gas royalty calculation information bulletin - december 2004excel transcontinental corporation 0ne4...

ENERGY

Petroleum Plaza – North Tower 9945 – 108 Street Edmonton, Alberta Canada T5K 2G6

GAS ROYALTY CALCULATION 04-12 INFORMATION BULLETIN

December 2004

A. PRICING RATES AND TRANSPORTATION INFORMATION Pricing, Royalty Rates and Transportation Information – October 2004 ................................................2 B. NOTICES Business Design Committee...................................................................................................................2

New and Revised Meter Station Factors ................................................................................................2 Alberta Energy – Gas Royalty Calculation Calendar ..............................................................................3

2000 Audits in Progress..........................................................................................................................3 User Defined File (UDF) Handbooks (Invoice and Crown Royalty Detail Statement)............................3

C. MONTHLY INFORMATION October 2004 Royalty Due January 31...................................................................................................3 November 2004 VA4 Due January 15 ...................................................................................................4 November 2004 Production Reporting....................................................................................................4 Interest Rate December 2004.................................................................................................................4 September Provisional Assessment Charge ..........................................................................................4 September Charges................................................................................................................................4 Alberta Royalty Tax Credit Program Quarterly Rate...............................................................................5 D. INFRASTRUCTURE DATA CHANGES Client ID Listing .......................................................................................................................................5 Projects/Blocks........................................................................................................................................6 Struck Clients ..........................................................................................................................................6 Nova Tolls – Multiple Gas Reference Prices ..........................................................................................6 E. REMINDERS Plant Type Changes................................................................................................................................7

Update - Statutory Requirement for 2000 Royalty..................................................................................7 Close-out for Operations.........................................................................................................................7

Electronic File Transfer of AC2/AC4 Forms Handbook ..........................................................................9 Office Closures – Christmas Period........................................................................................................9 Gas Reference Price Calculation............................................................................................................9 Royalty Exemption Reporting – Deep Gas Royalty Holiday Program (DGRHP) .................................10 EUB Reporting Requirements – Deep Gas Royalty Holiday Program (DGRHP).................................10 Credit Under Gas Processing Efficiency Assistance Regulation (GPEAR)/Sulphur Emission Control

Assistance Program (SECAP) ..............................................................................................................10

F. POINTS OF CONTACT Petroleum Registry of Alberta ...............................................................................................................11 Department of Energy Hotline & Internet..............................................................................................11 Gas Royalty Client Services .................................................................................................................11 Calgary Information Centre ..................................................................................................................12 Alberta Royalty Tax Credit Information ................................................................................................12 G. PRINCIPLES AND PROCEDURES Updates.................................................................................................................................................12

We would like to wish you the happiest of Holiday Seasons!

INFORMATION BULLETIN – December 2004

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A. PRICING RATES AND TRANSPORTATION INFORMATION

For Pricing, Royalty Rates and Transportation Information for October 2004, refer to Attachments 1, 1A, 2, 2A, and 3.

B. NOTICES

Business Design Committee

On July 22, 2004, representatives from the Department of Energy (DOE) and the Canadian Association of Petroleum Producers (CAPP) met to discuss the future role of the Business Design Committee. A review of the last two years shows that attendance at Business Design Meetings was minimal and no new matters were brought forward for discussion. In view of this, it is agreed that for better utilization of time and to better serve industry, the Business Design Committee meetings be discontinued and Department staff be available, monthly in Calgary, for clients who need assistance with royalty reporting. This change was implemented in October 2004.

Gas Royalty Calculation staff will be available monthly to meet with clients who need assistance with royalty reporting. Royalty clients requiring assistance are encouraged to call Mr. David Nichiporik, Manager Client Services (780-422-9239) or e-mail [email protected] two business days before the meeting date to arrange an appointment. The next 3-month schedule is as follows:

Where: Monenco Place Room 437 801-6 Avenue S.W. Calgary, AB Phone: 403-297-8954 (Industry must go to the 3rd Floor Reception upon arrival to sign-in and be given a visitor tag)

When – 9:30 am to 3 pm

January 26, 2005 February 24, 2005 March 23, 2005

New and Revised Meter Station Factors The Department has published in Information Letter 2004-32, new and revised Meter Station Factors. Meter Station Factor changes identified in Attachment 4 are effective from the stated production month until otherwise changed. Meter Station Factors for those prescribed effective October 2004 are identified in Attachment 5. If you have any questions, please contact Bill Zanewick, Director Gas Royalty Valuations and Markets Division @ (403) 297-5465 or e-mail: [email protected].


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Alberta Energy – Gas Royalty Calculation Calendar

A calendar for the year 2005 is enclosed for industry use. It shows important filing dates for clients required to meet Gas Royalty processing cut-offs.

2000 Audits in Progress

In accordance with Section 38 (4) of the Mines and Minerals Act, non-operator partners are advised that production year 2000 Facility Cost Centre filings for certain EUB facilities, Owner Activity Statements and S1 production filed for certain OFSG wells, and specific Enhanced Oil Recovery (EOR) schemes will continue to be audited into the fifth year. Completion of the audits and royalty recalculations and assessments, if required, will occur in 2005. For a complete listing of the affected EUB facilities, OFSG wells and EOR schemes, refer to Attachment 6.

If you have any questions, please contact Chris Lawton of the Compliance & Assurance group at (403) 297-6746.

User Defined File (UDF) Handbooks (Invoice and Crown Royalty Detail Statement)

As part of the changes to the UOCR calculation (Royalty and Related Information Review), the UDF handbooks will be updated to incorporate a new Annual Operating Cost adjustment (AOP charge type), effective with the February 2005 billing period (BP). These changes will require software changes to incorporate the AOP charge type, but will have no impact on the processing of the existing EDI information sent by the DOE Mineral Revenue Information System (MRIS).

For further information, or to coordinate testing of these changes, please contact Tannis Henderson at (780) 422-9297 or e-mail [email protected].

C. MONTHLY INFORMATION

October 2004 Royalty Due January 31 • Royalty clients are to remit the total amount payable shown on the January 2005

Statement of Account by January 31, 2005. If the amount payable includes accrued current period interest, the interest has only been accrued to the statement issue date. Clients must also include the additional interest that has accrued from the statement issue date to the date of payment, using the per diem amount provided.

• The January 2005 Statement of Account shows your amount payable as of the Statement issue date. It includes any outstanding balances from your previous statement, your October 2004 Invoice amount and any applicable current period interest charges. It also identifies refunds resulting from overpayments.

• Current period interest will not be charged on current invoice charges for the production month of October 2004 if it is paid in full by January 31, 2005.


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• Current period interest will accrue on any overdue charges commencing the first day after the due-date until it is paid in full.

Note: If the due date falls on a non-business day, payments will be accepted on the next business day.

• Cheques are payable to the Minister of Finance, Province of Alberta.

November 2004 VA4 Due January 15 The VA4 forms for the production month of November 2004 are due in the Department offices by January 15, 2005.

Note: If the due date (15th) falls on a non-business day, the next business day will apply as the due date for VA4 forms.

November 2004 Production Reporting November 2004 production reporting is submitted through the Registry. The deadline for submission of SAF, OAF, and Volumetrics is posted in the Petroleum Registry of Alberta website “Calendar” under Bulletin Board. Changes to this calendar will be posted on the Registry web site home page in “Broadcast Messages.”

Interest Rate December 2004

The Department of Energy’s interest rate for December 2004 is 5.25%. September Provisional Assessment Charge

The summary of Provisional Assessment Charges for all production periods for the September 2004 billing period was:

First Time Provisional Assessment

Reversals of Provisional Assessments

Net Provisional Assessment

$28,764,173.99 ($11,669,642.07) $17,094,531.92

September Charges The revised penalty table below shows at the form level, the total penalty charges and reversals, for the September 2004 billing period:

FORM Penalty Charges Penalty Reversals Net Penalty Charges for 2004/09

AC2 $293,400 ($46,200) $247,200 AC4 $167,800 ($1,200) $166,600 AC5 $9,300 ($4,200) $5,100 GR2 $0 $0 $0

NGL1 $0 $0 $0 VA2 $0 $0 $0 VA3 $0 $0 $0 VA4 $0 $0 $0 Total $470,500 ($51,600) $418,900

http://www.petroleumregistry.gov.ab.ca/PR49.asp


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Alberta Royalty Tax Credit Program Quarterly Rate

For the fourth quarter of 2004, the Alberta Royalty Tax Credit rate will be .2500. This rate is based on a royalty tax credit reference price of $464.81 per cubic metre. The Alberta Royalty Tax Credit rates for the past year were:

Third Quarter, 2004 .2500 Second Quarter, 2004 .2500 First Quarter, 2004 .2500 Fourth Quarter, 2003 .2500

If you have any questions, please contact Kent Nelson of Tax Services at (780) 427-9425, ext. 44066.

D. INFRASTRUCTURE DATA CHANGES

Client ID Listing

The BA Identifiers Report is a directory of Business Associate (BA) names; codes, status (e.g. struck, active, amalgamated, etc.), status effective dates and will now, effective August 2004, include Working Interest Owner (WIO) role start/end dates.

This report is also published daily on the Petroleum Registry website at:

http://www.petroleumregistry.gov.ab.ca

The Department would like to remind the Business Associates to review their WIO role to ensure the start and end dates are reflected correctly. If the BA does not have an active WIO role, the operators cannot allocate volumes to the BA for the relevant production periods through the SAF/OAF allocations. If a BA has a WIO start date, then that BA can receive allocations from the stated date

forward.

If a BA has a WIO start and end date, then they can only receive allocations from the stated start date until the end date. Any allocations after the end date will be rejected.

If a BA does not have a WIO start date, then that BA cannot receive allocations at all.

Please contact Client Registry at (780) 422-1395 if you have any questions regarding the information supplied on this listing.

https://wwp.petroleumregistry.gov.ab.ca/bbreports/PRABAIdentifiers.pdf


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Projects/Blocks The following projects/blocks have been rescinded by the EUB. If further information is required on these or any other projects, please contact Isabelle Warwa at (780) 427-8952.

Project/ Block Name

Effective Date

Operator

Stream ID

Zama Keg River KK Project No 1 October 31, 2004 0BN9 WG 98589 Horsefly Lake Mannville Proj No 3 October 31, 2004 0058 WG 02295

Struck Clients Clients must ensure that all royalty documents are completed using only valid client names and IDs. It is critical that royalty clients use current legal client names and their appropriate IDs on all documents to ensure accurate royalty calculation and to prevent provisional assessment and penalties. Rejects will occur when invalid IDs are used.

If you require information regarding client names or IDs, please contact Client Registry at (780) 422-1395. The following is a list of struck, dissolved, and revived clients:

Company Name Client ID Struck Date Rimrock Drilling Ltd. 0Z02 November 2, 2004 Gorilla Capital Inc. 0HL6 November 2, 2004 Excel Transcontinental Corporation 0NE4 November 2, 2004 565514 Alberta Ltd. 0CY6 November 2, 2004 Cornerstone Petro-Tech Services Inc. 0WW8 November 2, 2004 Tornado Resources Ltd. 0TZ9 November 2, 2004 933676 Alberta Ltd. 0D6K November 2, 2004 Company Name Client ID Dissolved Date Dradco Drilling and Exploration Ltd. 0Z35 November 10, 2004 Mayfair Energy Ltd. 0YY9 November 15, 2004 Granville Resources Ltd. 0J01 November 17, 2004 323374 Alberta Ltd. 0Y72 November 30, 2004 Penn West Canadian Fuel Ltd. 0AJ1 November 26, 2004 Company Name Client ID Revived Date Gower Petroleum Ltd. 0G3W November 8, 2004

Nova Tolls - Multiple Gas Reference Prices

Royalty information related to the implementation of the Factor Model negotiated with industry for determining Multiple Gas Valuation Prices is provided on the Department Internet site at:

http://www.energy.gov.ab.ca

http://www.energy.gov.ab.ca/NaturalGas/1141.asp


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E. REMINDERS

Plant Type Changes

Please note the following plant type changes listed below.

Facility ID Facility Name Plant Type Plant Class Effective Date AB GP 0001793 Devon Rycroft 4 Sour 2005-01-01 AB GP 0001404 Devon Eaglesham 4 Sour 2005-01-01

Update - Statutory Requirement for 2000 Royalty Section 38 of the Mines and Minerals Act provides for recalculation of royalty that can be initiated in either two ways: a) On the Department’s initiative in conjunction with an audit or examination; or b) At the request of a royalty payer. Industry Recalculation of 2000 Royalty Industry initiated royalty recalculation requests for the 2000 production year must be submitted in writing to the attention of David Nichiporik of the Gas Royalty Client Services before December 31, 2004. Please note that the Petroleum Registry is open until 5:30 pm on Friday, December 31, 2004.

Close-out for Operations Production Year 2002 As prescribed by the Natural Gas Royalty Regulation, 2002, royalty clients are required to file accurate and timely information within specified time frames for a production month or production year. Inherent in the business of gas production is the frequent adjustment and balancing of reported volumes and distribution of costs. These adjustments result in retroactive processing of Industry submitted royalty documents to accurately reflect volumetric ownership and ensure appropriate distribution of costs. To contain the extent of retroactive processing and to facilitate the completion of audits within the legislated time frames, an Operational Close-out process was established. Normally two years after the end of a production year, that production year is operationally closed. When a production year is operationally closed, the Mineral Revenues Information System (MRIS) will reject any royalty document submitted for a closed out production year after the established close-out dates, unless written authorization is granted by the Department. Facility Operators and Owners must ensure that correcting documents required to clear unreconciled volumetric discrepancies and to amend the distribution of costs for the closed-out production year are submitted prior to the close-out dates. Facility operators and owners are encouraged to review the following reports produced by the Department to focus on facilities that require immediate attention prior to close-out:


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• Rejection Notices • Summary of Outstanding OAS Volumetric Discrepancies • Ensure Complete • Annual Reports • Reconcile Statement of Account Balances • Operating Cost Deduction at Facilities with No Capital Ownership or Custom Processing Fees The close-out dates are as follows for the production year of 2002:

Production Year Primary Documents Secondary Documents Close-Out Date Close-Out Date January 17, 2005 March 15, 2005 Note: There are only two secondary documents: the Reassignment of Volumes Set Up/Change (RMF2) and the Annual Capital Cost Allowance Reallocation (AC3). All others are primary documents. Should circumstances warrant the amending of documents for a closed-out year, the Department must receive a Year End Close Out (YECO) form, or a written request to open the year. The YECO form is an alternative to the formal written request. A written request must include the following detailed information: 1. Specific reason for processing documents after operational close-out. 2. List of document types being amended (i.e. OAS, RMF2, AC2). 3. Affected facilities and/or stream IDs (i.e. Gas plant code, facility cost centre code, well event). 4. Estimated dollar impact; 5. Paper copies of the document(s) to be processed. Operators and owners must ensure that submitted documents meet MRIS edit criteria. Documents that do not meet MRIS edit criteria will be rejected and issued a rejection notice. Royalty documents that meet MRIS edit criteria will be processed and will be subject, where applicable, to the following: • Provisional Assessments • Recalculation of Royalty • Interest Calculations • Re-calculation of Allowable Costs, including the Corporate Effective Royalty Rate (CERR). Where applicable, results of the processed documents will be reflected in the Crown Royalty Detail Statement, Invoice, and Statement of Account. The YECO requests together with the applicable royalty documents must be submitted to:

Gas Royalty Client Services 8th Floor, North Petroleum Plaza 9945- 108 Street Edmonton, Alberta T5K 2G6


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Electronic File Transfer of AC2/AC4 Forms Handbook As part of the annual form changes (Royalty and Related Information Review), the Electronic File Transfer of AC2/AC4 Forms Handbook has been updated. The new file format specifications for AC2-V3 and AC4-V2 documents can be retrieved from the Handbook by clicking on the ELECTRONIC FORMAT.xls link in Appendix C.

We encourage clients to submit test input files through the ETS website under “Submit Forms” and “Test Input Files”.

If you have any questions or require assistance, please contact Penny White at (780) 415-2679.

Office Closures – Christmas Period

All Department of Energy offices will be closed from Friday, December 24 to Tuesday, December 28, 2004 inclusive. Our offices are also closed on Monday, January 3, 2005. Gas Reference Price Calculation

In 2003, both Industry and the Department participated in a review of the Gas Reference Price calculation to determine whether it continued to be a representative average field price for natural gas at the exit of the gas plant. While completion of the review process was suspended until the fall of 2005, certain desired changes relating to the valuation of non-arm’s length transactions were identified, for implementation as soon as practicable. Effective with the August 2004 production month, the following two changes have been implemented in the Gas and ISC Reference Price calculations:

1. Ratio of arm’s length quantities used to value non-arm’s length quantities increases

from 1:1 to 1:2.

Before this change, the average price of arm’s length transactions in a particular valuation pool was used to value the arm’s length quantities and an equivalent quantity of non-arm’s length transactions. After the change, non-arm’s length quantities equal to twice the arm’s length quantities are valued at the arm’s length price. Any remaining non-arm’s length quantities continue to be removed from the calculation and are effectively valued at the Gas Reference Price.

