l - Statcnrcnt of Rates
l"ootnotes to Staternent of Eftectivc Rates and ('hargcs
v.15.0.0 Superseding v. | -3.0.0
For ll-lS:
Peak NM Res
Peak Mi. Res.
Oll-Pk NM Res.
OtT-Pk Mi. Rcs.
4 Peak
Mos.
$0.0481s0
$0.000608
s0.0275 r5
$0.000347
3 Peak
Mos.
s0.0481 50
s0.000608
$0.029807
$0.000376
3 Peak
Mos.
s0.0.r8 t 50
s0.000608
s0.03 r64l
$0.00039e
2 Pcak
Mtls.
$0. r r 5s60
$0.001.t5e
s0.0759+ I
$0.000958
I Pcak
Mo.
$0.048 r50
$0.000608
$0.0_13 t4l
$0.0(x)^l I 8
I Peak
Mo.
s0.l r5560
$0.001459
s0.07e5-t r
$0.00 r003
0 Peak
Mos.
$0.034393
$0.000,134
$0.0343e3
$0.000134
0 Peak
Mos.
$0.082s1i
$0.00 r0{2
s0.0815+3
s0.0010.r2
Peak NM Res.
Peak Mi. Res.
OfI'-Pk Nlll Res.
0t1'-Pk Mi. Rcs.
-l Pcak
Mos.
$0. I I 5560
$0.00145e
$0.0660i6
$0.000833
3 Peak
Mos.
$0.1 15560
$0.00145e
s0.071 -53 7
$0.000902
Months currently'designated as "Peak Months" ma1, he tound on G'lN's lnternet r"ehsitc
under "lnformational Postings." B;* March I of each.v-ear. GTN willpost the Peak Months
tbr the upcclrning trvelve-month period beginning.lune I of the sanre vear.
(l) Applicable to finn service on CiTN's Medtbrd Extension.
Reserved tbr Futurc Use.(s)
(h)E-2 (t)iamond I ) is a negotiated rescrvation charge of $0.002972 per Dth pcr du1 lirr first
45.000 Dth/d and [:-2 (Diamoncl 2) is a negotiated rcsenation charge of $0.001 166 per Dth
per day for the second -15.000 Dth/d. During leap,"-ears. E-2 (Diamond l) is a negotiated
reservation charge of $0.002964 per Dth per day ttrr first 4-5.()00 Dth/d and F.-2
(Diamond 2) is a negotiated reservation charge of $0.001 163 per Dth per day' lor the second
.$5.000 Dth/d.
(i) Applicahlc to Ilrm service on C}JN's Coyotc Spr:irrgs l:xtension
0l The Overrun Charge shall he equal to the ratcs and charges set forth tbr interruptible service
under Rate Schedule IT'S- 1 .
(k) ln accordance u'ith Section 6.22 of thc Transportation General 'ferms and Conditions of this
FERC Gas Taritt. Fou(h Revised Volunre Ntr. l-A. all Transportation services that involvc
the phy'sical movement of gas shall pa1' an ACA unit adjustnrcnt. The currently el}'ective
ACA unit adjustrncnt as publishcd on thc C'ornrnission's rvcbsitc (*-u'rv.fbrc.gov) is
lssued: November 27. 2017
Etlectivc: January l. 2018
Dockct No. RPI tt- I 8-l-000
Accc'pted: Decembc'r 18. 2017
Attachment D - Pipeline Tariff Sheets Page 8 of 45
Gas'['ransnrission Northn'cst l-1,('
IrI:RC Gas'l'arit]'
l"'ourth Reviscd Volume No. l-r\
lssued: Novctnber 27. 2017
Etl'ectil'e: Januarl' l. 20 l8
PnRT 1._i
4.-1 - Statemcnt ol'Ratcs
I"ootnotes to Statcmcnt ol'Hflective Rates and Chargcs
v. I 5.0.0 Superseding v. I 3.0.0
Docket No. RP l8- 184-000
Acccptcd: Dcccmber 18. 2017
incorporated herein by reterence. This adjustment shall bc' in addition to the Base Tarifl'
Rate(s) specified above.
(l) Reserved for Future Use.
(m) Reserved.
(n) '[he Rate Schedule I1'S-l Mileage Component shall be applicd per pipeline mile to gas
transported by GTN hascd on the distance of -qas transportcd. Consult CTN's system map
in Section 3 lor receipt and delil'ery point and rnilcpost dcsignations.
(o) 'l'he Rate Schr.'dule ITS-I Non-Mileage Ciomponcnt shall be applicd pcr Dth of gas
transportcd try C'tN for irnrnediate dclivcry to thc facilities of another c'ntit-v or an extcnsion
tacilit;".
(p) Applicahlc to lirm sc'n'icc: on CTN's Carty Lateral Extcnsiort.
Attachment D - Pipeline Tariff Sheets Page 9 of 45
(ias'['ransmission Northrvcst l.l.('
FERC Gas'l'aritT
Fourth Revised Volume'No. l-A
PAR'r 4.1
-1.-l - Statcment of Ratc's
Reserved For Future LIse
v.3.0.0 Superseding v.2.0.0
RESERVIID IrOR IrLJl-URE tJSE
lssued: May 26. 201 I
Etlbctive: June 27. 201 I
Dockct No. RPI l-21 32-000
Accc'pted: Junc 10. l0l I
Attachment D - Pipeline Tariff Sheets Page 10 of45
Gas J'ransnrission Northwesl l,l,C
IrERC Gas TarilT
Irourth Revised Volumc No. l-A
Issued: November 20. 2015
Etlectivc: Januar-r- l. 20 l6
PART 4.5
4.5 - Staterncnt of Ratcs
Parking and [.,ending Service
v.6.0.0 Superseding v.5.0.0
STAT'EMENT OF EFFECTIVE RATES AND CHARGF,S
FOR'TRANSPORTATION OF NATURAL CN S I.OR
Parking and l.ending Service
(S/Dth)
IlAStl'l'n RlFl' RATE
MINIMT-]M MAXII\,ILIN,I
0.0PAL I'arking and Lending Service;
Notes:
0.2.t354 r/d
Docket No. RP I 6-209-000
Acccpted: December 22. l0l 5
Attachment D - Pipeline Tariff Sheets Page 11 of45
(]as'l'ransm ission Northlvest l.[,C'
IrtrRC Cas'l'aritT
l'ourth Revised Volunrc No. l-A
PAR'T.I.6
-1.5 - Staterrrent of Rates
Negotiated Rate Agreernents - l"l'S-l and l,l"S-l
v.5.0.0 Supc'rseding v..1.0.0
STATEMENT OF EF'FEC]'IVE RATES AND CHARGES
FOR TRANSPORTA'I'ION OF' NA'TURAL GAS
NEGO'I'IA'TED RA'TE AGREEMI]NTS UNDER RATE SCI-IEDULES FTS-I AND LFS.I
TERM OF
CONTRACT
il/t/01 -
to/3U25
04101/16 -
r0/3 r/r6
RATE
SCHEDULE
rTS- I
PRIMARY
RIICEIPT
POrN-[
PRIIVIARY
DEI-IVIIRY
POIN-I'SHIPPER
Avista
(lorporation /l
Powerex Corp./l
RATII
!2 !3DTH/t)
l0.ffxf
Issued: March 29- 20l8
F.li'ectivc: April l. l0l8
Mercuria Commodities 04/0 l/l 8
Canada Corporatit-rn / I 0i/i li31
FTS- I 20.000 Kingsgatc lVlalin
l1-S-l 60.000 Kingsgatc Mnlin
Mc'dfirrd lvledf'ord Ext. /l
NIctc.r
/5
/4
I)ocket No. RP l8-642-000
Accepted: April ll. l0l 8
Attachment D - Pipeline Tariff Sheets Page 12 oI 45
Gas Transmission Norlhn'est l.[,C'
FERCI Gas'I'aritT
Fourth Revised Volume No. l-A
Ellectivc Period
I l/t/0t-l0i3r/02
t I t1 102-t 0/-3 I /03
il/t/03-l(v_11/0+
Issued: March 29. 2018
Efl'cctivc: April l. l(ll8
PAR'l'.1.7
4.7 - Statement ol'Rates
Footnotes tbr Nc'gotiated Rates - I.TS-l and LFS-l
v.7.0.0 Supcrscding v.6.0.0
STATEMENT OF EFFI]CTIVE RATES AND C}IARCES
FOR TRANSPORTATION OF NATURAL GAS
Negotiated Rate Agreements IJnder Rate Schedules F1'S-l and LFS- |
l:xplanatory Footnotcs tbr Negotiated Ratcs
under Rate Schedules FTS- | and l.l;S- l
il 'Ihis contract dms not deviale in any' material aspect from thc Form of Service Agreement
in this ]'arifl'.
