20160829Application.pdf

Avista Corp.
1411 East Mission P.O. Box 3727
Spokane. Washington 99220-0500
Telephone [phone]
J19nt1STJI.
Toll Free 800-727-9170
August 26, 2016
State of Idaho
Idaho Public Utilities Commission
4 72 W. Washington Street
Boise, Idaho 83702-5983
Case No. AVU-G-16-0..A_}Advice No. 16-02-G
Attention: Ms. Jean D. Jewell
I.P.U.C. No. 27 -Natural Gas Service
Enclosed for electric filing with the Commission are the following revised tariff sheets:
Corp.
Twenty-Second Revision Sheet 150
Eighteenth Revision Sheet 155
canceling Twenty-First Revision Sheet 150
canceling Seventeenth Revision Sheet 155
The Company requests that the proposed tariff sheets be made effective November 1, 2016.
These tariff sheets reflect the Company's annual Purchased Gas Cost Adjustment ("PGA''). If
approved, the Company's annual revenue will decrease by approximately $6.1 million or
approximately 7.8%. 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 residential or small commercial customer using an average
of 61 therms per month will see decrease of $4.65 per month, or approximately 8.4%. The present
bill for 61 therms is $55.59 while the proposed bill is $50.94. The Company will issue a notice to its
customers through a bill insert starting on or about September 2, 2016 and ending on or about
October 1, 2016. A copy of the bill insert has been included in the Company's filing.
If you have any questions regarding this filing, please contact Patrick Ehrbar at [phone] or
Ryan Finesilver at [phone].
Sincerely,
,:r-7 ,~-
Davi'flJ. Meyer
Vice President and Chief Counsel for Regulatory and Governmental Affairs
Enclosures
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that I have served Avista Corporation dba Avista Utilities' Advice
filing ADV 16-02-G (Tariff IPUC No. 27 Natural Gas Service) by mailing a copy thereof,
postage prepaid to the following:
Jean D Jewell, Secretary
Idaho Public Utilities Commission
472 W . Washington Street
Boise, ID 83720-5983
Chad Stokes
Cable Huston Benedict Haagensen &
Lloyd, LLP
1001 SW 5th, Suite 2000
Portland , OR 97204-1136
Edward A. Finklea
Northwest Industrial Gas Users
545 Grandview Drive
Ashland, OR 97520
Curt Hibbard
St. Joseph Regional Medical Center
PO Box 816
Lewiston, ID 83501
okane, Washington this 25th day of August 2016.
Patrick Ehrbar
Senior Manager, State & Federal Regulation
RECE IVED
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSI0[jj16 t.UG 29 AM 9: 13
IN THE MATTER OF THE APPLICATION OF )
A VISTA UTILITIES FOR AN ORDER APPROVING ) CASE: A VU-G-16-0 f}.....
A CHANGE IN NATURAL GAS RA TES 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, 2016. If approved as filed, the Company's annual revenue will decrease by
approximately $6.1 million or about 7.8%. In support of this Application, Applicant states as follows :
I.
The name of the Applicant is A VISTA CORPORATION, doing business as A VISTA UTILITIES
(hereinafter Avista, Applicant or Company), a Washington corporation, whose principal business
office is 1411 East Mission Avenue, Spokane, Washington, and is qualified to do business in the state
of Idaho. Applicant maintains district offices in Moscow, Lewiston, Coeur d'Alene, and Kellogg,
Idaho. Communications in reference to this Application should be addressed to:
Kelly 0. Norwood
Vice President of State & Federal Regulation
A vista Utilities
1411 E. Mission A venue
Spokane, WA 99220-3727
Phone: [phone]
Fax: [phone]
[e-mail]
II.
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 A venue
Spokane, WA 99220-3727
Phone: [phone]
Fax: [phone]
[e-mail]
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
Eastern Washington.
IV.
Twenty.Second Revision Sheet 150, which Applicant requests the Commission approve, is filed
herewith as Exhibit "A". Additionally, Eighteenth 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·Second Revision Sheet 150 and Eighteenth Revision Tariff Sheet 155 with the changes
underlined and a copy of Twenty.first Revision Sheet 150 and Seventeenth 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.
VI.
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". In 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
starting on or about September 2, 2016 and will end on or about October 1, 2016.
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 ("W ACOG")
purchased and the W ACOG 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: I) pass through changes in the estimated
cost of natural gas for the November 2016 through October 2017 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.1
"'f ' .. ,. " .
'Service
General
Lg. General
Interruptible
Sch.
,}-lo.
101
111
131
Commodity Costs
Commodity ' Demand Total Amortiz.ation Total Rate Overall 1 , , -
. Chang~ .. 1 .fhan.ge I Sch. 150 _ghange, Chai}~_
: .RYr tberin J. pertberm Cb.ange I?<?.r the!J11 .. J:~er ~he,rm
Percent
Change
L t(O.O_]J40L-~ 0:.9048,Q 1 $J 0.00~60) $ (0.069-_58), $. (0.0]618l -7.7%
. $ (0.0114Q)' $ 0.00480 · $ (0.00660) ~ (0.06958)_ $ (0.07618) -7.7%
$ (0.01 !40}j $ ,_$ (O.Ol 14Q), $ ,, (0.07202) $ (0.0834~). 0.0%
IX.
As shown in the table above, the estimated W ACOG change is a decrease of 1.14 cents per therm.
The proposed W ACOG, including the revenue conversion factor, is 24.06 cents per therm compared to
the present W ACOG of 25.2 cents per therm included in rates. The overall reduction in the W ACOG
is generally the result of the continued increase in natural gas supply coupled with an overall reduction
in customer demand due to a warmer than normal winter of 2015-2016, resulting in lower wholesale
natural gas prices. The downward pressure on wholesale prices has continued even after the winter
period due to the abundance of natural gas in storage and continued high natural gas production levels.
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 2015-2016
for the forthcoming PGA year (twelve months). Approximately 45% of estimated annual load
requirements for the PGA year (November 2016 through October 2017) will be hedged at a fixed-price
derived from the Company's Plan. These volumes are comprised of: I) volumes hedged for a term of
one year or less, 2) volumes from prior multi-year hedges. Through June, the planned hedge volumes
for the PGA year have been executed at a weighted average price of $2.60 per dekatherm ($0.26 per
therm).
The Company used a 30-day historical average of forward prices and supply basins ( ending July 15,
2016) 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 55% of estimated annual load
requirements for the coming year. The annual weighted average price for these volumes is $2.44 per
dekatherm ($0.24 per therm).
1 The overall percentage change for all schedules is a decrease of 7.8%. Customers on Schedules 112 and 132 receive
either a one-time rebate or surcharge rather than participate in the Schedule 155 amortization. The amount rebated to
customers on these schedules totaled $81,784 for an overall proposed revenue decrease of $6,119,167. The overall present
billed revenue is $78,661 ,797 making the percentage decrease 7.8% (-$6, 119,167 / 78,66 I ,797 = -7.8%).
X.
Demand Costs
Demand costs primarily represent the cost of transporting natural gas on interstate pipelines to the
Company's local distribution system. As shown in the table above, there is a slight increase in the
overall demand rate of $0.00480 per them1 for Schedules IO I and 111 which is, in part, related to the
reduction in Northwest Pipeline capacity release revenue Avista had been receiving.
XI.
Schedule 155 / Amortization Rate Change
As shown in the table above, the proposed amortization rate change for Schedule 101 and Schedule
111 is a rate decrease of $0.06958 per therm. The current rate applicable to Schedule IO I and
Schedule 111 is $0.02886 per therm in the rebate direction; the proposed rate is $0.09844 per thenn
also in the rebate direction. Contributing to the proposed amortization rebate rate, as discussed in the
Commodity Cost Section of this Application, are the effects of wholesale natural gas prices that were
lower than the level approved in the Company's 2015 PGA. As a result of the lower prices, the
amount of revenue collected from customers exceeded the Company's costs. However, a portion of
the benefit of reduced wholesale natural gas prices was offset by an under collection of fixed demand
costs which was the result of a warmer than normal winter.
XII.
If approved as filed, the Company's annual revenue will decrease by approximately $6. l million or
about 7.8% effective November 1, 2016. Residential or small commercial customers using an average
of 61 therms per month would see a decrease of $4.65 per month, or approximately 8.4%. The present
bill for 61 therms is $55.59 while the proposed bill is $50.94.
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 I,
2016, 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 I, 2016.
Dated at Spokane, Washington, this 261h day of August 2016.
AVISTA UTILITIES
BY
Dav1d.eyer
Vice President and Chief Counsel for
Regulatory and Governmental Affairs
VERIFICATION
STATE OF WASHINGTON )
)
County of Spokane )
David J. Meyer, being first duly sworn on oath, deposes and says: That he is the Vice President
and Chief Counsel for Regulatory and Governmental 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 contents thereof~ and believes the same to be trne.
SIGNED AND SWORN to before me this 261h day of August 2016, by David J. Meyer
WENDY D. MANSKEV
Notary Publ!c
State of Washington
My Commission Expires
October 09. 2018
Commission Expires: /O ·D9 . / r
AVISTA UTILITIES
Case No. AVU-G-16-0 ;;J_
EXHIBIT "A"
Proposed Tariff Sheets
August 26, 2016
1.P.U.C. No.27
APPLICABLE:
Twenty-Second Revision Sheet 150
Replacing
Twenty-First Revision Sheet 150
AVISTA CORPORATION
d/b/a Avista Utilities
SCHEDULE 150
PURCHASE GAS COST ADJUSTMENT -IDAHO
150
To Customers in the State of Idaho 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 , 111 and 112 are to be
increased by 35.447¢ per therm in all blocks of these rate schedules.
(b) The rates of interruptible Schedules 131 and 132 are to be increased by
24.058¢ per therm.
(c) The rate for transportation under Schedule 146 is to be decreased by
0.000¢ 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
Schedules 101 11 .389¢ 24.058¢
Schedules 111 and 112 11 .389¢ 24.058¢
Schedules 131 and 132 0.000¢ 24.058¢
The above amounts include a gross revenue factor.
Total
35.477¢
35.447¢
24.058¢
Demand Commodity Total
Schedules 101 11.331¢ 23.935¢ 35.265¢
Schedules 111 and 112 11 .331 ¢ 23.935¢ 35.265¢
Schedules 131 and 132 0.000¢ 23.935¢ 23.935¢
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.
Issued August 26, 2016 Effective November 1, 2016
Issued by Avista Utilities
By~ ~6'1~elly 0 . Norwood -Vice-President, State & Federal Regulation
I.P.U.C. No.27
APPLICABLE:
Twenty F'irst Revision Sheet 150
Replacing
Twentieth Revision Sheet 150
AVISTA CORPORATION
d/b/a Avista Utilities
SCHEDULE 150
PURCHASE GAS COST ADJUSTMENT -IDAHO
150
To Customers in the State of Idaho 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 , 111 and 112 are to be
increased by 36.107¢ per therm in all blocks of these rate schedules.
(b) The rates of interruptible Schedules 131 and 132 are to be increased by
25.198¢ per therm.
(c) The rate for transportation under Schedule 146 is to be decreased by
0.000¢ 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
Schedules 101 10.909¢ 25.198¢
Schedules 111 and 112 10.909¢ 25.198¢
Schedules 131 and 132 0.000¢ 25.198¢
The above amounts include a gross revenue factor.
Total
36.107¢
36.107¢
25.198¢
Demand Commodity Total
Schedules 101 10.855¢ 25.072¢ 35.927¢
Schedules 111 and 112 10.855¢ 25.072¢ 35.927¢
Schedules 131 and 132 0.000¢ 25.072¢ 25.072¢
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.
Issued Al:lgl:lst 26, 2015 Effective ll>lovember 1, 2015
Issued by Avista Utilities
By Kelly 0 . Norwood -Vice-President, State & Federal Regulation
1.P.U.C. No.27
APPLICABLE:
Twenty-Second Revision Sheet 150
Replacing
Twenty-First Revision Sheet 150
AVISTA CORPORATION
d/b/a Avista Utilities
SCHEDULE 150
PURCHASE GAS COST ADJUSTMENT -IDAHO
150
To Customers in the State of Idaho 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 , 111 and 112 are to be
increased by 35.447¢ per therm in all blocks of these rate schedules .
(b) The rates of interruptible Schedules 131 and 132 are to be increased by
24.058¢ per therm.
(c) The rate for transportation under Schedule 146 is to be decreased by
0.000¢ 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
Schedules 101 11 .389¢ 24.058¢
Schedules 111 and 112 11 .389¢ 24.058¢
Schedules 131 and 132 0.000¢ 24.058¢
The above amounts include a gross revenue factor.
Total
35.477¢
35.447¢
24.058¢
Demand Commodity Total
Schedules 101 11 .331¢ 23.935¢ 35.265¢
Schedules 111 and 112 11 .331¢ 23.935¢ 35.265¢
Schedules 131 and 132 0.000¢ 23.935¢ 23.935¢
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.
Issued August 26. 2016 Effective November 1. 2016
Issued by Avista Utilities
By~ ~vc~elly 0 . Norwood -Vice-President, State & Federal Regulation
I.P.U.C. No.27
AVAILABLE:
Eighteenth Revision Sheet 155
Canceling
Seventeenth Revision Sheet 155
AVISTA CORPORATION
d/b/a Avista Utilities
SCHEDULE 155
GAS RATE ADJUSTMENT -IDAHO
To Customers in the State of Idaho 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 9.844¢ per therm in all blocks of these rate schedules.
(b) The rate of interruptible gas Schedule 131 is to be decreased by
10.222¢ 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:
155
The above Monthly Rate is subject to the provisions of Tax Adjustment Schedule
158.
Issued August 26, 2016 Effective November 1, 2016
Issued by Avista Utilities
By ~ Atn~Kelly Norwood, Vice President, State & Federal Regulation
I.P.U.C. No.27
AVAILABLE:
Seventeenth Revision Sheet 155
Canceling
Si><-teenth Revision Sheet 155
AVISTA CORPORATION
d/b/a Avista Utilities
SCHEDULE 155
GAS RATE ADJUSTMENT -IDAHO
To Customers in the State of Idaho where Company has natural gas service
available.
PURPOSE:
To adjust gas rates for amounts generated by the sources listed below.
MONTHLY RA TE:
(a) The rates of firm gas Schedules 101 and 111 are to be
decreased by U8e¢ per therm in all blocks of these rate schedules.
(b) The rate of interruptible gas Schedule 131 is to be decreased by
3-,00-0¢ 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:
155
The above Monthly Rate is subject to the provisions of Tax Adjustment Schedule
158.
Issued /\1;191;1st 26, 2015 Effective November 1, 2015
Issued by Avista Utilities
By Kelly Norwood, Vice President, State & Federal Regulation
I.P.U.C. No.27
AVAILABLE:
Eighteenth Revision Sheet 155
Canceling
Seventeenth Revision Sheet 155
AVISTA CORPORATION
d/b/a Avista Utilities
SCHEDULE 155
GAS RATE ADJUSTMENT -IDAHO
To Customers in the State of Idaho 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 9.844¢ per therm in all blocks of these rate schedules.
(b) The rate of interruptible gas Schedule 131 is to be decreased by
10.222¢ 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 :
155
The above Monthly Rate is subject to the provisions of Tax Adjustment Schedule
158.
Issued August 26, 2016 Effective November 1, 2016
Issued by Avista Utilities
By ~ ~"..,._JKelly Norwood, Vice President, State & Federal Regulation
AVISTA UTILITIES
Case No. A VU-G-16-0 J-
EXHIBIT "B"
Notice of Public Applicant's Proposed Tariffs
August 26, 2016
AVISTA UTILITIES
NOTICE OF IDAHO TARIFF CHANGE
(Natural Gas Service Only)
Notice is hereby given that the "Sheets" listed below of Tariff !PUC No. 27, covering natural gas service
applicable to Idaho customers of Avista Utilities have been filed with the Idaho Public Utilities Commission
(!PUC) in Boise, Idaho.
Twenty-Second Revision Sheet 150
Eighteenth Revision Sheet 155
canceling
canceling
Twenty-First Revision Sheet 150
Seventeenth Revision Sheet 155
Eighteenth Revision Sheet 155 updates the amortization rate used to refund or recover previous gas cost
differences and Twentieth Revision Sheet 150 updates the forward-looking cost of natural gas purchased for
customer usage.
These tariffs request an annual revenue decrease of approximately $6.1 million, or about 7.8%. This filing
requests an effective date of November I, 2016.
PGAs are filed each year to balance the actual cost of wholesale natural gas purchased by A vista 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 the request is approved,
Avista residential customers using an average of 61 therms a month could expect their bill to decrease by $4.65,
or 8.36 percent, for a revised monthly bill of $50.94 beginning Nov. I, 2016. A vista's natural gas revenues would
decrease by $6.1 million, or approximately 7.8 percent. The requested natural gas rate change by customer
segment is as follows:
General Service -Firm -Schedule IO I -Residential & Small Commercial
Large General Service -Firm -Schedules -Commercial 111 & 112
High Annual Load Factor Large -Interruptible Service Schedules 132
-7.7%
-7.7%
-0.0%
A vista does not mark up the cost of natural gas purchased to meet customer needs, so the filing does not increase
or decrease company earnings.
The Company's application is a proposal, subject to public review and a Commission decision. Copies of the
application are available for public review at the offices of both the Commission and A vista, and on the
Commission's homepage (www.puc.idaho.gov). Customers may file with the Commission written comments
related to the Company's filing. Customers may also subscribe to the Commission's RSS feed
(http://www.puc.idaho.gov/rssfeeds/rss.htm) to receive periodic updates via e-mail about the case. Copies of rate
filing are also available on our website, www.avistautilities.com/rates.