2. Valuation of non-arm’s length quantities for gas removed from Alberta is based on type

of disposition – netback for “affiliate sales” and “cost plus” for other types of dispositions.

Before the change, the arm’s length netback price at the Alberta border was used to value non-arm’s quantities at that border point except for gas removed by ex-Alberta gas distributors. For ex-Alberta gas distributors, a supply cost plus transportation to the Alberta border valuation mechanism was in effect. After the change, only non-arm’s quantities that


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are transacted with affiliates are valued at the arm’s length netback price. Other types of non-arm’s length quantities are valued at the ex-Alberta gas distributor supply costs plus transportation price.

If you have any questions on this matter, please contact Bill Zanewick, Director, Gas Royalty Valuation and Markets at (403) 297-5465.

Royalty Exemption Reporting – Deep Gas Royalty Holiday Program (DGRHP)

In order to receive royalty exemption under Deep Gas Royalty Holiday Program (DGRHP), royalty clients must report the applicable volumes at the single well level. Thus, if a well is tied to a project, unit or well group the DGRHP volumes must be reported at the unique well identifier level. Reporting at the higher level (unit, well group, etc) will result in no royalty exemption. Well's production reported on the SAF/OAF should reflect the volumes as reported on the EUB volumetric submission. If you have any questions on this matter, please contact Lu-Enn Toon at (780) 422-9082.

EUB Reporting Requirements – Deep Gas Royalty Holiday Program The Department of Energy (DOE) relies upon information and advice from the Alberta Energy and Utilities Board (EUB) on an ongoing basis, in support of identification of wells eligible for benefits under the Deep Gas Royalty Holiday Program (DGRHP). The EUB is increasingly experiencing inaccurate, inconsistent and incomplete well drilling and completion data, and volumetric data, being submitted via the EUB’s Digital Data Submission Subsystem and the Petroleum Registry of Alberta. Consequently, this results in processing delays in qualification for benefits under the Deep Gas Royalty Holiday Program. The EUB requests that all drilling and completion data and volumetric data submitted via the EUB’s Digital Data Submission Subsystem and the Petroleum Registry of Alberta is consistent, complete and accurate in order to expedite the DGRHP eligibility assessment process. Should you require additional clarification, on any of these areas of concern, please visit Guide 59 and Guide 7 on the EUB Website or contact Kerry Johnson at (403) 297 6973 or e-mail at [email protected].

Credit Under Gas Processing Efficiency Assistance Regulation (GPEAR)/Sulphur Emission Control Assistance Program (SECAP)

To receive credit under the GPEAR/SECAP, royalty clients must remit gas royalty payments due, as invoiced. This is required in order to process GPEAR/SECAP credits related to the corresponding account. If you have any questions on this matter, please contact Lu-Enn Toon at (780) 422-9082.

http://www.eub.gov.ab.ca/BBS/requirements/Guides/g59.htm



http://www.eub.gov.ab.ca/bbs/default


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F. POINTS OF CONTACT Petroleum Registry of Alberta The Petroleum Registry of Alberta Service Desk is the focal point for communications with the Registry regarding preparations for, access to, or utilization of the Registry. To contact the Petroleum Registry of Alberta Service Desk call: 1-800-992-1144. Please note that the Petroleum Registry is open until 5:30 pm on Friday, December 31, 2004.

Department of Energy Hotline & Internet Prices, Royalty Rates, and Transportation Information are available on the Department of Energy Internet address or hotline: (403) 297-5430. In addition, both the Gas Royalty Calculation Information Bulletin and Information Letter are also available on the Internet address:


Note: To access the sulphur price call the Department of Energy hotline at (403) 297-5430. Wait to hear the recorded list of options, then press #1 on your touch-tone phone for Natural Gas Information. Again, wait for the recorded list of options, then press #3 for Gas Royalty Rates.

Gas Royalty Client Services The Gas Royalty Client Services is structured as a Business Associate client portfolio system, which assigns a given Business Associate to one of four Client Service teams. Listed below is the portfolio breakdown along with Client Service Team Leads and phone numbers. The portfolios are divided by company name and not by BA ID. Example: If your company name is the “Gas Company” you would call C – G team at (780) 644-1202.

Business Associate Phone Number Team Lead Numbered companies, A, B & L (780) 644-1201 Mary Carrie

C – G (780) 644-1202 Dilshad Hudda (Acting)

H – P (excluding L) (780) 644-1203 Chris Nixon

Q – Z (780) 644-1204 Kamal Rajendra

Gas Royalty Reception: (780) 427-2962 Fax: (780) 427-3334 or (780) 422-8732

Alberta Toll Free: (780) 310-0000 Hours of operation are 8:15 a.m. to 4:30 p.m. Voice messages left after 4:30 p.m. will be answered the next business day.



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In situations where a company has just amalgamated or purchased another company, the general rule is to call the team that is responsible for the “Supra” business associate, or Royalty payer. Below are some guidelines for clients who are unsure which Client Services Team to call regarding their questions. 1. Amalgamation/consolidation - Call the team responsible for the “Supra” business associate

(Royalty Payer). i.e. ABC Oil and Gas amalgamates with Zed Exploration and Zed is the amalgamator

(royalty payer). When calling Client Services regarding business for ABC Oil and Gas you would call Team 4 (Q-Z) (780-644-1204) because Zed Exploration is now the Supra business associate and royalty payer. This rule would apply even if you were calling regarding business that is prior to the acquisition or amalgamation.

2. Asset Purchase - Call the team responsible for your company.

i.e. 123 Gas purchases the assets of TSP Exploration, but not the company. When calling Client Services regarding business for 123 Gas you would call Team 1 (# Co., A, B, & L) (780-644-1201) because you have only purchased assets. You would not be entitled to information regarding business for TSP Exploration that is prior to the asset purchase.

3. Consultants/service providers - If you have a contract to provide production accounting

services to a company, call the team responsible for your client’s company. i.e. Paul Snow Consulting Services enters into a contract with Duckback Oil and Gas and

Olive Oil and Gas. Paul Snow would contact Team 2 (C-G) (780-644-1202) to discuss Duckback Oil business and Team 3 (H-P excluding L) (780-644-1203) to discuss Olive Oil and Gas business. At the time the contract is signed, Paul Snow would have had each company notify the appropriate team that he was authorized to access information for their company.

Calgary Information Centre 300, 801 – 6th Avenue S.W. Calgary, Alberta T2P 3W2 Telephone (403) 297-6324 Fax (403) 297-8954

Alberta Royalty Tax Credit Information

Alberta Tax and Revenue Administration Tax Services Telephone: (780) 427-3044 Alberta Toll Free: (780) 310-0000 Fax: (780) 427-5074

For further information, please contact Tax Services at (780) 427-9425. G. PRINCIPLES AND PROCEDURES

Updates Please replace the following pages within your copy of the June 2003 issue of the Gas Royalty Principles and Procedures (Post Registry) with the enclosed updates.


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Location of Change Details of Change as of December 2004 Chapter I, Section 3 Section 3.4 Pg. 3

Process Summary Incorporate the Departments policy on releasing information to a third party.

Chapter II, Section 1 Section 1 Pg. 10-19

Alberta’s Royalty Share of Gas and Gas Products Update to reflect January 2004 methodology changes to the calculation of the par prices.

Chapter II, Section 10 Section 10.1.2 Pg. 1

Amalgamations and Consolidations Correct spelling error.

Chapter III, Section 1 Section 1 Pg. 2 & 4 - 15

Valuing Raw Gas, and Residue Gas (Pricing Calculation) Update Gas Reference Price Calculation Information.

Chapter III, Section 2 Section 2.1 Pg. 1 Section 2.5.1 Pg. 7 & 8

Valuing Gas Products Clarify wording of Valuing Crown Share of Ethane. Clarification on amending monthly sulphur (VA4) submissions.

Chapter III, Section 3 Section 3.8 Pg. 11

Alberta’s Royalty Share of Cost Allowance Clarify wording on Re-allocation of Capital Cost Allowance (AC3).

Chapter III, Section 4 Section 4.2.1, Pg 2-5

Other Programs Administered with Natural Gas Royalty Provide clarification on resubmission of SECAP applications.

Chapter III, Section 7 Section 7.1, Pg 1

Levying and Collecting Natural Gas Royalty Add word ‘to’ in the sentence “owed the Crown”.

Chapter IV, Section 2 Section 2.3, Pg. 12

Volumetric Reporting of Mineral Activity Remove information on Well groups beginning with “A”.

Chapter IV, Section 3 Section 3.2 Pg. 7

Valuing Raw Gas, Residue Gas and Ethane Add management service fee for CO2 extraction to CAP transportations costs.

Chapter IV, Section 5 Section 5.2.1 Pg. 14 Section 5.2.2 Pg. 24-26 Section 5.2.2, Pg. 30

Alberta’s Royalty Share of Allowable Costs Clarification on when AFE’s are required for an AC2-V2. Change alpha sequencing and clarification on when AFE’s are required for an AC2-V3. Change font in part 3, 3.2.

Appendix D Replace section

Calculation of the Gas and ISC Reference Prices Update to include CO2 management service fees.

Appendix I I-7

Unit Operating Cost Rates Correct the 2003 processing rate for AB-GP-0001522 s/b $4.49.

Appendix O O-2 O-12

User Guide to Client Invoicing Correct closing balance and amount payable on statement of account. Correct spelling error.

Appendix G Replace section

Allowable and Non-Allowable Capital Cost Provide updates to allowable and non-allowable capital costs and new diagram.

Appendix H Replace section

Allowable and Non-Allowable Operating Costs Provide updates to allowable and non-allowable operating costs.

Appendix P AC1-V2 AC2-V3 AC3-V2 AC4-V2 AC5-V3 ICC1

Forms Allowable Costs Facility Cost Centre Setup/Change. Allowable Costs Capital Cost Allowance for Production Years 2004 and Onwards. Allowable Costs Capital Cost Allowance and Custom Processing Volume Reallocations for Production Years 2004 and Onwards. Allowable Costs Operating Costs for Production Years 2004 and Onwards. Allowable Costs Custom Processing Fees Paid for Production Years 2004 and Onwards. Invoice Consolidation Concurrence - add production month.

Deen Khan Director, Gas Royalty Calculation

Gas Development Attachments

INFORMATION BULLETIN – December 2004 ATTACHMENT 1

2004 GAS AND ISC PRICES

MONTH

Gas Reference

Price ($/GJ)

Methane ISC

Reference Price ($/GJ)

Methane ISC Par Price

($/GJ)

Ethane ISC Reference

Price ($/GJ)

Propane ISC Reference

Price ($/GJ)

Butanes ISC Reference

Price ($/GJ)

Pentanes plus ISC


Natural Gas and NGLs Select Prices for 2004

JAN 6.10 6.06 6.06 6.38 6.48 6.52 6.54 Commodity 2004

FEB 5.83 5.80 5.80 6.07 6.13 6.17 6.19 New Methane 1.333 $/GJ

MAR 5.49 5.42 5.42 5.87 6.00 6.07 6.10 Old Methane 0.392 $/GJ

APR 5.64 5.58 5.58 6.02 6.16 6.20 6.23 New Ethane 1.333 $/GJ

MAY 6.28 6.23 6.23 6.56 6.67 6.72 6.75 Old Ethane 0.392 $/GJ

JUN 6.47 6.45 6.45 6.68 6.69 6.72 6.76 Propane 1.333 $/GJ

JUL 6.17 6.13 6.13 6.43 6.49 6.53 6.56 Butanes 1.333 $/GJ

AUG 5.99 5.96 5.96 6.22 6.27 6.32 6.35 Pentanes plus 47.65 $/m3

SEPT 5.21 5.17 5.17 5.44 5.51 5.54 5.57 Royalty Factors for Pentanes plus

OCT 5.29 5.22 5.22 5.85 6.01 6.06 6.09 Base Marginal

NOV New Pentanes 22 35

DEC Old Pentanes 22 50

DETAIL OF THE OCTOBER 2004 GAS AND ISC REFERENCE PRICES

Gas Methane C2-IC C3-IC C4-IC C5-IC

Weighted Average Price of Alberta 5.670 5.632 5.980 6.094 6.112 6.118

Deductions: Intra – Alberta Transportation 0.280 0.298 0.170 0.120 0.092 0.070

2003 Weighted Average Reference Price

($/GJ)

Marketing Allowance 0.023 0.023 0.023 0.023 0.023 0.023 5.830 Price Before Pipeline Factor 5.367 5.311 5.787 5.951 5.997 6.025 Pipeline Fuel/Loss Factor .991 .991 .991 .991 .991 .991

Price before Special Adjustment 5.320 5.264 5.736 5.899 5.945 5.973 2003 Weighted Average

OMAC ($/GJ) Special Adjustment 0.000 0.000 0.000 0.000 0.000 0.000 0.021 Price before 2% amendment limitation or rounding 5.320 5.264 5.736 5.899 5.945 5.973 Amendments: Carry forward (from previous RP month) 0.032 0.044 0.109 0.133 0.140 0.091 Prior Period Amendment Adjustment (current RP month) -0.061 -0.084 0.145 0.250 0.219 0.208 Calculated RP after Amendments 5.291 5.224 5.990 6.282 6.304 6.272 OCTOBER 2004 Reference Price 5.29 5.22 5.85 6.01 6.06 6.09 Difference = value carried forward to next RP month 0.001 0.004 0.140 0.272 0.244 0.182 Adjusted IATD (before Prior Period Amendments) n/a 0.295 0.168 0.118 0.092 0.069 Prior period Amendments (IATD and Pipeline Fuel Loss) n/a 0.000 0.000 0.000 0.000 0.000 Adjusted IATD (after Prior Period Amendments) n/a 0.295 0.168 0.118 0.092 0.069

INFORMATION BULLETIN – December 2004 ATTACHMENT 1A

2004 NATURAL GAS LIQUIDS PRICES

MONTH Ethane


Ethane Par Price ($/GJ)

Propane Reference

Price ($/m3)Propane Par Price ($/GJ)

Propane Floor Price

($/m3)

Butanes Reference

Price ($/m3)

Butanes Par Price

($/GJ)

Butanes Floor Price

($/m3)

Pentanes plus Reference

Price ($/m3)

Pentanes plus Par

Price ($/m3)

Sulphur Default Price ($ per tonne)

JAN 6.38 6.38 208.59 6.48 172.19 269.04 6.52 211.06 296.01 283.35 26.73

FEB

6.07 6.07 187.63 6.13 164.69 237.75 6.17 166.16 301.09 290.27 24.94

MAR

5.87 5.87 168.28 6.00 143.27 229.80 6.07 171.58 329.21 318.81 32.65

APR

6.02 6.02 178.48 6.16 158.79 235.53 6.20 189.59 339.05 326.36 30.26

MAY

6.56 6.56 201.30 6.67 181.31 265.89 6.72 213.92 377.36 349.25 37.15

JUN

6.68 6.68 200.53 6.69 179.15 266.36 6.72 211.96 338.99 325.57 37.27

JUL

6.43 6.43 218.71 6.49 193.22 268.54 6.53 236.07 335.42 319.89 34.15

AUG

6.22 6.22 259.17 6.27 243.48 293.66 6.32 252.80 353.70 347.92 39.37

SEPT

5.44 5.44 247.55 5.51 224.00 294.68 5.54 252.42 367.66 337.84 28.05

OCT

5.85 5.85 274.62 6.01 251.96 345.59 6.06 288.18 413.49 401.68 39.90

NOV

DEC

ANNUAL SULPHUR DEFAULT PRICE

1999 2000 2001 2002 2003

$10.54 $11.03 $0.28 $6.74 $30.97


2004 NGL TRANSPORTATION ALLOWANCE AND DEDUCTIONS

PENTANES PLUS (a)

PROPANE AND BUTANES (b)

PENTANES PLUS, PROPANE & BUTANE (c)

REGION REGION REGION

MONTH

1 2 3 4 1 2 3 4 1 2 3 4

FRAC.

ALLOW.

(per m3)

JAN 11.09 13.04 21.07 10.50 10.34 3.20 8.30* 14.13 18.54 17.98 28.23 16.49 10.50

FEB 7.83 10.98 18.12 13.54 16.85 -1.86 11.93* 14.34 14.92 15.62 23.08 14.50 10.50

MAR 12.39 7.58 4.31 15.77 5.88 -0.27 11.45* 9.67 16.35 18.39 27.02 16.69 10.50

APR 13.09 4.89 19.42 15.22 7.61 4.76 6.83* 5.24 24.05 22.98 30.06 19.43 10.50

MAY 32.23 18.47 25.21 32.08 6.70 2.36 5.48* -0.31 13.74 18.17 28.78 19.82 10.50

JUN 11.50 9.53 19.87 18.36 2.67 -0.30 1.87* 2.16 16.60 14.70 34.62 14.83 10.50

JUL 11.86 18.49 18.71 16.55 6.89 3.63 6.02* 10.35 14.65 19.86 33.71 18.82 10.50

AUG 0.00 5.21 23.05 5.67 4.97 0.25 3.64* -4.40 -1.60 10.29 21.50 11.24 10.50

SEPT 15.63 37.15 52.81 32.48 -2.15 -0.25 -1.70* -7.78 13.91 17.80 29.74 13.97 10.50

OCT 9.58 13.01 18.31 7.24 12.63 1.83 9.63* -0.64 19.63 19.62 32.76 19.01 10.50

NOV

DEC

(a) Pentanes Plus obtained as a specification gas product, (b) Propane and Butanes obtained as specification products, and (c) Pentanes Plus, Propane and Butane contained in a natural gas liquids mix. * Current month calculated allowance is based on an estimate.