12 lJnless otherwise noted. all Shippcrs pay (i'fN's maximum Reservation C'harge" Delivery
Ciharge. A('A. and contribute tirel in-kind in accordance rvith this Tariff.
13 lndex Price Referenccs: lJnlcss rltherwise noted. references to "Dail-v lndcx Price" shall
mean the price sun'e1' nridpoint for thc sp*citied p()int as published in Grs Dailv tirr thc
da1,of gas t1on. Weekend and holiday'prices rr'ill bc'du'tr'nnincd using thc next availablc'
Cas Dail,v- publication. lJrrless othenvise noted. the relbrences to the "N(il FOM" lirr a
specitied point shall mcan Natural (ias lntelligcnce's First of iVtonth Bid Wcck Sun'e1'
lSupplement to NGI's Weekll'Gas Indcx) Spot Gas Price for the specitied point.
l1 G1N and Shipper have agrc"cd to a ti:icd reservatiorr resen'atitln chargc of S.27 alon-u with
applicablc surcharges lirr all quantities on the Kingsgate to lVtalin path.
/5 GTN and Shipper have agreed to a Fiscd Rescn'ation Rate ('hargc'of $0.26300 inchrsive of
the mileagc and non-rnileage components. whiclr shall bc applicahle to the l)rimarl' Rcccipt
and Delivery Points as rvell as secondarv points. as ltrllorvs:
Sccondary Rcccipt Points: All points on CTN's systcm
Secondary Delivery Points: All points on GTN's systcrn
ln addition. Shippcr shall pay all applicable charscs and surcharges in accordance rvith
GTN's FERC Gas Tariff.
16 Reserved
17 The Reservation charge shall be equal to the rate set forth in CTN's FIIRC Cas l'aritT
identified as FTS-l E-2 (WWP). or its successor. nrultiplied by the appropriate tjtlbctive
Period Perccnta,qc as shorvn in thc f'ollowing tablc'.
Percentagc
75o/o
80o/"
8-5%
Drrcket No. RI' I 8-641-000
Accepted: April ll. l0l 8
Attachment D - Pipeline Tariff Sheets Page '13 of 45
Cas'l'ransmission North$cst LLC'
I"llRC (ius'l'arilT
Fourth Revised Volume No. l-A
tUU04-t0/31/05
IvU05-10/3U06
1t/U06-t0t3v25
Issucd: March 29. 201 8
[:llective: April l. ]018
PART.I.7
4.7 - Statcmcnt o[ Ratcs
Footnoles lbr Negotiated Rates - ljl'S- | and l.F'S- |
v.7.0.0 Superseding v.6.0.0
9lYo
950h
1000h
'I'he Dail"r- Deliver,v Charge shall bc cqual to the 100% load factor equivalent of the F'l'S-l
E-2 rate. or its successor. and shall be multiplied b.v.. the positive difference betrveen (a)
volumes delivered and (b) the contmct MDQ times the appropriate Elfective Period
Percentage.
Dail.," Dclivcry Chargc: [tlth Delivered - (MDQ * Ellectivc Period %)'l * 100% Load
l'actor l:quivalcnt FTS-l U-2
18 Resen'ed
/9 Reserved
ll0 Resen'ed
ll I Rcsen r".d
ll2 Reserved
/13 Resen'ed
/14 Reserved
ll5 Reserved
ll6 Reservcd
l17 Reserved
/18 Reserved
Docket No. RP I 8-6.11-000
Acccpted: April 13. 201 8
Attachment D - Pipeline Tariff Sheets Page 14 ot 45
Cias l'ransrnission Nomh\.\'est LLC
IjtiRC Cas l'aritl'
Foufth Revised Volurne No. l-A
PAI{1'4.8
-1.8 - Statenrcnt tll'Ratcs
Negotiatcd Ratc'Agreernents - l'l'S-l and PAL
v.5.0.0 Superseding v.-1.0.0
SI'ATEMENl' OI.' EFI.ECTIVE RA ES AND CI IARGES
FOR TRANSPORTA'TION Ot.' NA'I'URAL GAS
NEGOTIATED RATE ACREEMENTS UNDER RATE SCHEDULE II'S.I AND PAI,
SHII'I'IJIT
Issued: April 24. 201 5
Etl'cctivc: June l. l0l-5
TERM OF
CJ)NTRACT
RATE
SCI-IEDIJI,II, DTIJ/I)
PRltvlARY
RECEIPT
POIN'T
PRIMARY
DEI-IVERY
POINT
RATE
t2 t3
Dockct No. RP l 5-905-000
Accepted: N'la1' 19. 20l-i
Attachment D - Pipeline Tariff Sheets Page 15 of45
(ias'l'ransmission Northlvcst [-l.C'
FtiRC' ( ias 'farifl'
Fourth Revised Volume No. l-A
PARI'-1.9
.1.9 - Statr.ment of Ratcs
l"ootnotes ttrr Negotiated Ratcs - l'fs-l and PAL
v.5.0.0 Supersc'ding v.4.0.0
S]'NTEMENT OF EFITE(']'IVt' RATI:S AND C]TIARGES
FOR TRANSPORTA'I'ION O}.' NATL'RAL GAS
NEGOTIATED RATE ACREEMENTS UNDER RATE SCHI:DTJI,E ITS-I AND PAT,
Explanatory l'ootnotes tbr Negotiated Rates under Rate Schedule ITS-l and PAL
ll 'l'his contract does not deviate in any material aspect frorn thc Fomr ol Service Agreement
in this Tarill.
/2 Unless other*'isc noted. all Shippers pay CTN's rna.ximurn Milea_ee and Non-Milea_uc
Charge. ACA, and contribute tLel in-kind in accordance rvith this'tarifl.
/3 Index Price Rel'crenccs: Unless othc'rwisc notcd. retbrences to "Daily lndex Price" shall
nrean the price suncr midpoint tirrthe specilied point as publishcd in Gas t)ui11- forthe da_l'
of gas flou. Weekend and holidal priccs rvill he detennined using thc'ncxt available Cas
Daily publication. lJnless otherw'ise noted. the ret'erenccs to the "NGl ['OM" ttrr a specitied
point shall mean Nalural Gas lntelligcnce's First of lvlonth llid Week Survel' lSupplement
to NGI's Weekll'(ias lndcx)Spxrt Gas Price tbr the spccified point.
lssued: April24.20l5
[',ffective: June l. 2015
Docket No. Rl') I 5-905-000
Accepted: Ma1' 29. 2015
Page 16 of45Attachment D - Pipeline Tariff Sheets
(ias Transmission Nonhwest LLC
I'ERC Gas Tariff
Fourth Revised Volume No. l-A
PAR'r 4.10
4.t0 - Statement of Ratcs
Non-Contbrming Service Agreements
v.4.0.0 Superseding v.3.0.0
NON-CONFORM ING SERVICE AGREEM ENTS
PURSUAN'r TO $ ls4.l l?(b)
Nanr." of Slrinner
Contracl Itate
Schedrrle
Effective
Date
Terrnination
I)nteNurn
Cascade Natural Gas Corporation
Chevron USA Inc.
Cit-v of Burbank
ICI Resources. lnc.
Northem Calitbrnia Power AgencY
Talisman Enerry lnc
Paramount Resources US lnc.
Petro-Canada l{ydrocarbons. lnc.
Sacramento Municipal Utility District
Avista Corporation
Avista Corporation
Cascade Natural Gas Corporation
Northwest Natural Cas CompanY
Puget Sound Enery;v. Inc.
Avista Corporation
Avista Corporation
Avista Corporation
Avista Corporation
lberdrola Renewables. Inc.
Avista Corporation
Pacitic Gas and Electric ComPan-v
Northwest Natural Cas ComPanY
Petro-Canada H-vdrocarbons. Inc.
Morgan Stanley Capital CrouP Inc.
Shell Energv North America (US). L.P
BP Canada Energv Marketing CorP.
Sempra Energr'l'rading CorP.
EnCana Marketing (USA) lnc.
Nexen Marketing U.S.A.. lnc.
Shell Energy North America (US). L.P
Sierra Pacific Power Company
Ciq'ofClendale
Iberdrola Renervables. Inc.
Petro-Canada Hydrocarbons. lnc.
Chevron I.J.S.A. Inc.
Salmon Resources Ltd.
Constellation Energv C'ommodities
Group. lnc.
Enscrco Energ-v- lnc.