If you would like to submit comments on the proposed rate decrease, you can do so by going to the Commission
website or mailing comments to :
Idaho Public Utilities Commission
P. 0 . Box 83720
Boise, ID 83720-0074
Copies of the proposed tariff changes are also available for inspection in the Company's offices, its website
(www.avistautilities.com/rates), by calling [phone] or by writing:
A vista Utilities
Attention : Manager, Rates & Tariffs
P.O. Box 3727
Spokane, WA. 99220-3727
August 26, 2016
AVISTA UTILITIES
Case No. AVU-G-16-0 J..
EXHIBIT "C"
Workpapers
August 26, 2016
Title Descri~tion Page Number
TARRIF CHANGE COMPARISONS
Revenue Change Summarv'!Al Change in Revenue as a result of filing 2
Rate Change Summarv' !Al Change in rate, by schedule, Schedule 150 and 155 3
PGA COMPONENT CALCULATIONS
lnout!Al Demand Volumes and Customers Inputs 4
lnout!A26 Commodity Inputs 5
Commoditv!Al Commodity WACOG Calculation 6
In out -Demand Contracts' !Al Demand WACOG Calculation 7
Amortization !Al Amortization WACOG Calculation 10
OTHER
Conversion Factor' !Al Revenue Conversion Factor 11
GRI Funding GRI Funding 12
Lost and Unaccounted for Gas Lost and Unaccounted for Gas 13
Tab: Index Page 1 of 13
Avista Utilities
State of Idaho
Revenue Rate Change Sumamry
Based on 12 months November 1, 2016 -October 31, 2017
Rate Revenue
une
No. Schedule Therms Chanse Iner (Deer!
1 Schedule 150 PGA Commodit~
2 Rate Schedule 101 56,026,100 $ (0.01140) $ (638,698)
3 Rate Schedule 111 23,224,517 $ (0.01140) $ (264,759)
4 Rate Schedule 112 0 $ (0.01140) $
5 Rate Schedule 131 0 $ (0.01140) $
6 Rate Schedule 132 0 $ (0.01140) $
7 79,250,617 (903,457)
8
9 Schedule 150 PGA Demand
10 Rate Schedule 101 56,026,100 $ 0.00480 $ 268,875
11 Rate Schedule 111 23,224,517 $ 0.00480 $ 111,457
12 Rate Schedule 112 0 $ 0.00480 $
13 Rate Schedule 131 0 $ $
14 Rate Schedule 132 0 $ $
15 79,250,617 $ 380,332
16
17 Schedule 155 Amortization
18 Rate Schedule 101 56,026,100 $ (0.06958) $ (3,898,296)
19 Rate Schedule 111 23,224,517 $ (0.06958) $ (1,615,962)
20 Rate Schedule 112 0 $ $
21 Rate Schedule 131 0 $ (0.07202) $
22 Rate Schedule 132 0 $ $
23 Customer 1 0 $ $ (81,614)
24 Customer 2 0 $ $ (154)
25 Customer 3 0 $ $
26 Customer4 0 $ $ 8
27 Customer 5 0 $ $ (24!
28 79,250,617 s (5,596,042)
29
30 Total Chanse 150 & 155
31 Rate Schedule 101 56,026,100 $ (0.07618) $ (4,268,119)
32 Rate Schedule 111 23,224,517 $ (0.07618) $ (1,769,264)
33 Rate Schedule 112 0 $ (0.00660) $
34 Rate Schedule 131 0 $ (0.08342) $
35 Rate Schedule 132 0 $ (0.01140) $
36 Customer 1 0 $ (81,614)
37 Customer 2 0 $ (154)
38 Customer 3 0 $
39 Customer4 0 $ 8
40 Customer 5 0 $ (24!
41 Total Change 79,250,617 $ (6,119,167!
42
43 Rate Schedule 146 & Special Contracts 0 $
44
45 Total $ !6,119,167!
46 % Change from Current Billed Revenue
t Summarv of Rate Change
Present Billed
Pro11osed Rates Revenue % Change
Rate Schedule 101 (4,268,119) $ 55,714,011 -7.7%
Rate Schedule 111 (1,769,264) $ 22,947,786 -7.7%
Rate Schedule 112 0
Rate Schedule 131 0
Rate Schedule 132 0 $ 0 0.0%
Customer Refunds {81,784}
Total Chan2e {6,119,167} $ 78,661,797 -7.8%
Tab: Revenue Change Summary Page: 2 of 13
Avista Utilities
State of Idaho
Summary of Changes
Firm Sales Firm Sales Total Gas Cost
(Demand) (Commodity) Rate (Demand) (Commodity) Rate
Present GRF: 1.005165
1 WACOG before revenue sensitive
2 Rate Schedule 101 $0.10855 $0.25072 $0.35927 $0.10909 $0.25198 $0.36107
3 Rate Schedule 111 $0.10855 $0.25072 $0.35927 $0.10909 $0.25198 $0.36107
4 Rate Schedule 112 $0.10855 $0.25072 $0.35927 $0.10909 $0.25198 $0.36107
5 Rate Schedule 131 $0.25072 $0.25072 $0.25198 $0.25198
6 Rate Schedule 132 $0.00000 $0.25072 $0.25072 $0.00000 $0.25198 $0.25198
7
8 Proposed GRF: 1.057611
9 WACOG before revenue sensitive
10 Rate Schedule 101 $0.11331 $0.23935 $0.35265 $0.11389 $0.24058 $0.35447
11 Rate schedule 111 $0.11331 $0.23935 $0.35265 $0.11389 $0.24058 $0.35447
12 Rate Schedule 112 $0.11331 $0.23935 $0.35265 $0.11389 $0.24058 $0.35447
13 Rate Schedule 131 $0.23935 $0.23935 $0.24058 $0.24058
14 Rate Schedule 132 $0.00000 $0.23935 $0.23935 $0.00000 $0.24058 $0.24058
15
16 Change
17 WACOG before revenue sensitive
18 Rate Schedule 101 $0.00476 ($0.01137) ($0.00661) $0.00480 ($0.01140) ($0.00660)
19 Rate schedule 111 $0.00476 ($0.01137) ($0.00661) $0.00480 ($0.01140) ($0.00660)
20 Rate Schedule 112 $0.00476 ($0.01137) ($0.00661) $0.00480 ($0.01140) ($0.00660)
21 Rate Schedule 131 ($0.01137) ($0.01137) ($0.01140) ($0.01140)
22 Rate Schedule 132 $0.00000 ($0.01137) ($0.01137) $0.00000 ($0.01140) ($0.01140)
23
24
25
26
27
Firm Sales Firm Sales
(Demand) (Commodity) (Demand) (Commodity)
28 Amort Amort Total Amort Rate Amort Amort Total Amort Rate
29 Present GRF: 1.005165
30 WACOG before revenue sensitive
31 Rate Schedule 101 $0 00133 ($0.03004) ($0.02871) $0.00134 ($0.03020) ($0.02886)
32 Rate Schedule 111 $0.00133 ($0.03004) ($0.02871) $0.00134 ($0.03020) ($0.02886)
33 Rate Schedule 112
34 Rate Schedule 131 ($0.03004) ($0.03004) ($0.03020) ($0.03020)
35 Rate Schedule 132 $0.00000 $0.00000
36
37 Proposed GRF: 1.057611
38 WACOG before revenue sensitive
39 Rate Schedule 101 $0.00357 ($0.09665) ($0.09308) $0.00378 ($0.10222) ($0.09844)
40 Rate schedule 111 $0.00357 ($0.09665) ($0.09308) $0.00378 ($0.10222) ($0.09844)
41 Rate Schedule 112
42 Rate Schedule 131 ($0.09665) ($0.09665) ($0.10222) ($0.10222)
43 Rate Schedule 132
44
45 Change
46 WACOG before revenue sensitive
47 Rate Schedule 101 $0.00224 ($0.06661) ($0.06437) $0.00244 ($0.07202) ($0.06958)
48 Rate schedule 111 $0.00224 ($0.06661) ($0.06437) $0.00244 ($0.07202) ($0.06958)
49 Rate Schedule 112
so Rate Schedule 131 ($0.06661) ($0.06661) ($0.07202) ($0.07202)
51 Rate Schedule 132
52
Tab: Rate Change Summary Page 3 of 13
STATE OF IDAHO
ANNUAL PGA FILING
•AN -Allocated North sum of Washington + Idaho
Une
No.
I· f\f$'t\@YtgfuvotO,._,FOfl£CA:St0"l[H:Mf I 12 month Ended
l Demand Forecast Nov-16 Dec-16 Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aua-17 Sep-17 Oct-17 Total
Rate Schedule 101 6,910,394 9,813.977 9,674.232 7.656,439 6.797.742 4,196,766 2,379,662 1.405.293 1,112.174 1.038,979 1.377.687 3,662.733 56,026,100
Rate Schedule 111 2.813.239 3,291,101 3,301.346 2.617.433 2,317,973 ; .429,719 921.758 818,004 1.022.685 1.233.277 1,247,564 2.210.399 23,224,517
S FIRM DEMAND THERMS 9,723,633 13,105,078 12,975,578 10,273,872 9,115,715 5,626,485 3,301,440 2,223,297 2,134,859 2,272,256 2,625,272 5,873,132 79,250,617
Rate Schedule 132 0 0 0 0 0 0 0 0 0 0 0 0
COMMODITY THERMS (SAlES) 9,723,633 13,105,078 12,975,578 10,273,872 9,115,715 5,626,485 3,301,440 2,223,297 2,134,859 2,272,256 2,625,272 S,873,132 79,250,617
6 Fuel ~23.942 140,342 137.046 118.881 117,531 69.473 40,657 27,366 47.873 51,098 59,063 105.469 1,038,740
7 Lost and Unaccounted for 72,349 97.508 96,545 76,4-43 67.825 41,864 24,564 16.542 15,664 16,907 19.533 43,699 589,664
7 TOTAL PURCHASE THERMS 9,919,924 13,342,928 13,209,169 10,469,197 9,301,071 5,737,821 3,366,662 2,267,205 2,198,616 2,340,260 2.703,868 6,022,300 80,879,020
8 9! KWf~nMER FORECASJtfP, I 12 month Ended
10 Demand Forecast Nov-16 Dec-16 Jan-17 Feb--17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Au1-17 Sep-17 Oct-17 Total
11 Rate Schedule 101 78,886 79,210 79.340 79,352 79,347 79,298 79,272 79,230 79,323 79,389 79,S91 79,743 951,979
12 Rate Schedule 111 1A41 1.442 l,44S 1,4.17 1,449 1,451 1.453 1,454 l,,:S6 1,459 1,460 l,,:63 17,422
13 Rate Schedule 132 0 0 0 0 0 0 0 0 0 0 0 0
14 Total Customers 80,328 80,653 80,786 80,798 80,795 80,749 80,724 80,684 80,779 80,848 81,051 81,206 969,400
15
Tab: Input Page: 4 of 13
16
17 i,1i11 Nov-16 Oec-16 Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep.17 Oct-17 Total
18
Commodity Allocation (based on Calendar
19 Volumes) 31.73% 31.23% 30.48'lf'. 29.71% 30.63'lt 30.73% 30.93% 32.33% 34.9o-M. 37.21% 3S.S4X. 33.44% 32.405%
20
21 Hedees
22
23 Executed
24 AW System Total Volumes (Th) 14,085,000 21,250,500 21,2SO.SOO 19,194,000 14,554,500 1,500,000 1,550,000 750,000 775,000 n~.ooo 750,000 1,550,000 97,984,500
25 AN· System Total Dollars($) 5 3,940.640 5 5,505,966 $ S,SB,543 S 4,987,620 $ 4,0?1.995 S 297,769 $ 307,694 $ 144,806 $ 149,633 S 149,633 $ 144,806 $ 320.133 $ 25,544,239
26
27 10 Volumes (Th) 4,468,910 6,635,837 6,477,041 5,702,841 4,458,066 460,947 479,489 242,479 270,489 288,384 266,522 518,330 30,269,334
28 10 Dollars($) $ 1,250,292 $ 1,719,333 $ 1,683,547 $ 1,481,901 $ 1,247,258 $ 91,504 $ 95,185 $ 46,817 $ 52,225 $ 55,680 $ 51,459 $ 107,055 $ 7,882,254
29 WACOG $ 0.27978 $ 0.25910 $ 0.25993 $ 0.25985 $ 0.27978 $ 0.19851 S 0.19851 $ 0.19308 $ 0.19308 $ 0.19308 $ 0.19308 $ 0.20654 $ 0.26040
30
31 Remaining to be Executed
32 AN· System Total Volumes (Th) 1,575,000 4,696.500 4,696,500 4,242,000 1,627.500 1,500,000 1.550,000 19,887,500
33 AW System Total Dollars($) $ 332,798 S 1.114.245 S 1,162,149 $ l,046,07i S 393,530 S 332.700 $ s s s 5 s 357,663 $ 4.739,160
34
35
36 ID Volumes (Th) 499,718 1,466,564 1,431,469 1,260,365 498,506 460,947 0 0 0 0 0 518,330 6,135,899
37 ID Dollars (S) $ 105,590 $ 347,942 $ 354,217 $ 310,806 $ 120,539 $ 102,238 $ $ $ $ $ $ 119,605 $ 1,460,937
38 WACOG $ 0.21130 $ 0.23725 $ 0.24745 $ 0.24660 $ 0.24180 $ 0.22180 #DIV/0! #OIV/01 #DIV/0! #OIV/0! #OIV/0! $ 0.23075 $ 0.23810
39
40 Deferred Exchange Credits
41 AN· Deferred Exchange s (375.00C) S t375,000} S \3?5.000) $ (375.000) $ (375,000) $ (37S.000) $ (375.000) $ (375,000) S (37S.000) $ {375,000) $ (375,C-00) S (375.000) $ (4,500,000)
42
43 ID Deferred Exchange $ (118,981) $ (117,100) $ (114,298) $ (111,418) $ (114,863) $ (115,237) $ (116,005) $ (121,239) $ (130,882) $ (139,541) $ (133,261) 5 (125,402) $ {1,458,227)
44
45 Price Forecast Nov-16 o«-16 Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aue-17 Sep-17 Oct-17 Total
46 30 Day average Price based on: 7-b· ?Q16
47 Aeco $ 2.113 S l.374 S 2.482 $ 2.472 s 2.417 S 2.177 $ 2.140 5 2.127 $ 2.118 $ 2.176 5 2.li'l S 2.270
48 Sumas 5 3.057 S 3549 S 3.437 s 3.335 $ 3.0S4 $ 2.375 5 2.326 $ 2.327 $ 2.S06 S 2.571 $ 2.597 $ 2.730
49 Rockies $ 2.937 $ 3.338 S 3.427 $ 3.395 5 3.158 $ 2.762 $ 2.748 S 2.776 $ 2.854 $ 2.867 5 2.835 5 2.889
so
51 Basin Weighting
52 Aeco 59.94% 67.47% 70.93% 97.98% 6J35% 95.73% 97.35% 100.00% 74.54% 78.78o/,, 70.92% 81.11% 82%
53 Sumas 34.01% 27.61% 2S.02% 0.00%, 3.24% 0.31% 0.57% 0.00% n .84% 3.31% ]8.94% 1.1.08% 12%
54 Rockies 6.05% 4.92% 4.0S% 2.02% 9.41% 3.96% 2.08% 0.00% 2.63';1.: 17.91% 10.14% 7.82% 6%
55
56 Basin-Weighted Index Price $ 2.4898 $ 2.7455 $ 2.7594 $ 2.4908 $ 2.5074 S 2.2011 $ 2.1536 $ 2.U66 5 2.2258 $ 2.3128 5 2.31919 $ 2.36935
57 Index Volumes {Th) 4,951,296 5,240,528 5,300,659 3,505,990 4,344,500 4,815,927 2,887,172 2,024,727 1,928,127 2,051,876 2,437,346 4,985,639 44,473,788
58 Index Cost $ 12,327,936 $ 14,387,669 S 14,626,478 $ 8,732,781 $ 10,893,292 $ 10,600,113 5 6,217,903 $ 4,305,870 $ 4,291,673 $ 4,745,652 S 5,652,662 S 11,812,708 $ 108,594,737
59
60 Embedded Charges
61 Variable Transportation s 15,744 $ 14,352 $ 15,964 S 1.4.372 S 15,579 $ 2.l,610 S 19,563 $ 18,589 S .D,948 S 10,737 $ 14,565 $ 16.056 192,277
62
63
64
65
66 J ihAP,,IQRm.ATION BAlAN(.'ES1 MMfa
67
Firm Customers Sales Customers
68 (Demand) (Commodity) Customer 1 Customer 2 Customer 3 Customer 4 Customers Customer6 Total
69
70 Unamortized Deferrals (191CXX>) $ 3~0,683 s (584,483) S (21) $ I) 5 $ 8 $ i3l $ (233,816)
73 Current Deferrals (191010) s (67,847i $ (7,07~ • .103) $ i81,S92) $ (154) $ $ s (llj s $ (7,224,718)
74 Total S 282,836 $ (7,659,586) $ (81,614) $ (154) $ $ 8 $ (24) $ $ (7,458,534)
Tab: Input Page: S of 13
Avista Utilities
State of Idaho
Gas Cost calculation (per Therm)
1•1
Nov-16 4,468,910 S
Oec-16 6,635,837 s
Jan-17 6,477,041 $
Feb-17 5,702,841 $
Mar-17 4,458,066 S
Apr-17 460,947 s
May-17 479,489 s
Jun-17 242,479 s
Jul-17 270,489 $
Aug-17 288,384 S
Sep-17 266,522 $
Oct-17 518,330 S
30,269,334 I
Average s
Tab: Commodity
(bl
1,250,292
1,719,333
1,683,547
1,481,901
1,247,258
91,504
95,185
46,817
52,225
55,680
51,459
107,055
7,882,254
0.2604
37.4%
(cl (di 1,1 (hi
499,718 S 105,S90 4,951,296 S 1,232,794
1,466,564 $ 347,942 5,240,528 S 1,438,767
1,431,469 $ 354,217 5,300,659 S 1,462,648
1,260,365 $ 310,806 3,505,990 S 873,278
498,506 $ 120,539 4,344,500 $ 1,089,329
460,947 $ 102,238 4,815,927 s 1,060,011
0 $ 2,887,172 s 621,790
0 S 2,024,727 $ 430,587
0 S 1,928,127 $ 429,167
0 $ 2,051,876 $ 474,565
0 S 2,437,346 $ 565,266
518,330 $ 119,605 4,985,639 s 1,181,271
6,135,899 I 1,460,937 44,473,788 I 10,859,474
s 0.2381 s 0.2442
7.6% 55%
(a)-t (c)-t (e)-t (g) (b)-t (d) -t(f) + (hJ 1;1 UI (kl
9,919,924 s 2,588,676 s 15,744 s (118,981) $ 2,485,439 9,723,633 s 0.2556
13,342,928 s 3,506,042 s 14,352 s (117,100) $ 3,403,294 13,105,078 $ 0.2597
13,209,169 $ 3,500,412 s 15,964 s (114,298) S 3,402,077 12,975,578 $ 0.2622
10,469,197 S 2,665,985 s 14,372 s (111,418) $ 2,568,939 10,273,872 S 0.2500
9,301,071 $ 2,457,126 $ 15,579 s (114,863) $ 2,357,842 9,115,715 s 0.2587
5,737,821 $ 1,253,753 s 21,810 S (115,237) $ 1,160,326 5,626,485 5 0.2062
3,366,662 s 716,975 s 19,563 s (116,005) S 620,533 3,301,440 S 0.1880
2,267,205 s 477,404 s 18,589 s (121,239) $ 374,753 2,223,297 s 0.1686
2,198,616 $ 481,392 s 12,948 s (130,882) S 363,458 2,134,859 S 0.1702
2,340,260 $ 530,245 s 10,737 s (139,541) $ 401,441 2,272,256 $ 0.1767
2,703,868 $ 616,725 s 14,565 s (133,261) $ 498,029 2,625,272 s 0.1897
6,022,300 $ 1,407,930 $ 18,056 s (125,402) $ 1,300,583 5,873,132 s 0.2214
80,879,020 $ 20,202,665 s 192,277 s (1,458,227) $ 18,936,715 79,250,617 s 0.2389 s 0.2498
GRI Funding (no change) 0.00040
TOTAL Rate 0.23935
RCF: 1.005165
Proposed Rate
Proposed WACOG without RCF S 0.23935
Proposed WACOG with RCF $ 0.24058
Page: 6 of 13
Avista Utilities
WA Gas Operations
Demand Cost Calculation (per Therm)
Allocation
Line No. Description Estimated Demand Expense Allocator Percentage Idaho Allocation
10
Northwest Pipeline Corporation (NWP) 17,163,194 ID System Allocated 29.47% $ 5,057,993
TCPL-Gas Transmission Northwest 2,614,309 ID System Allocated 29.47% $ 770,437
4
5 Total Fixed Domestic Transportation Costs 19,777,502 $ 5,828,430
6
7 TransCanada -AB (NOVA System) $ 6,348,994 ID System Allocated 29.47% $ 1,871,049
8
9 TransCanada - BC (Foothills Pipe Line Ltd.) $ 3,305,495 ID System Allocated 29.47% $ 974,129
10
11 Spectra -Westcoast Energy Inc 1,038,626 ID System Allocated 29.47% $ 306,083
12
13 Total Fixed Canadian Transportation Costs $ 10,693,115 $ 3,151,261
14
15 Total Fixed Pipeline Charges $ 30,470,618 $ 8,979,691
16
17 Demand Costs $ 30,470,618 $ 8,979,691
18 Demand Volumes 79,250,617
19 Demand Rate $ 0.11331
20
21
22 RCF: 1.0051650
23 Rate Chan e Calculation:
24 Proposed WACOG without Revenue Sensitive Costs $ 0.11331
25 Pro osed WACOG with Revenue Sensitive Costs $ 0.11389
JURISDICTIOIAN
. PROFIHENT LDC ......... ··-·····-··-··-·-·-
Sum of US DOLLARS
St:!ORT NAIV CH,~G E ,:V_PE . PIPEUjlj.E ~Or>i:T~<;I IVl.1.L.£.5 ... ...... 1V11.LA.~t .~:re. . r:,JON .. MILAGERA.-.MMB.TUPER.DAY .... Grandfota_l ....