Note: For details on “Prior Period Amendment Effects”, see Attachment 2A.

INFORMATION BULLETIN – December 2004 ATTACHMENT 2A

.

PRIOR PERIOD AMENDMENT EFFECTS

NGL REFERENCE PRICES OCTOBER 2004

Propane Butanes Pentanes

Price before amendments 274.620021 345.585214 413.489598

Opening Rollover (from prior business mth) -0.004448 0.001677 -0.001146

Prior Period Amendment Adj. (NGL-1) 0.000000 0.000000 0.000000

Prior Period Amendment Adj. (NGL-100) 0.000000 0.000000 0.000000

Published Reference Price 274.62 345.59 413.49

TRANSPORTATION ALLOWANCES OCTOBER 2004

Pentanes Plus Propane and Butanes Pentanes Plus, Propane & Butane

AMENDMENTS Region 1 Region 2 Region 3 Region 4 Region 1 Region 2 Region 3 Region 4 Region 1 Region 2 Region 3 Region 4

Opening Rollover (from prior business mth) 0.001285 -0.004560 0.004097 0.003656 0.003317 0.002359 0.004145 -0.002465 -0.003885 0.000177 0.001868 -0.001119

Prior Period Amendment Adj. (NGL1) 0.000000 0.000000 0.000000 0.000000 0.000000 0.000000 0.000000 0.000000 0.000000 0.000000 0.000000 0.000000

Prior Period Amendment Adj. (NGL-100) 0.000000 0.000000 0.000000 -5.686223 0.013957 0.004053 0.011192 0.000000 0.000000 0.173947 0.000000 0.000000

Total Amendment Effect 0.001285 -0.004560 0.004097 -5.682567 0.017274 0.006412 0.015337 -0.002465 -0.003885 0.174124 0.001868 -0.001119

Calculated Transp. Differential 9.582891 13.012950 18.307231 12.917681 12.609776 1.820259 9.610590* -0.636758 19.633728 19.447022 32.757608 19.016042

Calculated Transp. Differential after Total

Amendments 9.584176 13.008390 18.311328 7.235114 12.627050 1.826671 9.625927* -0.639223 19.629843 19.621146 32.759476 19.014923

Published Transportation Allowance 9.58 13.01 18.31 7.24 12.63 1.83 9.63* -0.64 19.63 19.62 32.76 19.01 *Any estimates represented by (*) are calculated as the weighted average of the other regions for the same spec product transportation allowance, since the region is zero. The weightings are based on the previous year's production.


2004 ROYALTY RATES

METHANE-OLD METHANE-NEW ETHANE - OLD ETHANE - NEW PROPANE BUTANES

MONTH (% per GJ) (% per GJ) (% per GJ) (% per GJ) (% per m3) (% per m3)

PENTANES – OLD(POL)

(% per m3)

PENTANES - NEW(PNE)

(% per m3)

JAN

35.00000 30.00000 35.00000 30.00000 30.00000 30.00000 45.29134 32.81383

FEB

35.00000 30.00000 35.00000 30.00000 30.00000 30.00000 45.40359 32.86595

MAR

35.00000 30.00000 35.00000 30.00000 30.00000 30.00000 45.81506 33.05699

APR

35.00000 30.00000 35.00000 30.00000 30.00000 30.00000 45.91188 33.10194

MAY

35.00000 30.00000 35.00000 30.00000 30.00000 30.00000 46.17981 33.22634

JUN

35.00000 30.00000 35.00000 30.00000 30.00000 30.00000 45.90196 33.09734

JUL

35.00000 30.00000 35.00000 30.00000 30.00000 30.00000 45.82919 33.06355

AUG

35.00000 30.00000 35.00000 30.00000 30.00000 30.00000 46.16521 33.21956

SEPT

35.00000 30.00000 35.00000 30.00000 30.00000 30.00000 46.05079 33.16644

OCT

35.00000 30.00000 35.00000 30.00000 30.00000 30.00000 46.67845 33.45785

NOV

DEC

INFORMATION BULLETIN - December 2004 ATTACHMENT 4

METER STATION

ID METER STATION NAMEMETER STATION

LOCATION

METER STATION FACTOR PIPELINE COMPANY NAME

PIPELINE COMPANY

ID

PRODUCTION MONTH

EFFECTIVE

PRODUCTION MONTH

INEFFECTIVE0081778 Brooks (Stn #12742) - 17 - 019 - 13 - 4 0.93 ATCO PIPELINES SOUTH 0Z7N October-03 October-040079245 Princess East 13-36 13 - 36 - 019 - 11 - 4 0.42 ALTAGAS HOLDINGS INC. A0WA November-03 October-040079246 Princess West 13-03 13 - 03 - 020 - 12 - 4 0.42 ALTAGAS HOLDINGS INC. A0WA November-03 October-040078975 Viking South Receipt 2570 16 - 01 - 048 - 13 - 4 1.11 ATCO PIPELINES NORTH 0Z6J November-03 October-040079063 Lostpoint Lake Receipt Stn (2437) 15 - 20 - 056 - 23 - 4 1.11 ATCO PIPELINES NORTH 0Z6J November-03 October-040079266 Langford Park Receipt (Stn. 2614) 10 - 29 - 053 - 04 - 5 1.11 ATCO PIPELINES NORTH 0Z6J November-03 October-040079511 Sawn Lake 14 - 13 - 091 - 13 - 5 1.36 NOVA - NGTL 0TB3 December-03 October-040079901 Foremost Receipt Station (#13637) - 11 - 008 - 12 - 4 0.93 ATCO PIPELINES SOUTH 0Z7N January-04 October-040079440 Hartell South 01 - 05 - 019 - 02 - 5 0.80 NOVA - NGTL 0TB3 January-04 October-040080255 Bolton Creek Receipt (Stn. 2687) 01 - 36 - 060 - 03 - 6 1.11 ATCO PIPELINES NORTH 0Z6J February-04 October-040079847 Ksituan River East # 2 08 - 07 - 079 - 06 - 6 1.36 NOVA - NGTL 0TB3 February-04 October-040079884 Amisk South 02 - 16 - 041 - 08 - 4 1.27 NOVA - NGTL 0TB3 February-04 October-040079881 Basset Lake 16 - 35 - 107 - 04 - 6 1.36 NOVA - NGTL 0TB3 March-04 October-040079882 Pakan Lake 01 - 18 - 057 - 11 - 4 1.19 NOVA - NGTL 0TB3 April-04 October-040080205 Marsh Head Creek West #2 07 - 16 - 059 - 24 - 5 0.96 NOVA - NGTL 0TB3 April-04 October-040080213 Ekwan 10 - 15 - 111 - 12 - 6 1.36 NOVA - NGTL 0TB3 April-04 October-040080769 Parker Creek 07 - 18 - 069 - 02 - 5 1.36 NOVA - NGTL 0TB3 May-04 October-040081141 Snuff Mountian 09 - 01 - 066 - 25 - 5 1.01 NOVA - NGTL 0TB3 May-04 October-040081331 Clear Prairie 08 - 36 - 086 - 10 - 6 1.36 NOVA - NGTL 0TB3 June-04 October-040081629 Sylvan Lake East # 2 16 - 19 - 038 - 01 - 5 0.84 NOVA - NGTL 0TB3 August-04 October-040082406 Smoky-CDN. NAT. Resources 07 - 36 - 058 - 03 - 6 1.16 ALLIANCE PIPELINE 0A2X September-04 October-040082497 Good Hope Receipt Station (#3488) 00 - 30 - 054 - 20 - 4 1.05 ATCO PIPELINES NORTH 0Z6J September-04 October-040081332 Hughenden East 16 - 08 - 041 - 07 - 4 1.16 NOVA - NGTL 0TB3 September-04 October-04

METER STATION FACTORSEFFECTIVE FROM STATED PRODUCTION MONTH

1 of 1


METER STATION


LOCATION


PIPELINE COMPANY

ID0082406 Smoky-CDN. NAT. Resources 07 - 36 - 058 - 03 - 6 1.11 ALLIANCE PIPELINE 0A2X0400070 BOUNDARY LAKE SOUTH 01 - 14 - 085 - 13 - 6 1.11 ALLIANCE PIPELINE 0A2X0400090 FOURTH CREEK 14 - 11 - 082 - 09 - 6 1.11 ALLIANCE PIPELINE 0A2X0400100 JOSEPHINE 08 - 01 - 083 - 10 - 6 1.11 ALLIANCE PIPELINE 0A2X0400110 POUCE COUPE 11 - 34 - 079 - 12 - 6 1.11 ALLIANCE PIPELINE 0A2X0400140 GORDONDALE 11 - 24 - 079 - 11 - 6 1.11 ALLIANCE PIPELINE 0A2X0400160 PROGRESS 01 - 01 - 078 - 10 - 6 1.11 ALLIANCE PIPELINE 0A2X0400170 VALHALLA 12 - 21 - 076 - 09 - 6 1.11 ALLIANCE PIPELINE 0A2X0400200 VALHALLA 16 - 20 - 075 - 09 - 6 1.11 ALLIANCE PIPELINE 0A2X0400210 TEEPEE CREEK 07 - 02 - 074 - 04 - 6 1.11 ALLIANCE PIPELINE 0A2X0400230 SEXSMITH 01 - 07 - 075 - 07 - 6 1.11 ALLIANCE PIPELINE 0A2X0400240 HYTHE/BRAINARD 14 - 18 - 074 - 12 - 6 1.11 ALLIANCE PIPELINE 0A2X0400260 KNOPCIK 01 - 28 - 073 - 10 - 6 1.11 ALLIANCE PIPELINE 0A2X0400270 WEMBLEY 06 - 19 - 073 - 08 - 6 1.11 ALLIANCE PIPELINE 0A2X0400271 ELMWORTH 01 - 08 - 070 - 11 - 6 1.11 ALLIANCE PIPELINE 0A2X0400290 WAPITI 03 - 08 - 068 - 08 - 6 1.11 ALLIANCE PIPELINE 0A2X0400300 GOLD CREEK 14 - 26 - 067 - 05 - 6 1.11 ALLIANCE PIPELINE 0A2X0400310 KARR 10 - 10 - 065 - 02 - 6 1.11 ALLIANCE PIPELINE 0A2X0400350 WASKAHIGAN 11 - 07 - 064 - 23 - 5 1.11 ALLIANCE PIPELINE 0A2X0400360 BIGSTONE WEST 14 - 28 - 059 - 22 - 5 1.11 ALLIANCE PIPELINE 0A2X0400380 TWO CREEKS 02 - 04 - 063 - 16 - 5 1.11 ALLIANCE PIPELINE 0A2X0400400 KAYBOB 03 - 10 - 064 - 19 - 5 1.11 ALLIANCE PIPELINE 0A2X0400410 KAYBOB SOUTH 1&2 05 - 12 - 062 - 20 - 5 1.11 ALLIANCE PIPELINE 0A2X0400440 EDSON 03 - 11 - 053 - 18 - 5 1.11 ALLIANCE PIPELINE 0A2X0400441 WOLF SOUTH 11 - 01 - 051 - 15 - 5 1.11 ALLIANCE PIPELINE 0A2X0400450 KAYBOB SOUTH #3 13 - 15 - 059 - 18 - 5 1.11 ALLIANCE PIPELINE 0A2X0400460 WEST WHITECOURT 02 - 17 - 060 - 15 - 5 1.11 ALLIANCE PIPELINE 0A2X0400470 CARSON CREEK 16 - 15 - 061 - 12 - 5 1.11 ALLIANCE PIPELINE 0A2X0400480 WHITECOURT 12 - 26 - 059 - 11 - 5 1.11 ALLIANCE PIPELINE 0A2X0400490 PADDLE RIVER 12 - 06 - 057 - 08 - 5 1.11 ALLIANCE PIPELINE 0A2X

EFFECTIVE OCTOBER 2004 PRODUCTION MONTHMETER STATION FACTORS

1 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0078532 Tide Lake 6-23 06 - 23 - 017 - 10 - 4 0.40 ALTAGAS HOLDINGS INC. A0WA0078997 Monogram 13-14-17-10w4 13 - 14 - 017 - 10 - 4 0.40 ALTAGAS HOLDINGS INC. A0WA0079245 Princess East 13-36 13 - 36 - 019 - 11 - 4 0.40 ALTAGAS HOLDINGS INC. A0WA0079246 Princess West 13-03 13 - 03 - 020 - 12 - 4 0.40 ALTAGAS HOLDINGS INC. A0WA0700001 C 00 - 33 - 014 - 08 - 4 0.40 ALTAGAS HOLDINGS INC. A0WA0700002 D 00 - 33 - 014 - 08 - 4 0.40 ALTAGAS HOLDINGS INC. A0WA0700003 CHANNEL LAKE 00 - 26 - 015 - 05 - 4 0.41 ALTAGAS HOLDINGS INC. A0WA0700004 DROWNING FORD 00 - 26 - 015 - 05 - 4 0.41 ALTAGAS HOLDINGS INC. A0WA0700005 KOOMATI 00 - 33 - 016 - 04 - 4 0.40 ALTAGAS HOLDINGS INC. A0WA0700006 GEX 00 - 04 - 017 - 02 - 4 0.41 ALTAGAS HOLDINGS INC. A0WA0700007 ALDERSON 1 09 - 02 - 014 - 08 - 4 0.40 ALTAGAS HOLDINGS INC. A0WA0700008 ALDERSON 2 04 - 13 - 014 - 07 - 4 0.40 ALTAGAS HOLDINGS INC. A0WA0700009 A1 STATION 04 - 03 - 019 - 09 - 4 0.40 ALTAGAS HOLDINGS INC. A0WA0700010 A2 STATION 16 - 15 - 020 - 08 - 4 0.40 ALTAGAS HOLDINGS INC. A0WA0700011 AB STATION 16 - 16 - 020 - 06 - 4 0.40 ALTAGAS HOLDINGS INC. A0WA0700012 B2 STATION 14 - 15 - 020 - 04 - 4 0.40 ALTAGAS HOLDINGS INC. A0WA0700013 E STATION 00 - 04 - 018 - 09 - 4 0.40 ALTAGAS HOLDINGS INC. A0WA0075200 Corbett South 2398 15 - 19 - 061 - 06 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0075359 Fabyan B (Viking 10-11) (353) 10 - 11 - 045 - 08 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0075765 West Lloydminister Rec Station 2410 06 - 09 - 050 - 01 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0076108 Rabbit Hill Receipt Station 2423 - 34 - 050 - 26 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0077073 Woking Receipt Stn 2432 15 - 11 - 076 - 06 - 6 1.01 ATCO PIPELINES NORTH 0Z6J0077210 VERNON LAKE Rec Stn 2435 07 - 09 - 047 - 10 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0077500 Gambling Lake (443) - 16 - 051 - 19 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0078873 Kneller Receipt Station 2575 - 02 - 051 - 23 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0078975 Viking South Receipt 2570 16 - 01 - 048 - 13 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0079063 Lostpoint Lake Receipt Stn (2437) 15 - 20 - 056 - 23 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0079266 Langford Park Receipt (Stn. 2614) 10 - 29 - 053 - 04 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0080255 Bolton Creek Receipt (Stn. 2687) 01 - 36 - 060 - 03 - 6 1.01 ATCO PIPELINES NORTH 0Z6J0082497 Good Hope Receipt Station (#3488) 00 - 30 - 054 - 20 - 4 1.01 ATCO PIPELINES NORTH 0Z6J

2 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0083017 Kneller South (Stn 2690) 12 - 10 - 050 - 23 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500026 EEEP RECEIPTS 00 - 04 - 052 - 24 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500070 MAGEE TIE-IN 00 - 20 - 042 - 25 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500073 PEAVEY EXCELSIOR 00 - 35 - 054 - 23 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500081 FABYAN 06 - 08 - 045 - 07 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500082 PASCHENDALE METER STATION 09 - 29 - 045 - 08 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500083 WAINWRIGHT RECEIPTS 00 - 25 - 044 - 07 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500084 GRATTON CREEK 00 - 22 - 045 - 08 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500086 WATELET 00 - 31 - 047 - 26 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500090 BRUDERHEIM 04 - 34 - 055 - 20 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500120 KITSCOTY 00 - 18 - 050 - 02 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500123 SUNNYBROOK 00 - 15 - 049 - 02 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0500125 PEMBINA #1 00 - 25 - 048 - 07 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0500126 PEMBINA #2 00 - 15 - 047 - 07 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0500128 PEMBINA #4 00 - 16 - 049 - 08 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0500130 PEMBINA #7 00 - 34 - 047 - 09 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0500131 PEMBINA #8 00 - 05 - 049 - 09 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0500135 "KEYSTONE ""A""" 05 - 35 - 048 - 04 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0500136 "KEYSTONE ""B""" 00 - 15 - 048 - 03 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0500140 "THORSBY ""A""" 07 - 14 - 049 - 01 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0500142 "THORSBY ""B""" 00 - 19 - 049 - 01 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0500157 BIGORAY B 00 - 21 - 051 - 08 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0500167 MAJEAU LAKE 13 - 15 - 057 - 03 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0500175 FREEMAN RIVER 00 - 24 - 063 - 10 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0500184 VILLENEUVE 7-54-26-W4 00 - 07 - 054 - 26 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500185 "CHERHILL ""B""" 00 - 01 - 056 - 05 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0500196 HAIGHT TIE-IN 00 - 24 - 052 - 17 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500220 JOARCAM 00 - 19 - 047 - 19 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500222 LLOYDMINSTER A 00 - 11 - 051 - 04 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500223 LLOYDMINSTER B 00 - 17 - 051 - 03 - 4 1.01 ATCO PIPELINES NORTH 0Z6J