ConocoPhi I I i ps Compan-""
UBS AC (London Branch)
l_sl
153
154
158
r63
167
r68
169
t70
t77
t78
l7e
t80
t8r
t82
25el
2857
1858
7E28
8035
ut
il3
l19
t44
r46
462 I
172t
4770
675e
7047
7068
7804
7806
7807
78 r2
78 t6
FTS.I
t-'TS-t
FTS.I
FTS-I
F'TS-I
FTS-I
FTS-I
F'TS-I
l'TS-r
FTS-I
FTS-I
I.'TS.I
FTS.I
F'TS-I
FTS.I
FTS.I
t-'TS-t
I.TS.I
FTS- I
FTS- I
ITS.I
ITS-I
ITS-I
ITS.I
ITS-I
Als-l
AIS-I
AIS.I
AIS-I
AIS-I
AIS.I
AIS-I
AIS.I
n ls-l
AIS.I
AIS-I
I l/l/t993
r t/t/1993
I t/t/1e93
r l/l/lee3
I t/l/1e93
M/1993
I l/r/r9e3
I l/t/te93
I l/t/t993
I t/t/te93
I t/t/1993
I l/l/1993
r l/l/1s93
I t/l/lee3
r l/t/te93
8/lilses
I l/t/1e95
I t/t/1995
6/312001
il/t/200r
2lt/tee?
1/vtsez
1/22il9e2
7t23/1e93
8/l /l ee3
12il/1996
lll/1e97
ll25/1e97
6l17ll9e9
41t012000
4t27/200()
5/30/200 I
5/30n001
5i30l200 I
-i/_10/2001
5/30/200 I
l0/3 l/2023
t013v2023
1013il2023
r0/3 t/2013
I 0/3 I /2023
t0/3U2023
10t3112023
I 0/3 r/1013
l0/3 t/3023
l0/3 r/2013
l0/3 r/2023
t0/3 Ii20l3
I 0/3 l/2023
I 0/3 I /2023
r 0/3 I /2023
r 0/3 I /2025
t0/3 t/10:5
t0i3 t/2025
t0/3v2025
t0/3 t/1025
t0/31/10t0
3/3t/201 I
4t22t20lt
9/30/20 t 0
8/ t/20 t0
r2l3i/20r0
I 2/3 r /20 l0
t2l31/20t0
t2l3 t/2010
t2t3v20to
ta4D0t9
t2l31t2fi2.t
t2/3v202t
I 2/3 I /103 r
t213v20?l
t7t3lt202t
8/2/100 I
nl27t200l
ti8il002
.t/l t/2002
8/3 l/201 I
I V3(y2031
v3v2022
"t/30/:033
Issncd: September 25. 2015
lillective: October 36. 2015
Docket No. RPI 5-1294-000
Accepted: October 23. 201 5
Attachment D - Pipeline Tariff Sheets
AIS-I
AIS-I
AIS-I
AIS-I
Page'17 oI 45
8038
8176
8l:ti
8_11 8
Cas Transmission Northwest LI-C
IERC Cas'l'aritT
Fourth Revised Volume No. l-A
lssued: September 25. 2015
Etlcctive: October 25. 2015
l,AR'r 4.10
4.10 - Statement of Rates
Non-Con tbrm ing Service Agreements
v.4.0.0 Supcrseding v.3.0.0
Concord Energy LLC
Tenaska Marketing Ventures
Cargill.lnc.
Menill Lynch Commodities. lnc.
Apache Corporation
Tenaska Marketing Ventures
Califomia Dept. of Water Resottrces
LJnited Energ;v Trading, LLC
Select Natural Cas LLC
National Fuel Marketing C'ornpany LLC
Fortis Enerry Marketing & Trading CP
Powerex Corp.
Louis Dreytus Energr Services l..P'
Pacific Summit Energy LLC
Devlar Energv Marketingl LLC
Suncor Energy Marketing Inc.
CanNat Energr lnc.
Eagle Energ,l Partners I. LP
Sequent Enerp' Management LP
Occidental Energr Marketing. lnc.
NextEra Energv Porver Marketing. t.LC
Natural Cas Exchange. lnc.
Citigroup Energry Inc.
ICI Resources. lnc.
Macquarie Cook Energtr. LLC
Sempra Energr Trading CorP.
EnCana Marketing (IJSA) Inc,
Shell Energy North America (US). L.P.
l{usky Cas Markcting lnc.
Enserco Energ,' lnc.
National Fuel Marketing Company LLC
United States Cypsum Company
Northrvest Natural Gas Company
Chevron U.S.A. lnc.
San Diego Cas & Electric ComPanY
Southem Califomia Gas CompanY
Puget Sotmd Enerjy, lnc.
Hermiston Generating Company- L.P.
Citv of Glendale
Iberdrola Renewables. lnc.
Questar Energy Trading ComPanY
El Paso Energy Marketing CompanY
Sempra Energy Trading Corp.
Constellation Energy Cornmodities
Group.lnc.
ConocoPhill ips Company'l'ractebel Energy Marketing. lnc.
UBS AG (L,ondon Brartch)
842 I
8559
859.1
8674
8670
8880
8887
9002
8978
9035
9t t5
9t.t9
e28 I
9285
9630
9774
t0 t97
I 0308
r 0336
r 0359
t0615
I 0639
10646
{576
{619
4720
486lt
4908
5348
5677
5679
5837
5992
6726
6378
6613
706 I
7798
7803
7805
78 t9
7820
7833
AIS.I
AIS.I
AIS-I
AIS-I
Als-l
Ats-t
AIS.I
AIS.I
AIS-I
AIS-I
AIS.I
AIS-I
AIS.I
AIS.I
Als-l
AIS-I
AIS.I
AIS.I
AIS-I
AIS-I
AIS-I
Als-l
AIS.I
PS-I
PS.I
PS.I
PS-I
PS.I
PS-I
PS.I
PS-I
PS-l
PS.I
PS-I
PS.I
PS.I
PS.I
PS.I
PS-l
PS-I
PS.I
PS-l
PS.I
PS- I
PS-I
PS.I
PS-I
7n2t2002
l/l/2003
3/l 9/2003
61t312003
7/v2003
t2/U2003
I 2/t /2003
3^t2004
313t2001
4127120A4
7/t7t2004
8/r6/3004
r l/8/2004
r t/t5/2004
6/l/2005
r0/ttr005
7t2612006
t027/2Ut6
It/V2006
t2t22n0a6
d/t 0/2008
4t29/2008
5/30/2008
t2il/t996
t2ll/t9e6
Uv1997
3/t/1997
315/tee7
7 t311997
lot6/t997
lo/7il997
n/3lt9e7
2/t i/r 998
5/r4/r998
8n5/t9e8
t2n4l1998
1n0no00
5/30/200 r
5R0ll00r
5/30/?00 I
-s/30/2001
_5/30/100t
6n1n0a1
7/3v2012
l2t3t/20t2
3/3r/20t3
6il3/2023
6/30/20 I 3
I t/30/20t3
7ilt201t
2/28/201"t
3t3/2014
4t30/2011
6/30/20 I 4
7t3v2011
l0/3r/20r4
r 0/3 t/20 r 0
5/31/201-i
9/30/20 I 5
7t?5/2011
r 0/3 l/:0 I I
r 0/3 r/:0 t0
r2l3 r/:01 0
4/30/3018
4/30i20 I 8
5/3 l/20 I 8
r2llr/:0r0
l2l3t/2010
l2l3 l/t0 I 0
lll3t/2010
l2lir/1010
l2l3t/3010
n/3r/20t0
r 2/3 t/20 I 0
5/r 7/30 r 0
t!3v2a23
r2l31/20r0
ta3l/2010
t2/3v20t0
.1t20t2020
ty3U202t
t2/3v2021
I 2/3 I /203 I
t2/31!2021
t2t3v202l
618t2020
8/2/200 I
r/8/1002
31t412002
4/t l/200:
8/3 l/102 I
I 13 t/t032
l/3 t/2022
r/30/2033
Docket No. RPI 5-1294-000
Acceptcd: Octoher 2-1. 2015
Attachment D - Pipeline Tariff Sheets
8037
8229
8283
tt3t6
Page 1B of45
Gas Transmission Northwest I.l,C
FERC Gas Tariff
Fourth Revised Volume No. l-A
lssued: September 25. 2015
El'tective: October 26. 2015
PART 4.IO
4.10 - Statement of Rates
Non-Conforming Service Agreernents
v.4.0.0 Superseding v.3.0.0
RWE 'l"rading Americas Inc.
Fo(is Energv Marketing & Trading GP
Concord Energy LLC
Select Natural Gas LLC
Tenaska Marketing Ventures
Cargill.lnc.