GTNW DMD 17013 27 0 0 300 $ 2,532
879 s 7,380
17014 56 0 0 1,000 s 10,702
1,827 s 19,445
17015 59 0 0 2,500 s 27,501
3,327 s 36,399
17017 85 0 0 150 s 1,954
191 s 2,474
17020 98 0 0 250 s 3,512
871 s 12,170
17024 108 0 0 3,400 s 50,641
7,165 s 106,136
17027 121 0 0 2,000 s 31,832
3,241 s 51,302
17029 134 0 0 150 s 2,543
233 s 3,928
17030 146 0 0 100 s 1,787
183 s 3,252
17032 159 0 0 100 s 1,891
224 s 4,213
17035 183 0 0 50 s 1,041
133 s 2,753
17038 108 0 0 45,000 $ 670,254
61,549 s 911,734
17043 98 0 0 2,758 s 77,281
17044 108 0 0 2,470 s 73,378
17045 121 0 0 15,077 s 478,617
17046 134 0 0 117 s 3,956
17047 146 0 0 117 s 4,169
17048 159 0 0 146 s 5,508
17049 183 0 0 97 s 4,026
DMD Total $ 2,614,309
GTNWTotal $ 2,614,309
NWPL CR 100010 0 0 0 0 s
2,000 s (298,482)
Input -Demand Contracts 7 ofl3
NWPL CR 100010 0 0 0 2,841 $ (423,994)
3,360 $ (83,804)
4,100 $
4,517 s
5,400 s (1,611,805)
6,450 s (962,606)
7,159 $ (1,068,418)
8,056 $ (1,202,287)
9,211 $ (1,374,661)
10,000 $ (2,984,824)
10,394 $ (1,551,213)
15,400 $ (2,298,314)
19,432 $ (5,800,110)
20,394 $ (3,043,625)
100164 0 0 0 1,500 $ (447,724)
8,500 $ (1,268,550)
115163 0 0 0 7,000 $ (61,107)
135133 0 0 0 17,682 $ (2,638,883)
135198 0 0 0 17,394 $ (2,595,901)
137227 0 0 0 8,500 $
137337 0 0 0 4,100 $
137341 0 0 0 2,130 s (317,884)
141059 0 0 0 8,056 $ (1,202,287)
190203 0 0 0 2,841 s (847,988)
190204 0 0 0 7,159 $ (2,136,836)
195151 0 0 0 2,841 $ (423,994)
195152 0 0 0 6,709 $ (1,001,259)
CR Total $(35,646,557)
DMD 100010 0 0 0 132,687 $ 19,802,403
100164 0 0 0 10,000 $ 1,492,412
100314 0 0 0 7,962 $ 1,188,258
115161 0 0 0 2,841 $ 423,994
115163 0 0 0 7,159 $ 1,068,418
135132 0 0 0 19,432 $ 2,900,055
135133 0 0 0 19,432 $ 2,900,055
135198 0 0 0 20,394 $ 3,043,625
135199 0 0 0 10,394 $ 1,551,213
135200 0 0 0 10,000 $ 1,492,412
136948 0 0 0 5,000 $ 746,206
136950 0 0 0 5,330 $ 795,456
137226 0 0 0 8,500 $ 1,268,550
137227 0 0 0 8,500 $
137286 0 0 0 9,211 $ 1,374,661
137287 0 0 0 9,211 $
137333 0 0 0 5,400 $
137334 0 0 0 5,400 $ 805,902
137335 0 0 0 2,000 $ 298,482
137337 0 0 0 4,100 $
137339 0 0 0 4,517 $
137340 0 0 0 10,000 $
137341 0 0 0 15,400 $ 2,298,314
137343 0 0 0 5,400 $ 805,902
137346 0 0 0 17,682 $ 2,638,883
137347 0 0 0 17,682 $
137348 0 0 0 8,500 $
137349 0 0 0 8,500 $
137852 0 0 0 4,100 $
137853 0 0 0 4,100 $
137899 0 0 0 1,500 $ 223,862
137900 0 0 0 1,500 $ 223,862
137901 0 0 0 1,500 $
140278 0 0 0 2,130 $ 317,884
140279 0 0 0 2,130 $
140546 0 0 0 8,056 $ 1,202,287
140547 0 0 0 8,056 $
141059 0 0 0 8,056 $ 961,830
190203 0 0 0 2,841 $ 423,994
190204 0 0 0 7,159 s 1,068,418
195151 0 0 0 2,841 s 423,994
195152 0 0 0 7,159 $ 1,068,418
DMD Total $ 52,809,751
NWPL Total -----·---$17,163,194
Grand Total $ 19,777,502
Input· Demand Contracts 8 of 13
JURISOICTIOIAN
PROFIT CENT LDC
Sum of CON DOLLARS
SHORT NAIi/CHARGE TYPE
TCPLAB OMO
DMD Total
TCPL AB Total
TCPL BC DMD
DMD Total
TCPL BC Total -•••-••••·------M·-••••---•••--mOMMM------•••MooMo
WEI DMD
PIPELINE CONTRACT MILES
2010-445834 0
2010-445835 0
2010-445836 0
2010-445837 0
2010-447082 0
2014-623869 0
AVA 0
AVA-F2 0
AVA-F4 0
AVA-F6 0
AVA-F8 0
MILAGE RATE NON MILAGE RA" CON VOLUME PER O,Grand Total
0
0
0
0
0
0
0
0
0
0
0
5 12,776 $ 749,719
5 8,947 $ 524,992
5 15,609 $ 915,954
5 746 $ 43,787
5 46,825 $ 2,747,697
5 23,293 $ 1,366,845
3
3
3
3
$ 6,348,994
$ 6,348,994
$
5,011 $ 155,369
40,799 $ 1,264,912
11,772 $ 364,972
49,034 $ 1,520,243
$ 3,305,495
···············--·-··--·-·--·--·---·--········-----------·--··-·---.. ·-·---·---···--.... ·-·-·----·-···----·---··--$ .. 3,305,495 ... 2,483 0 0 387 8,427 $ 1,022,426
ACCTSP -100370 (blank) (blank) (blank) (blank) $ 16,200
... _D_M_D_To_t~-----··----------------------·------··-----··---·----··-------·-·-·-·-------· s __ 1,038,626 .. WEI Total
Grand Total
Input -Demand Contracts
. $1,0~~'~?6
$ 10,693,115
30,470,618
9 of13
Avista Utilities
Idaho Gas Operations
Development of Amortization Rate
Line I SALES AMORTIZATION (Sch 101-131} I I FIRM AMORTIZATION {Sch 101 and 111}
No.
1 Sales Therms Amortization Interest Balance Firm Sales Amortization Interest Balance
2 $ (0.09665) 1.00% Therms $ 0.00357 1.00%
3
4 Rate Schedule: 101-132 $ (7,659,586) Rate Schedule: 101-121 $ 282,836
5
6 Nov/16 9,723,633 s 939,790.81 $ (5,991.41) $ (6,725,786.21) Nov/16 9,723,633 s (34,713.37) $ 221.23 s 248,343.80
7 Dec/16 13,105,078 s 1,266,608.02 $ (5,077.07) $ (5,464,255.26) Dec/16 13,105,078 s (46,785.13) $ 187.46 s 201,746.13
8 Jan/17 12,975,578 s 1,254,091.83 s (4,031.01) $ (4,214,194.44) Jan/17 12,975,578 s (46,322.81) $ 148.82 $ 155,572.14
9 Feb/17 10,273,872 s 992,971.52 s (3,098.09) $ (3,224,321.01) Feb/17 10,273,872 s (36,677.72) $ 114.36 s 119,008.78
10 Mar/17 9,115,715 s 881,035.44 s (2,319.84) $ (2,345,605.41) Mar/17 9,115,715 s (32,543.10) $ 85.61 s 86,551.29
11 Apr/17 5,626,485 s 543,800.71 s (1,728.09) $ (1,803,532.79) Apr/17 5,626,485 $ (20,086.55) $ 63.76 $ 66,528.50
12 May/17 3,301,440 s 319,084.73 $ (1,369.99) $ (1,485,818.05) May/17 3,301,440 s (11,786.14) $ 50.53 s 54,792.89
13 Jun/17 2,223,297 s 214,882.05 s (1,148.65) $ (1,272,084.65) Jun/17 2,223,297 $ (7,937.17) $ 42.35 s 46,898.07
14 Jul/17 2,134,859 s 206,334.47 s (974.10) $ (1,066,724.28) Jul/17 2,134,859 s (7,621.45) $ 35.91 s 39,312.53
15 Aug/17 2,272,256 s 219,613.93 s (797.43) $ (847,907.78) Aug/17 2,272,256 $ (8,111.95) $ 29.38 s 31,229.96
16 Sep/17 2,625,272 s 253,732.95 s (600.87) $ (594,775.70) Sep/17 2,625,272 $ (9,372.22) $ 22.12 $ 21,879.86
17 Oct/17 5,873,132 s 567,639.17 s (259.13) $ (27,395.66) Oct/17 5,873,132 $ (20,967.08) $ 9.50 s 922.28
18 79,250,617 s 7,659,585.63 s (27,395.68) $ (27,395.66) 79,250,617 s (282,924.69) $ 1,011.03 s 922.28
TOTAL AMORTIZATION RATES
RCF: 1.05761 RCF: 1.05761
Sales Amortization Firm Amortization
Proposed Amort. Rate without revenue sensitive costs $ (0.09665) Proposed Amort. Rate without revenue sensitive costs $ 0.00357
Proposed Amort. Rate witll_r_l!_ve__11_ue_ sensitive costs s (0.10222) Proposed Amort. Rate with revenue sensitive costs $ 0.00378
Tab: Amortization Page: 10 of 13
AVISTA UTILITIES
Revenue Conversion Factor
Idaho -Natural Gas System
TWELVE MONTHS ENDED DECEMBER 31, 2014
Line
No.
Revenues
Expenses:
2 Uncollectibles
3 Commission Fees
Description
4 Idaho State Income Tax
5 Total Expenses
6 Net Operating Income Before FIT
7 Federal Income Tax @ 35%
8 REVENUE CONVERSION FACTOR
REVENUE GROSS UP:
Tab: RCF (Conversion Factor)
Factor
1.000000
0.003407
0.002371
0.048695
0.054473
0.945527
0.330934
0.61459
( 1/1-.054473) 1.057611
Prior RCF 1.005165
Page: 11 of 13
Avista Utilities
State of Idaho
Voluntary GRI Funding
Northwest Pipeline Transcanada -GTN Pipeline Total
TF-1 TF-1 TF-1 TF-1
Reservation Volumetric Reservation Volumetric
Previous Pipeline Rate (Per Therm) $0.00086 $0.00088 $0.00086 $0.00088
Current Pipeline Rate {Per Therm) $0.00076 $0.00075 $0.00076 $0.00075
Reduction in Pipeline Funding Rate {Per Therm) $0.00010 $0.00013 $0.00010 $0.00013
Monthly Rate (Daily Rate X 365 Days/12 Months) $0.00316 $0.00316
NWP Demand Billing Determinants 558,085,000 0
Estimated Transportation Volumes {Therms) 0 0
GRI Funding Shortfall $1,764,000 $0 $0 $0
Idaho Percentage 30.01% 30.57% 30.01% 30.57%
Total Idaho GRI Funding Shortfall $14,000 $3,000 $9,000 $6,000 $32,000
Set the GRI Funding at the 11/1/99 Level.
Tab: GRI Page: 12 of 13
12 MONTHS ENDED TOTAL
LOSS & UNACCOUNTED FOR GAS
BY DELIVERY POINT· THERMS
IDAHO %OF
DELIVERY REVENUE LOSS+/. PURCHASE
ID SPO-CDA area 45,043,559 44,640,037 403,522 0.90
ID LEWIS-CLARK area 54,824,788 54,741,524 83,264 0.15
99,868,347 99,381,561 486,785 0.49
Bonners 2,463,920 4,475,910 {2,011,990) (81.66)
Genesee 231,140 206,816 24,324 10.52
Kellogg 4,021,370 4,220,058 (198,688) (4.94)
Moscow 6,357,060 6,298,431 58,629 0.92
Pinehurst-Kingston 724,400 454,864 269,536 37.21
Sandpoint 6,893,350 4,746,440 2,146,910 31.14
Smelterville-Page 398,990 274,504 124,486 31.20
IDAHO TOTAL 120,958,577 120,058,585
Lost and Uaccounted For Gas 13 of 13
AVISTA UTILITIES
Case No. A VU-G-16-0 J._
EXHIBIT "D"
Pipeline Tariffs
August 26, 2016
Gas Transmission Northwest LLC
FERC Gas Tariff
Fourth Revised Volume No. 1-A
Description
TABLE OF CONTENTS
PART 1
TABLE OF CONTENTS
v.9.0.0 Superseding v.8.0.0
Section No.