3 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0500241 JOFFRE REFRIG PLT 00 - 12 - 038 - 27 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500290 MYRNAM 00 - 10 - 053 - 09 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500291 MUNDARE A 00 - 34 - 053 - 18 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500292 "MUNDARE ""B""" 00 - 34 - 053 - 18 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500293 LAMONT 00 - 05 - 055 - 19 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500355 "BUFFALO CREEK A 2430 00 - 23 - 048 - 09 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500356 "IRMA ""B""" 16 - 09 - 046 - 09 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500358 ALICE LAKE 11 - 02 - 049 - 11 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500371 FBA FRIG PLT INLET 00 - 20 - 056 - 23 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500419 TRAPPERS LAKE METER STATION 11 - 27 - 053 - 21 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500440 BEAVERHILL LAKE (Lindbrook 2420) 00 - 16 - 051 - 19 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500442 RYLEY -BEAVERHILL LAKE 2422 11 - 02 - 049 - 17 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500500 OPAL Redwater 01 - 25 - 057 - 23 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500505 IRMA NORTH 11 - 12 - 047 - 07 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500507 WILDMERE SOUTH 15 - 05 - 048 - 06 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500508 WILDMERE NORTH 11 - 20 - 048 - 06 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0500543 INVERNESS RIVER 00 - 29 - 069 - 10 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0500798 GRIMSHAW 00 - 23 - 083 - 23 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501024 CRYSTAL LAKE 06 - 15 - 048 - 03 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501044 HUGGETT 00 - 27 - 049 - 01 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501056 PARTRIDGE HILL (FT. SASK.) 2421 00 - 15 - 053 - 21 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501078 "BERRYMOOR ""B""" 00 - 10 - 049 - 06 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501120 JAYAR METER STATION 00 - 05 - 061 - 03 - 6 1.01 ATCO PIPELINES NORTH 0Z6J0501130 Pemburton Hill Meter Station 00 - 01 - 051 - 03 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501153 GRIZZLY BEAR CREEK METER STN 00 - 05 - 049 - 06 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501166 CARDINAL LAKE 07 - 16 - 083 - 23 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501174 FASHENDALE 08 - 32 - 046 - 07 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501202 SANDY LAKE 09 - 30 - 054 - 27 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501218 BREMNER (FT. SASK.) 2419 00 - 06 - 054 - 21 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501242 EUREKA RIVER 00 - 19 - 085 - 05 - 6 1.01 ATCO PIPELINES NORTH 0Z6J

4 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0501278 DEVILLE METER STATION 01 - 04 - 052 - 20 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501291 CLAYSMORE METER STN 00 - 22 - 050 - 07 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501314 MOTT LAKE 11-01-045 11 - 01 - 045 - 07 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501315 MOTT LAKE 16-12-45-7 W4 16 - 12 - 045 - 07 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501346 BATTLE RIVER 00 - 18 - 045 - 07 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501367 BARRHILL 04 - 22 - 050 - 07 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501369 ANTLER LAKEMETER STATION 00 - 15 - 052 - 21 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501375 SADDLE HILLS SALES 05 - 29 - 074 - 06 - 6 1.01 ATCO PIPELINES NORTH 0Z6J0501378 FISH CREEK -1378 05 - 29 - 051 - 25 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501379 FISH CREEK -1379 06 - 29 - 051 - 25 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501384 TOMAHAWK CREEK 08 - 18 - 053 - 06 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501385 MEDICINE LODGE 00 - 32 - 053 - 21 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501387 CHIP LAKE 00 - 29 - 053 - 10 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501398 PIPESTONE CREEK 10 - 23 - 046 - 23 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501399 SCHULTZ LAKE 14 - 22 - 049 - 23 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501400 IRVINE CREEK 10 - 09 - 051 - 23 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501444 ASTOTIN CREEK 00 - 03 - 055 - 22 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501466 TWIN LAKES METER STATION 00 - 22 - 059 - 05 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501473 KITTO LAKEMETER STATION 00 - 10 - 049 - 06 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501482 "ACHESON ""B""" 00 - 02 - 053 - 26 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501532 YEKAU LAKE 11 - 25 - 052 - 26 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501535 CREEKLAND METER STATION 15 - 14 - 050 - 03 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501536 AUBURNDALE 13 - 15 - 047 - 08 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501537 RIVERDALE 11 - 25 - 046 - 07 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501562 LAC LARONGER METER STATION 04 - 27 - 048 - 11 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501563 CAMP LAKE METER STATION 03 - 04 - 048 - 11 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501564 CARRIER LAKE METER STATION 04 - 25 - 047 - 11 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501565 LAC DEROCHES METER STATION 14 - 11 - 047 - 11 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501590 REDWATER CNSV PL NET. 00 - 29 - 057 - 21 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501616 EUREKA RIVER NORTH 00 - 02 - 086 - 06 - 6 1.01 ATCO PIPELINES NORTH 0Z6J

5 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0501657 GOOSE CREEK 00 - 32 - 061 - 07 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501658 EASTGATE METER STATION 13 - 03 - 057 - 22 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501671 ERIC CREEK 01 - 08 - 047 - 10 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501673 HOLT 06 - 18 - 047 - 09 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501677 MAYATAN LAKE 09 - 03 - 052 - 04 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501685 BIRCH LAKE 01 - 31 - 048 - 11 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501686 GODSON LAKE 01 - 32 - 048 - 11 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501707 NEWTON METER STATION 12 - 06 - 058 - 03 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501709 PADDLE RIVER NET 13 - 06 - 057 - 08 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501710 BIGORAY NET 00 - 28 - 051 - 08 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501711 THUNDER NET 00 - 14 - 060 - 06 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501712 LISBURN A NET 02 - 25 - 056 - 06 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501713 EARLIE LAKE NET 00 - 10 - 049 - 02 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501714 KENILWORTH NET 00 - 02 - 050 - 04 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501715 CONJURING CREEK NET 08 - 18 - 048 - 26 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501716 RODINO NET 01 - 30 - 047 - 09 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501721 HOUSE MTN NET 00 - 29 - 069 - 10 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501734 BIG STURGEON 00 - 26 - 054 - 25 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501742 LAWSON LAKE 04 - 05 - 051 - 06 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501746 RIVERDALE 11 - 25 - 046 - 07 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501754 BRAEBURN CREEK 14 - 08 - 077 - 05 - 6 1.01 ATCO PIPELINES NORTH 0Z6J0501760 AKUSA METER STATION 04 - 06 - 049 - 11 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501763 WOLF CREEK 00 - 18 - 042 - 25 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501767 PERCY LAKE 04 - 28 - 048 - 10 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501769 NORTHMARK 08 - 31 - 076 - 05 - 6 1.01 ATCO PIPELINES NORTH 0Z6J0501770 ELK ISLAND 04 - 19 - 055 - 20 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501771 MAPLE LODGE 10 - 24 - 048 - 12 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501787 MASKWA CREEK 00 - 22 - 043 - 25 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501789 KILINI CREEK 15 - 28 - 053 - 02 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501791 ROSS CREEK 06 - 24 - 054 - 22 - 4 1.01 ATCO PIPELINES NORTH 0Z6J

6 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0501792 IRON CREEK MASTER 12 - 26 - 048 - 12 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501799 MANAWAN LAKE 15 - 23 - 056 - 25 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501802 DUAGH 00 - 27 - 055 - 22 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501809 NOYES CROSSING 02 - 16 - 055 - 01 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501810 HIGHVALE NET 12 - 34 - 048 - 04 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501813 TOAD LAKE RECEIPT STN 06 - 02 - 056 - 02 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501816 KAKUT 14 - 18 - 077 - 04 - 6 1.01 ATCO PIPELINES NORTH 0Z6J0501821 BEAR HILLS METER STATION 14 - 11 - 045 - 27 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501828 BUCKWHEAT NET 01 - 27 - 051 - 27 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501829 HANGING STONE METER STATION 00 - 07 - 053 - 25 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501830 BLACKFOOT CREEK REC POINT 05 - 18 - 050 - 02 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501834 COYOTE CREEK RECEIPT STATION 00 - 32 - 005 - 21 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501853 Vantage Net 10 - 07 - 051 - 09 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501856 LLOYD CREEK NET 10 - 07 - 051 - 09 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501859 TRIBUTE NET 10 - 07 - 051 - 09 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501864 VIKING FIELD NET 00 - 36 - 048 - 13 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501875 MCLEOD RIVER RECEIPT 01 - 24 - 052 - 20 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501879 MANNVILLE RECEIPT STATION 04 - 27 - 050 - 09 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501880 BERRYMORE A GROUP 00 - 03 - 049 - 06 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501892 Paddy Creek Receipt Station 16 - 25 - 048 - 09 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501896 BONNIE GLEN GROUP LOCATION 00 - 17 - 047 - 27 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501897 MOTT LAKE 2-12 02 - 12 - 045 - 07 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501901 LOBSTICK 00 - 17 - 050 - 07 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501903 Blue Sky Group 01 - 36 - 060 - 03 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501910 Feign Lake 09 - 10 - 047 - 09 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0501913 SUNDANCE CREEK REC STN 14 - 14 - 053 - 20 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0501960 ROCKY CREEK REC STN 07 - 15 - 064 - 02 - 6 1.01 ATCO PIPELINES NORTH 0Z6J0501962 BINGO LAKE RECEIPT 11 - 28 - 082 - 03 - 6 1.01 ATCO PIPELINES NORTH 0Z6J0501974 LAC MAGLIORE 06 - 23 - 080 - 22 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0502021 QUEENIE RECEIPT STN 09 - 07 - 052 - 07 - 4 1.01 ATCO PIPELINES NORTH 0Z6J

7 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0502022 VERMILION RIVER REC STATION 15 - 17 - 051 - 06 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0502025 ANSEL NET 03 - 11 - 053 - 18 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0502147 SWIMMING POND RECEIPT 05 - 05 - 051 - 06 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0502150 NORBUCK NET 11 - 17 - 049 - 04 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0502184 HARGWEN RECEIPT STATION 16 - 31 - 052 - 21 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0502189 SOUTH CARROT CREEK RECEIPT STATION 10 - 16 - 053 - 13 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0502193 PERCY LAKE RECEIPT STATION 04 - 08 - 048 - 10 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0502194 NOBLE RECEIPT STATION 06 - 02 - 049 - 13 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0502195 IRMA RECEIPT STATION 12 - 01 - 046 - 09 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0502234 ALEXIS RECEIPT STATON 07 - 01 - 056 - 05 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0508000 BATTLE LAKE 00 - 23 - 046 - 02 - 5 1.01 ATCO PIPELINES NORTH 0Z6J0509602 VIKING 6-2 06 - 02 - 049 - 13 - 4 1.01 ATCO PIPELINES NORTH 0Z6J0076968 Blizzard Lake 13467 10 - 15 - 021 - 27 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0077916 Frank Lake 13460 05 - 13 - 019 - 28 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0078870 Weston Lake Receipt Station (12739) 10 - 12 - 005 - 17 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0079901 Foremost Receipt Station (#13637) - 11 - 008 - 12 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0081778 Brooks (Stn #12742) - 17 - 019 - 13 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0610100 SHELL J. P. GROUP LOCATION 00 - 13 - 025 - 05 - 5 1.02 ATCO PIPELINES SOUTH 0Z7N0611501 PAN CANADIAN REDLAND 00 - 08 - 029 - 22 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0611507 STRATHM. #2 N PHASE 1 09 - 27 - 024 - 25 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0611508 STRATHMORE # 2 S. PHASE 2 06 - 28 - 023 - 25 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0611509 PAN CANADIAN-CARSELAND 01 - 29 - 022 - 26 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0611530 GAYFORD SOUTH PAN CAN 12 - 35 - 026 - 25 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0611593 ROSEBUD GROUP 01 - 22 - 027 - 25 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0611595 KEOMA RECEIPT STATION 16 - 18 - 026 - 26 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0612403 GRASSY LAKE GROUP LOCATION 00 - 07 - 012 - 13 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0612404 GRASSY LAKE EAST METER STATION 13 - 35 - 010 - 13 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0612503 BECKER COULEE RECEIPT STATION 04 - 23 - 006 - 11 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0612506 CHIN COULEE RECEIPT STATION 03 - 05 - 010 - 19 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0612507 "ENTICE ""B""" 00 - 05 - 028 - 24 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N

8 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0612509 YELLOW LAKE GROUP 03 - 05 - 010 - 19 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0612515 DEADHORSE RECEIPT STATION 00 - 14 - 023 - 27 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0612527 Horseshoe Receipt Station 01 - 34 - 009 - 22 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0612529 A/P CARBON TO CALGARY 08 - 17 - 029 - 22 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0612548 Benaman 12 - 30 - 024 - 25 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0612549 Purple Springs Receipt Station 00 - 04 - 010 - 15 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0612550 Sharples Receipt Station 08 - 17 - 029 - 22 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0612551 Nevis Receipt Station 00 - 33 - 038 - 22 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0612556 LONG COULEE RECEIPT STATION 08 - 18 - 015 - 22 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0612611 MEDALLION RECEIPT STATION 12 - 02 - 020 - 27 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0612666 CAIRN HILL NET 04 - 04 - 011 - 12 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0612702 HILLSDOWN RECEIPT STATION 02 - 01 - 038 - 26 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0612862 BOW ISLAND SHARED FACILITY 14 - 08 - 011 - 11 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0612920 WRENTHAM EAST-RENAISSANCE 00 - 31 - 006 - 16 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0613405 CARBON SOUTH 08 - 17 - 029 - 22 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0614201 JOFFRE 00 - 01 - 038 - 25 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0615001 COALDALE SOUTH B #5402/LETH. A 00 - 10 - 008 - 21 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0615004 COALDALE SOUTH A&B #3884 00 - 10 - 008 - 21 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0615253 WEST LETHBR. GROUP LOC. 00 - 10 - 080 - 21 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0615260 MOSQUITO CREEK 07 - 05 - 015 - 26 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0615272 COALDALE EAST GROUP LOCATION 04 - 05 - 010 - 19 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0615701 CLARESHOLMRANGER 00 - 36 - 012 - 27 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0615705 CLARESHOLM CDN. HUNTER 00 - 31 - 012 - 25 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0641000 ANTHONY HENDAY STN 6528 00 - 36 - 035 - 01 - 5 1.02 ATCO PIPELINES SOUTH 0Z7N0641103 OLDS-CAN 88 GROUP LOCATION 00 - 36 - 035 - 01 - 5 1.02 ATCO PIPELINES SOUTH 0Z7N0642001 CIMARRON ARDLEY 00 - 21 - 038 - 23 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0653900 BLOODWELLING 00 - 21 - 060 - 21 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0672650 GRANUM CWNG & GRAD WALKER COMP 00 - 19 - 011 - 25 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0673700 BLOOD 00 - 34 - 005 - 22 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0675401 WINNIFRED - BALLISTIC 02 - 17 - 011 - 10 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N