United Enerry Trading- LLC
Apache Corporation
Occidental Energv Marketing. lnc.
Tenaska Marketing Ventures
California Dept. of Water Resources
Devon Canada Marketin-e Corporation
Merrill Lynch Commodities. lnc.
Pacific Summit Encrgr LI-C
Louis Dreyfus Energy Canada LP
Louis Dreyt'us Energy Services L.P.
Devlar Energv Marketing LLC
Suncor Energv Marketing lnc.
J.P. Morgan Ventures Energg' C'orporalion
CanNat Energv" lnc.
Eagle Energ, Partners l. [.P
Sequent Energy Management LP
El Paso Ruby Holding Company. l,LC
Portland General Electric Compan.v
8324
8340
8406
8534
8539
8595
8652
8668
8784
8873
8886
8923
90 t8
et73
9263
9273
e584
e772
99.t8
t0195
r03 r0
r 0332
t207t
I 7l9i
PS-I
PS-I
PS.I
PS.I
PS.I
PS.I
PS.I
PS-l
PS. I
PS.I
PS.I
PS-I
PS.I
PS.I
PS-I
PS.I
PS-I
PS.I
PS-I
PS-I
PS.I
PS.I
F']"S- I
t Ts-l
411612002
5nnooz
7t22t2002
I t/15/2002
t2/v2002
3/t 9/2003
_5/23/2003
7/112003
9/ I 0/2003
t2/v2003
tytn(n3
2n/2001
$7n004
8/30/2004
t0129t2004
n/4t2001
5/}2005
I 0/t/3005
?n/20a6
7t26/2006
t0/2'7t2006
lvtno06
nlt/2012
l0/31/10r5
413012022
513v2022
713U20t2
t0/3v20t2
I t/30/20t3
3t3t/2013
5t3t/2013
6/30/20 r 3
8/3 U20 rl
il /30/20 t 3
7lv20t1
t/31i2014
11712014
8/30/30t0
l0/3r/20t0
r0/3r/?0r4
4/30/:0 r-i
e/i0/:0 I 5
l13v20t6
1125!2An
I 0/_1 t/10 I I
l0/3t/20t I
3/3 r/20 I 8
I 0/3 l/:0.t-i
Docket No. RPI 5-l 294-000
Accepted: Octotrer 23. 2015
Page 19 of45Attachment D - Pipeline Tariff Sheets
Cas'l'ransmission Northwest [.[-C'
IrER(' Gas'l-aritT
F'ourth Revised Volumc No. l-A
Issued: April 2.t.2015
l:tfectivc: Junr' l. ]015
PART'-i
RATE SCI Itll)I.lt-t:S
v.i.0.0 Superscding v.2.0.0
RATE SCHEDULES
Firm Transportation Servicc ltrT'S- I )
Limited Firm Transportation Service (LFS-l)
I nterrupti ble Transportation Serv ice ( I'l'S- I )
Unbundled Sales Sen'ice (LJSS-l)
Parking and [,ending Service (PAl-)
Docket No. RP l5-90-5-000
Acceptc'd: May 39. 2015
Attachment D - Pipeline Tariff Sheets Page 20 of 45
STATEMENT OE RATES
Effective Rates Applicable to
Rate Schedules TF-1, TF-2, T1-1, TFL-1 and TIL-1
(Dol-l-ars per Dth)
Rate Schedule and
Type of Rate
Rate Schedule TF-1 (4) (5)
Reservation
(Large Customer)
System-Wide
15 Year Evergreen Exp
25 Year Evergreen Exp
Volumetric (2)
(Large Customer)
System-Wide
15 Year Evergreen Exp.
25 Year Evergreen Exp.
(Smaf1 Customer) (6)
Scheduled Overrun (2)
Rate Schedule TF-2 (4) (5)
Reservation
Volumetric
Scheduled Daily Overrun
Annual Overrun
Rate Schedule TI-1 (2)
Volumetric (7)
Rate Schedule TFL-1 (4) (5)
Reservation
Volumetr j- c (2\
Scheduled Overrun (2\
Rate Schedule TIL-1 (2\
Volumetric
BaseTariff Rate(1),(3)
Minimum Maximum
.00000
.00000
.00000
.39294
.35011
.32093
.00832
.00832
.00832
.00832
.00832
.00832
.00832 .69421
. 00832 .40126
.00000
.00832
.00832
.00832
.3929 4
.00832
.40126
.40126
00832 .40726
Attachment D - Pipeline Tariff Sheets Page21 of45
STATEMENT OF RATES (Continued)
Effective Rates Applicable to
Rate Schedules TF-1, TF-2, TI-1, TFL-1 and TfL-1 (Continued)
(Doffars per Dth)
Entitlement Unauthorized Overrun and Underrun (8) Rate
Generaf System Unauthorized Daily Overrun (e)
General System Unauthorized Daily Underrun 10.00000
General System Unauthorj-zed Underrun Imbalances
not el-lminated after 72 hours 10.00000
Customer-Specifi-c Entj-tlement Penalty 10.00000
Footnotes
(1) Rate excludes surcharges approved by the Commission.(2) Annual Charge Adjustment (*ACA") surcharge may be applicabfe. Section
16 of the General Terms and Conditions describes the basis andapplicability of the ACA surcharge.
Attachment D - Pipeline Tariff Sheets Page 22 ot 45
STATEMENT OF RATES (Continued)
Effective Rates AppJ-icable to
Rate Schedules TF-1, TF-2, TI-1, TFL-1 and TIL-1 (Continued)
Eootnotes (Continued)
(3) To the extent Transporter discounts the Maximum Base Tariff Rate, such
discounts will be applied on a non-discrimi-natory basis, subject to the
poli-cies of Order No. 49'7.
Shippers receiving service under these rate schedules are required to
furni-sh fuel reimbursement in-kind at the rates specified on Sheet No.
74.
An lncremental facilitles charge or other palrment method provlded for
in Section 21 or 29 of the General Terms and Conditions, is payable in
addition to all other rates and charges if such a charge is included in
Exhibit C to a Shipper's Transportation Service Agreement.
In addition to the rates set forth on Sheet No. 5, Puget Sound Energy,
Inc.'s Transportation Service Agreement No. 140053 is sublect to an
annual incremental facility charge pursuant to Sectlon 21 of the
General Terms and Conditions for the South Seattle Delivery Lateral
Expanslon Project. The effective annual- incremental facillty charge
is $3,20'7,431 and is bj-lled in equal monthly one-twelfth increments.
The daily incremental facllity charge is $0.13152 per Dth.
In addition to the reservatj-on rates shown on Sheet No. 5, Shippers who
contract for Columbia Gorge Expansion Project capacity are subject to a
facility reservation surcharge pursuant to Section 3.4 of Rate Schedufe
TF-1. The facility charge used in deriving the Cofumbia Gorge Expansion
Project facility reservation surcharge has a minimum rate of $0 and a
maximum rate during the indicated months or cafendar years as foflows:
(Dol-l-ars per Dth)
Year
201_8
2019
2020
Rate
s0.09855
s0.09189
s0.08667
Year
2023
2024
Rate
$0.07199
$0.06680
Year Rate2021. S0.081942022 $0.07696
January 1,2025 - March 31, 2025 $0.06552
Attachment D - Pipeline Tariff Sheets Page 23 ol 45
STATEMENT OF RATES (Conti-nued)
Effecti-ve Rates Applicable to
Rate Schedules TE-1, TF-2, TI-1, TFL-1 and TIL-1 (Continued)
(Dollars per Dth)
Footnotes (Continued)
(4) A1I 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 Schedufe TF-1, the 1S-Year and 25-Year Evergreen Expansion
reservation and volumetric rates apply to Shippers receiving service
under Rate Schedule TF-1 Evergreen Expansion service aqreements. The
System-Wide reservation and volumetrlc rates apply to Shippers
receiving service under aII 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 $0.34641 and
$0.31657 for transmj-ssion costs and $0.00436 and $0.00436 for storagecosts, respectlvely. The System-Wj-de maximum base tariff reservatlonrates for Rate Schedule TF-1 and the maximum base tarlff reservationrates for Rate Schedul-e TE-2 are comprj-sed of $0.38858 for transmissioncosts and $0.00436 for storage costs.
For Rate Schedule TF-1 (Large Customer), the maximum base tariffvolumetric rates applicable to Shippers receiving service under Rate
Schedule TF-1 Evergreen Expansion service agreements are comprised of
$0.00806 for transmission costs and $0.00026 for storage costs. The
maximum base tariff volumetric rates for all other services under Rate
Schedule TF-1 (Large Customer) and for servj-ces under Rate Schedule TF-
2 are comprised of $0.00806 for transmission costs and $0.00026 for
storage costs.