Table of Contents .................................................................................................................. 1
Preliminary Statement. .......................................................................................................... 2
System Map .......................................................................................................................... 3
Statement of Rates
FTS-1 and LFS-1 Rates ................................................................................................... 4.1
ITS-1 Rates ...................................................................................................................... 4.2
Footnotes to Statement of Effective Rates and Charges ................................................. .4.3
Reserved For Future Use ................................................................................................. 4.4
Parking and Lending Service ............................................................................................ 4.5
Negotiated Rate Agreements -FTS-1 and LFS-1 ........................................................... .4.6
Footnotes for Negotiated Rates -FTS-1 and LFS-l ........................................................ 4.7
Negotiated Rate Agreements -ITS-1 and PAL .............................................................. .4.8
Footnotes for Negotiated Rates -ITS-I and PAL ............................................................ 4.9
Non-Conforming Service Agreement .............................................................................. 4.10
Rate Schedules
FTS-1 (Firm Transportation Service) ............................................................................ 5. I
LFS-1 (Limited Firm Transportation Service) ............................................................... 5.2
ITS-1 (Interruptible Transportation Service) ................................................................ 5.3
USS-I (Unbundled Sales Service) ................................................................................. 5.4
PAL (Parking and Lending Service) ............................................................................ 5 .5
Issued: September 25, 2015
Effective: October 26, 20 15
2016 Attachment H Pipeline Tariffrs
Docket No. RPIS-1294-000
Accepted: October 23, 2015
Page 1 of 41
Gas Transmission Northwest LLC
FERC Gas Tariff
Fourth Revised Volume No. 1-A
Issued: April 11, 2011
Effective: April 4, 2011
2016 Attachment H Pipeline Tariffrs
STATEMENT OF RA TES
PART4
STATEMENT OF RATES
v.2.0.0 Superseding v.1.0.0
Docket No. RP 11-1986-000
Accepted: May 4, 2011
Page 2 of 41
Gas Transmission Northwest LLC
FERC Gas Tariff
Fourth Revised Volume No. 1-A
PART 4.1
4.1 -Statement of Rates
FTS-1 and LFS-1 Rates
v.15.0.0 Superseding v.14.0.0
STATEMENT OF EFFECTIVE RATES AND CHARGES FOR
TRANSPORTATION OF NATURAL GAS
Rate Schedules FTS-1 and LFS-1
RESERVATION
DAILY DAILY
MILEAGE(a) NON-MILEAGE (b) DELIVERY (c) FUEL (d)
(Dth-MILE) (Dth) (Dth-MTLE) (Dth-MlLE)
Max. Min. Max. Min. Max. Min. Max. Min.
BASE 0.000434 0.000000 0.034393 0.000000 0.000016 0.000016 0.0050% 0.0000%
STF (e) (e) 0.000000 (e) 0.000000 0.000016 0.000016 0.0050% 0.0000%
EXTENSION CHARGES
MEDFORD
E-1 (t) 0.002759 0.000000 0.004641 0.000000 0.000026 0.000026
E-2 (h) 0.002972 0.000000 0.000000 0.000000
(Diamond 1)
E-2 (h) 0.001166 0.000000 0.000000 0.000000
(Diamond 2)
COYOTE SPRINGS
E-3 (i) 0.001282 0.000000 0.001283 0.000000 0.000000 0.000000
CARTY LATERAL
E-4 (p)
OVERRUN CHARGE G)
SURCHARGES
ACA (k)
Issued: November 24, 2015
Effective: January 1, 2016
2016 Attachment H Pipeline Tariffrs
0.166475 0.000000 0.000000 0.000000
(k) (k)
Docket No. RP16-235-000
Accepted: December 30, 2015
Page3of41
Gas Transmission Northwest LLC
FERC Gas Tariff
Fourth Revised Volume No. 1-A
PART 4.2
4.2 -Statement of Rates
ITS-1 Rates
v.6.0.0 Superseding v.5.0.0
STATEMENT OF EFFECTIVE RATES AND CHARGES FOR
TRANSPORTATION OF NATURAL GAS (a)
MILEAGE (n)
(0th-Mile)
Max. Min.
BASE (e) 0.000000
EXTENSION CHARGES
MEDFORD
E-1 (Medford) (f)
Rate Schedule ITS-1
NON-MILEAGE (o) DELIVERY (c)
(Dth) (0th-Mile)
Max. Min. Max. Min.
FUEL (d)
(0th-Mile)
Max. Min.
(e) 0.000000 0.000016 0.000016 0.0050% 0.0000%
0.002759 0.000000 0.004641 0.000000 0.000026 0.000026
COYOTE SPRINGS
E-3 (Coyote Springs) (i)
0.001282 0.000000 0.001283 0.000000 0.000000 0.000000
CARTY LATERAL
E-4 (Carty Lateral) (p)
SURCHARGES
ACA (k)
Issued: November 20, 2015
Effective: January 1, 2016
2016 Attachment H Pipeline Tariffrs
0.166475 0.000000 0.000000 0.000000
(k) (k)
Docket No. RP16-209-000
Accepted: December 22, 2015
Page 4 of 41
Gas Transmission Northwest LLC
FERC Gas Tariff
Fourth Revised Volume No. 1-A
PART 4.3
4.3 -Statement of Rates
Footnotes to Statement of Effective Rates and Charges
v.12.0.0 Superseding v.11.0.0
STATEMENT OF EFFECTIVE RA TES AND CHARGES
FOR TRANSPORTATION OF NATURAL GAS
Notes:
(a) The mileage component shall be applied per pipeline mile to gas transported by GTN for
delivery to shipper based on the primary receipt and delivery points in Shipper's contract.
Consult GTN's system map in Section 3 for receipt and delivery point and milepost
designations.
(b) The non-mileage component is applied per Shipper's MDQ at Primary Point(s) of Delivery
on Mainline Facilities.
(c) The delivery rates are applied per pipeline mile to gas transported by GTN for delivery to
shipper based on distance of gas transported. Consult GTN's system map in Section 3 for
receipt and delivery point and milepost designations.
(d) Fuel Use: Shipper shall furnish gas used for compressor station fuel, line loss, and other
utility purposes, plus other unaccounted-for gas used in the operation of GTN's combined
pipeline system in an amount equal to the sum of the current fuel and line loss percentage
and the fuel and line loss percentage surcharge in accordance with Section 6.38 of this
tariff, multiplied by the distance in pipeline miles transported from the receipt point to the
delivery point multiplied by the transportation quantities of gas received from Shipper
under these rate schedules. The current fuel and line loss percentage shall be adjusted each
month between the maximum rate of 0.0050% per 0th per pipeline mile and the minimum
rate of 0.0000% per Dth per mile. The fuel and line loss percentage surcharge is 0.0000%
per Dth per pipeline mile. No fuel use charges will be assessed for backhaul service.
Currently effective fuel charges may be found on GTN's Internet website under
"Informational Postings."
(e) Seasonal recourse rates apply to short-term firm (STF) service under Rate Schedule FTS-1
(i.e., firm service that has a term of less than one year and that does not include multiple­
year seasonal service) and IT Service under Rate Schedule ITS-I. By March 1 of each year
GTN may designate up to four (4) months as peak months during a twelve-month period
beginning on June I of the same year through May 31 of the following year. All other
months will be considered off-peak months. Reservation rate components that apply to
STF service and per-unit-rate IT service are as follows (delivery charges and applicable
surcharges continue to apply):
Peak NM Res.
Peak Mi. Res .
Issued: November 24, 2015
Effective: January 1, 2016
2016 Attachment H Pipeline Tariffrs
4 Peak
Mos.
$0.048150
$0.000608
3 Peak
Mos.
$0.048150
$0.000608
2 Peak
Mos.
$0.048150
$0.000608
1 Peak
Mo.
$0.048150
$0.000608
0 Peak
Mos.
$0.034393
$0.000434
Docket No. RP16-235-000
Accepted: December 30, 2015
Page 5 of 41
Gas Transmission Northwest LLC
FERC Gas Tariff
Fourth Revised Volume No. 1-A
Off-Pk NM Res.
Off-Pk Mi. Res.
$0.027515
$0.000347
PART4.3
4.3 -Statement of Rates
Footnotes to Statement of Effective Rates and Charges
v.12.0.0 Superseding v.11.0.0
$0.029807
$0.000376
$0.031642
$0.000399
$0.033142
$0.000418
$0.034393
$0.000434
Months currently designated as "Peak Months" may be found on GTN's Internet website
under "lnfonnational Postings." By March l of each year, GTN will post the Peak Months
for the upcoming twelve-month period beginning June 1 of the same year.
(f) Applicable to finn service on GTN's Medford Extension.
(g) Reserved for Future Use.
(h) E-2 (Diamond 1) is a negotiated reservation charge of $0.002972 per 0th per day for first
45,000 Dth/d and E-2 (Diamond 2) is a negotiated reservation charge of $0.001166 per Dth
per day for the second 45,000 Dth/d. During leap years, E-2 (Diamond 1) is a negotiated
reservation charge of $0.002964 per 0th per day for first 45,000 Dth/d and E-2
(Diamond 2) is a negotiated reservation charge of $0.001163 per Dth per day for the second
45,000 Dth/d.
(i) Applicable to firm service on GTN's Coyote Springs Extension.
G) The Overrun Charge shall be equal to the rates and charges set forth for interruptible service
under Rate Schedule ITS-I.
(k) In accordance with Section 6.22 of the Transportation General Terms and Conditions of this
FERC Gas Tariff, Fourth Revised Volume No. 1-A, all Transportation services that involve
the physical movement of gas shall pay an ACA unit adjustment. The currently effective
ACA unit adjustment as published on the Commission's website (www.ferc.gov) is
incorporated herein by reference. This adjustment shall be in addition to the Base Tariff
Rate(s) specified above.
(1) Reserved for Future Use.
(m) Reserved.
(n) The Rate Schedule ITS-I Mileage Component shall be applied per pipeline mile to gas
transported by GTN based on the distance of gas transported. Consult GTN's system map
in Section 3 for receipt and delivery point and milepost designations.
(o) The Rate Schedule ITS-1 Non-Mileage Component shall be applied per 0th of gas
transported by GTN for immediate delivery to the facilities of another entity or an extension
facility.
(p) Applicable to firm service on GTN's Carty Lateral Extension.
Issued: November 24, 2015
Effective: January 1, 2016
2016 Attachment H Pipeline Tariffrs
Docket No. RP16-235-000
Accepted: December 30, 2015
Page 6 of 41
Gas Transmission Northwest LLC
FERC Gas Tariff
Fourth Revised Volume No. 1-A
Issued: May 26, 2011
Effective: June 27, 2011
2016 Attachment H Pipeline Tariffrs
RESERVED FOR FUTURE USE
PART 4.4
4.4 -Statement of Rates
Reserved For Future Use
v.3.0.0 Superseding v.2.0.0
Docket No. RPI 1-2132-000
Accepted: June 10, 2011
Page 7 of 41
Gas Transmission Northwest LLC
FERC Gas Tariff
Fourth Revised Volume No. 1-A
PART 4.5
4.5 -Statement of Rates
Parking and Lending Service
v.6.0.0 Superseding v.5.0.0
STATEMENT OF EFFECTIVE RA TES AND CHARGES
FOR TRANSPORTATION OF NATURAL GAS FOR
Parking and Lending Service
($1Dth)
BASE TARIFF RA TE
MINIMUM MAXIMUM
PAL Parking and Lending Service: 0.0 0.243541/d
Notes:
Issued: November 20, 2015
Effective: January 1, 2016
2016 Attachment H Pipeline Tariffrs
Docket No. RP16-209-000
Accepted: December 22, 2015
Page 8 of 41
---------------------------------
Gas Transmission Northwest LLC
FERC Gas Tariff
Fourth Revised Volume No. 1-A
PART 4.6
4.6 -Statement of Rates
Negotiated Rate Agreements -FTS-1 and LFS-1
v.4.0.0 Superseding v.3.1.0
ST A TEMENT OF EFFECTIVE RA TES AND CHARGES
FOR TRANSPORTATION OF NATURAL GAS
NEGOTIATED RA TE AGREEMENTS UNDER RA TE SCHEDULES FTS-1 AND LFS-1
TERM OF
SHIPPER CONTRACT
Avista
Corporation /1
Powerex Corp.fl
Issued: April l, 2016
Effective: April l, 2016
11/1/01 -
10/31/25
04/01/16 -
10/31/16
2016 Attachment H Pipeline Tariffrs
RATE
SCHEDULE DTH/D
FTS-1 20,000
FTS-1 20,000
PRIMARY PRIMARY
RECEIPT DELIVERY RATE
POINT POINT /2 /3
Medford Medford Ext. /7
Meter
Kings gate Malin /5
Docket No. RP l 6-794-000
Accepted: April 26, 2016
Page 9 of 41
Gas Transmission Northwest LLC
FERC Gas Tariff
Fourth Revised Volume No. 1-A
PART 4.7
4.7 -Statement of Rates
Footnotes for Negotiated Rates -FTS-1 and LFS-1
v.6.0.0 Superseding v.5.0.0
STATEMENT OF EFFECTIVE RA TES AND CHARGES
FOR TRANSPORTATION OF NATURAL GAS
Negotiated Rate Agreements Under Rate Schedules FTS-1 and LFS-1
Explanatory Footnotes for Negotiated Rates
under Rate Schedules FTS-1 and LFS-1
/1 This contract does not deviate in any material aspect from the Form of Service Agreement
in this Tariff.
/2 Unless otherwise noted, all Shippers pay GTN's maximum Reservation Charge, Delivery
Charge, ACA, and contribute fuel in-kind in accordance with this Tariff.
/3 Index Price References: Unless otherwise noted, references to "Daily Index Price" shall
mean the price survey midpoint for the specified point as published in Gas Daily for the
day of gas flow. Weekend and holiday prices will be determined using the next available
Gas Daily publication. Unless otherwise noted, the references to the "NGI FOM" for a
specified point shall mean Natural Gas Intelligence's First of Month Bid Week Survey
(Supplement to NGl's Weekly Gas Index) Spot Gas Price for the specified point.
/4 Reserved
/5 GTN and Shipper have agreed to a Fixed Reservation Rate Charge of $0.26300 inclusive of
the mileage and non-mileage components, which shall be applicable to the Primary Receipt
and Delivery Points as well as secondary points, as follows:
Secondary Receipt Points: All points on GTN's system
Secondary Delivery Points: All points on GTN's system
In addition, Shipper shall pay all applicable charges and surcharges in accordance with
GTN's FERC Gas Tariff.
/6 Reserved
/7 The Reservation charge shall be equal to the rate set forth in GTN's FERC Gas Tariff
identified as FTS-1 E-2 (WWP), or its successor, multiplied by the appropriate Effective
Period Percentage as shown in the following table.
Effective Period
I I /1/01-10/31 /02
11/1/02-10/31/03
11/1/03-10/31/04
l l/l/04-10/31/05
Issued: April 1,2016
Effective: April 1, 2016
2016 Attachment H Pipeline Tariffrs
Percentage
75%
80%
85%
90%
Docket No. RP 16-794-000
Accepted: April 26, 2016
Page 10 of 41
Gas Transmission Northwest LLC
FERC Gas Tariff
PART4.7
4.7 -Statement of Rates
Footnotes for Negotiated Rates -FTS-1 and LFS-1
v.6.0.0 Superseding v.5.0.0
Fourth Revised Volume No. 1-A
/8
/9
/10
/11
/12
/13
/14
/15
/16
/17
/18
l 1/1/05-10/31/06
11/1/06-10/31 /25
95%
100%
The Daily Delivery Charge shall be equal to the 100% load factor equivalent of the FTS-1
E-2 rate, or its successor, and shall be multiplied by the positive difference between (a)
volumes delivered and (b) the contract MDQ times the appropriate Effective Period
Percentage.
Daily Delivery Charge = [Dth Delivered -(MDQ * Effective Period %)] * 100% Load
Factor Equivalent FTS-1 E-2
Reserved
Reserved
Reserved
Reserved
Reserved
Reserved
Reserved
Reserved
Reserved
Reserved
Reserved
Issued: April 1, 2016
Effective: April 1, 2016
Docket No. RP16-794-000
Accepted: April 26, 2016
2016 Attachment H Pipeline Tariffrs Page 11 of 41
Gas Transmission Northwest LLC
FERC Gas Tariff
Fourth Revised Volume No. 1-A
PART4.8
4.8 -Statement of Rates
Negotiated Rate Agreements -ITS-1 and PAL
v.5.0.0 Superseding v.4.0.0
STATEMENT OF EFFECTIVE RA TES AND CHARGES
FOR TRANSPORTATION OF NATURAL GAS
NEGOTIATED RA TE AGREEMENTS UNDER RA TE SCHEDULE ITS-I AND PAL
.SHIPPER
Issued: April 24, 2015
Effective: June I, 2015
TERM OF RATE
CONTRACT SCHEDULE DTH/D
2016 Attachment H Pipeline Tariffrs
PRIMARY
RECEIPT
POINT
PRIMARY
DELIVERY RATE
POINT /2 /3
Docket No. RP15-905-000
Accepted: May 29, 2015
Page 12 of 41
Gas Transmission Northwest LLC
FERC Gas Tariff
Fourth Revised Volume No. 1-A
PART4.9
4.9 -Statement of Rates
Footnotes for Negotiated Rates -ITS-I and PAL
v.5.0.0 Superseding v.4.0.0
STATEMENT OF EFFECTIVE RA TES AND CHARGES
FOR TRANSPORTATION OF NATURAL GAS
NEGOTIATED RA TE AGREEMENTS UNDER RA TE SCHEDULE ITS-I AND PAL
Explanatory Footnotes for Negotiated Rates under Rate Schedule ITS-I and PAL
/1 This contract does not deviate in any material aspect from the Form of Service Agreement
in this Tariff.
/2 Unless otherwise noted, all Shippers pay GTN's maximum Mileage and Non-Mileage
Charge, ACA, and contribute fuel in-kind in accordance with this Tariff.
/3 Index Price References: Unless otherwise noted, references to "Daily Index Price" shall
mean the price survey midpoint for the specified point as published in Gas Daily for the day
of gas flow. Weekend and holiday prices will be determined using the next available Gas
Daily publication. Unless otherwise noted, the references to the ''NGI FOM" for a specified
point shall mean Natural Gas Intelligence's First of Month Bid Week Survey (Supplement
to NGI's Weekly Gas Index) Spot Gas Price for the specified point.