9 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0677601 TABER/WEST 00 - 35 - 009 - 17 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0677610 FINCASTLE-MAGRATH ENERGY 00 - 12 - 010 - 16 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0677698 FINCASTLE SOUTH (WESTERN STAR) 02 - 04 - 010 - 15 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0677700 COALDALE EAST #2 04 - 02 - 010 - 19 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0677750 BROXBURN NORTH 08 - 02 - 010 - 21 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0678100 MAZEPPA GROUP LOCATION 00 - 02 - 020 - 28 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0678401 ARROWWOOD - SOUTH 16 - 06 - 020 - 25 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0678601 ARROWWOOD - NORTH 04 - 15 - 021 - 25 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0678602 MOSSLEIGH 00 - 31 - 020 - 24 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0678701 GLADYS RIDGE 00 - 03 - 020 - 27 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0678900 PARKLAND 04 - 10 - 015 - 27 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0679201 CANTERRA ENTICE 00 - 24 - 028 - 24 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0680210 PAN CDN. ENTICE 10 - 07 - 028 - 23 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0680230 "ENTICE ""A""" 00 - 05 - 028 - 24 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0682903 STIRLING PLANT OUTLET 00 - 35 - 006 - 19 - 4 1.02 ATCO PIPELINES SOUTH 0Z7N0001001 BINDLOSS SOUTH 00 - 13 - 022 - 04 - 4 0.81 NOVA - NGTL 0TB30001002 BINDLOSS NORTH #1 00 - 27 - 022 - 04 - 4 0.81 NOVA - NGTL 0TB30001003 PROVOST NORTH 00 - 18 - 036 - 05 - 4 0.93 NOVA - NGTL 0TB30001004 CESSFORD WARDLOW 02 - 31 - 022 - 11 - 4 0.81 NOVA - NGTL 0TB30001007 OYEN 00 - 36 - 028 - 05 - 4 0.86 NOVA - NGTL 0TB30001009 ATLEE-BUFFALO 00 - 13 - 021 - 07 - 4 0.77 NOVA - NGTL 0TB30001010 PRINCESS-DENHART 00 - 16 - 020 - 11 - 4 0.76 NOVA - NGTL 0TB30001012 CESSFORD WEST 02 - 09 - 024 - 12 - 4 0.81 NOVA - NGTL 0TB30001013 PROVOST SOUTH 08 - 34 - 034 - 06 - 4 0.97 NOVA - NGTL 0TB30001015 COUNTESS MAKEPEACE 00 - 33 - 022 - 18 - 4 0.50 NOVA - NGTL 0TB30001016 HUSSAR-CHANCELLOR 15 - 36 - 024 - 21 - 4 0.75 NOVA - NGTL 0TB30001017 MEDICINE HAT NORTH #1 02 - 27 - 017 - 02 - 4 0.22 NOVA - NGTL 0TB30001018 MEDICINE HAT SOUTH #1 01 - 07 - 016 - 02 - 4 0.81 NOVA - NGTL 0TB30001019 NEVIS SOUTH 00 - 03 - 039 - 22 - 4 0.93 NOVA - NGTL 0TB30001020 NEVIS NORTH 07 - 22 - 039 - 22 - 4 0.95 NOVA - NGTL 0TB3

10 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0001021 WAYNE NORTH 04 - 04 - 028 - 20 - 4 0.86 NOVA - NGTL 0TB30001022 PRINCESS-IDDESLEIGH 16 - 16 - 020 - 10 - 4 0.79 NOVA - NGTL 0TB30001023 SEDALIA SOUTH 00 - 18 - 030 - 04 - 4 0.85 NOVA - NGTL 0TB30001024 ENCHANT 00 - 03 - 014 - 17 - 4 0.83 NOVA - NGTL 0TB30001025 CESSFORD EAST 00 - 36 - 023 - 11 - 4 0.81 NOVA - NGTL 0TB30001027 CESSFORD-BURFIELD WEST 13 - 10 - 027 - 15 - 4 0.83 NOVA - NGTL 0TB30001028 COUNTESS 00 - 06 - 021 - 15 - 4 0.70 NOVA - NGTL 0TB30001029 THREE HILLS CREEK 00 - 13 - 035 - 26 - 4 0.88 NOVA - NGTL 0TB30001034 CHIGWELL 04 - 17 - 041 - 24 - 4 1.11 NOVA - NGTL 0TB30001035 WOOD RIVER 00 - 08 - 043 - 23 - 4 1.08 NOVA - NGTL 0TB30001036 SEDALIA NORTH 01 - 32 - 031 - 05 - 4 1.10 NOVA - NGTL 0TB30001037 GILBY #2 00 - 25 - 040 - 03 - 5 0.87 NOVA - NGTL 0TB30001038 PROVOST-KESSLER 00 - 05 - 039 - 08 - 4 1.20 NOVA - NGTL 0TB30001039 WAYNE-DALUM 15 - 07 - 027 - 19 - 4 0.51 NOVA - NGTL 0TB30001040 CHIGWELL EAST 07 - 14 - 041 - 24 - 4 1.08 NOVA - NGTL 0TB30001043 MEDICINE HAT SOUTH #2 01 - 07 - 016 - 02 - 4 0.22 NOVA - NGTL 0TB30001045 PROVOST WEST 00 - 21 - 036 - 07 - 4 1.15 NOVA - NGTL 0TB30001046 WIMBORNE 05 - 01 - 034 - 26 - 4 0.81 NOVA - NGTL 0TB30001053 OLDS 03 - 18 - 032 - 01 - 5 0.84 NOVA - NGTL 0TB30001054 SYLVAN LAKE 00 - 16 - 038 - 02 - 5 0.86 NOVA - NGTL 0TB30001055 SYLVAN LAKE WEST 00 - 33 - 037 - 03 - 5 0.89 NOVA - NGTL 0TB30001056 VERGER 05 - 28 - 021 - 14 - 4 0.49 NOVA - NGTL 0TB30001057 RETLAW 00 - 10 - 013 - 19 - 4 0.81 NOVA - NGTL 0TB30001058 OYEN NORTH 10 - 17 - 029 - 04 - 4 0.77 NOVA - NGTL 0TB30001060 CESSFORD-BURFIELD #2 08 - 05 - 027 - 14 - 4 0.81 NOVA - NGTL 0TB30001064 EDSON 00 - 11 - 053 - 18 - 5 0.91 NOVA - NGTL 0TB30001065 SOUTH ELKTON 00 - 03 - 031 - 04 - 5 1.13 NOVA - NGTL 0TB30001066 TWINING NORTH 00 - 31 - 032 - 24 - 4 0.83 NOVA - NGTL 0TB30001069 LONE PINE CREEK 06 - 23 - 030 - 28 - 4 0.81 NOVA - NGTL 0TB30001070 WINTERING HILLS 00 - 07 - 025 - 17 - 4 0.49 NOVA - NGTL 0TB3

11 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0001073 GHOSTPINE 16 - 02 - 031 - 21 - 4 0.80 NOVA - NGTL 0TB30001074 EQUITY 00 - 29 - 031 - 23 - 4 0.86 NOVA - NGTL 0TB30001075 ALDERSON 00 - 29 - 015 - 11 - 4 0.68 NOVA - NGTL 0TB30001076 VULCAN 00 - 19 - 015 - 21 - 4 0.77 NOVA - NGTL 0TB30001077 VERGER-HOMESTEAD 00 - 19 - 021 - 13 - 4 0.81 NOVA - NGTL 0TB30001079 SUNNYNOOK 09 - 23 - 026 - 12 - 4 0.81 NOVA - NGTL 0TB30001084 GILBY SOUTH PACIFIC 00 - 25 - 040 - 03 - 5 0.87 NOVA - NGTL 0TB30001085 BERRY-CAROLSIDE 01 - 16 - 026 - 12 - 4 0.80 NOVA - NGTL 0TB30001086 CESSFORD WEST GAGE 00 - 09 - 024 - 12 - 4 0.81 NOVA - NGTL 0TB30001089 BELLIS 00 - 15 - 059 - 16 - 4 1.07 NOVA - NGTL 0TB30001090 MITSUE 10 - 30 - 072 - 04 - 5 1.35 NOVA - NGTL 0TB30001091 MARTEN HILLS 14 - 07 - 076 - 25 - 4 1.23 NOVA - NGTL 0TB30001093 GREENCOURT 00 - 26 - 059 - 09 - 5 1.16 NOVA - NGTL 0TB30001094 WHITECOURT 00 - 26 - 059 - 11 - 5 1.12 NOVA - NGTL 0TB30001095 FLAT LAKE 00 - 27 - 065 - 19 - 4 1.33 NOVA - NGTL 0TB30001096 BRAZEAU SOUTH 00 - 10 - 044 - 12 - 5 0.88 NOVA - NGTL 0TB30001097 MARTEN HILLS SOUTH 00 - 22 - 074 - 24 - 4 1.35 NOVA - NGTL 0TB30001098 ATLEE-BUFFALO SOUTH 00 - 19 - 020 - 06 - 4 0.80 NOVA - NGTL 0TB30001099 JENNER WEST 00 - 14 - 020 - 09 - 4 0.76 NOVA - NGTL 0TB30001100 BANTRY 07 - 28 - 017 - 12 - 4 0.76 NOVA - NGTL 0TB30001101 FERRIER NORTH 00 - 31 - 040 - 07 - 5 0.88 NOVA - NGTL 0TB30001103 ALDERSON SOUTH 00 - 29 - 015 - 11 - 4 0.77 NOVA - NGTL 0TB30001104 WINTERING HILLS EAST 12 - 23 - 023 - 17 - 4 0.81 NOVA - NGTL 0TB30001106 RAINIER 15 - 35 - 016 - 16 - 4 0.80 NOVA - NGTL 0TB30001107 WAYNE-ROSEBUD 00 - 04 - 027 - 21 - 4 0.49 NOVA - NGTL 0TB30001110 PLAIN LAKE 00 - 36 - 052 - 13 - 4 1.25 NOVA - NGTL 0TB30001111 FERRIER SOUTH B 00 - 20 - 039 - 07 - 5 0.91 NOVA - NGTL 0TB30001112 CRAIGEND EAST 00 - 26 - 064 - 14 - 4 1.28 NOVA - NGTL 0TB30001114 SEDGEWICK 00 - 16 - 042 - 12 - 4 1.35 NOVA - NGTL 0TB30001115 STRACHAN 00 - 35 - 037 - 09 - 5 0.81 NOVA - NGTL 0TB3

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ID


0001116 ATLEE-BUFFALO EAST 00 - 22 - 020 - 04 - 4 0.81 NOVA - NGTL 0TB30001118 WARWICK 00 - 04 - 054 - 14 - 4 1.00 NOVA - NGTL 0TB30001120 UKALTA 00 - 25 - 057 - 17 - 4 1.24 NOVA - NGTL 0TB30001122 BANTRY NORTH 01 - 02 - 019 - 14 - 4 0.74 NOVA - NGTL 0TB30001128 MEDICINE HAT SOUTH #4 01 - 07 - 016 - 02 - 4 0.22 NOVA - NGTL 0TB30001131 STANMORE 01 - 11 - 030 - 12 - 4 0.85 NOVA - NGTL 0TB30001132 LAVOY 00 - 12 - 052 - 14 - 4 1.10 NOVA - NGTL 0TB30001134 ROCKYFORD 10 - 24 - 026 - 23 - 4 0.79 NOVA - NGTL 0TB30001135 RICINUS 00 - 02 - 037 - 10 - 5 0.83 NOVA - NGTL 0TB30001139 LONE PINE SOUTH 00 - 27 - 029 - 28 - 4 0.81 NOVA - NGTL 0TB30001140 NEWELL NORTH 00 - 21 - 018 - 14 - 4 0.81 NOVA - NGTL 0TB30001142 HUXLEY 00 - 17 - 034 - 24 - 4 0.86 NOVA - NGTL 0TB30001143 JENNER EAST 00 - 21 - 020 - 08 - 4 0.77 NOVA - NGTL 0TB30001144 MIKWAN NORTH 00 - 08 - 037 - 23 - 4 0.88 NOVA - NGTL 0TB30001145 CESSFORD NORTH 00 - 19 - 026 - 13 - 4 0.81 NOVA - NGTL 0TB30001146 MIKWAN 00 - 19 - 035 - 22 - 4 1.00 NOVA - NGTL 0TB30001147 DONALDA 15 - 18 - 040 - 18 - 4 1.22 NOVA - NGTL 0TB30001148 CRAIGEND SOUTH 00 - 20 - 063 - 12 - 4 1.32 NOVA - NGTL 0TB30001150 MATZHIWIN WEST 00 - 35 - 022 - 15 - 4 0.76 NOVA - NGTL 0TB30001152 CESSFORD NORTHEAST 12 - 05 - 026 - 12 - 4 0.81 NOVA - NGTL 0TB30001154 VALE 00 - 19 - 014 - 02 - 4 0.81 NOVA - NGTL 0TB30001156 STANMORE SOUTH 00 - 02 - 029 - 12 - 4 0.82 NOVA - NGTL 0TB30001157 BIG BEND 00 - 06 - 067 - 26 - 4 1.35 NOVA - NGTL 0TB30001159 JARROW SOUTH 04 - 05 - 044 - 09 - 4 1.27 NOVA - NGTL 0TB30001161 HOLDEN 00 - 20 - 048 - 16 - 4 1.07 NOVA - NGTL 0TB30001162 KILLAM 09 - 05 - 045 - 12 - 4 1.35 NOVA - NGTL 0TB30001163 JARROW 00 - 05 - 045 - 10 - 4 1.32 NOVA - NGTL 0TB30001164 RANFURLY 00 - 28 - 050 - 09 - 4 1.26 NOVA - NGTL 0TB30001165 RANFURLY WEST 00 - 32 - 049 - 11 - 4 1.15 NOVA - NGTL 0TB30001166 HARMATTAN-ELKTON 12 - 26 - 031 - 04 - 5 0.81 NOVA - NGTL 0TB3

13 of 41


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LOCATION


PIPELINE COMPANY

ID


0001167 JOFFRE 00 - 36 - 038 - 27 - 4 1.05 NOVA - NGTL 0TB30001168 BRUCE 00 - 06 - 047 - 15 - 4 0.89 NOVA - NGTL 0TB30001169 TILLEY 00 - 16 - 017 - 12 - 4 0.80 NOVA - NGTL 0TB30001172 MEDICINE HAT WEST 01 - 07 - 016 - 02 - 4 0.81 NOVA - NGTL 0TB30001173 WARWICK SOUTH 00 - 18 - 053 - 14 - 4 1.06 NOVA - NGTL 0TB30001179 STROME-HOLMBERG 00 - 13 - 044 - 17 - 4 0.99 NOVA - NGTL 0TB30001180 PENHOLD 00 - 29 - 036 - 27 - 4 0.81 NOVA - NGTL 0TB30001181 BANTRY NORTH WEST 09 - 07 - 019 - 13 - 4 0.76 NOVA - NGTL 0TB30001182 HANNA 13 - 22 - 031 - 14 - 4 0.81 NOVA - NGTL 0TB30001183 PRINCESS WEST 00 - 13 - 020 - 12 - 4 0.81 NOVA - NGTL 0TB30001184 MEDICINE HAT NORTH ARCO 00 - 27 - 017 - 02 - 4 0.22 NOVA - NGTL 0TB30001185 DISMAL CREEK 00 - 01 - 049 - 16 - 5 0.92 NOVA - NGTL 0TB30001186 MEDICINE HAT EAST 00 - 07 - 016 - 01 - 4 0.81 NOVA - NGTL 0TB30001187 SYLVAN LAKE EAST #1 00 - 19 - 038 - 01 - 5 0.84 NOVA - NGTL 0TB30001188 WEST VIKING 00 - 01 - 049 - 14 - 4 1.08 NOVA - NGTL 0TB30001189 RANFURLY NORTH 14 - 32 - 050 - 13 - 4 1.04 NOVA - NGTL 0TB30001190 TWINING 00 - 10 - 031 - 24 - 4 0.81 NOVA - NGTL 0TB30001191 SYLVAN LAKE SOUTH 00 - 25 - 037 - 03 - 5 0.90 NOVA - NGTL 0TB30001193 SULLIVAN LAKE 00 - 18 - 034 - 13 - 4 1.02 NOVA - NGTL 0TB30001194 NIPISI 10 - 30 - 072 - 04 - 5 1.35 NOVA - NGTL 0TB30001196 CHAUVIN 00 - 36 - 042 - 02 - 4 1.35 NOVA - NGTL 0TB30001197 BAXTER LAKE 00 - 28 - 046 - 05 - 4 1.35 NOVA - NGTL 0TB30001198 BAXTER LAKE WEST 00 - 28 - 045 - 05 - 4 1.35 NOVA - NGTL 0TB30001199 WAINWRIGHT SOUTH 00 - 36 - 043 - 06 - 4 1.29 NOVA - NGTL 0TB30001201 IRVINE 00 - 23 - 012 - 02 - 4 0.99 NOVA - NGTL 0TB30001203 VERGER-MILLICENT 00 - 17 - 021 - 13 - 4 0.49 NOVA - NGTL 0TB30001204 BOWMANTON SOUTH 00 - 22 - 014 - 04 - 4 0.81 NOVA - NGTL 0TB30001205 MEDICINE HAT NORTHWEST 00 - 27 - 017 - 02 - 4 0.80 NOVA - NGTL 0TB30001206 LANFINE 00 - 27 - 027 - 05 - 4 0.83 NOVA - NGTL 0TB30001207 HUDSON 00 - 31 - 030 - 02 - 4 1.01 NOVA - NGTL 0TB3