Attachment D - Pipeline Tariff Sheets Page 24 ot 45
Northwest Pipeline LLC
FERC Gas Tariff
Fifth Revised Volume No. I
Sixth Revised Sheet No. 5-D
Superseding
Fifth Revised Sheet No. 5-D
STATEMENT OF RATES (Continued)
Effective Rates Applicable to
Rate Schedules TF-1, TF-2, TI-1, TFL-1 and TIL-1 (Continued)
(Do11ars per Dth)
Eootnotes (Contlnued)
(5) Rates for Rate Schedules TF-1, TF-2 and TFL-1 are afso applicable to
capacity release service except for short-term capacity release
transactions for a term of one year or less that take effect on or
before one year from the date on which Transporter is notified of the
release, which are not subject to the stated Maximum Base Tariff Rate.(Section 22 of the General- Terms and Conditions describes how blds for
capacity release wiII 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.
(6)For Rate Schedule TF-1 (Smaff Customer), the Maximum Base Tariff Rate
is comprised of $0.68529 for transmission costs and $0.00898 for
storage costs. Transporter wil-l not schedule gas for delivery to a
SmalI Customer subject to this Rate Schedufe TF-l- under any
transportation Service Agreement (excluding lts Rate Schedule TF-2
Service Agreement at Plymouth held at the time of storage servlce
unbundllng in RP93-5) unfess such Smal-l- Customer has scheduled its fuff
Contract Demand for firm servlce under its Rate Schedule TF-1 (Small
Customer) Service Agreement(s)for that day.
(1\Rate Schedule TI-1 maximum base tariff volumetric rate is comprised of
$0.39664 for transmission costs and $0.00462 for storage costs.
(8)Applicable to Rate Schedules TF-1, TF-2, TI-1, TEL-1 and TIL-1 pursuant
to Section 15.5 of the Generaf Terms and Conditions.
(e)The Unauthorized Overrun Charge per Dth is the greater of $10 or 150
percent of the highest midpoint price at NW Wyo. Pool, NW s. of Green
Ri-ver, Stanfield Ore., NW Can. Bdr. (Sumas), Kern River Opa1, or E1
Paso Bondad as reffected j-n the Dally Price Survey published in "Gas
udrry.
Attachment D - Pipeline Tariff Sheets Page 25 of 45
Northwest Pipeline LLC
FERC Gas Tariff
Fifth Revised Volume No. I
Fifth Revised Sheet No. 6
Superseding
Fourth Revised Sheet No. 6
STATEMENT OF RATES (Continued)
Effective Rates Applicable to Rate Schedules DEX-1 and PAL
(Do11ars per Dth)
Type of Rate
Base
Tariff Rate (1), (3)
Minimum Maximum
Rate Schedul-e DEX-]- (2) , (4)
Deferred Exchange
Rate Schedule PAL
Park and Loan
Eootnotes
(4)
. 00000 .40126
. 00000 .40726
1
2
Rate excludes surcharges approved by the Commission,
ACA surcharge may be applicable. Section 16 of the General Terms and
Conditions describes the basis and applicability of the ACA surcharge.
To the extent Transporter discounts the maximum currently effectivetariff rate, such discounts will be applied on a non-discriminatorybasis, subject to the policj-es of Order No. 49'7.
Shippers recelving service under this rate schedule are required to
furnish fuel relmbursement in-kind at the rates specified on Sheet No.
74, except as provided 1n Sectj-on 4 of Rate Schedu1e DEX-1.
(3)
Attachment D - Pipeline Tariff Sheets Page 26 of 45
STATEMENT OE RATES (Continued)
Effective Rates Applicable to Rate Schedules SGS-2F and SGS-2I
(Do11ars per Dth)
Rate Schedufe and
Type of Rate
Rate Schedule SGS-2F (2) (3) (4) (5)
Demand Charge
Pre-Expansion Shipper
Expanslon Shipper
Capaclty Demand Charge
Pre-Expansion Shj-pper
Expansion Shipper
Volumetri-c Bld Rates
Withdrawal Charge
Pre-Expansion Shipper
Expansion Shipper
Storage Charge
Pre-Expansion Shipper
Expansion Shipper
Rate Schedule SGS-2I
Volumetric
Base
Tariff Rate (1)
Minimum Maximum
0.00000
0.00000
0.00000
0.00000
0.00000
0.00000
0.00000
0.00000
0.00000
0.01562
0.04056
0.00057
0.00348
0.01562
0.04056
0.000s7
0.00348
Footnotes
( 1 ) Shippers
furnishNo. 74 .
0 . a0224
receiving service under these rate schedules are required tofuel reimbursement in-kind at the rates specified on Sheet
Attachment D - Pipeline Tariff Sheets Page27 ol45
STATEMENT OF RATBS (Continued)
Effective Rates Applicable to Rate Schedul-es SGS-2F and SGS-2I (Continued)
Footnotes (Continued)
(2) Rates are daily rates computed on the basis of 365 days per year,
except that rates for leap years are computed on the basis of 366 days.
Rates are afso appllcable to capacity release service except for short-
term capacity release transactions for a term of one year or }ess that
take effect on or before one year from the date on which Transporter is
notified of the release, whlch are not subject to the stated Maximum
Base Tariff Rate. (Secti-on 22 of the General Terms and Conditions
describes how bids for capaclty release will be evaluated. ) The
Withdrawal Charge and Storage Charge are applicable to Replacement
Shippers bidding for capacity released on a one-part volumetric bld
basis .
Attachment D - Pipeline Tariff Sheets Page 28 of 45
STATEMENT OF RATES (Continued)
Effective Rates Applicable to Rate Schedules LS-2F and LS-21
(Do1l-ars per Dth)
Rate Schedule and
Type of Rate
Rate Schedule LS-2F (3)
Demand Charge (2)
Capacity Demand Charge (2)
Volumetrlc Bid Rates
Vaporization Demand-Refated Charge (2)
Storage Capacity Charge (2)
Liquefaction
Vapori zation
Rate Schedule LS-2I
Vol-umetric
Li-quef action
Vapori zation
Base
Tar j-f f Rate (1)
Minimum Maximum
0.00000
0.00000
0.00000
0.00000
0.90855
0.03386
0.908s5
0.03386
0.02587
0.00331
0 .02581
0.00331
0.90855
0.03386
0.9085s
0.03386
0.00000 0.00662
Footnotes
(1) Shippers receiving service under these rate schedules are required tofurnish fuel- reimbursement in-klnd at the rates specified on Sheet No
14.
(2t Rates are daily rates computed on the basis of 365 days per year,
except that rates for leap years are computed on the basls of 366 days.
(3)Rates are al-so applicable to capacity release service except for short-
term capacity release transactions for a term of one year or l-ess that
take effect on or before one year from the date on which Transporter is
notified of the release, whlch are not subject to the stated Maximum
Base Tariff Rate. (Section 22 of the General- Terms and Conditions
describes how bids for capaci-ty release w11l be evaluated. ) The
Vapori-zation Demand-Related Charge and Storage Capacity Charge are
applicable to Replacement Shippers bidding for capacity released on a
one-part volumetric bid basis.
Attachment D - Pipeline Tariff Sheets Page 30 of 45
STATEMENT OE RATES (Continued)
Effective Rates Applicable to Rate Schedules LS-3F and LD-41
(Doll-ars per Dth)
Rate Schedule and
Type of Rate
Rate Schedule LS-3F (3)
Demand Charge (2)
Capacity Demand Charge (2\
Volumetric Bid Rates
Vaporization Demand-Refated Charge (21
Storage Capacity Charge (21
Liquefaction Charge (4)
Vaporization Charge
Rate Schedule LD-4I
Volumetrlc Charge
Liquefaction Charge (4)
Base
Tariff Rate (1)
Minimum Maximum
0.00000
0.00000
0.00000
0.00000
0.90855
0.03386
0.00000
0.90855
0.02587
0.00331
0 .02581
0.00331
0.90855
0.03386
0.188'72
0.90855
Eootnotes
(1) Shippers receiving service under these rate schedules are required to
furnish fuel relmbursement in-kind at the rates specj-fled on Sheet No
t4.
(2)Rates are daily rates computed on the basis of 365 days per year,
except that rates for leap years are computed on the basis of 366 days.