Issued: April 24, 2015
Effective: June I, 2015
2016 Attachment H Pipeline Tariffrs
Docket No. RPI5-905-000
Accepted: May 29, 2015
Page13of41
Gas Transmission Northwest LLC
FERC Gas Tariff
Fourth Revised Volume No. 1-A
PART 4.10
4.10 -Statement of Rates
Non-Conforming Service Agreements
v.4.0.0 Superseding v.3.0.0
NON-CONFORMING SERVICE AGREEMENTS
PURSUANT TO§ 154.l 12(b)
Contract Rate Effective Termination
Name of Shipper Number Schedule Date Date
Cascade Natural Gas Corporation 152 FTS-1 11/1/1993 10/31/2023
Chevron USA Inc. 153 FTS-1 11/1/1993 10/31/2023
City of Burbank 154 FTS-1 11/1/1993 10/31/2023
IOI Resources, Inc. 158 FTS-1 11/1/1993 10/31/2013
Northern California Power Agency 163 FTS-1 11/1/1993 10/31/2023
Talisman Energy Inc 167 FTS-1 11/1/1993 10/31/2023
Paramount Resources US Inc. 168 FTS-1 11/1/1993 10/31/2023
Petro-Canada Hydrocarbons, Inc. 169 FTS-1 11/1/1993 10/31/2023
Sacramento Municipal Utility District 170 FTS-1 11/1/1993 10/31/2023
A vista Corporation 177 FTS-1 11/1/1993 10/31/2023
A vista Corporation 178 FTS-1 11/1/1993 10/31/2023
Cascade Natural Gas Corporation 179 FTS-1 11/1/1993 10/31/2023
Northwest Natural Gas Company 180 FTS-1 11/1/1993 10/31/2023
Puget Sound Energy, Inc. 181 FTS-1 11/1/1993 10/31/2023
A vista Corporation 182 FTS-1 11/1/1993 10/31/2023
A vista Corporation 2591 FTS-1 8/1/1995 10/31/2025
A vista Corporation 2857 FTS-1 11/1/1995 10/31/2025
A vista Corporation 2858 FTS-1 11/1/1995 10/31/2025
Iberdrola Renewables, Inc. 7828 FTS-1 6/3/2001 10/31/2025
A vista Corporation 8035 FTS-1 11/1/2001 10/31/2025
Pacific Gas and Electric Company 111 ITS-1 2/1/1992 10/31/2010
Northwest Natural Gas Company 112 ITS-I 4/1/1992 3/31/2011
Petro-Canada Hydrocarbons, Inc. 119 ITS-I 4/22/1992 4/22/2011
Morgan Stanley Capital Group Inc. 144 ITS-I 7/23/1993 9/30/2010
Shell Energy North America (US), L.P. 146 ITS-I 8/1/1993 8/1/2010
BP Canada Energy Marketing Corp. 4621 AIS-1 12/1/1996 12/31/2010
Sempra Energy Trading Corp. 4721 AIS-1 1/1/1997 12/31/2010
EnCana Marketing (USA) Inc. 4770 AIS-1 1/25/1997 12/31 /2010
Nexen Marketing U.S.A., Inc. 6759 AIS-1 6/17/1999 12/31 /2010
Shell Energy North America (US), L.P. 7047 AIS-1 4/10/2000 12/31/2010
Sierra Pacific Power Company 7068 AIS-1 4/27/2000 12/4/2019
City of Glendale 7804 AIS-1 5/30/2001 12/31/2021
Iberdrola Renewables, Inc. 7806 AIS-1 5/30/2001 12/31/2021
Petro-Canada Hydrocarbons, Inc. 7807 AIS-1 5/30/2001 12/31/2021
Chevron U.S.A. Inc. 7812 AIS-1 5/30/2001 12/31/2021
Salmon Resources Ltd. 7816 AIS-1 5/30/2001 12/31/2021
Constellation Energy Commodities
Group, Inc. 8038 AIS-1 8/2/2001 8/31/2021
Enserco Energy Inc. 8176 AIS-1 11 /27/2001 11/30/2021
ConocoPhillips Company 8228 AIS-1 1/8/2002 1/31/2022
UBS AG (London Branch) 8318 AIS-1 4/11/2002 4/30/2023
Issued: September 25, 2015 Docket No. RP 15-1294-000
Effective: October 26, 2015 Accepted: October 23, 2015
2016 Attachment H Pipeline Tariffrs Page 14 of41
Gas Transmission Northwest LLC PART 4.10
FERC Gas Tariff 4. 1 0 -Statement of Rates
Fourth Revised Volume No. 1-A Non-Conforming Service Agreements
v.4.0.0 Superseding v.3.0.0
Concord Energy LLC 8421 AIS-1 7/22/2002 7/31/2012
Tenaska Marketing Ventures 8559 AIS-1 1/1/2003 12/31/2012
Cargill, Inc. 8594 AIS-1 3/19/2003 3/31/2013
Merrill Lynch Commodities, Inc. 8674 AIS-1 6/13/2003 6/13/2023
Apache Corporation 8670 AIS-1 7/1/2003 6/30/2013
Tenaska Marketing Ventures 8880 AIS-1 12/1/2003 11/30/2013
California Dept. of Water Resources 8887 AIS-1 12/1/2003 7/1/2011
United Energy Trading, LLC 9002 AIS-1 3/1/2004 2/28/2014
Select Natural Gas LLC 8978 AIS-1 3/3/2004 3/3/2014
National Fuel Marketing Company LLC 9035 AIS-1 4/27/2004 4/30/2014
Fortis Energy Marketing & Trading GP 9115 AIS-1 7/17/2004 6/30/2014
Powerex Corp. 9149 AIS-1 8/16/2004 7/31/2014
Louis Dreyfus Energy Services L.P. 9281 AIS-1 11/8/2004 10/31/2014
Pacific Summit Energy LLC 9285 AIS-1 11/15/2004 10/31/2010
Devlar Energy Marketing, LLC 9630 AIS-1 6/1/2005 5/31/2015
Suncor Energy Marketing Inc. 9774 AIS-1 I 0/1/2005 9/30/2015
CanNat Energy Inc. 10197 AIS-1 7/26/2006 7/25/2011
Eagle Energy Partners I, LP 10308 AIS-1 10/27/2006 10/31/2011
Sequent Energy Management LP 10336 AlS-1 11/1/2006 10/31/2010
Occidental Energy Marketing, Inc. 10359 AIS-1 12/22/2006 12/31/2010
NextEra Energy Power Marketing, LLC 10625 AIS-1 4/10/2008 4/30/2018
Natural Gas Exchange, lnc. 10639 AIS-1 4/29/2008 4/30/2018
Citigroup Energy Inc. 10646 AIS-1 5/30/2008 5/31/2018
IGI Resources, Inc. 4576 PS-1 12/1/1996 12/31/2010
Macquarie Cook Energy, LLC 4619 PS-I 12/1/1996 12/31/2010
Sempra Energy Trading Corp. 4720 PS-I 1/1/1997 12/31/2010
EnCana Marketing (USA) Inc. 4868 PS-I 3/1/1997 12/31/2010
Shell Energy North America (US), L.P. 4908 PS-I 3/5/1997 12/31/2010
Husky Gas Marketing Inc. 5348 PS-I 7/3/1997 12/31/2010
Enserco Energy Inc. 5677 PS-I 10/6/1997 12/31/20 I 0
National Fuel Marketing Company LLC 5679 PS-I 10/7/1997 12/31/2010
United States Gypsum Company 5837 PS-I 11/3/1997 5/17/2010
Northwest Natural Gas Company 5992 PS-1 2/13/1998 12/31/2023
Chevron U.S.A. Inc. 6226 PS-1 5/14/1998 12/31/2010
San Diego Gas & Electric Company 6378 PS-I 8/25/1998 12/31/2010
Southern California Gas Company 6613 PS-I 12/14/1998 12/31/2010
Puget Sound Energy, Inc. 7061 PS-I 4/20/2000 4/20/2020
Hermiston Generating Company, L.P. 7798 PS-I 5/30/2001 12/31/2021
City of Glendale 7803 PS-I 5/30/2001 12/31/2021
Iberdrola Renewables, Inc. 7805 PS-I 5/30/2001 12/31/2021
Questar Energy Trading Company 7819 PS-1 5/30/2001 12/31/2021
El Paso Energy Marketing Company 7820 PS-I 5/30/2001 12/31/2021
Sempra Energy Trading Corp. 7833 PS-I 6/14/2001 6/8/2020
Constellation Energy Commodities
Group, Inc. 8037 PS-1 8/2/2001 8/31/2021
ConocoPhillips Company 8229 PS-I 1/8/2002 1/31/2022
Tractebel Energy Marketing, Inc. 8283 PS-1 3/14/2002 3/31/2022
UBS AG (London Branch) 8316 PS-I 4/11/2002 4/30/2023
Issued: September 25, 2015 Docket No. RP] 5-1294-000
Effective: October 26, 2015 Accepted: October 23, 2015
2016 Attachment H Pipeline Tariffrs Page 15 of 41
Gas Transmission Northwest LLC
FERC Gas Tariff
Fourth Revised Volume No. 1-A
RWE Trading Americas Inc.
Fortis Energy Marketing & Trading GP
Concord Energy LLC
Select Natural Gas LLC
Tenaska Marketing Ventures
Cargill, Inc.
United Energy Trading, LLC
Apache Corporation
Occidental Energy Marketing, Inc.
Tenaska Marketing Ventures
California Dept. of Water Resources
Devon Canada Marketing Corporation
Merrill Lynch Commodities, Inc.
Pacific Summit Energy LLC
Louis Dreyfus Energy Canada LP
Louis Dreyfus Energy Services L.P.
Devlar Energy Marketing, LLC
Suncor Energy Marketing Inc.
J.P. Morgan Ventures Energy Corporation
CanNat Energy Inc.
Eagle Energy Partners I, LP
Sequent Energy Management LP
El Paso Ruby Holding Company, LLC
Portland General Electric Company
Issued: September 25, 2015
Effective: October 26, 2015
2016 Attachment H Pipeline Tariffrs
8324
8340
8406
8534
8539
8595
8652
8668
8784
8873
8886
8923
9018
9173
9263
9273
9584
9772
9948
10195
10310
10332
12071
17293
PART 4.10
4.10 -Statement of Rates
Non-Conforming Service Agreements
PS-1
PS-1
PS-I
PS-1
PS-1
PS-I
PS-I
PS-I
PS-I
PS-1
PS-1
PS-1
PS-1
PS-1
PS-1
PS-1
PS-1
PS-1
PS-1
PS-1
PS-1
PS-1
FTS-1
FTS-1
v.4.0.0 Superseding v.3.0.0
4/16/2002 4/30/2022
5/2/2002 5/31/2022
7/22/2002 7/31/2012
11/15/2002 10/31/2012
12/1/2002 11/30/2012
3/19/2003 3/31/2013
5/23/2003 5/31/2013
7/1/2003 6/30/2013
9/10/2003 8/31/2013
12/1/2003 11/30/2013
12/1/2003 7/1/2011
2/1/2004 1/31/2014
4/7/2004 4/7/2014
8/30/2004 8/30/2010
10/29/2004 10/31/2010
11/4/2004 10/31/2014
5/2/2005 4/30/2015
10/1/2005 9/30/2015
2/1/2006 1/31/2016
7/26/2006 7/25/2011
10/27/2006 10/31/2011
11/1/2006 10/31/2011
11/1/2012 3/31/2018
10/31/2015 10/31/2045
Docket No. RP 15-1294-000
Accepted: October 23, 2015
Page 16 of 41
Northwest Pipeline LLC
FERC Gas Tariff
Fifth Revised Volume No. 1
STATEMENT OF RATES
Effective Rates Applicable to
Rate Schedules TF-1 , TF-2, TI -1 , TFL-1 and TIL-1
(Dollars per Dth)
Ra t e Schedule and
Type of Rate
Rat e Schedule TF-1 (4) (5)
Reservation
( Large Customer)
System-Wide
1 5 Year Evergreen Exp.
25 Year Evergreen Exp .
Volumetri c (2 )
(Large Customer)
System-Wide
15 Year Evergreen Exp .
25 Year Evergreen Exp .
(Small Customer) (6 )
Scheduled Overrun (2)
Rate Schedule TF-2 (4) (5)
Reservation
Volumetric
Scheduled Dail y Overrun
Annual Over r un
Rate Sch edule TI -1 (2)
Volumetric (7)
Rate Sch edul e TFL-1 (4) (5)
Rese r vation
Volume t ric (2)
Scheduled Overrun (2)
Rate Schedule TIL-1 (2)
Volumetric
2016 Attachment H Pipeline Tariffrs
Base
Tariff Rate(l), (3)
Mi nimum Maximum
.0000 0
.00000
.00000
. 00813
.00813
.00813
.00813
.00813
.00000
.00813
. 00813
.00813
.00813
.40888
.36164
.3414 0
.03000
.0081 3
.00813
. 72155
.44 000
.40888
.03000
.44000
.44 000
. 44000
Sixth Revised Sheet No. 5
Superseding
Fifth Revised Sheet No. S
Page 17 of 41
Northwest Pipeline LLC
FERC Gas Tariff
Fifth Revised Volume No. l
STATEMENT OF RATES (Continued)
Effective Rates Applicable to
Third Revised Sheet No. 5-A
Superseding
Second Revised Sheet No. 5-A
Rate Schedules TF-1 , TF-2 , TI-1, TFL-1 and TIL-1 (Continued)
(Dollars per 0th)
Entitlement Unauthorized Overrun and Underrun (8)
General System Unauthorized Daily Overrun
General System Unauthorized Daily Underrun
General Sys tem Unauthorized Underrun Imbalances
not eliminated after 72 hours
Customer -Specific Entitlement Penalty
Footnotes
Rate
(9)
10 .00000
10 .00000
10 .00000
(1) Rate excludes surcharges approved by the Commission.
(2) Annual Charge Adjustment {"ACAn) surcharge may be applicable . Section
16 of the General Terms and Conditions describes the basis and
applicability of the ACA surcharge.
2016 Attachment H Pipeline Tariffrs Page 18 of 41
Northwest Pipeline LLC
FERC Gas Tariff
Fifth Revised Volume No. l
STATEMENT OF RATES (Continued)
Effective Rates Applicable to
Ninth Revised Sheet No. 5-B
Superseding
Eighth Revised Sheet No. 5-B
Rate Schedules TF-1, TF-2, TI-1, TFL-1 and TIL-1 (Continued)
Footnotes (Continued)
(3) To the extent Transporter discounts the Maximum Base Tariff Rate , such
discounts wi l l be applied on a non -discriminatory basis, subject to the
policies of Order No. 497 .
Shippers receiving service under these rate schedules are required to
furnish fuel reimbursement in-ki nd at the rates specified on Sheet No.
14.
An incremental facilities charge or other payment method provided 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 Transportat i on Service Agreement.
In addition to the rates set forth on Sheet No. 5, Puget Sound Energy,
Inc.'s Transportation Servi ce Agreement No. 140053 is subject to an
annual incremental facility charge pursuant to Section 21 of the
General Terms and Conditions for the South Seattle Delivery Lateral
Expansion Project. The effective annual incremental facility charge is
$3 ,625,910 and is bill ed in equal monthly one-twelfth increments. The
daily incremental facility charge is $0.15546 per Dth.
In addition to the reservation rates shown on Sheet No. 5, Shippers who
contract for Columbia Gorge Expansion Project capacity are subject to a
facility reservati on surcharge pursuant to Section 3.4 of Rate Schedule
TF-1 . The facility charge used in deriving the Columbia Gorge Expansion
Project facility reservation surcharge has a minimum ra te of $0 and a
maximum rate during the indicated months or calendar years as follows:
(Dollars per Dth)
Year Rate Year Rate Year Rate
2013 $0.09549 2017 $0.07471 2021 $0.05409
2014 $0.09255 2018 $0.06876 2022 $0. 05273
2015 $0.08661 2019 $0 .06282 2023 $0 .05137
2016 $0 .08044 2020 $0.05671 2024 $0.05023
January 1 , 2025 -March 31, 202 5 $0 .02442
2016 Attachment H Pipeline Tariffrs Page 19 of 41
Northwest Pipeline LLC
FERC Gas Tariff
Fifth Revised Volume No. 1
STATEMENT OF RATES (Continued)
Effective Rates Appl i cable to
Fourth Revised Sheet No. 5-C
Superseding
Third Revised Sheet No. 5-C
Rate Schedules TF-1, TF-2 , TI-1 , TFL-1 and TIL-1 (Continued)
(Dol l ars per Dth)
Footnotes (Continued)
(4) All reservation rates are daily rates computed on the basis of 365 days
per year, except that such rates for leap years are computed on the
basis of 366 days.
For Rate Schedule TF-1 , t he 15-Year and 25-Year Evergreen Expansion
reservation and volumetric rates apply to Shippers receiving service
under Rate Schedule TF-1 Evergreen Expansion service agreements. The
System-Wide reservation and volumetric rates apply to Shippers
receiving service under all other Rate Schedule TF-1 service
agreements .
For Rate Schedule TF-1 , the 15-Year and 25-Year Evergreen Expansion
maximum base tari ff reservation rates are comprised of $0 .35745 and
$0 .33721 for transmission costs and $0 .00419 and $0.00419 for storage
costs, respectively. The System-Wide maximum base tariff reservation
rates for Rate Schedule TF-1 and the maximum base tariff reservation
rates for Rate Schedule TF-2 are comprised of $.40469 for transmission
costs and $0 .00419 for storage costs.
Fo r Rate Schedule TF-1 (Large Customer), the maximum base tariff
volumetric rates applicable to Shippers receiving service under Rate
Schedule TF-1 Evergreen Expansion service agreements are comprised of
$0.00775 for transmi ssion costs and $0.00038 for storage costs. The
maximum base tariff volumetric rates for all other services under Rate
Schedule TF-1 (Large Customer) and for services under Rate Schedul e TF-
2 are comprised of $0.02962 for transmissi on c osts and $0.00038 for
storage costs .
2016 Attachment H Pipeline Tariffrs Page 20 of 41
Northwest Pipeline LLC
FERC Gas Tariff
Fifth Revised Volume No. 1
STATEMENT OF RATES (Continued)
Effective Rates Applicable to
Fourth Revised Sheet No. 5-D
Superseding
Third Revised Sheet No. 5-D
Rate Schedules TF-1, TF-2, TI-1, TFL-1 and TIL-1 (Continued)
(Dollars per 0th)
Footnotes (Continued)
(5) Rates for Rate Schedules TF-1, TF-2 and TFL-1 are also 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 bids for
capacity release will be evaluated.) The reservation rate is the
comparable volumetric bid reservation charge applicable to Replacement
Shippers bidding for capacity released on a one-part volumetric bid
basis.