14 of 41


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LOCATION


PIPELINE COMPANY

ID


0001208 ALDERSON NORTH 00 - 18 - 018 - 12 - 4 0.79 NOVA - NGTL 0TB30001209 REDCLIFF 12 - 29 - 014 - 05 - 4 0.92 NOVA - NGTL 0TB30001210 LAKE NEWELL EAST 00 - 21 - 017 - 14 - 4 0.49 NOVA - NGTL 0TB30001211 PROVOST MONITOR 00 - 16 - 033 - 07 - 4 1.23 NOVA - NGTL 0TB30001212 VALE EAST 00 - 17 - 014 - 01 - 4 0.58 NOVA - NGTL 0TB30001213 EDWAND 00 - 01 - 061 - 17 - 4 1.13 NOVA - NGTL 0TB30001214 MEDICINE RIVER A 00 - 16 - 038 - 04 - 5 1.26 NOVA - NGTL 0TB30001215 BRUCE NORTH 00 - 01 - 048 - 15 - 4 1.13 NOVA - NGTL 0TB30001216 BOWMANTON 00 - 33 - 015 - 04 - 4 0.28 NOVA - NGTL 0TB30001218 RETLAW SOUTH 00 - 19 - 012 - 18 - 4 0.67 NOVA - NGTL 0TB30001219 REDCLIFF SOUTH 16 - 07 - 014 - 05 - 4 0.86 NOVA - NGTL 0TB30001220 DUNMORE 00 - 26 - 013 - 04 - 4 0.93 NOVA - NGTL 0TB30001221 CHINOOK-CEREAL 00 - 26 - 030 - 06 - 4 0.92 NOVA - NGTL 0TB30001222 MONITOR SOUTH 00 - 34 - 034 - 05 - 4 0.90 NOVA - NGTL 0TB30001223 TIDE LAKE SOUTH 00 - 23 - 017 - 10 - 4 0.81 NOVA - NGTL 0TB30001224 KEHO LAKE 00 - 11 - 011 - 22 - 4 0.81 NOVA - NGTL 0TB30001225 BIG BEND EAST 00 - 07 - 067 - 26 - 4 1.35 NOVA - NGTL 0TB30001227 BOLLOQUE 00 - 23 - 064 - 26 - 4 1.35 NOVA - NGTL 0TB30001228 CAVENDISH SOUTH 00 - 02 - 021 - 03 - 4 0.81 NOVA - NGTL 0TB30001229 MAJESTIC 00 - 14 - 021 - 06 - 4 0.87 NOVA - NGTL 0TB30001230 HAIRY HILL 00 - 36 - 055 - 14 - 4 1.10 NOVA - NGTL 0TB30001231 BAXTER LAKE SOUTH 00 - 05 - 045 - 05 - 4 1.35 NOVA - NGTL 0TB30001232 ERSKINE NORTH 15 - 31 - 039 - 20 - 4 1.06 NOVA - NGTL 0TB30001234 WIMBORNE NORTH 00 - 05 - 035 - 26 - 4 0.81 NOVA - NGTL 0TB30001236 DOROTHY 00 - 05 - 028 - 17 - 4 1.01 NOVA - NGTL 0TB30001237 BOWMANTON WEST 00 - 26 - 015 - 05 - 4 1.09 NOVA - NGTL 0TB30001241 HYLO 01 - 25 - 066 - 14 - 4 1.35 NOVA - NGTL 0TB30001242 BODO WEST 00 - 31 - 037 - 02 - 4 1.04 NOVA - NGTL 0TB30001246 PRINCESS EAST 16 - 16 - 020 - 10 - 4 0.79 NOVA - NGTL 0TB30001256 TWEEDIE SOUTH 00 - 05 - 068 - 12 - 4 1.31 NOVA - NGTL 0TB3

15 of 41


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LOCATION


PIPELINE COMPANY

ID


0001257 VIKING NORTH 00 - 31 - 049 - 13 - 4 1.17 NOVA - NGTL 0TB30001259 GREGORY WEST 00 - 14 - 022 - 14 - 4 0.74 NOVA - NGTL 0TB30001264 BENALTO WEST 00 - 12 - 038 - 03 - 5 0.91 NOVA - NGTL 0TB30001265 EDGERTON 05 - 13 - 045 - 04 - 4 1.35 NOVA - NGTL 0TB30001266 EDGERTON WEST 00 - 36 - 044 - 05 - 4 1.35 NOVA - NGTL 0TB30001267 GREGORY 00 - 18 - 022 - 13 - 4 0.81 NOVA - NGTL 0TB30001268 TIDE LAKE NORTH 00 - 26 - 019 - 10 - 4 0.81 NOVA - NGTL 0TB30001270 MATZHIWIN EAST 04 - 14 - 024 - 14 - 4 0.88 NOVA - NGTL 0TB30001272 LEO 09 - 17 - 035 - 15 - 4 0.81 NOVA - NGTL 0TB30001273 MAPLE GLEN 00 - 01 - 037 - 16 - 4 0.81 NOVA - NGTL 0TB30001274 BENTON WEST 00 - 28 - 028 - 04 - 4 0.70 NOVA - NGTL 0TB30001275 BADGER EAST 09 - 13 - 016 - 17 - 4 0.50 NOVA - NGTL 0TB30001276 NESTOW 09 - 26 - 060 - 24 - 4 1.27 NOVA - NGTL 0TB30001277 IDDESLEIGH SOUTH 00 - 01 - 020 - 11 - 4 0.71 NOVA - NGTL 0TB30001278 PATRICIA 00 - 05 - 021 - 12 - 4 0.78 NOVA - NGTL 0TB30001279 DAPP EAST 00 - 08 - 062 - 25 - 4 1.35 NOVA - NGTL 0TB30001281 JARROW WEST 00 - 14 - 045 - 11 - 4 1.34 NOVA - NGTL 0TB30001282 RALSTON 00 - 01 - 016 - 10 - 4 0.81 NOVA - NGTL 0TB30001284 MATZHIWIN NORTHEAST 00 - 09 - 023 - 14 - 4 0.81 NOVA - NGTL 0TB30001287 COUNTESS WEST 00 - 24 - 020 - 16 - 4 0.49 NOVA - NGTL 0TB30001289 PATRICIA WEST 00 - 26 - 021 - 13 - 4 0.50 NOVA - NGTL 0TB30001290 BOLLOQUE SOUTH 10 - 10 - 064 - 26 - 4 1.35 NOVA - NGTL 0TB30001291 HAMLIN 00 - 11 - 058 - 13 - 4 1.35 NOVA - NGTL 0TB30001292 MONS LAKE 00 - 24 - 060 - 18 - 4 1.35 NOVA - NGTL 0TB30001296 BANTRY NORTHEAST 00 - 09 - 020 - 13 - 4 0.49 NOVA - NGTL 0TB30001297 ATMORE 00 - 32 - 067 - 17 - 4 1.22 NOVA - NGTL 0TB30001298 KILLAM NORTH 00 - 31 - 045 - 13 - 4 1.35 NOVA - NGTL 0TB30001299 ROYAL PARK 16 - 23 - 051 - 15 - 4 1.01 NOVA - NGTL 0TB30001300 FITZALLAN SOUTH 16 - 34 - 052 - 14 - 4 1.12 NOVA - NGTL 0TB30001302 FLAT LAKE NORTH 00 - 07 - 067 - 18 - 4 1.35 NOVA - NGTL 0TB3

16 of 41


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LOCATION


PIPELINE COMPANY

ID


0001304 PROSPERITY 00 - 15 - 068 - 19 - 4 1.08 NOVA - NGTL 0TB30001307 PADDLE RIVER 00 - 10 - 056 - 11 - 5 1.20 NOVA - NGTL 0TB30001308 STETTLER SOUTH 00 - 12 - 040 - 20 - 4 1.13 NOVA - NGTL 0TB30001310 SADDLE LAKE WEST 00 - 25 - 057 - 13 - 4 1.35 NOVA - NGTL 0TB30001311 SADDLE LAKE NORTH 09 - 09 - 058 - 11 - 4 1.22 NOVA - NGTL 0TB30001312 CESSFORD SOUTH 00 - 22 - 023 - 12 - 4 0.81 NOVA - NGTL 0TB30001314 TILLEBROOK 00 - 20 - 018 - 13 - 4 0.80 NOVA - NGTL 0TB30001315 CASSILS 13 - 24 - 019 - 15 - 4 0.49 NOVA - NGTL 0TB30001316 NETOOK 00 - 21 - 033 - 01 - 5 1.35 NOVA - NGTL 0TB30001317 UKALTA EAST 00 - 35 - 057 - 16 - 4 1.14 NOVA - NGTL 0TB30001318 BOWELL SOUTH 00 - 24 - 013 - 09 - 4 0.49 NOVA - NGTL 0TB30001320 CRAIGEND NORTH 00 - 01 - 064 - 13 - 4 1.35 NOVA - NGTL 0TB30001321 WESTLOCK 00 - 24 - 060 - 26 - 4 1.35 NOVA - NGTL 0TB30001322 CHOICE 00 - 17 - 040 - 09 - 4 1.35 NOVA - NGTL 0TB30001323 CHOICE B 00 - 17 - 040 - 09 - 4 1.35 NOVA - NGTL 0TB30001325 MEDICINE HAT NORTH F 00 - 27 - 017 - 02 - 4 0.81 NOVA - NGTL 0TB30001326 ATHABASCA 00 - 17 - 066 - 23 - 4 1.31 NOVA - NGTL 0TB30001327 PRINCESS SOUTH 00 - 03 - 020 - 12 - 4 0.71 NOVA - NGTL 0TB30001329 BASHAW 00 - 10 - 042 - 22 - 4 1.13 NOVA - NGTL 0TB30001330 BASSANO SOUTH 00 - 05 - 022 - 18 - 4 0.50 NOVA - NGTL 0TB30001331 TIDE LAKE EAST 00 - 35 - 018 - 10 - 4 0.81 NOVA - NGTL 0TB30001334 BAXTER LAKE B 00 - 28 - 046 - 05 - 4 1.35 NOVA - NGTL 0TB30001335 THREE HILLS CREEK WEST 03 - 06 - 035 - 26 - 4 0.81 NOVA - NGTL 0TB30001336 ROCHESTER 00 - 27 - 062 - 24 - 4 1.35 NOVA - NGTL 0TB30001337 ABEE 00 - 32 - 061 - 22 - 4 1.35 NOVA - NGTL 0TB30001338 MEANOOK 00 - 23 - 063 - 22 - 4 1.35 NOVA - NGTL 0TB30001339 BAPTISTE SOUTH 00 - 18 - 067 - 22 - 4 1.10 NOVA - NGTL 0TB30001340 WARDLOW EAST 00 - 24 - 021 - 12 - 4 0.81 NOVA - NGTL 0TB30001341 SPRUCEFIELD 00 - 03 - 061 - 20 - 4 1.35 NOVA - NGTL 0TB30001342 YOUNGSTOWN 00 - 29 - 030 - 09 - 4 1.05 NOVA - NGTL 0TB3

17 of 41


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LOCATION


PIPELINE COMPANY

ID


0001343 TWEEDIE 00 - 20 - 068 - 12 - 4 1.25 NOVA - NGTL 0TB30001345 WHITFORD 08 - 20 - 056 - 15 - 4 1.12 NOVA - NGTL 0TB30001346 REDCLIFF WEST 00 - 23 - 013 - 07 - 4 0.91 NOVA - NGTL 0TB30001347 VIKING EAST 01 - 27 - 049 - 13 - 4 0.99 NOVA - NGTL 0TB30001348 TIDE LAKE 00 - 14 - 018 - 10 - 4 0.81 NOVA - NGTL 0TB30001350 BULLPOUND SOUTH 00 - 29 - 024 - 14 - 4 1.09 NOVA - NGTL 0TB30001352 GRAINGER 00 - 35 - 029 - 24 - 4 0.81 NOVA - NGTL 0TB30001353 WARSPITE 00 - 15 - 059 - 18 - 4 1.11 NOVA - NGTL 0TB30001354 SLAWA NORTH 04 - 18 - 056 - 09 - 4 1.32 NOVA - NGTL 0TB30001355 MONS LAKE EAST 00 - 17 - 060 - 17 - 4 1.35 NOVA - NGTL 0TB30001357 HYLO SOUTH 00 - 01 - 066 - 14 - 4 1.35 NOVA - NGTL 0TB30001359 EQUITY B 00 - 29 - 031 - 23 - 4 0.91 NOVA - NGTL 0TB30001362 MEYER 00 - 02 - 070 - 25 - 4 1.35 NOVA - NGTL 0TB30001365 GREGORY NORTHEAST 00 - 25 - 022 - 13 - 4 0.81 NOVA - NGTL 0TB30001366 LOUISIANA LAKE 00 - 03 - 018 - 11 - 4 0.76 NOVA - NGTL 0TB30001368 ATHABASCA EAST 00 - 23 - 066 - 22 - 4 1.28 NOVA - NGTL 0TB30001370 SEPTEMBER LAKE NORTH 11 - 21 - 067 - 24 - 4 1.35 NOVA - NGTL 0TB30001371 STEELE LAKE 00 - 34 - 065 - 24 - 4 1.35 NOVA - NGTL 0TB30001372 RICINUS SOUTH 00 - 31 - 033 - 07 - 5 0.83 NOVA - NGTL 0TB30001373 CALLING LAKE 13 - 14 - 071 - 20 - 4 1.35 NOVA - NGTL 0TB30001374 RICH LAKE 00 - 36 - 063 - 12 - 4 1.25 NOVA - NGTL 0TB30001375 FAWCETT RIVER 00 - 32 - 074 - 25 - 4 1.35 NOVA - NGTL 0TB30001376 FORSHEE 10 - 08 - 041 - 01 - 5 0.84 NOVA - NGTL 0TB30001377 THORHILD 10 - 25 - 059 - 22 - 4 1.35 NOVA - NGTL 0TB30001378 RAINIER SOUTH 10 - 28 - 015 - 15 - 4 0.49 NOVA - NGTL 0TB30001379 MATZHIWIN SOUTH 00 - 18 - 022 - 14 - 4 0.49 NOVA - NGTL 0TB30001380 RAINIER SOUTHWEST 11 - 35 - 015 - 16 - 4 0.71 NOVA - NGTL 0TB30001382 BAXTER LAKE NORTHWEST 00 - 14 - 046 - 06 - 4 1.35 NOVA - NGTL 0TB30001383 WAINWRIGHT EAST 00 - 04 - 043 - 04 - 4 1.35 NOVA - NGTL 0TB30001385 JENNER WEST B 00 - 23 - 020 - 09 - 4 0.81 NOVA - NGTL 0TB3

18 of 41


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LOCATION


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ID


0001386 LUCKY LAKE 00 - 09 - 062 - 18 - 4 1.35 NOVA - NGTL 0TB30001387 CALLING LAKE SOUTH 10 - 28 - 070 - 21 - 4 1.15 NOVA - NGTL 0TB30001388 STEVEVILLE 00 - 01 - 022 - 12 - 4 0.81 NOVA - NGTL 0TB30001389 FAWCETT RIVER EAST 00 - 21 - 074 - 24 - 4 1.35 NOVA - NGTL 0TB30001391 HALKIRK 02 - 34 - 038 - 16 - 4 0.91 NOVA - NGTL 0TB30001392 RIBSTONE 00 - 07 - 043 - 02 - 4 1.35 NOVA - NGTL 0TB30001393 BASHAW B 00 - 10 - 042 - 22 - 4 1.13 NOVA - NGTL 0TB30001394 FLATBUSH 00 - 09 - 066 - 01 - 5 1.35 NOVA - NGTL 0TB30001395 SEDGEWICK EAST 00 - 23 - 043 - 11 - 4 1.35 NOVA - NGTL 0TB30001396 MINBURN 00 - 24 - 051 - 10 - 4 1.35 NOVA - NGTL 0TB30001397 CASTOR 00 - 03 - 038 - 13 - 4 0.99 NOVA - NGTL 0TB30001398 BAPTISTE 00 - 28 - 067 - 22 - 4 1.33 NOVA - NGTL 0TB30001400 ROCK ISLAND LAKE 09 - 36 - 075 - 23 - 4 1.03 NOVA - NGTL 0TB30001401 BONAR WEST 03 - 02 - 031 - 14 - 4 0.81 NOVA - NGTL 0TB30001403 SEDGEWICK NORTH 00 - 22 - 044 - 10 - 4 1.31 NOVA - NGTL 0TB30001407 ISLAND LAKE 08 - 18 - 068 - 23 - 4 1.21 NOVA - NGTL 0TB30001409 BULLPOUND 00 - 32 - 025 - 15 - 4 0.84 NOVA - NGTL 0TB30001411 HORBURG 00 - 18 - 039 - 08 - 5 0.83 NOVA - NGTL 0TB30001412 TIELAND 00 - 14 - 067 - 02 - 5 1.35 NOVA - NGTL 0TB30001413 HUDSON WEST 00 - 26 - 030 - 04 - 4 0.92 NOVA - NGTL 0TB30001414 ST. LINA 00 - 09 - 062 - 08 - 4 0.94 NOVA - NGTL 0TB30001415 ST. LINA NORTH 00 - 07 - 063 - 08 - 4 1.34 NOVA - NGTL 0TB30001416 ST. LINA WEST 00 - 20 - 061 - 09 - 4 1.07 NOVA - NGTL 0TB30001418 HATTIE LAKE NORTH 14 - 10 - 047 - 12 - 4 1.35 NOVA - NGTL 0TB30001419 MAKEPEACE NORTH 15 - 33 - 023 - 18 - 4 0.56 NOVA - NGTL 0TB30001423 SUFFIELD WEST 00 - 16 - 014 - 08 - 4 0.49 NOVA - NGTL 0TB30001424 ACADIA VALLEY 12 - 12 - 026 - 02 - 4 0.80 NOVA - NGTL 0TB30001427 MIKWAN EAST 00 - 19 - 035 - 21 - 4 1.29 NOVA - NGTL 0TB30001428 WILLINGDON 12 - 24 - 055 - 15 - 4 1.06 NOVA - NGTL 0TB30001430 THORHILD WEST 12 - 11 - 060 - 22 - 4 1.21 NOVA - NGTL 0TB3