(3)Rates are also applicable to capaclty release service except for short-
term capacity release transactions for a term of one year or less that
take effect on or before one year from the date on which Transporter is
notified of the release, which are not subject to the stated Maximum
Base Tariff Rate. (Section 22 of the General Terms and Conditions
describes how bids for capacity release will be evaluated. ) The
Vaporizatj-on Demand-Related Charge and Storage Capacity Charge are
applicable to Replacement Shippers bidding for capacity released on a
one-part volumetric bid basis.
(4)The Liquefaction Charge wilI be trued-up annually pursuant to Section
74.20 of the General Terms and Conditions.
Attachment D - Pipeline Tariff Sheets Page 31 of45
RESERVED EOR FUTURE USE
Aftachment D - Pipeline Tariff Sheets Page 32 of 45
STATEMENT OF FUEL USE REQUIREMENTS FACTORS
FOR REIMBURSEMENT OF FUEL USE
Applicable to Transportation Service Rendered Under
Rate Schedules Contai-ned 1n this Tariff, Fj-fth Revised Vo1ume No. 1
The rates set forth on Sheet Nos. 5, 6,'7, 8 and 8-A are excl-usive of
fuel use requlrements. Shipper shafl rej-mburse Transporter in-kind for j-ts
fuel use requirements in accordance with Section 14 of the Generaf Terms and
Conditions contalned herein.
The fuel use reimbursement furnished by Shippers shal-l- be as folfowsfor the appllcable Rate Schedules included in thj-s Tariff:
Rate Schedul-es TE-1, TF-2, TI-l-, and DEX-I-
Rate Schedufe TF-1 - Evergreen Expansion
lncremental Surcharge (1)
Rate Schedule TFL-1
Rate Schedule TIL-1
Rate Schedules SGS-2F and SGS-2I
Rate Schedufes LS-2F, LS-3F and LS-2I
Liquefaction
Vaporization
Rate Schedule LD-4I
Liquefaction
1.16%
0.50%
0.17%
0.53?
0.532
0.53?
The fuel use factors set forth above shall be calculated and adjustedas explained in Section !4 of the General Terms and Conditj-ons. Fuel
reimbursement quantities to be supplled by Shippers to Transporter sha1l be
determi-ned by applying the factors set forth above to the quantlty of gas
nominated for receipt by Transporter from Shi-pper for transportation,
Jackson Prairie injection, Plymouth liquefaction, Plymouth vaporization, orfor deferred exchange, as appli-cab1e.
Footnote
(1) In addition to the Rate Schedule TF-1 fuel use requi-rements factor, the
Evergreen Expansion Incremental Surcharge w111 apply to the quantity of gas
nominated for receipt at the Sumas, SIPI or Pacific PooI receipt points under
Evergreen Expansion service agreements.
Attachment D - Pipeline Tariff Sheets Page 33 of 45
6t25nO18
f$Average Demand Rate (3 yrterm) 1
lT-R (lnteruptible Receipt)
Delivery Services
Sp Demand Rate (1 yr term) 2
Group 1:
Empress/McNeill Bordsr
Alberta-B.C. Border
Gordondale Border/Boundary Lk Border
ATCO: ClairmonUShell CreeUEdson
Group 2:
All Group 2 delivery points
() TransCanada I Customer Express
NGTL System
'1
NOTL Syrtem
TransCanada's - NGTL System Transportation Rates & Abandonment Surcharge
2018 FlnalRates - Effectlve f,lay 1,2018
R*elpt md dellvery tr.nrpott don R.rDs D.row do not lnclude ogpllczblc zhndonment surchtrges.
Receipt Scllces Tarlff Rate
t/10'm'(Cdn)
207.201mo
7.83td
Tariff Rate
$GJ (Cdn)
5.38/mo
4.99/mo
4.99/mo
4.99/mo
lnformatlon Purpoees
flGJld (Cdn) #Mcf/d (Cdn) f/MMBtu/d (US)
18.0 19.3 14.9
20.7 22.2 17.2
lnformation Purposss
l/GJld (Gdn) 6/Mcf/d (Gdn) ,rMMBtu/d (US)
17.7
16.4
16.4
16.4
18.9
17.6
17.6
17.6
14.7
13.6
13.6
13.6
All Group 3 delivery points
lT-D (lnteruptible Delivery)
Group l:
Empress/McNeill Border
Alberta-B.c. Border
Gordondale Border/ Boundary Lk BordEr
ATCO: ClairmonUShell CreeUEdson
Group 2:
Attachment D - Pipeline Tariff Sheets
http :/Arww.tccusto merexpr€s3. com/2766. htm l?p rint--y6s
4.99/mo
5.99/mo
16.4
19.7
19.46
18.05
18.05
18.05
17.6
21.1
20.83
19.32
19.32
19.32
13.6
16.3
16.1
15.0
15.0
15.0
Page 34 of 45
1t3
6t25nmg NGTL System
All Group 2 ddivery points 18.05 19.32
lFind more detaile on Racelpt Prlce Points at Receip!fgi4!!g!9g
1-2 year term: 105% (Pric6 Point C)
3.4 y€ar term: 100% (Pdce Point B)
5+ ysar term: 96% (Price Polnt A)
2 Find more dehib on Delivery Price Polnts at Qeliygyld8lBelgg
1-2 year term: 100% (Price Polnt Z)
$4 year term: 95% (Price Point Y)
5+ y6ar torm: 90% (Prbe Pdnt X)
- Aggr€gals charyes for servlce vyill be de*armlned in accordance wlth fie NGTL System tarlff and as such, shall lnclude the appllcabls
abandonment surcterge(s).
- Rates arc payable in Canadlan dollars.
- For bllllng prlrposas,lOrmt unlts arc used to Recelpt Servicss and GJ unitr are tor Dellvery servlces
- Mcf and MMBtu unlts ate provided fur illuslmtive purposes only.
. Comerslon factors below ha\re been used to calculab ths rates provkletl for lnlormatlon purposos:
Cdn$/US$ 1.27 - zubjecr to change (updated t{ov 27,20171
o/GJ to ,/MMBtu 1.06
$11&1n'to g/G.l 37.8 MJ/nr
- Actual heatiqg vall.E is depsnd€nt upon rpecific r€cdpt or dcllvory points and ranges from 36.0 MJ/m3 to 44.0 MJ/m3.
- Rates do not indude GST.
- FTfi rate range:
FT-R Rate Range St03m3 tlGJld AlMdtd d/MMBtu/d
FT-R Ceilrp Rate 293.10/mo 25.5 27.3 21J
FT-R Floor Rale 121.30/mo 10.6 11.3 8.7
2018 Abandonmont Surcharges - Effectlve January 1, 2018
Abtndonmont sutchargr[ an lo .ddlalon to .Ntc.ble ,t,cotpt tnd dallvery transportatloo ntet.
Abandonment Surchargcr Tarlf Ratc lnformatlon Purporeo
$/l0'm'(Cdn) $rG,(Cdn) $/llcf (Cdnl
Monthly Abandonment 10.51/mo 0.28/mo 0.3O/mo
15.0
Daily Abandonment Surcharge 0.35/d 0.0091/d 0.01/d
- The seMces to which abandonment surchaqes apply are denoted on the NGTL TaritrTable of Rates, Tolls and Charges.
Other informatlon for TranaCanada'a NGTL System:
Gurent Archlvcs
Receiplfulnlfislgg ReceiplSqinlfisles
Fuel Rates Fuel Rates (20O4 - 2010) (22 KB, XLS)
AB Border Heat Values Fuel Ratgs (2000 - 20O4) (4i KB, DOC)
Attachment D - Pipeline Tariff Sheets
http:/www.tccustomer9xprEss. com/2766.htl| l?prin t=y?s
Page 35 of 45
a3
6t25t2018
Deliverv Point Rates
NGTL System
AB Bordar Heat Valges (61 KB, PDF)
Disclaimer:
The pricing and tolls information included on this website is intended to be used for planning purposes only and although
TransCanada endeavours to maintain the information in such a way that is accurate and current, it may not provide accurate
results. Use of this information is at user's sole risk and Transcanada shall not be liable for user's use or rellance on any results
obtained from it.