(6) For Rate Schedule TF-1 (Small Customer), the Maximum Base Tariff Rate
is comprised of $0.71277 for transmission costs and $0.00878 for
storage costs. Transporter will not transport gas for delivery for
Small Customers subject to this Rate Schedule TF-1 under any
interruptible Service Agreement or under any capacity release Service
Agreement unless such Small Customer has exhausted its daily levels of
firm service entitlement for that day .
(7) Rate Schedule TI-1 maximum base tariff volumetric rate is comprised of
$0.43542 for transmission costs and $0.00458 for storage costs.
(8) Applicable to Rate Schedul es TF-1, TF-2, TI-1, TFL-1 and TIL-1 pursuant
to Section 15 .5 of the General Terms and Conditions.
(9) 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
River , Stanfield Ore ., NW Can. Bdr. (Suma s), Kern River Opal, or El
Paso Bondad as reflected in the Daily Price Survey published in "Gas
Daily."
2016 Attachment H Pipeline Tariffrs Page 21 of 41
Northwest Pipeline LLC
FERC Gas Tariff
Fifth Revised Volume No. 1
Fourth Revised Sheet No. 6
Superseding
Third Revised Sheet No. 6
STATEMENT OF RATES (Continued)
Effective Rates App l icable to Rate Schedules DEX-1 and PAL
(Dollars per Dth)
Type of Rate
Rate Schedule DEX-1 (2),(4)
Deferred Exchange
Rate Schedule PAL
Park and Loan
Footnotes
Base
Tariff Rate (1), (3)
Minimum Maximum
. 00000 . 4400 0
. 00000 . 44000
(1) Rate excludes surcharges approved by the Commission.
(2 ) ACA surcharge may be applicabl e. Section 16 of the General Terms and
Conditions describes the basis and applicability of the ACA surcharge .
(3) To the extent Transporter discounts the maximum currently effective
tariff rate , such discounts will be applied on a non-discriminatory
basis , subject to the policies of Order No. 497 .
(4 ) Shi ppers receiving service under this rate schedule are required to
f ur nish fuel reimbursement i n-kind at the rates specified on Sheet No.
14, except as provi ded in Section 4 of Rate Schedule DEX-1.
2016 Attachment H Pipeline Tariffrs Page 22 of 41
Northwest Pipeline LLC
FERC Gas Tariff
Fifth Revised Volume No. 1
Sixth Revised Sheet No. 7
Superseding
Fifth Revised Sheet No. 7
STATEMENT OF RATES (Continued)
Effective Rates Applicable to Rate Schedules SGS-2F and SGS-2I
(Dol l ars per Dth)
Rate Schedule and
Type of Rate
Rate Schedule SGS-2F (2) (3) (4) (5)
Demand Charge
Pre-Expansion Shipper
Expansion Shipper
Capacity Demand Charge
Pre-Expansion Shipper
Expansion Shipper
Volumetric Bid Rates
Withdrawal Charge
Pre-Expansion Shipper
Expansion Shipper
Storage Charge
Pre-Expansion Shipper
Expansion Shipper
Rate Schedule SGS-2I
Volumetric
Footnotes
Base
Tariff Rate (1)
Minimum
0.00000
0.00000
0.00000
0.00000
0.00000
0.00000
0 .00000
0.00000
0.00000
Maximum
0.01558
0.0404 5
0.00057
0.0034 7
0.01558
0 .04045
0.00057
0.00347
0.00224
(1) Shippers receiving service under these rate schedules are required to
furnish fuel reimbursement in-kind at the rates specified on Sheet
No. 14.
2016 Attachment H Pipeline Tariffrs Page 23 of 41
Northwest Pipeline LLC
FERC Gas Tariff
Fifth Revised Volume No. 1
STATEMENT OF RATES (Continued)
Third Revised Sheet No. 7-A
Superseding
Second Revised Sheet No. 7-A
Effective Rates Applicable to Rate Schedules 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 also 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 bids for capacity release will be evaluated.) The
Withdrawal Charge and Storage Charge are applicable to Replacement
Shippers bidding for capacity released on a one-part volumetric bid
basis .
2016 Attachment H Pipeline Tariffrs Page 24 of 41
Northwest Pipeline LLC
FERC Gas Tariff
Fifth Revised Volume No. I
Footnotes
STATEMENT OF RATES (Continued)
Effective Rates Applicable to Rate Schedule LS-1
(Dollars per Dth)
Type of Rate
Demand Charge (2)
Capacity Demand Charge (2)
Liquefaction
Vaporization
Base
Tariff Rate ( 1)
0.02580
0.00330
0 .90855
0 .03386
Sixth Revised Sheet No. 8
Superseding
Fifth Revised Sheet No. 8
(1) Shippers rece1v1ng service under this rate schedule are required to
furnish fuel reimbursement in-kind at the rat e specified on Sheet No.
14.
(2) Rates are daily rates computed on the basis of 365 days per year,
except that rates for leap years are computed on the basis of 366 days.
2016 Attachment H Pipeline Tariffrs Page 25 of 41
Northwest Pipeline LLC
FERC Gas Tariff
Fifth Revised Volume No. 1
STATEMENT OF RATES (Continued)
Sixth Revised Sheet No. 8-A
Superseding
Fifth Revised Sheet No. 8-A
Effective Rates Applicable to Rate Schedules LS-2F and LS-2I
(Dollars per Dth)
Rate Schedule and
Type of Ra te
Rate Schedule LS-2F (3)
Demand Charge (2)
Capacity Demand Charge (2)
Volumetric Bid Rates
Vaporization Demand-Relat ed Charge (2)
Storage Capacity Charge (2)
Liquefaction
Vaporization
Rate Schedule LS-2I
Volumetric
Liquefaction
Vaporization
Footnotes
Base
Tariff Rate (1)
Minimum
0.00000
0 .00000
0 .00000
0 .000 00
0 .90855
0 .03386
0.00000
0 .90855
0.03386
Maxi.mum
0.02580
0.00330
0.02580
0.00330
0.90855
0.03386
0 .00662
0 .90855
0 .03386
(1) Shippers receiving service under these ra te schedules are required to
f urnish fuel reimbursement in-kind at the rates specified on Sheet No.
14.
(2) Rates are dai l y rates comput ed on t he basis of 365 days per year,
except that rates for leap years are computed on t he basis of 366 days .
(3) Rates are also 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 bids for capacity release will be eval uated.) The
Vaporizat ion Demand-Relat ed Charge and Storage Capacity Charge are
applicable to Replacement Shippers bidding for capacity released on a
one-part volumetric bid basis.
2016 Attachment H Pipeline Tariffrs Page 26 of 41
Northwest Pipeline LLC
FERC Gas Tariff
Fifth Revised Volume No. 1
STATEMENT OF RATES (Continued)
Fourth Revised Sheet No. 9
Superseding
Third Revised Sheet No. 9
Effective Rates Applicable to Rate Schedules 1S-3F and LD-4I
(Dollars 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-Related Charge (2)
Storage Capacity Charge (2)
Liquefaction Charge (4)
Vaporization Charge
Rate Schedule LD-4I
Volumetric Charge
Liquefaction Charge (4)
Footnotes
Base
Tariff Rate (1)
Minimum
0 .00000
0 .00000
0 .00000
0.00000
0 .90855
0.03386
0.00000
0 .90855
Maximum
0.02580
0.00330
0 .02580
0.00330
0.90855
0.03386
0 .78872
0 .90855
(1) Shippers receiving service under these rate schedules are required to
furnish fuel reimbursement in-kind a t the rates specified on Sheet No.
14.
(2) Rates are daily rates computed on th e basis of 365 days per year,
except that rates for l eap years are computed on the bas.ts of 366 days.
(3) Rates are also applicable to capacity release service except for short­
term capacity release transactions f or a term of one year or less that
take effect on or before one year from the date on which Transporte r is
notified of the release, which are not subject to the stated Maximum
Base Tariff Rate. (Sec tion 22 of the General Terms and Conditions
describes how bids for capacity release will be evaluated .) The
Vaporization Demand-Related Charge and Storage Capacity Charge are
applicable to Replacement Shippers bidding for capaci ty released on a
one-part volumetric bid basis.
(4) The Liquefact i on Charge wil l be trued-up annually pursuant to Section
14 .20 of the General Terms and Conditions.
2016 Attachment H Pipeline Tariffrs Page 27 of 41
Page 8.1
Westcoast Energy Inc.
TOLL SCHEDULES · SERVICE
TRANSPORTATION SERVICE • SOUTHERN
DEFINITIONS
1. In 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;
(b) "Kingsgate Export Point" 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
(c) "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
2. This Toll Schedule applies to all Firm Transportation Service -Southern, AOS and
Interruptible Transportation Service -Southern, including Import Backhaul Service, provided
by Westcoast on facilities in Zone 4 under the provisions of a Firm Service Agreement or an
Interruptible 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:
(a) 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 Agreement;
(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 General
Effective Date: April 1, 2014
2016 Attachment H Pipeline Tariffrs Page 28 of41
Page 8.2
Westcoast Energy Inc.
TOLL SCHEDULES • SERVICE
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
4. 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
5. If 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 Interruptible Transportation
Service, other than Import 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 Interruptible 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
Interruptible 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) of the
Effective Date: April 1, 2014
2016 Attachment H Pipeline Tariffrs Page 29 of 41
Page 8.3
Westcoast Energy Inc.
TOLL SCHEDULES -SERVICE
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 Interruptible 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 Interruptible 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 Interruptible
Transportation Service -Southern.
6. The amount payable by a Shipper to Westcoast in respect of AOS, Interruptible
Transportation Service -Southern, and Import 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, Interruptible Transportation Service -Southern and Import
Backhaul Service, respectively, by the Receipt Volume for such AOS or Interruptible
Transportation Service -Southern (as determined after applying the rules set out in
Section 5) or for such Import 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;
(b) 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
(c) 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.
2016 Attachment H Pipeline Tariffrs
Effective Date: April 1, 2014
Page 30 of 41
Westcoast Energy Inc.
TOLL SCHEDULES -SERVICE
APPENDIX A
DEMAND AND COMMODITY TOLLS
TRANSPORTATION SERVICE -SOUTHERN
Firm Transportation Service -Southern
Service Term
1 year
2 years
3 years
PNG
Delive~ Point
89.70
87.09
84.48
Inland
Demand Tolls
$/103m3/mo.
Huntingdon
Delive~ Area Delive~ Area*
229.37
222.69
216.01
395.91
384.38
372.85
Page 8.4
FortisBC
Kingsvale to
Huntingdon°
166.54
161.69
156.84
4 years 83.60 213.79 369.01 155.22
5yearsormore 82.73 211.56 365.16 153.60
• To be increased to the percentage amount of the applicable toll specified in a Service Agreement for
Enhanced T-South Service
•• For Firm Transportation Service -Southern provided by Westcoast pursuant to a Firm Service Agreement
dated April 15, 2002 between Westcoast and FortisBC Energy Inc.
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.
AOS and Interruptible Transportation Service -Southern
Commodity Tolls
$/103m3
PNG Inland Huntingdon
Months Delive~ Point Delive~ Area Delive~ Area
May 1, 2016 to 2.929 7.490 12.928
October 31, 2016
November 1, 2016 to 3.905 9.987 17.237
December 31, 2016
FortisBC
Kingsvale to
Huntingdon•
5.438
7.251
• For AOS provided by Westcoast pursuant to a Firm Service Agreement dated April 15, 2002 between
Westcoast and FortisBC Energy Inc.
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.
Effective Date: May 1, 2016
2016 Attachment H Pipeline Tariffrs Page 31 of41
Import Backhaul Service
Months
May 1, 2016 to
October 31, 2016
November 1, 2016 to
December 31 , 2016
Westcoast Energy Inc.
TOLL SCHEDULES -SERVICE
Inland
Delivery Area
5.438
7.250
Commodify Tolls
$/103m3
PNG
Delivery Point
9.999
13.332
Compressor
Station No. 2
12.928
17.237
Page 8.5
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.
2016 Attachment H Pipeline Tariffrs
Effective Date: May 1, 2016
Page 32 of 41
NOVA Gas Transmission Ltd.
Service
I. Rate Schedule FT-R
2. Rate Schedule FT-RN
3. Rate Schedule FT-D 1
4. Rate Schedule STFT
5. Rate Schedule FT-DW
6. Rate Schedule FT-P 1
7. Rate Schedule LRS
8. Rate Schedule LRS-3
9. Rate Schedule lT-R
10. Rate Schedule IT-D t
11 . Rate Schedule FCS
12. Rate Schedule PT
13. Rate Schedule OS
14. Rate Schedule CO2
15. Monthly Abandonment
Surcharge 2
16. Daily Abandonment
Surcharge 3
Table of Rates, Tolls and Charges
Page 1 of 1
Rates, Tolls and Charges
Refer to Attachment "I" for applicable FT-R Demand Rate per month based on a three
year term (Price Point "B") & Surcharge for each Receipt Point
Average Firm Service Receipt Price (AFSRP) $ 229.87/103m3
Refer to Attachment "I" for applicable FT-RN Demand Rate per month & Surcharge
for each Receipt Point
Refer to Attachment "2" for applicable FT-D Demand Rate per month based on a one
year term (Price Point "Z") & Surcharge for each Group I or Group 2 Delivery Point
Average FT-D Demand Rate for Group 1 Delivery Points $ 5.45/GJ
FT-D Demand Rate for Group 2 Delivery Points $ 5.08/GJ
FT-D Demand Rate for Group 3 Delivery Points $ 6.09/GJ
STFT Bid Price= Minimum of 100% of the applicable FT-D Demand Rate based on a
one year term (Price Point "Z") for each Group I Delivery Point
FT-DW Bid Price= Minimum of 125% of the applicable FT-D Demand Rate based on
a three year term (Price Point "Y") for each Group I Delivery Point
Refer to Attachment "3" for applicable FT-P Demand Rate per month
Contract Term Effective LRS Rat~ (~lQ'm1lda)'.)
1-5 years 11.75
20 vears 7.81
LRS-3 Demand Rate per month $ 129.55/103m3
Refer to Attachment "I" for applicable IT-R Rate for each Receipt Point
Refer to Attachment "2" for applicable IT-D Rate for each Delivery Point
The FCS Charge is determined in accordance with Attachment "1" to the applicable
Schedule of Service
Schedule No. PT Rate PT Gas Rate
9009-01001-1 $ 660.00/d 50.0 l03m3/d
Schedule No. __ C.h1.1.rge_
2016732105 $ 143.73 /103m3 / month
2016732103 $ 143.73 /103m3 I month
2016732101 $ 143 .73 II 03m3 / month
2016732102 $ 143.73 /103m3 / month
2016732106 $ 143.73 /I 03m3 I month
2011475772 $ 9.250.00 I month
2016732104 $ 805.00 / month
2003004522 Applicable IT-Rand IT-D Rate
2011476052/ $ 0.1665 I OJ subject to
2011476054 $ 717 000.00 Minimum Annual Charne
2011475056 / 2011476092 / $ 0.095 I OJ and
2016721799 $ I 000.00 I month
Tier CO.a Rate (i/103m3}
I 544.24
2 430.63
3 279.70
$1 J.94/103m3/month $0.32/GJ/month
$ 0.39/103m3/day $0.0104/GJ/day
I. Service under rate Schedules FT-D, FT-P and IT-D for delivery stations identified in Attachment 2, and stations identified on rate Schedules OS No.
2011476092, are subject to the ATCO Pipelines Franchist Fees pursuant to paragraph 15.13 of the General Terms and Conditions.
2. Monthly Abandonment Surcharge applicable to Rate Schedules FT-R, FT-D, FT-P, FT-RN. FT-DW, STFT, LRS-3, and the following Rate Schedules
OS: 2016732105, 2016732103, 2016732101, 2016732102, and 2016732106.