19 of 41


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LOCATION


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ID


0001433 COUSINS WEST 00 - 22 - 013 - 06 - 4 0.89 NOVA - NGTL 0TB30001434 CHISHOLM MILLS 15 - 29 - 068 - 01 - 5 1.35 NOVA - NGTL 0TB30001435 GEM SOUTH 00 - 26 - 022 - 16 - 4 0.50 NOVA - NGTL 0TB30001436 HUSSAR NORTH 00 - 22 - 025 - 20 - 4 0.49 NOVA - NGTL 0TB30001437 RICINUS WEST 00 - 30 - 035 - 08 - 5 0.85 NOVA - NGTL 0TB30001439 HEISLER 00 - 15 - 042 - 16 - 4 0.85 NOVA - NGTL 0TB30001440 TAPLOW 01 - 25 - 029 - 14 - 4 0.81 NOVA - NGTL 0TB30001441 IRISH 00 - 36 - 054 - 06 - 4 1.03 NOVA - NGTL 0TB30001442 TRAVERS 00 - 31 - 014 - 18 - 4 0.81 NOVA - NGTL 0TB30001443 CALLING LAKE WEST 08 - 20 - 070 - 22 - 4 1.14 NOVA - NGTL 0TB30001444 HARDISTY 16 - 11 - 043 - 09 - 4 1.24 NOVA - NGTL 0TB30001446 KIRBY 10 - 25 - 073 - 05 - 4 1.26 NOVA - NGTL 0TB30001447 SEIU CREEK 00 - 12 - 026 - 19 - 4 0.73 NOVA - NGTL 0TB30001448 GRACE CREEK 00 - 34 - 040 - 09 - 5 0.91 NOVA - NGTL 0TB30001449 KIRBY NORTH 00 - 08 - 074 - 05 - 4 1.35 NOVA - NGTL 0TB30001452 GOODFARE 00 - 19 - 072 - 11 - 6 1.20 NOVA - NGTL 0TB30001454 CLYDE 00 - 35 - 071 - 10 - 4 1.04 NOVA - NGTL 0TB30001456 GLENDON 03 - 16 - 061 - 08 - 4 1.35 NOVA - NGTL 0TB30001457 MITSUE SOUTH 02 - 12 - 070 - 04 - 5 1.35 NOVA - NGTL 0TB30001458 MORRIN 10 - 33 - 030 - 19 - 4 1.01 NOVA - NGTL 0TB30001460 MORECAMBE 00 - 09 - 054 - 10 - 4 1.35 NOVA - NGTL 0TB30001461 ROSEMARY NORTH 00 - 09 - 022 - 15 - 4 0.49 NOVA - NGTL 0TB30001462 KARR 00 - 10 - 065 - 02 - 6 1.02 NOVA - NGTL 0TB30001464 VILNA 00 - 32 - 059 - 13 - 4 1.32 NOVA - NGTL 0TB30001465 LONE BUTTE 00 - 33 - 028 - 15 - 4 0.99 NOVA - NGTL 0TB30001466 ROSEMARY 00 - 21 - 021 - 15 - 4 0.49 NOVA - NGTL 0TB30001467 EDWAND SOUTH 00 - 06 - 060 - 16 - 4 1.12 NOVA - NGTL 0TB30001468 ROSALIND 09 - 26 - 045 - 16 - 4 0.94 NOVA - NGTL 0TB30001469 ANDREW 00 - 19 - 057 - 15 - 4 1.04 NOVA - NGTL 0TB30001474 BINDLOSS WEST 00 - 28 - 022 - 05 - 4 0.99 NOVA - NGTL 0TB3

20 of 41


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LOCATION


PIPELINE COMPANY

ID


0001476 DEMMITT 15 - 18 - 074 - 12 - 6 1.27 NOVA - NGTL 0TB30001479 HYTHE 00 - 10 - 074 - 11 - 6 1.23 NOVA - NGTL 0TB30001480 GLEICHEN 04 - 01 - 022 - 21 - 4 1.04 NOVA - NGTL 0TB30001482 GRAHAM 00 - 19 - 080 - 04 - 4 1.35 NOVA - NGTL 0TB30001483 KENT 00 - 13 - 062 - 03 - 4 1.35 NOVA - NGTL 0TB30001484 MOOSELAKE RIVER 00 - 08 - 062 - 07 - 4 1.35 NOVA - NGTL 0TB30001487 SPURFIELD 00 - 28 - 071 - 02 - 5 1.35 NOVA - NGTL 0TB30001489 CUTBANK RIVER 00 - 16 - 062 - 08 - 6 1.22 NOVA - NGTL 0TB30001490 GEM WEST 00 - 24 - 023 - 17 - 4 0.49 NOVA - NGTL 0TB30001491 CASLAN 00 - 08 - 065 - 17 - 4 1.35 NOVA - NGTL 0TB30001492 CASLAN EAST 00 - 29 - 064 - 16 - 4 1.35 NOVA - NGTL 0TB30001494 LITTLE SUNDANCE 00 - 02 - 054 - 19 - 5 0.92 NOVA - NGTL 0TB30001495 OWLSEYE 00 - 10 - 059 - 10 - 4 1.35 NOVA - NGTL 0TB30001496 LOUSANA 00 - 16 - 037 - 22 - 4 1.19 NOVA - NGTL 0TB30001497 BARICH 00 - 20 - 060 - 18 - 4 1.35 NOVA - NGTL 0TB30001499 ROBB 00 - 12 - 049 - 20 - 5 0.96 NOVA - NGTL 0TB30001500 MIRROR 00 - 07 - 041 - 22 - 4 1.08 NOVA - NGTL 0TB30001502 NEWBROOK 00 - 11 - 062 - 20 - 4 1.35 NOVA - NGTL 0TB30001504 GOODRIDGE 00 - 34 - 061 - 09 - 4 1.35 NOVA - NGTL 0TB30001505 BLOOD INDIAN CREEK 00 - 11 - 023 - 12 - 4 0.81 NOVA - NGTL 0TB30001507 ENDIANG 00 - 28 - 034 - 15 - 4 0.81 NOVA - NGTL 0TB30001508 MICHICHI 04 - 08 - 031 - 18 - 4 1.03 NOVA - NGTL 0TB30001510 RIVERCOURSE 00 - 36 - 046 - 02 - 4 1.35 NOVA - NGTL 0TB30001511 BLUE JAY 00 - 13 - 068 - 18 - 4 1.35 NOVA - NGTL 0TB30001514 MAUGHAN 00 - 32 - 052 - 07 - 4 1.34 NOVA - NGTL 0TB30001516 SUNDANCE CREEK 00 - 23 - 053 - 20 - 5 1.10 NOVA - NGTL 0TB30001517 KEHIWIN 00 - 25 - 059 - 07 - 4 1.35 NOVA - NGTL 0TB30001519 ST. BRIDES 00 - 16 - 058 - 10 - 4 1.08 NOVA - NGTL 0TB30001520 DONATVILLE 00 - 27 - 066 - 18 - 4 1.26 NOVA - NGTL 0TB30001521 SMITH 00 - 01 - 071 - 02 - 5 1.35 NOVA - NGTL 0TB3

21 of 41


METER STATION


LOCATION


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ID


0001522 CALLING LAKE EAST 00 - 29 - 071 - 19 - 4 1.35 NOVA - NGTL 0TB30001523 HELINA 00 - 21 - 064 - 09 - 4 1.27 NOVA - NGTL 0TB30001524 MILLS 00 - 31 - 069 - 11 - 4 1.34 NOVA - NGTL 0TB30001526 AKUINU RIVER 00 - 06 - 067 - 02 - 5 1.35 NOVA - NGTL 0TB30001527 VIMY 00 - 11 - 059 - 25 - 4 1.35 NOVA - NGTL 0TB30001528 HOOLE 16 - 36 - 080 - 25 - 4 1.31 NOVA - NGTL 0TB30001529 DAYSLAND 00 - 24 - 044 - 16 - 4 0.91 NOVA - NGTL 0TB30001530 RUMSEY 00 - 31 - 033 - 20 - 4 1.02 NOVA - NGTL 0TB30001534 STANDARD 00 - 01 - 024 - 22 - 4 0.49 NOVA - NGTL 0TB30001535 CLANDONALD 00 - 34 - 052 - 06 - 4 1.35 NOVA - NGTL 0TB30001536 LINARIA 00 - 05 - 062 - 01 - 5 1.35 NOVA - NGTL 0TB30001537 SCOTFIELD 00 - 16 - 030 - 10 - 4 1.09 NOVA - NGTL 0TB30001538 HACKETT 00 - 27 - 035 - 19 - 4 1.29 NOVA - NGTL 0TB30001539 DELIA 07 - 15 - 032 - 18 - 4 1.09 NOVA - NGTL 0TB30001540 ROWLEY 01 - 13 - 032 - 19 - 4 1.02 NOVA - NGTL 0TB30001541 CRAIGMYLE 00 - 08 - 032 - 17 - 4 1.21 NOVA - NGTL 0TB30001545 OPAL 00 - 29 - 057 - 21 - 4 1.35 NOVA - NGTL 0TB30001547 ETZIKOM A 00 - 27 - 006 - 08 - 4 1.29 NOVA - NGTL 0TB30001548 ETZIKOM B 05 - 27 - 006 - 08 - 4 1.29 NOVA - NGTL 0TB30001551 MURRAY LAKE 00 - 32 - 009 - 07 - 4 0.61 NOVA - NGTL 0TB30001555 BULLSHEAD 00 - 06 - 012 - 06 - 4 0.98 NOVA - NGTL 0TB30001556 SOUTH SASKATCHEWAN RIVER 00 - 23 - 012 - 07 - 4 1.19 NOVA - NGTL 0TB30001557 ETZIKOM D 00 - 27 - 006 - 08 - 4 1.29 NOVA - NGTL 0TB30001558 ELK RIVER SOUTH 06 - 10 - 047 - 14 - 5 0.88 NOVA - NGTL 0TB30001560 GOUGH LAKE 15 - 07 - 036 - 15 - 4 0.83 NOVA - NGTL 0TB30001561 BYEMOOR 00 - 32 - 034 - 17 - 4 0.95 NOVA - NGTL 0TB30001562 LAKEVIEW LAKE 07 - 17 - 035 - 24 - 4 0.83 NOVA - NGTL 0TB30001564 LARKSPUR 00 - 36 - 062 - 27 - 4 1.35 NOVA - NGTL 0TB30001565 STONEY CREEK 00 - 13 - 060 - 15 - 4 1.30 NOVA - NGTL 0TB30001566 STONEY CREEK WEST 00 - 04 - 060 - 15 - 4 1.21 NOVA - NGTL 0TB3

22 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0001567 ARMENA 00 - 03 - 049 - 21 - 4 1.35 NOVA - NGTL 0TB30001568 EDBERG 00 - 10 - 044 - 22 - 4 1.20 NOVA - NGTL 0TB30001569 IROQUOIS CREEK 04 - 08 - 069 - 08 - 6 1.07 NOVA - NGTL 0TB30001570 WATTS 02 - 04 - 031 - 15 - 4 0.89 NOVA - NGTL 0TB30001572 MARLBORO 00 - 24 - 052 - 20 - 5 1.07 NOVA - NGTL 0TB30001573 ANSELL 02 - 29 - 053 - 17 - 5 0.92 NOVA - NGTL 0TB30001574 TROCHU 00 - 31 - 032 - 23 - 4 0.96 NOVA - NGTL 0TB30001576 HADDOCK 15 - 30 - 055 - 14 - 5 0.99 NOVA - NGTL 0TB30001577 WINEFRED RIVER 08 - 04 - 077 - 05 - 4 1.35 NOVA - NGTL 0TB30001578 MILO 03 - 31 - 018 - 19 - 4 0.80 NOVA - NGTL 0TB30001579 ROSE LYNNE 00 - 21 - 028 - 13 - 4 0.81 NOVA - NGTL 0TB30001580 SPEAR LAKE 00 - 20 - 066 - 21 - 4 1.24 NOVA - NGTL 0TB30001583 CRAIGMYLE EAST 00 - 28 - 031 - 16 - 4 1.35 NOVA - NGTL 0TB30001585 WEASEL CREEK 00 - 06 - 060 - 19 - 4 1.25 NOVA - NGTL 0TB30001586 EQUITY EAST 00 - 29 - 031 - 23 - 4 0.92 NOVA - NGTL 0TB30001587 OVERLEA 07 - 09 - 072 - 04 - 5 1.35 NOVA - NGTL 0TB30001589 HADDOCK NORTH 00 - 15 - 056 - 14 - 5 1.00 NOVA - NGTL 0TB30001590 BOHN LAKE 10 - 02 - 080 - 06 - 4 1.35 NOVA - NGTL 0TB30001591 HUXLEY EAST 04 - 29 - 034 - 23 - 4 1.24 NOVA - NGTL 0TB30001593 IRON SPRINGS 01 - 03 - 012 - 21 - 4 0.81 NOVA - NGTL 0TB30001595 SUNDANCE CREEK EAST 04 - 29 - 054 - 19 - 5 0.92 NOVA - NGTL 0TB30001600 RUMSEY WEST 04 - 35 - 033 - 21 - 4 1.12 NOVA - NGTL 0TB30001601 QUEENSTOWN 02 - 11 - 020 - 23 - 4 1.11 NOVA - NGTL 0TB30001602 FORT KENT 14 - 11 - 062 - 04 - 4 1.33 NOVA - NGTL 0TB30001603 HAYS 11 - 31 - 013 - 14 - 4 0.95 NOVA - NGTL 0TB30001604 BERRY CREEK SOUTH 01 - 17 - 026 - 10 - 4 0.87 NOVA - NGTL 0TB30001605 MONITOR CREEK 00 - 25 - 033 - 05 - 4 0.88 NOVA - NGTL 0TB30001606 VICTOR 05 - 11 - 033 - 18 - 4 1.21 NOVA - NGTL 0TB30001607 PENHOLD WEST 04 - 13 - 035 - 28 - 4 0.91 NOVA - NGTL 0TB30001608 KIKINO 00 - 06 - 063 - 15 - 4 1.26 NOVA - NGTL 0TB3

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METER STATION


LOCATION


PIPELINE COMPANY

ID


0001609 CHISHOLM MILLS WEST 11 - 36 - 068 - 03 - 5 1.35 NOVA - NGTL 0TB30001610 PICTURE BUTTE 12 - 06 - 011 - 20 - 4 1.08 NOVA - NGTL 0TB30001612 COATES LAKE 13 - 19 - 032 - 01 - 4 1.19 NOVA - NGTL 0TB30001613 ACADIA NORTH 09 - 30 - 026 - 03 - 4 0.72 NOVA - NGTL 0TB30001614 CONTRACOSTA LAKE 10 - 09 - 032 - 12 - 4 0.99 NOVA - NGTL 0TB30001615 ELMWORTH HIGH 00 - 08 - 070 - 11 - 6 1.08 NOVA - NGTL 0TB30001616 BLOOD INDIAN CREEK EAST 03 - 06 - 023 - 10 - 4 0.81 NOVA - NGTL 0TB30001617 GHOSTPINE B 16 - 02 - 031 - 21 - 4 0.81 NOVA - NGTL 0TB30001619 BRIGGS 05 - 01 - 039 - 01 - 5 0.84 NOVA - NGTL 0TB30001621 TORRINGTON EAST 05 - 11 - 033 - 26 - 4 0.81 NOVA - NGTL 0TB30001622 CARBON WEST 00 - 34 - 029 - 22 - 4 0.81 NOVA - NGTL 0TB30001623 GATINE 10 - 08 - 029 - 22 - 4 0.49 NOVA - NGTL 0TB30001624 CONKLIN 02 - 12 - 077 - 08 - 4 1.35 NOVA - NGTL 0TB30001627 KETTLE RIVER 15 - 02 - 081 - 06 - 4 1.35 NOVA - NGTL 0TB30001628 WINEFRED RIVER NORTH 07 - 15 - 078 - 04 - 4 1.35 NOVA - NGTL 0TB30001630 LONG LAKE WEST 03 - 14 - 064 - 20 - 4 1.35 NOVA - NGTL 0TB30001631 ACADIA EAST 02 - 15 - 026 - 03 - 4 0.87 NOVA - NGTL 0TB30001632 FOISY 04 - 30 - 056 - 11 - 4 1.18 NOVA - NGTL 0TB30001633 MAY HILL 10 - 36 - 076 - 15 - 4 1.35 NOVA - NGTL 0TB30001634 CONKLIN WEST 09 - 23 - 077 - 09 - 4 1.35 NOVA - NGTL 0TB30001635 CONTRACOSTA EAST 16 - 03 - 032 - 11 - 4 1.16 NOVA - NGTL 0TB30001636 HADDOCK SOUTH 06 - 33 - 055 - 14 - 5 1.08 NOVA - NGTL 0TB30001637 SMITH WEST 09 - 01 - 071 - 02 - 5 1.35 NOVA - NGTL 0TB30001639 TIDE LAKE B 00 - 14 - 018 - 10 - 4 0.81 NOVA - NGTL 0TB30001641 MOUNT VALLEY 11 - 06 - 071 - 13 - 6 1.21 NOVA - NGTL 0TB30001644 TILLEBROOK WEST 09 - 18 - 018 - 14 - 4 0.80 NOVA - NGTL 0TB30001645 METISKOW NORTH 01 - 09 - 040 - 06 - 4 1.10 NOVA - NGTL 0TB30001646 DECRENE NORTH 11 - 06 - 073 - 01 - 5 1.35 NOVA - NGTL 0TB30001647 GRIST LAKE 11 - 01 - 073 - 06 - 4 1.13 NOVA - NGTL 0TB30001649 BADGER NORTH 01 - 18 - 017 - 18 - 4 0.81 NOVA - NGTL 0TB3