Customer Express Home r Pricing & Tolls I NGTL System
Copyright @ 2018 TransCanada PipeLines Limited
Attachment D - Pipeline Tariff Sheets
httpJ/www.tccustomerexpress.com/2766.hUrll?print=yes
i
Page 36 of 45
3t3
6t25t2018 Foothills System - BC
() Transcanada Customer Express
Foothlllr Syrtrm. BC
TransCanada's Foothills BC Transportation Rates & Abandonment Surcharges
2018 Rataa Effective January 1,2018
Tnnspr|atlon Rrtas De,low do noa lnclude appllcable Abandonment Surcharges
Serulce Tariff Rate lnlormation Purposes
AB/BC to Kingegate
l,lcJld $lMctld f,lMMbtu/d
(cdn) (Cdn) (Us)
$IGJ/km(cdn)
FT Flrm Servlce . Zone 8
FT Rata
II lntrruptlble Scrvice -
Zone 8
lT Rate
7.3 7.8 6.0
8.0
0.01 301 54360(Monthly)
0.00il706952(Daily)E.6
Aggregate charges for servlce wlll be determined in accordance with the Foothills Pipe Lines Gas Transportation Tarifi and as such, shall
lnclude the applicable abandonm€nt surcharge(s)
2018 Abandonment Surcharges Effectlve January 1,2018
Abandanment ruierrarges ere ln addltlon to appllcable frzntporletlon Reles.
Abandonment Surcharges
lnformatlon Purposes
Tariff Rate
All Transportrtlon Scrvices
UGJ
(cdn)
d/GJ
(Cdn)
l/Mcf
(Cdn)
6.6
l/MMbtu
(us)
Monthly Abandonment Surchrrgc
Dally Abandonment Surcharge
0.0941620428(monthly) 9.4 10.1 7.7
0.0030957522(Daily) 0.31 0.33 0.25
The services to which abandonmenl surcharges apply are denoted on the Foothills Pipe Lines Table of Efiectiva Rates
Attachment D - Pipeline Tariff Sheets
http:/,vlvw.lccustomerexpress.comz76E.htrnl?print=yes
Page 37 of45
1t2
Gl25l2O1E Foothills Syelom - BC
1. For information purposes, the maximum Shippefs Haul Distance used in the Shippe/s monthly charge for Service calculation is
170.7 km.
2. Rates are payable in Canadian dollars and GJ units are ussd for billing purposes. Mcf and MMbtu units are provided for
informalion purposes only.
3. Conversion Factors below have been used to calculate the rErtes provlded for information purposes:
Cdn$/US$ 1.2886-subjecttochange (updated Dec0,2017l
0/GJ to 9/MMBU x 1.055056
#/GJ to 0/Mct at a heat value of 37.8 MJ/m3
4. All rates are based on 100 psr cent load faclor utilization. The lT rate is 110 per cont of the FT rate.
5. Rates do not include G.S,T.
6. lnquiries regarding the BC System may be direcied to:
Arhley Stowkowy
Phone: [phone]
Emai[ ashley stowkowv@[e-mail]
AndnaWrtbr
Phone: [phone]
Email: gg[gg_1gg]lg6(@transcanada.com
Other information for TransCanada's Foothills (BC) System:
Current fuchlvee
Fuel Rates and Heating Values Heating Values
AB Bordar Heat Values AB Border Heat Values (61 KB, PDF)
Disclaimer:
The pricing and tolls informaticn included on this website is intonded to be used for plannlng purposes only and althougtr
TransCanada endeavours to maintain the informaIon in such a way that is accurate and cunent, it may not provide accurale
resulB. Use of ftis information ls at user's sole dsk and Transcanada shall nol b€ liable hr userl use or rellance on any results
obbined trom ft.
Customer Express Home r Pricing & Tolls e Foothllls System . BC
Copyright @ 201 I TransCanada Pipelines Limited
Attachment D - Pipeline Tariff Sheets
http ://www.tccuslomerexpr€ss,com/2768.htrr1?print=yes
Page 38 of 45
2t2
'l'uscarora (ias -l'ransntission C'otnpunS'
I:tlRC (ias Tariff
Second Rcviscd Volume No. I
lssued: 0ctobcr 28. l0l0
Iilll'ctive: May ?7. 201 0
Attachment D - Pipeline Tariff Sheets
S'l'Al'EMl :N'l' Ol" RA'IES
PART.I
S'I'A'I'[MIiNT 0F RATES
v. I.0.0 Superscdinr: v.0.0.0
Dockct No, RP l0-773-001
Acccptcd: Dccenrher l. l0l0
Page 39 of 45
Tuscarora (la.s Transm i-ssion Companv
IrIRC Cas l'ariff
Second Revised Volunrc No, I
l,AR'l'-l.l
l.l - Statenrent ol'Ratcs
F'l'and l.FS Rates
v.7.0.0 Superseding v.6.0,0
RATE SCI-IEDULES FT and LFS
CTJRRTJNT'I,Y EI.'I.'EC]'IVE RA]'ES I /
Reservation Chargc (Ma.ximum)
(Minimum)
s 8.3615
$ 0.0000
Delivcr-v Charge (Ma.xirnum)
(Minirnum)
$ 0.003 r
$ 0.(x)31
Authorized Ovcrrun Charge (Maximurn)
lMinirrrurn)
$ 0.2780
s 0.003 t
Annual C'harge Adjustment
Mc'asurement Variance Gas Factor
2l
(lVtarimum)
lN.linimurn)
2.09'o
(1,0e6)
Volunretric Rescrvation Charge ttrr Capucity' Release s 0.1780.1/
1l For scheduling. imbalance and unauthorizcd ot'errun charges see Cencral l'erms and
Conditions. Section 6.6. Maximum and minimum rates are applicablc to backhaul
service.
2l The Annual Charge Adjustment (A('A) is in addition to the ahovc Delivery'('hurge and
the Authorized Overrun Charge. The currcntl,v- etI'ectivc ACA unit chnrge as publishcd
on the Commission's website (w*"w.felc.gov) is incorporatcd herein h-r'rel'ercnce.
3l The Maximum Rate does not apply to capacit.v release trunsuctions of one ( I ) -vcar or
lcss.
lssucd: Au-qust l. l0l6
litfbctivc: August I. 2016
Attachment D - Pipeline Tariff Sheets
Docket No. RP l6-l 1 37-000
Accepted: Scptember 22. 2016
Page 40 of 45
Page 8.1
Effective Date: April 1,2014
Page41 of45
Westcoast Energy lnc.
TOLL SCHEDULES . SERVICE
TRANSPORTATION SERVICE . SOUTHERN
DEFINITIONS
1. ln this Toll Schedule, the following term shall have the following meaning
(a)"Enhanced T-South Service" means Transportation Service - Southern provided
pursuant to a Service Agreement under which gas is to be delivered to the
Huntingdon Delivery Area and, subject to the fulfillment of the conditions specified in
the Service Agreement, to the Kingsgate Export Point;
"Kinqsqate Export P " means the point on the international boundary between
Canada and the United States of America near Kingsgate, British Columbia, where
the Foothills Pipe Lines (South BC) Ltd. pipeline facilities connect with the pipeline
facilities of Gas Transmission Northwest Corporation; and
"Service Term" means in respect of each Firm Transportation Service - Southern
specified in a Firm Service Agreement, the term of each such Firm Transportation
Service - Southern as determined in accordance with Section 3.
All other terms used in this Toll Schedule shall have the same meaning as set forth in the
General Terms and Conditions.
APPLICATION
This Toll Schedule applies to all Firm Transportation Service - Southern, AOS and
lnterruptible Transportation Service - Southern, including lmport Backhaul Service, provided
by Westcoast on facilities in Zone 4 under the provisions of a Firm Service Agreement or an
lnterruptible Service Agreement into which the General Terms and Conditions and this Toll
Schedule are incorporated by reference.
3.For all purposes of this Toll Schedule, the Demand Toll applicable to any Firm
Transportation Service - Southern provided pursuant to a Firm Service Agreement shall be
determined based upon the Service Term, and the Service Term for each such service shall
be determined as follows:
in the case of each Firm Transportation Service - Southern provided for in a Firm
Service Agreement entered into by a Shipper with Westcoast prior to November 1,
2005, the number of whole years remaining in the term of each such service as of
November 1,2005;
(b)in the case of each Firm Transportation Service - Southern provided for in a Firm
Service Agreement entered into by a Shipper with Westcoast after November 1,
2005, the number of whole years in the term of each such service specified in the
Firm Service Ag reement;
(c)in the case of each such Firm Transportation Service - Southern which is renewed
by a Shipper after November 1, 2005 in accordance with Section 2.06 of the
(b)
(c)
2.
(a)
Attachmenl D - Pipeline Tariff Sheets
Page 8.2
Effective Date: April 1,2014
Page 42 of 45
Westcoast Energy lnc.
TOLL SCHEDULES . SERVICE
4.
General Terms and Conditions, the number of whole years in the renewal term of
each such service, with effect from the first day of the renewal term; and
(d)in the case of each Firm Transportation Service - Southern provided for in a Firm
Service Agreement which is extended by the Shipper and Westcoast after
December 31, 2005, the number of whole years remaining in the term of each such
service, including the period of the extension, with effect from the first day of the
month immediately following the execution by the Shipper of an amendment to the
Firm Service Agreement providing for such extension.