3. Daily Abandonment Surcharge applicable to Rate Schedules IT-R, IT-D, LRS, the following Rate Schedules OS: 2011476052, 2011476054,
20 I 1475056, 20 I 1476092, 20 I 6721799, 2003004522, and if applicable Over-Run Gas.
Effective Date: January 1, 2016 (Amended March 1, 2016)
2016 Attachment H Pipeline Tariffrs Page 33 of 41
NOVA Gas Transmission Ltd. Attachment 2
Delivery Point Rates
Page 1 of 5
Group 1 FT-0 ~nd Rat• IT-0 R~t• per Monlh Oellv.ry Point Group 1 o«llve,y Point Name Prlc• Point "Z'" per Day
Number ($/GJ) ($/GJ)
2000 AL8ERTA.B.C, BORDER 5,06 0,1832
31111 ALLIANCE CLAIRMONT INTERCONNECT APN 5.06 0.1832
31110 ALLIANCE EDSON INTERCONNECT APN 5.08 0.1832
31112 ALLIANCE SHELL CREEK INTERCONNECT APGC 5.08 0.1832
3002 BOUNDARY LAKE BORDER 5.08 0.1832
1958 EMPRESS BORDER 5,94 0.2141
3886 GORDONDALEBORDER 5.08 0.1832
6404 MCNEILL BORDER 5,94 0.2141
Group l FT -0 04tffl.and Rat• rr..o Rat• Subject to
Ddw,yPoklt Group :z O.llve,y Point Nam• per Month p,erOay ATCOPl,.llnu Pric• Point ·r N11mblir ($/GJ) ($/GJ) FninchlHfffs1
31000 A.T. PLASTICS SALES APN 6.08 0.1832 YO$
31001 ADM AGRI INDUSTRIES SALES APN 5.08 0.1832 Yes
3880 AECO INTERCONNECTION 5.08 0.1632
31003 AGRIUM CARSELAND SALES APS 5.08 0.1832
31002 AGRIUM FT. SASK SALES APN 5.08 0.1832 Yes
31004 AGRIUM REDWATER SALES APN 5.08 0.1832
31005 AINSWORTH SALES APGP 5.08 0.1832
31006 AIR LIQUIDE SALES APN 5.08 0.1832
3214 AKUINU RIVER WEST SALES 5.08 0.1832
31007 ALBERTA ENVIROFUELS SALES APN 5.08 0.1832 Yes2
31008 ALBERTA HOSP IT AL SALES APN 5.08 0.1832 Yes
3868 ALBERTA-MONTANA BORDER 5.08 0.1832
3297 ALDER FLATS SOUTH NO 2 SALES 5.08 0.1832
3059 ALLISON CREEK SALES 5.08 0.1832
31009 AL TASTEEL SALES APN 5.08 0.1832 Yes'
3562 AMOCO SALES (BP SALES TAP) 5.08 0.1832
31012 APL JASPER SALES APN 5.08 0.1832 Yes
3488 ARDLEY SALES 5.08 0.1832
3237 ASPEN SALES 5.08 0.1832
3682 ATUSIS CREEK EAST SALES 5.08 0.1832
3216 AURORA NO 2 SALES 5.08 0.1832
3135 AURORA SALES 5.08 0.1832
3288 BANTRY SALES 5.08 0.1832
3423 BASHAW WEST SALES 5.08 0.1832
31013 BAYMAG SALES APS 5.08 0.1832
3101-4 BEAR CREEK COGEN SALES APGP 5.08 0.1832
3299 BEAR RIVER WEST SALES 5.08 0.1832
3068 BEAVER HILLS SALES 5.08 0.1832
3268 BENBOW SOUTH SALES 5.08 0.1832
3933 BIG EDDY INTERCONNECTION 5.08 0.1832
3655 BIG PRAIRIE SALES 5.08 0.1832
3067 BIGSTONE SALES 5.08 0.1832
3285 BILBO SALES 5.08 0.1832
3468 BLEAK LAKE SALES 5.08 0.1832
3295 BOOTIS HILL SALES 5.08 0.1832
3225 BOTHA SALES 5.08 0.1832
3259 BOULDER CREEK SALES 5.08 0.1832
3164 BRAINARD LAKE SALES 5.08 0.1832
3289 BRAZEAU EAST SALES 5.08 0.1832
3918 BUFFALO CREEK INTERCONNECTION 5.08 0.1832
31015 BURDETI COGEN SALES APS 5.08 0.1832
3265 BURNT TIMBER SAi.ES 5.08 0.1832
3204 CABIN SALES 5.08 0.1832
3293 CADOGAN SALES 5.08 0.1832
3109 CALDWELL SALES 5.08 0.1832
31016 CALGARY ENERGY CENTRE SALES APS 5.08 0.1832 Yes
3262 CALUMET RIVER SALES 5.08 0.1832
3634 CANOE LAKE SALES 5.08 0.1832
3165 CANOE LAKE SALES NO 2 5.08 0.1832
3866 CARBON INTERCONNECTION 5.08 0.1832
3484 CARIBOU LAKE SALES 5.08 0.1832
3157 CARIBOU LAKE SOUTH SALES 5,08 0.1832
3106 CARMON CREEK SALES 5.08 0.1832
3248 CARMON CREEK EAST SALES 5.08 0.1832
3101 CAROLINE SALES 5.08 0.1832
31017 CARSELAND COGEN SALES APS 5.08 0.1832
3275 CARSON CREEK SALES 5.08 0.1832
3495 CAVALIER SALES 5.08 0.1832
31018 CHAIN LAKES COOP SALES APS 5.08 0.1832
3907 CHANCELLOR INTERCONNECTION 5.08 0.1832
3151 CHEECHAM WEST NO 2 SALES 5.08 0.1832
3622 CHEECHAM WEST SALES 5.08 0.1832
6014 CHEVRON AURORA SALES 5.08 0. 1832
31019 CHEVRON FT. SASK SALES APN 5.08 0.1832 Yes
3097 CHICKADEE CREEK SALES 5.08 0.1832
3305 CHIGWELL NORTH SALES 5.08 0.1832
TARIFF Effective: January 1, 2016 (Amended July 1, 2016)
2016 Attachment H Pipeline Tariffrs Page 34 of 41
NOVA Gas Transmission Ltd. Attachment 2
Delivery Point Rates
Page 2 of 5
Group.: fT-0 Demand Rat• IT•OR1t11t Subjecl to per Month Dellve,ry Point Group 2 Delivery Point Name Price Poln1 '"Z"' JMtrOay ATCO PiptlU,w1
Numhr (I/OJ) (SIGJ) Franchls.e F.es.'
3496 CHIPEWYAN RIVER SALES 5.08 0.1832
3163 CHRISTINA LAKE NORTH SALES 5.08 0.1832
31020 CLOVERBAR FIBERGLASS SALES APN 5.08 0.1832 Yes
31021 CLOVERBAR POWER PLANT SALES APN 5.08 0.1832 Yes
3158 CL YOE NORTH SALES 5-08 0.1832
31022 COALDALE COGEN SALES APS 5.08 0.1832
1417 COLD LAKE BORDER 5.08 0.1832
3168 COLLICUTI SALES 5.08 0.1832
3239 CONKLIN SALES 5.08 0.1832
3416 COUSINS A SALES 5.08 0.1832
1963 COUSINS 8 & C SALES 5.08 0,1832
3483 CRAMMOND SALES 5.08 0.1832
3202 CRANBERRY LAKE EAST SALES 5.08 0.1832
3219 CRANBERRY LAKE EAST SALES NO 2 5.08 0.1832
3105 CRANBERRY LAKE SALES 5.08 0.1832
3897 CROSSFIELD EAST INTERCONNECTION 5.08 0.1832
3291 CROSSFIELD EAST NO 3 SALES 5.08 0.1832
3172 CROSSFIELD SALES 5.08 0.1832
5024 CROW LAKE SALES 5.08 0.1832
3071 CYNTHIA SALES 5.08 0.1832
3199 DAWES LAKE NORTH SALES 5.08 0.1832
3147 DAWES LAKE SALES 5.08 0.1832
3184 DAWES LAKE SALES NO 2 5.08 0.1832
3119 DEAORICK CREEK SALES (RETURN RUN) 5,08 0.1832
3065 DEEP VALLEY CREEK SALES 5.08 0.1832
3124 DEEP VALLEY CREEK SOUTH SALES 5.08 0.1832
31023 DEGUSSA CANNJA INC. SALES APN 5.08 0.1832
3465 DEMMITI SALES 5.08 0.1832
3121 DEMMITI SALES NO 2 5.08 0.1832
3277 DEMMITI NO 3 SALES 5.08 0,1832
31024 DEVONIA LAKE SALES APN 5.08 0.1832
6011 DOVER SALES 5.08 0.1832
3186 DUNKIRK RIVER SALES 5.08 0.1832
3098 DUTCH CREEK SALES 5.08 0.1832
3632 EAST CALGARY SALES 5.08 0,1832
31027 EASYFORD SALES APN 5.08 0.1832
31028 ECHO MIDPOINT SALES APN 5.08 0.1832
3175 EGG LAKE SALES 5.08 0.1832
3129 EKWANSALES 5.08 0.1832
3456 ELK POINT SALES 5.08 0.1832
3270 ELK RIVER SOUTH NO 2 SALES 5.08 0.1832
3082 ELK RIVER SOUTH SALES 5.08 0.1832
3651 ELK RIVER SOUTHWEST SALES 5.08 0.1832
31029 ENV1ROFORS PRESERVERS SALES APN 5.08 0.1832 Yes2
3469 EVERGREEN SALES 5.08 0.1832
31030 EXSHAW LIME SALES APS 5.08 0.1832
31031 FALHER ALFALFA PLANT 1 SALES APWM 5.08 0.1832 Yes
31032 FALHER ALFALFA PLANT 2 SALES APWM 5.08 0.1832 Yes
3185 FAWCETI RIVER NORTH SALES 5.08 0.1832
3159 FAWCETI RIVER SALES 5.08 0.1832
3107 FERGUSON SALES 5.08 0.1832
3623 FERINTOSH NORTH SALES (RETURN RUN) 5.08 0.1832
3430 FERINTOSH SALES 5.08 0.1832
3182 FERRIER SOUTH A SALES 5.08 0,1832
3077 FIRE CREEK SALES 5.08 0.1832
3154 FIREBAG SALES 5.08 0.1832
3138 FISHER CREEK SALES 5.08 0.1832
31033 FORESTBURG SALES APNI 5.08 0.1832
3247 FORT KENT NO 2 SALES 5.08 0.1832
31034 FORT MACLEOD COGEN SALES APS 5.08 0.1832
31036 FT SASK SULPHIDES SALES APN 5.08 0.1832 Yes
31035 FT SASK VEGETABLE OIL SALES APN 5.08 0.1832
31010 FT. SASK FRAC SALES APN 5.08 0.1832 Yes
31011 FT. SASK UTILITY SALES APN 5.08 0.1832 Yes
3490 GAETZ LAKE SALES 5.08 0.1832
3128 GARRINGTON SALES 5.08 0.1832
3616 GAS CITY SALES 5.08 0.1832
31037 GENESEE PLANT GROUP SALES APN 5.08 0.1832
31038 GEON CANADA INC. SALES APN 5.08 0.1832
31039 GEORGIA PACIFIC SALES APN 5.08 0.1832 Yes
3201 GERMAIN SALES 5.08 0.1832
3195 GILBY SALES 5.08 0.1832
3624 GODS LAKE SALES (RETURN RUN) 5.08 0.1832
3087 GOLD CREEK SALES 5.08 0.1832
31040 GOLDEN SPIKE SALES APN 5.08 0.1832
3213 GORDONDALE EAST SALES 5.08 0.1832
3659 GRAHAM SALES 5.08 0.1832
31041 GRANDE CACHE MINE SALES APGC 5.08 0.1832
3055 GRANDE PRAIRIE SALES 5.08 OJ832
3183 GRANOR SALES 5,08 0.1832
TARIFF Effective: January 1, 2016 (Amended July 1, 2016)
2016 Attachment H Pipeline Tariffrs Page 35 of 41
NOVA Gas Transmission Ltd. Attachment 2
Delivery Point Rates
Page 3 of 5
Group 2 n .0 Otma·nd Rat• IT·OR.att St.tbjtcl to per Month O.Hv.ty Point Group Z D•llvuy Point Name Price Point "ZR per Day ATCO Plptllnu
NumMr ($/GJ) ($/GJ) FranchlM fNs1
3464 GREENCOURT WEST SALE-S 5.08 0.1632
3229 GRIST LAKE SALES 5.08 0.1832
3117 GRIZZLY SALES 5.08 0.1832
3224 HANGINGSTONE SALES 5.08 0.1832
3414 HANNA SOUTH B SALES 5.08 0.1832
3294 HARMATIAN-ELKTON SALES 5.08 0,1832
3437 HARMATIAN SALES 5.08 0.1832
3615 HAYNES SALES 5.08 0.1832
3100 HEART RIVER SALES 5.08 0.1832
3240 HEART RIVER NO 2 SALES 5.08 0.1832
31091 HEARTLAND OFF GAS SALES APN 5.08 0.1832 Yes
310<42 HEARTLAND UPGRADER SALES APN 5.08 0.1832
3276 HEISLER SALES 5.08 0.1832
3861 HERMIT LAKE NO 2 SALES 5.08 0.1832
3162 HOOLE SALES NO 2 5.08 0.1832
3181 HOOLE SALES NO 3 5.08 0.1832
3153 HORIZON SALES 5.08 0.1832
31043 HR MILNER POWER PLANT SALES APGC 5.08 0.1832
3125 HUGGARD CREEK SALES 5.08 0.1832
31044 HUSKY OIL LLOYDMINISTER SALES APN 5.08 0.1832 Yes
31045 1.0.L STRATHCONA REFINERY SALES APN 5.08 0.1832 Yes2
3472 INNISFAIL SALES 5.08 0.1832
3193 IPIATIK LAKE SALES 5.08 0.1832
3282 IROQUOIS CREEK SALES 5.08 0.1832
3156 JACKFISH SALES 5.08 0.1832
3166 JACKPINE SALES 5.08 0.1832
3133 JACKPOT CREEK SALES (RETURN RUN) 5.08 0,1832
3860 JANUARY CREEK INTERCONNECTION 5.08 0.1832
6012 JAPf,J,I CANADA SALES 5.08 0.1832
3246 JAPAN CANADA NO 2 SALES 5.08 0.1832
3818 JENNER EAST SALES 5.06 0.1832
3864 JOFFRE INTERCONNECTION 5.06 0.1832
3269 JONES LAKE NO 2 SALES 5.06 0.1832
3152 JOSLYN CREEK SALES 5.06 0.1832
3078 JUDY CREEK SALES 5.08 0.1832
31129 JUMPING POUND SALES APS 5.08 0.1832
3273 KAYBOB SALES 5.08 0.1832
3222 KAYBOB SOUTH NO 3 SALES 5.06 0.1832
3242 KAYBOB SOUTH SALES 5.06 0.1832
3192 KEARL SALES 5.06 0.1832
31046 KEEPHILLS 3 SALES APN 5.06 0.1832
3179 KENT SALES 5.06 0.1832
3150 KETILE RIVER NORTH NO 2 SALES 5.08 0.1832
3249 KETILE RIVER SALES 5.08 0.1832
3258 KIDNEY LAKE SALES 5.08 0.1832
3203 KOMIE EAST SALES 5.08 0.1832
3931 KV OIL Sf,J,IDS EX 5.08 0.1832
3476 LAC LA BICHE SALES 5.08 0.1832
310<47 LAFARGE SALES APS 5.08 0.1832
31048 LAMB WESTON SALES APS 5.08 0.1832
3460 LANDON LAKE SALES 5.08 0.1832
310<49 LEGAL ALFALFA SALES APN 5.08 0-1832
31131 LINQUIST COULEE SALES APS 5.08 0.1832
3187 UTILE SUNDANCE SALES 5.08 0.1832
3196 LIVOCK SALES 5.08 0.1832
3474 LLOYD CREEK SALES 5.08 0.1832
31133 LOBSTICK SALES APN 5.06 0.1832
3482 LONE PINE CREEK SALES 5.06 0.1832
3608 LOSEMAN LAKE SALES 5.08 0.1832
3080 LOUISE CREEK SALES 5.08 0.1832
31132 LUNNFORD SALES APN 5.08 0.1832
3236 MACKAY SALES 5.08 0.1832
3146 MAHIHKAN SALES 5.08 0.1832
31096 M/>NAWAN LAKE SALES APN 5.08 0.1832
31099 MASKWA CREEK SAi.ES APN 5.08 0.1832
3604 MARGUERITE LAKE SALES 5.08 0.1832
3209 MARLOW CREEK SALES 5.08 0. 1832
3110 MARSH HEAD CREEK WEST SALES 5.08 0.1832
31135 MAZEPPA SALES APS 5.08 0.1832
31050 MCCAIN FOODS SALES APS 5.08 0.1832
3211 MEGA RIVER SALES 5.08 0.1832
6021 MILDRED LAKE NORTH SAi.ES 5.08 0.1832
3120 MILDRED LAKE SAi.ES 5.08 0.1832
31051 MILLAR WESTERN FOREST PROD LTD SALES APNI 5.08 0.1832 Yes
3653 MINNEHIK BUCK LAKE SALES 5.08 0.1832
3111 MINNOW LAKE SOUTH SALES 5.08 0.1832
31052 MITSUE PLANT SALES APNI 5.08 0.1832
3889 MITSUE SALES INTERCONNECTION 5.08 0.1832
31053 MOBIL FUEL GAS SALES APN 5.08 0.1832 Yes
31521 MONTANA BAND AP 5.08 0.1832
TARIFF Effective: January 1, 2016 (Amended July 1, 2016)
2016 Attachment H Pipeline Tariffrs Page 36 of 41
NOVA Gas Transmission Ltd. Attachment 2
Delivery Point Rates
Page 4 of 5
Gro1.1p2 FT .O o.mand R.ille IT-0 Rate S1.1b)ectlo per Month O.liv.,y Point Group 2 Dellwry Point Nam• Price Point "Z"' per Day ATCO Pipelines
NtimWr ($/OJ) ($/OJ) Franchise fees1
3167 MOOREHEAD SALES 5.08 0.1632
3930 MOOSA EXCHANGE 5,06 0.1632
3261 MUSKEG CREEK SALES 5.06 0.1832
3280 MUSKWA RIVER SALES 5.08 0.1832
3208 MUSREAU LAKE NO 2 SALES 5.08 0.1832
31123 NCL REDWATER FRACTIONATOR NORTH SALES APN 5.06 0.1832
31055 NCL REDWATER FRACTIONATOR SALES APN 5.08 0.1832
3658 NOSE MOUNTAIN SALES 5,06 0.1832
3479 NOSEHILL CREEK NORTH SALES 5.08 0.1832
3470 NOSEHILL CREEK SALES 5.08 0.1832
31056 NOVA CHEMICALS SALES APS 5.08 0.1832
31057 OBED MOUNTAIN COAL SALES APN 5.08 0.1832
31098 OHATON SALES APN 5.08 0.1832
3660 OLDS SALES 5.08 0.1832
31134 OLDS SALES APS 5.08 0.1832
3478 ONETREE SALES 5.08 0.1832
3300 OTAUWAU SALES 5.08 0.1832
31130 PADDLE RIVER SALES APN 5.08 0.1832
3072 PADDY CREEK SALES 5.08 OJ832
31058 PEMBINA CTS NO 9 SALES APN 5.08 0.1832
31059 PETROCAN AIR PRODUCTS SALES APN 5.08 0.1832 Yes2
31060 PETROCAN REFINERY SALES APN 5,08 0.1832 Yes2
31061 PIGEON LAKE SALES APN 5.08 0.1832
3444 PINCHER CREEK SALES 5.08 0.1632
3086 PINE CREEK SALES 5.08 0.1832
3178 POINTE LA BICHE SALES 5.08 0.1632
31062 PRAIRIE CREEK SALES APGC 5,08 0.1832
3287 PROGRESS SALES 5.08 0.1832
3174 QUIRK CREEK SALES NO 2 5.08 0.1832
3076 RAINBOW SALES 5.08 0.1832
3131 RASPBERRY LAKE SALES 5.08 0.1832
3819 RAT CREEK WEST INTERCONNECT 5.08 0.1832
31063 RED DEER GRAIN PROCESSORS SALES APN 5.08 0.1832 Yes
31064 REDWATER COGEN SALES APN 5.08 0.1832
31120 REDWATER CONSERVATION PLANT SALES APN 5.08 0.1832
31344 REDWATER UPGRADER UTILITY SALES APN 5.08 0.1832
31065 RENAISSANCE SALES APS 5.08 0.1832
3256 RESTHAVEN SALES 5.08 0.1832
3298 RICINUS SALES 5.08 0.1632
3263 RIMBEY SALES 5.08 0.1832
3652 ROBB SALES 5.08 0.1832
31066 ROCKY RAPIDS SALES APN 5.08 0.1832
3635 ROD LAKE SALES DELIVERY 5.08 0.1832
31093 RODINO SALES APN 5.08 0.1632
31067 ROGERS SUGAR SALES APS 5.06 0.1832 Yes
3446 ROSS CREEK SALES 5.08 0.1832
3169 SMMISSALES 5.06 0.1832
3095 SAKWATMIAU SALES 5.08 0. 1832
3139 SALESKISALES 5.08 0.1832
3050 SARATOGA SALES 5.08 0.1832
3609 SARRAIL SALES 5.08 0.1832
3207 SATURN SALES 5.08 0.1632
3301 SAUL TEAUX SALES 5.08 0.1632
3241 SAWN LAKE EAST NO 2 SALES 5.08 0.1632
3238 SAWN LAKE EAST SALES 5.08 0.1632
31068 SCHULLER INT JOHNS MANVILLE SALES APS 5.08 0.1632 Yes
31125 SCOTFORD HYDROGEN SALES APN 5,08 0.1632
31069 SCOTFORD UP EXP PHASE 1 SALES APN 5.08 0.1832
3264 SEDGEWICK SALES 5.08 0.1632
3862 SEVERN CREEK INTERCONNECTION 5.08 0.1832
3613 SHANTZ SALES 5.08 0.1832
31070 SHEERNESS SALES APSI 5.08 0.1832
31071 SHELL SCOTFORD SALES APN 5.08 0.1632
31072 SHELL UPGRADER MASTER SALES APN 5.08 0.1832
31127 SHEPARD ENERGY CENTRE SALES APS 5.06 0.1832 Yes
31073 SHERRITI INTERNATIONAL SALES APN 5.,08 0.1832 Yes
3494 SILVER VALLEY SALES 5.06 0.1832
3274 SIMONETIE NO 2 SALES 5.08 0.1832
31074 SLAVE LAKE PULP MILL SALES APNI 5.08 0.1832
3210 SNUFF MOUNTAIN NORTH SALES 5.08 0.1632
3099 SOUSA CREEK EAST SALES 5.08 0.1832
3140 SOUTH ELKTON SALES 5.08 0.1832
3149 SOUTH TERMINAL SALES 5.08 0.1832
3429 ST. PAUL SALES 5.08 0.1632
3272 STEEN RIVER SALES 5.08 0.1832
3600 STORNHAM COULEE SALES 5.08 0.1832
3271 ST RAC HAN SALES 5.08 0.1832
31075 STRATHCONA BUILDING PRODUCTS SALES APN 5.08 0.1832 Yes
31076 STYRENE PLANT SALES APN 5.08 0.1832
31077 SUMMIT LIME WORKS SALES APSI 5.08 0.1832 Yes
TARIFF Effective: January 1, 2016 (Amended July 1, 2016)
2016 Attachment H Pipeline Tariffrs Page 37 of 41
NOVA Gas Transmission Ltd.
Group 2 FT-D o.,,.and Rate
,-,Month OtNwi,y Polnl Group 2 O.Hwry Point Nam• Price Point "Z" Number ($/OJ)
31078 SUN GRO HORTICULTURE LTD SALES APN 5,08
3130 SUNDANCE CREEK EAST SALES 5.08
3205 SUNDAY CREEK SOUTH NO 2 SALES 5.08
3497 SUNDAY CREEK SOUTH SALES 5.08
31092 SWAN HILLS MISCIBLE INJECTION SALES APN 5.08
31079 SWAN HILLS WASTE TREATMENT SALES APN 5.08
31060 TABER COGEN SALES APS 5.08
3218 TEEPEE CREEK SALES 5.08
3656 TONY CREEK NORTH SALES 5.08
31081 TRANSALTA POWER PLANTS SALES APN 5.08
3198 TREMBLAY NO 2 SALES 5.08
3221 TREMBLAY WEST SALES 5.08
31122 TRIBUTE SALES APN 5.08
314'1 TUCKER LAKE SLS 5.08
3113 TWINLAKES CREEK SALES 5.08
1250 UNITY BORDER 5.08
31082 UNIVERSITY OF ALBERTA SALES APN 5.08
3088 VALHALLA SALES 5.08
3292 VANDERSTEENE LAKE SALES 5.08
31083 VIOLET GROVE SALES APN 5.08
3296 VIRGINIA HILLS NO 2 SALES 5.08
3103 VIRGO SALES 5.08
3206 WAPASU CREEK SALES 5.08
3281 WAPITI CENTRAL SALES 5.08
3227 WAPITI NORTH SALES 5.08
3251 WAPITI SOVTH SALES 5.08
3177 WARWICK SOVTH SALES 5.08
3948 WARWICK SOUTHEAST INTERCONNECTION 5.08
3074 WATERTON SALES 5.08
3171 WATERTON SALES NO 1 5.08
3264 WATINO SALES 5.08
3412 WAYNE NORTH B SALES 5.08
31084 WELDWOOD HINTON SALES APN 5.08
3255 WEMBLEY NO 2 SALES 5.08
3114 WEMBLEY SALES 5.08
3173 WEMBLEY SOUTH SALES 5.08
3230 WEMBLEY WEST SALES 5.08
31085 WEST EDMONTON CEMENT SALES APN 5.08
31086 WEST EDMONTON PLASTICS SALES APN 5.08
3228 WEST ELLS SALES 5.08
3486 WESTERDALE SALES 5.08
3871 WESTLOCK SALES INTERCONNECTION 5.08
31087 WEYERHAEUSER EDSON SALES APN 5.08
31088 WEYERHAUSER DRAYTON VALLEY SALES APN 5.08
31089 WEYERHAUSER GRANDE PRAIRIE SALES APGP 5.08
3191 WHISKEY JACK LAKE SALES 5.08
3267 WHITBURN EAST SALES 5.08
31090 WHITECOURT POWER LP SALES APNI 5.08
3663 WHITECOURT SALES 5.08
3176 WHITESANDS SALES 5.08
3231 WIAU LAKE SALES 5.08
3069 WILSON CREEK SOUTH SALES 5.08
3421 WIMBORNE SALES 5.08
3263 WINDFALL SALES 5.08
3148 WINEFRED SALES 5.08
1. Subjed to the ATCO PlpoMno, Fraochhst FHt puBuant lo paragraph 15, 13 of the Gen1m1I Terms and Condl~ooa.
2. ATCO Pipelinu Franchin Fee is current)y 0,00% at lhen locaUor.s,
FT -0 o.m.nd R~I•
Group .J O.tlwry Point fMme per Month
($/OJ)
All Group 3 Delivery Points 6.09
TARIFF
2016 Attachment H Pipeline Tariffrs
Attachment 2
Delivery Point Rates
Page 5 of 5
IT-0 Rat• Subject to
pt,rD•)' ATCO PlpeHhH
($/OJ) Franctllsa Fffs1
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832 Yes
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0,1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832 Yes
0.1832
0.1832
0.1832
0.1832
0.1832 Yes
0.1832 Yes
0.1832
0.1832
0.1832
0.1832 Yes
0.1832 Yes
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
0.1832
Effective: January 1, 2016 (Amended July 1, 2016)
Page 38 of 41
NGTL System Page I of 3
TransCanada
In business to deliver
NGTL System
TransCanada's -NGTL System Transportation Rates & Abandonment Surcharge
2016 Final Rates -Effective January 1, 2016
Receipt and delivery transportation /?ates below do not include applicable aban<,lonment surcharges.
Receipt Services
FT-R Average Demand Rate (3 yr term) 1
IT -R (Interruptible Receipt)
Delivery Services
FT-D Demand Rate (1 yr term) 2
Group 1:
Empress/McNeil! Border
Alberta-B.C. Border
Gordondale Border/Boundary Lk Border
ATCO: ClairmonUShell Creek/Edson
Group 2:
All Group 2 delivery points
Group 3:
All Group 3 delivery points
IT-D (Interruptible Delivery)
Group 1:
2016 Attachment H Pipeline Tariffrs
Tariff Rate Information Purposes
$/1 O'm• ¢fGJfd ¢/Mcf/d ¢/MMBtu/d
(US)
16.0
18.4
(Cdn) (Cdn) (Cdn)
229.87/mo
8.67/d
Tariff Rate
$GJ
(Cdn)
5.94/mo
5.08/mo
5.08/mo
5.08/mo
5.08/mo
6.09/mo
19.9
22.9
21 .3
24.6
Information Purposes
¢/GJ/d ¢/Mcf/d ¢/MMBtu/d
(Cdn) (Cdn) (US)
19.5 20.8 15.6
16.7 17.8 13.3
16.7 17.8 13.3
16.7 17.8 13.3
16.7 17.8 13.3
20.0 21.4 16.0
Page 39 of 41
http://www.transcanada.com/ customerexpress/27 66.html ?print=yes 7/19/2016
NGTL System
Monthly Abandonment Surcharge
Daily Abandonment Surcharge
$/103m3
(Cdn)
¢/GJ/d
(Cdn)
11 .94/mo 0.32/mo
0.39/d 0.0104/d
¢/Mcf/d
(Cdn)
0.34/mo
0.01/d
Page 3 of 3
-The services to which abandonment surcharges apply are denoted on the NGTL Tariff Table of Rates, Tolls and
Charges.
Other information for TransCanada's NGTL System:
Current
Receipt Point Rates
Fuel Rates
AB Border Heat Values
Delivery Point Rates
Disclaimer:
Archives
Receipt Poin1 Rates
Fuel Rates (2004 -2010) (22 KB, XLS)
Fuel Rates (2000 -2004) (41 KB, DOC)
AB Border Heat Values (61 KB, PDF)
The pricing and tolls information included on this website is intended to be used for planning purposes only and
although TransCanada endeavours to maintain the information in such a way that is accurate and current, it may not
provide accurate results. Use of this information is at user's sole risk and TransCanada shall not be liable for user's use
or reliance on any results obtained from it.
Page Updated: 2016-05-24 17:06:41h CT
Customer Express Home >1 Pricing & Tolls » NGTL System
Copyright© 2016 TransCanada Pipelines Limited
2016 Attachment H Pipeline Tariffrs
http://www.transcanada.com/ customerexpress/2 7 66 .html ?print=yes
Page 40 of 41 7/19/2016
Foothills Pipe Lines Ltd.
TABLE OF EFFECTIVE RATES
1. Rate Schedule FT, Firm Transportation Service
Zone6
Zone 7
Zone 8*
Zone 9
Demand Rate
($/GJ/Km/Month)
0.0065420922
0.0036177806
0.0145216983
0.0086057582
2. Rate Schedule OT, Overrun Transportation Service
Commodity Rate
($/GJ/Km)
Zone6
Zone 7
0.0002359443
0.0001304773
3. Rate Schedule IT, Interruptible Transportation Service
Commodity Rate
($/GJ/Km)
Zone 8* 0.0005237334
Zone 9 0.0003103716
4. Monthly Abandonment Surcharge**
All Zones 0.1047843362 ($/GJ/Month)
5. Daily Abandonment Surcharge***
All Zones
* For Zone 8, Shippers Haul Distance shall be 170.7 km.
0.0034355520 ($/GJ/Day)
Page 1
**Monthly Abandonment Surcharge applicable to Rate Schedule Finn Transportation Service, and Short Term Firm
Transportation Service for all zones.
***Daily Abandonment Surcharge applicable to Rate Schedule Overrun Transportation Service for zone 6 & 7,
Interruptible Transportation Service for zone 8 & 9, and Small General Service for zone 9.
TA RIFF -PHASE I Effective Date: January I, 2016
2016 Attachment H Pipeline Tariffrs Page 41 of 41
AVISTA UTILITIES
Case No. A VU-G-16-0 'J-
EXHIBIT "E"
Copy of Press Release and Customer Notice
August 26, 2016
Contact: DRAFT
Media: Casey Fielder [phone], [e-mail]
Investors: Lauren Pendergraft [phone], [e-mail]
Avista 24/7 Media Access [phone]
Avista Requests Natural Gas Price Decrease in Idaho
Annual price adjustment would take effect Nov. 1, 2016
SPOKANE, Wash. Aug. 29, 2015, 1:05 p.m. PST: Avista (NYSE: AVA) customers in Idaho
could see an overall 7.8 percent decrease in their natural gas rates on Nov. 1, 2016 if the Idaho
Public Utilities Commission (IPUC or Commission) approves the company's annual Purchased
Gas Cost Adjustment (PGA) filed today.
If the request is approved, Avista residential customers using an average of 61 therms a month
could expect their bill to decrease by $4.65, or 8.4 percent, for a revised monthly bill of $50.94
beginning Nov. 1, 2016. Avista's natural gas revenues would decrease by $6.1 million. Avista
does not mark up the cost of natural gas purchased to meet customer needs, so the filing does
not increase or decrease company earnings.
The requested natural gas rate change by customer segment is as follows:
General Service -Firm -Schedule 101 -Residential & Small Commercial
Large General Service -Firm -Schedules 111 & 112 -Commercial
-7.7%
-7.7%
PGAs are 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. The primary driver for the company's requested decrease is a
reduction in natural gas commodity costs due to a warmer than normal winter, an abundance of
natural gas held in storage, and continued high production levels of natural gas.
About 50 percent of an Avista natural gas customer's bill is the combined cost of purchasing
natural gas on the wholesale market and transporting it to Avista's system. These costs
fluctuate up and down based on market prices. The costs are not marked up by Avista. The
remaining 50 percent covers the cost of delivering the natural gas --the equipment and people
needed to provide safe and reliable service.
Rate Application Procedure
Avista'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.gov). Customers may file with the Commission written
comments related to Avista's filings. Customers may also subscribe to the Commission's RSS feed
(http://www.puc.idaho.gov/rssfeeds/rss.htm) to receive periodic updates via e-mail about the case.
Copies of rate filings are also available on Avista's website at www.avistautilities.com/rates.
About Avista Corp.
Avista Corp. is an energy company involved in the production, transmission and distribution of
energy as well as other energy-related businesses. Avista Utilities is our operating division that
provides electric service to 375,000 customers and natural gas to 335,000 customers. Its
service territory covers 30,000 square miles in eastern Washington, northern Idaho and parts of
southern and eastern Oregon, with a population of 1.6 million. Alaska Energy and Resources
Company is an Avista subsidiary that provides retail electric service in the city and borough of
Juneau, Alaska, through its subsidiary Alaska Electric Light and Power Company. Avista stock
is traded under the ticker symbol "AVA." For more information about Avista, please visit
www.avistacorp.com.
This news release contains forward-looking statements regarding the company's current
expectations. Forward-looking statements are all statements other than historical facts. Such
statements speak only as of the date of the news release and are subject to a variety of risks
and uncertainties, many of which are beyond the company's control, which could cause actual
results to differ materially from the expectations. These risks and uncertainties include, in
addition to those discussed herein, all of the factors discussed in the company's Annual Report
on Form 10-K for the year ended Dec. 31 , 2015 and the Quarterly Report on Form 10-Q for the
quarter ended June 30, 2016.
SOURCE: Avista Corporation
-16XX-
To unsubscribe from Avista's news release distribution, send a reply message to
[e-mail]
Proposed Natural Gas Rate Adjustment Filed
to be Effective Nov. 1, 2016
Avista has filed its annual Purchased Gas Cost
Adjustment (PGA) request with the Idaho Public
Utilities Commission (Commission), with a
requested effective date of Nov. 1, 2016. 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.
The proposed PGA would decrease natural gas
rates by an overall 7.8 percent and Avista's natural
gas revenues by $6.1 million. If the request is
approved, Avista residential customers using
an average of 61 therms a month could expect
their bill to decrease by $4.65, or 8.4 percent,
for a revised monthly bill of $50 .94 beginning
Nov. 1, 2016.
The requested natural gas rate change by customer
segment is as follows:
General Service -Firm -Schedule 101
Residential & Small Commercial -7.7%
Large General Service -Firm -Schedules 111 & 112
Commercial -7.7%
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 homepage (www.puc.idaho.
gov). 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.
htm) to receive periodic updates via e-mail about the
case. Copies of rate filings are also available on our
website, avistautilities.com/rates.
If you would like to submit comments on the
proposed decrease, you can do so by going to the
Commission website or mailing comments to:
Idaho Public Utilities Commission
P. 0. Box 83720
Boise, ID 83720-0074
To assist customers in managing their energy bills,
Avista offers services such as comfort level billing,
payment arrangements and Customer Assistance
Referral and Evaluation Services (CARES). CARES
provides assistance to special-needs customers
through referrals to area agencies and churches for
help with housing, utilities, medical assistance and
other needs. To learn more, visit avistautilities.com.
There, customers can also find information on energy
efficiency rebates and incentives, as well as online
tools for managing energy use.
AVA205i