MONTHLY BILL. FIRM TRANSPORTATION SERVICE . SOUTHERN
The amount payable by a Shipper to Westcoast in respect of Firm Transportation Service -
Southern provided in any month pursuant to a Firm Service Agreement shall be an amount
equal to:
(a)the product obtained by multiplying the Contract Demand for Firm Transportation
Service - Southern specified in the Firm Service Agreement by the applicable
Demand Toll specified in Appendix A for Firm Transportation Service - Southern; and
(b)the amount of tax on fuel gas consumed in operations payable under the Motor Fuel
Tax Act (British Columbia) and the Carbon Tax Act (British Columbia) which is
allocated to Shipper by Westcoast for the month,
less the amount of any Contract Demand Credits to which the Shipper is entitled for the
month pursuant to the General Terms and Conditions.
MONTHLY BILL . AOS, INTERRUPTIBLE TRANSPORTATION SERVICE - SOUTHERN AND
IMPORT BACKHAUL SERVICE
lf on any day Shipper has unutilized Firm Transportation Service - Southern at a Delivery
Point in Zone 4 and would incur on such day tolls for AOS and lnterruptible Transportation
Service, other than lmport Backhaul Service, at that Delivery Point or at any other Delivery
Point in Zone 4, then, notwithstanding the provisions of the General Terms and Conditions
and for the sole purpose of determining the amount of the Commodity Tolls payable by
Shipper in accordance with this Toll Schedule for AOS and lnterruptible Transportation
Service - Southern, the following rules shall apply:
(a)firstly, in the case where Shipper would otherwise incur tolls on such day for AOS
and lnterruptible Transportation Service - Southern at a Delivery Point where
Shipper has unutilized Firm Transportation Service - Southern, Shipper shall be
deemed to have utilized Firm Transportation Service at such Delivery Point on such
day in respect of a volume of gas not exceeding the volume of unutilized Firm
Transportation Service at such Delivery Point;
(b)secondly, in the case where a Delivery Point at which Shipper has unutilized Firm
Transportation Service - Southern is within the Huntingdon Delivery Area and
Shipper has any remaining volume of unutilized Firm Transportation Service at such
Delivery Point after applying the rule set out in paragraph (a) above, then Shipper
shall be deemed to have made a diversion on such day pursuant to Section 7.01(a)
E
Attachment D - Pipeline Tariff Sheets
Page 8.3
Effective Date: April 1,2014
Page 43 of 45
Westcoast Energy lnc.
TOLL SCHEDULES - SERVICE
6
of the General Terms and Conditions of a volume of gas not exceeding the amount of
the remaining volume of unutilized Firm Transportation Service, from that Delivery
Point to any other Delivery Point within the Huntingdon Delivery Area at which
Shipper would otherwise incur tolls for AOS and lnterruptible Transportation Service -
Southern;
(c)thirdly, if Shipper has any remaining volume of unutilized Firm Transportation Service
- Southern at any Delivery Point after applying the rules set out in paragraphs (a)
and (b) above, then Shipper shall be deemed to have made a diversion on such day
pursuant to Section 7.01(c) of the General Terms and Conditions of a volume of gas
not exceeding the amount of such remaining volume of unutilized Firm
Transportation Service from such Delivery Point to the nearest Downstream Delivery
Point at which Shipper would otherwise incur tolls for AOS and lnterruptible
Transportation Service - Southern; and
(d)fourthly, if Shipper has any remaining volume of unutilized Firm Transportation
Service - Southern at any Delivery Point after applying the rules set out in
paragraphs (a), (b) and (c) above, then Shipper shall be deemed to have made a
diversion on such day pursuant to Section 7.01(b) of the General Terms and
Conditions of a volume of gas not exceeding the amount of such remaining volume of
unutilized Firm Transportation Service, from such Delivery Point to the nearest
Upstream Delivery Point at which Shipper would otherwise incur tolls for AOS and
lnterruptible Transportation Service - Southern.
The amount payable by a Shipper to Westcoast in respect of AOS, lnterruptible
Transportation Service - Southern, and lmport Backhaul Service provided on each day in a
month shall be an amount equal to the sum of:
(a)the product obtained by multiplying the applicable Commodity Toll specified in
Appendix A for AOS, lnterruptible Transportation Service - Southern and lmport
Backhaul Service, respectively, by the Receipt Volume for such AOS or lnterruptible
Transportation Service - Southern (as determined after applying the rules set out in
Section 5) or for such lmport Backhaul Service, respectively, at the point from which
the residue gas is sourced, which is thermally equivalent to the volume of residue
gas (i) delivered to or for the account of Shipper at the Delivery Point, or (ii)
transmitted through Zone 4 for the account of Shipper on each such day during the
month;
the product obtained by multiplying the difference between the Commodity Tolls
specified in Section 7.03 of the General Terms and Conditions by the volume of gas
deemed to be diverted to a Downstream Delivery Point in accordance with Section
4(c) on each such day during the month; and
the amount of tax on fuel gas consumed in operations payable under the Motor Fuel
Tax Act (British Columbia) and the Carbon Tax Act (British Columbia) which is
allocated to Shipper by Westcoast for each day in the month.
(b)
(c)
Attachment D - Pipeline Tariff Sheets
INTERIM
8.4
Westcoast Energy lnc.
TOLL SCHEDULES . SERVICE
APPENDIX A
DEMAND AND COMMODITY TOLLS
TRANSPORTATION SERVICE . SOUTHERN
Firm Transportation Service - Southern
Year Round Service
Demand Tolls
$/1
PNG
Delivery Point
lnland
Delivery Area
Huntingdon
Delivery Area
FortisBC
Kingsvale to
Huntingdon*Service Term
l year 117.42 306.38 518.05 211.67
2 years 114.00 297.46 502.96 205.50
3 years 1 10.58 288.53 487.87 199.34
4 years 109.44 285.56 482.U 197.28
5 years or more 108.30 282.58 477.81 195.23
* For Firm Transportation Service - Southern provided by Westcoast pursuant to a Firm Service Agreement
dated April 15,2OO2 between Westcoast and FortisBC Energy lnc.
Plus the amount of tax on fuel gas consumed in operations payable under the Motor Fuel Tax Act
(British Columbia) and the Carbon Tax Act (British Columbia) which is allocated to Shipper by
Westcoast for each day in the month.
Winter Firm Service
Demand Tolls
$/1 3/mo.
Huntingdon Delivery Area
WF Service Revertible WF
November to March Service*
1 year 777.08 518.05
2 years 754.44 502.96
3 years 731.81 487 .87
4 years 724.26 482.U
5 years or more 716.72 477.81
* WF Service which has been designated as Revertible WF Service pursuant to Section 23.1 0 of the
General Terms and Conditions - Service to provide for firm transmission of residue gas in Zone 4 all days
of the year.
Plus the amount of tax on fuel gas consumed in operations payable under the Motor Fuel Tax Act
(British Columbia) and the Carbon Tax Act (British Columbia) which is allocated to Shipper by
Westcoast for each day in the month.
Service Term
Effective Date: April 1, 2018
Page 44 of 45Attachment D - Pipeline Tariff Sheets
Westcoast Energy lnc.
TOLL SCHEDULES . SERVICE
AOS and lnterruptible Transportation Service - Southern
CommodjtyJolls
$/10"m'
Months
PNG
Delivery Point
lnland
Delivery Area
Huntingdon
Delivery Area
FortisBC
Kingsvale to
Huntingdon*
April to October 3.843 10.027 18.650 6.927
November to March 5.124 1 3.369 18.650 9.236
. For AOS provided by Westcoast pursuant to a Firm Service Agreement dated April 15,2002 between
Westcoast and FortisBC Energy lnc.
Plus the amount of tax on fuel gas consumed in operations payable under the Motor Fuel Tax Act
(British Columbia) and the Carbon Tax Act (British Columbia) which is allocated to Shipper by
Westcoast for each day in the month.
lmport Backhaul Service
Commodity Tolls
$/10'm'
Months
April to October
November to March
lnland
Delivery Area
PNG
Delivery Point
14.807
13.526
Compressor
Station No.2
18.650
18.650
8.623
5.281
Plus the amount of tax on fuel gas consumed in operations payable under the Motor Fuel Tax Act
(British Columbia) and the Carbon Tax Act (British Columbia) which is allocated to Shipper by
Westcoast for each day in the month.
INTERIM
8.5
Effective Date: April 1, 2018
Page 45 of 45Attachment D - Pipeline Tariff Sheets