24 of 41


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LOCATION


PIPELINE COMPANY

ID


0001650 WILDUNN CREEK EAST 05 - 34 - 026 - 14 - 4 0.81 NOVA - NGTL 0TB30001651 CAMROSE CREEK 00 - 27 - 046 - 21 - 4 1.35 NOVA - NGTL 0TB30001652 WILLOW RIVER 00 - 07 - 078 - 01 - 5 1.35 NOVA - NGTL 0TB30001658 MIQUELON LAKE 05 - 23 - 049 - 21 - 4 1.35 NOVA - NGTL 0TB30001659 FERINTOSH WEST 09 - 12 - 044 - 21 - 4 1.35 NOVA - NGTL 0TB30001660 BONNYVILLE 16 - 12 - 062 - 06 - 4 1.35 NOVA - NGTL 0TB30001661 WILDHAY RIVER 14 - 36 - 057 - 23 - 5 0.94 NOVA - NGTL 0TB30001663 MARLBORO EAST 01 - 24 - 052 - 20 - 5 1.07 NOVA - NGTL 0TB30001665 PARSONS LAKE 12 - 07 - 044 - 04 - 4 1.35 NOVA - NGTL 0TB30001666 CHEECHAM 00 - 14 - 083 - 05 - 4 1.35 NOVA - NGTL 0TB30001667 COTTONWOOD CREEK 00 - 11 - 082 - 07 - 4 1.18 NOVA - NGTL 0TB30001669 WADDELL CREEK 16 - 01 - 079 - 06 - 4 1.16 NOVA - NGTL 0TB30001670 WINEFRED RIVER WEST 00 - 04 - 078 - 06 - 4 1.35 NOVA - NGTL 0TB30001671 WINEFRED RIVER SOUTH 06 - 04 - 075 - 05 - 4 1.35 NOVA - NGTL 0TB30001672 MARTEN HILLS NORTH 00 - 19 - 077 - 25 - 4 1.35 NOVA - NGTL 0TB30001673 HERMIT LAKE 00 - 36 - 071 - 07 - 6 1.20 NOVA - NGTL 0TB30001674 SUNDAY CREEK 00 - 22 - 078 - 05 - 4 1.35 NOVA - NGTL 0TB30001675 BELLIS SOUTH 15 - 34 - 058 - 16 - 4 1.06 NOVA - NGTL 0TB30001676 CALLING LAKE NORTH 13 - 25 - 070 - 21 - 4 1.08 NOVA - NGTL 0TB30001677 FAIRYDELL CREEK 00 - 11 - 059 - 23 - 4 1.35 NOVA - NGTL 0TB30001678 INDIAN LAKE 04 - 22 - 019 - 21 - 4 0.97 NOVA - NGTL 0TB30001679 CHUMP LAKE 02 - 16 - 065 - 18 - 4 1.35 NOVA - NGTL 0TB30001680 CHERRY GROVE EAST 00 - 12 - 062 - 01 - 4 1.35 NOVA - NGTL 0TB30001681 AKUINU RIVER WEST 00 - 27 - 065 - 04 - 5 1.35 NOVA - NGTL 0TB30001682 KINOSIS 07 - 02 - 085 - 06 - 4 1.35 NOVA - NGTL 0TB30001684 WIAU LAKE 00 - 30 - 074 - 08 - 4 1.35 NOVA - NGTL 0TB30001685 IPIATIK LAKE 00 - 29 - 073 - 07 - 4 1.35 NOVA - NGTL 0TB30001686 CRAMMOND 11 - 34 - 034 - 06 - 5 0.81 NOVA - NGTL 0TB30001689 DROPOFF CREEK 00 - 25 - 078 - 15 - 4 1.35 NOVA - NGTL 0TB30001692 CARIBOU LAKE 15 - 01 - 069 - 05 - 4 0.91 NOVA - NGTL 0TB3

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LOCATION


PIPELINE COMPANY

ID


0001693 MINNOW LAKE 05 - 01 - 051 - 15 - 5 1.07 NOVA - NGTL 0TB30001694 JACKFISH CREEK 00 - 32 - 065 - 04 - 4 1.35 NOVA - NGTL 0TB30001695 LAWRENCE LAKE NORTH 15 - 29 - 070 - 24 - 4 1.35 NOVA - NGTL 0TB30001696 SUNDAY CREEK SOUTH 13 - 05 - 076 - 06 - 4 1.35 NOVA - NGTL 0TB30001697 CORRIGALL LAKE 04 - 29 - 071 - 19 - 4 1.35 NOVA - NGTL 0TB30001699 TWELVE MILE COULEE 13 - 35 - 014 - 12 - 4 0.50 NOVA - NGTL 0TB30001700 ISLAND LAKE #2 08 - 18 - 068 - 23 - 4 1.21 NOVA - NGTL 0TB30001701 CROOKED LAKE SOUTH 07 - 13 - 063 - 22 - 5 1.02 NOVA - NGTL 0TB30001703 BOYLE WEST 03 - 21 - 064 - 18 - 4 1.13 NOVA - NGTL 0TB30001704 MEADOW CREEK 14 - 04 - 081 - 09 - 4 1.35 NOVA - NGTL 0TB30001705 MEADOW CREEK WEST 12 - 16 - 079 - 09 - 4 1.35 NOVA - NGTL 0TB30001706 ROURKE CREEK EAST 05 - 17 - 069 - 26 - 4 1.35 NOVA - NGTL 0TB30001707 MEADOW CREEK EAST 10 - 14 - 080 - 08 - 4 1.35 NOVA - NGTL 0TB30001708 CHELSEA CREEK 04 - 23 - 095 - 16 - 4 1.17 NOVA - NGTL 0TB30001709 HASTINGS COULEE 01 - 14 - 041 - 15 - 4 1.02 NOVA - NGTL 0TB30001710 PLEASANT WEST 02 - 27 - 068 - 20 - 4 1.11 NOVA - NGTL 0TB30001712 CHRISTINA LAKE 08 - 33 - 075 - 05 - 4 1.35 NOVA - NGTL 0TB30001713 CONN LAKE 00 - 31 - 063 - 07 - 4 1.35 NOVA - NGTL 0TB30001714 PICHE LAKE 14 - 06 - 071 - 11 - 4 1.21 NOVA - NGTL 0TB30001715 ELINOR LAKE 16 - 29 - 065 - 11 - 4 1.34 NOVA - NGTL 0TB30001716 OSBORNE LAKE 09 - 01 - 064 - 07 - 4 1.35 NOVA - NGTL 0TB30001717 INDIAN LAKE #2 04 - 22 - 019 - 21 - 4 0.94 NOVA - NGTL 0TB30001718 LACOREY 11 - 05 - 063 - 05 - 4 1.29 NOVA - NGTL 0TB30001719 MANATOKEN LAKE 10 - 29 - 063 - 07 - 4 1.00 NOVA - NGTL 0TB30001720 BELTZ LAKE 08 - 24 - 038 - 19 - 4 0.94 NOVA - NGTL 0TB30001721 LAC LA BICHE 05 - 03 - 067 - 13 - 4 1.35 NOVA - NGTL 0TB30001722 HACKETT WEST 13 - 02 - 036 - 20 - 4 1.33 NOVA - NGTL 0TB30001723 WEAVER LAKE 16 - 13 - 080 - 26 - 4 1.35 NOVA - NGTL 0TB30001724 WABASCA 08 - 18 - 081 - 01 - 5 1.35 NOVA - NGTL 0TB30001725 CADOGAN 08 - 14 - 040 - 03 - 4 1.35 NOVA - NGTL 0TB3

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LOCATION


PIPELINE COMPANY

ID


0001727 KIRBY NORTH #2 00 - 08 - 074 - 05 - 4 1.23 NOVA - NGTL 0TB30001728 PARADISE VALLEY 02 - 28 - 046 - 02 - 4 1.35 NOVA - NGTL 0TB30001730 MYRNAM 07 - 24 - 054 - 08 - 4 1.35 NOVA - NGTL 0TB30001733 DEVENISH WEST 09 - 03 - 074 - 12 - 4 1.35 NOVA - NGTL 0TB30001734 DEVENISH SOUTH 04 - 24 - 074 - 10 - 4 1.03 NOVA - NGTL 0TB30001736 WADDELL CREEK WEST 03 - 18 - 079 - 07 - 4 1.04 NOVA - NGTL 0TB30001737 CAVALIER 15 - 32 - 023 - 23 - 4 0.61 NOVA - NGTL 0TB30001738 DANCING LAKE 14 - 11 - 067 - 01 - 5 1.08 NOVA - NGTL 0TB30001739 PIPER CREEK 07 - 11 - 038 - 26 - 4 0.90 NOVA - NGTL 0TB30001741 RABBIT LAKE 12 - 31 - 094 - 18 - 4 1.35 NOVA - NGTL 0TB30001742 ELINOR LAKE EAST 12 - 22 - 065 - 11 - 4 1.34 NOVA - NGTL 0TB30001746 ESTRIDGE LAKE 13 - 31 - 043 - 02 - 4 1.35 NOVA - NGTL 0TB30001747 NIGHTINGALE 10 - 31 - 026 - 23 - 4 0.71 NOVA - NGTL 0TB30001753 FAWCETT RIVER NORTH 11 - 19 - 078 - 25 - 4 1.11 NOVA - NGTL 0TB30001759 WILLOW RIVER NORTH 06 - 22 - 079 - 25 - 4 1.35 NOVA - NGTL 0TB30001760 DECRENE EAST 14 - 14 - 072 - 01 - 5 1.17 NOVA - NGTL 0TB30001763 CORNER LAKE #2 09 - 22 - 065 - 07 - 4 1.35 NOVA - NGTL 0TB30001767 LAMERTON 08 - 27 - 042 - 21 - 4 1.35 NOVA - NGTL 0TB30001768 LONESOME LAKE 13 - 05 - 018 - 18 - 4 0.82 NOVA - NGTL 0TB30001769 MASTIN LAKE 16 - 05 - 064 - 21 - 4 1.31 NOVA - NGTL 0TB30001770 ARMSTRONG LAKE 11 - 09 - 062 - 24 - 4 1.35 NOVA - NGTL 0TB30001771 MONITOR CREEK WEST 16 - 32 - 032 - 06 - 4 1.04 NOVA - NGTL 0TB30001772 KIKINO NORTH 07 - 31 - 063 - 15 - 4 1.17 NOVA - NGTL 0TB30001773 CROW LAKE SOUTH 06 - 12 - 078 - 15 - 4 1.35 NOVA - NGTL 0TB30001774 MUNSON 08 - 36 - 029 - 20 - 4 1.22 NOVA - NGTL 0TB30001775 KEHO LAKE NORTH 16 - 13 - 012 - 22 - 4 0.72 NOVA - NGTL 0TB30001776 NISBET LAKE 10 - 03 - 075 - 05 - 4 1.35 NOVA - NGTL 0TB30001777 WIAU LAKE SOUTH 09 - 06 - 074 - 08 - 4 1.35 NOVA - NGTL 0TB30001778 BOLLOQUE #2 00 - 23 - 064 - 26 - 4 1.35 NOVA - NGTL 0TB30001779 BLOOR LAKE 06 - 14 - 034 - 13 - 4 1.11 NOVA - NGTL 0TB3

27 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0001780 WEAVER LAKE SOUTH 00 - 17 - 079 - 25 - 4 1.01 NOVA - NGTL 0TB30001781 MOSS LAKE 07 - 01 - 063 - 14 - 4 1.35 NOVA - NGTL 0TB30001782 BAILEYS BOTTOM 00 - 12 - 007 - 22 - 4 0.66 NOVA - NGTL 0TB30001783 GOODRIDGE NORTH 04 - 16 - 062 - 09 - 4 1.35 NOVA - NGTL 0TB30001785 MUSKWA RIVER 02 - 33 - 083 - 25 - 4 1.28 NOVA - NGTL 0TB30001787 WHISTWOW 06 - 08 - 087 - 22 - 4 1.35 NOVA - NGTL 0TB30001792 ATUSIS CREEK EAST 14 - 34 - 027 - 22 - 4 0.49 NOVA - NGTL 0TB30001793 DIAMOND CITY 11 - 22 - 011 - 21 - 4 0.93 NOVA - NGTL 0TB30001794 BASSANO SOUTH #2 10 - 05 - 022 - 18 - 4 0.80 NOVA - NGTL 0TB30001796 BONNIE GLENN 15 - 08 - 047 - 27 - 4 1.03 NOVA - NGTL 0TB30001797 PITLO 04 - 17 - 070 - 13 - 4 1.35 NOVA - NGTL 0TB30001798 GOOSEQUILL 00 - 22 - 035 - 22 - 4 1.18 NOVA - NGTL 0TB30001799 JARVIE NORTH 16 - 33 - 064 - 01 - 5 1.35 NOVA - NGTL 0TB30001800 AKUINU RIVER WEST #2 05 - 27 - 065 - 04 - 5 1.35 NOVA - NGTL 0TB30001801 VANDERSTEENE LAKE 06 - 10 - 087 - 01 - 5 1.35 NOVA - NGTL 0TB30001802 MOSS LAKE NORTH 07 - 02 - 064 - 14 - 4 1.22 NOVA - NGTL 0TB30001803 CLYDE NORTH 09 - 23 - 073 - 09 - 4 1.35 NOVA - NGTL 0TB30001805 CANOE LAKE 05 - 08 - 070 - 04 - 4 0.91 NOVA - NGTL 0TB30001806 SIMON LAKES 07 - 34 - 086 - 18 - 5 1.35 NOVA - NGTL 0TB30001807 CULP NORTH 13 - 09 - 079 - 22 - 5 1.35 NOVA - NGTL 0TB30001811 KAKWA 00 - 03 - 064 - 07 - 6 1.15 NOVA - NGTL 0TB30001812 OSLAND LAKE 10 - 20 - 096 - 07 - 6 1.30 NOVA - NGTL 0TB30001814 ORLOFF LAKE 16 - 05 - 075 - 25 - 4 1.08 NOVA - NGTL 0TB30001817 OWL LAKE 14 - 29 - 096 - 11 - 6 1.30 NOVA - NGTL 0TB30001818 DOWLING 04 - 29 - 032 - 14 - 4 0.81 NOVA - NGTL 0TB30001820 ROCK ISLAND LAKE SOUTH #2 09 - 15 - 075 - 23 - 4 1.35 NOVA - NGTL 0TB30001822 WANDERING RIVER 05 - 32 - 073 - 14 - 4 1.35 NOVA - NGTL 0TB30001823 MOOSE PORTAGE 07 - 12 - 073 - 25 - 4 1.15 NOVA - NGTL 0TB30001824 OBED CREEK 11 - 19 - 055 - 20 - 5 1.02 NOVA - NGTL 0TB30001825 WELLING 02 - 01 - 007 - 22 - 4 0.97 NOVA - NGTL 0TB3

28 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0001826 RALSTON SOUTH 11 - 27 - 014 - 09 - 4 0.49 NOVA - NGTL 0TB30001827 SEDALIA 00 - 17 - 031 - 04 - 4 0.81 NOVA - NGTL 0TB30001828 LAKEVIEW LAKE #2 07 - 17 - 035 - 24 - 4 0.81 NOVA - NGTL 0TB30001829 OBED NORTH 00 - 31 - 055 - 20 - 5 0.93 NOVA - NGTL 0TB30001833 LEE LAKE 02 - 03 - 035 - 19 - 4 1.07 NOVA - NGTL 0TB30001834 HALKIRK NORTH #2 00 - 11 - 039 - 16 - 4 0.82 NOVA - NGTL 0TB30001835 BIGKNIFE CREEK 12 - 24 - 038 - 17 - 4 0.88 NOVA - NGTL 0TB30001837 TAWADINA CREEK 10 - 22 - 039 - 10 - 5 0.81 NOVA - NGTL 0TB30001838 REDCLIFF SOUTH #2 16 - 07 - 014 - 05 - 4 0.86 NOVA - NGTL 0TB30001839 TILLEY SOUTH #2 00 - 34 - 016 - 13 - 4 0.49 NOVA - NGTL 0TB30001840 CARSELAND 12 - 19 - 027 - 24 - 4 0.81 NOVA - NGTL 0TB30001841 Torlea East 00 - 06 - 049 - 12 - 4 1.09 NOVA - NGTL 0TB30001842 BOWMANTON EAST 01 - 27 - 015 - 04 - 4 0.86 NOVA - NGTL 0TB30001942 FIGURE LAKE SUMMARY 01 - 13 - 063 - 18 - 4 1.23 NOVA - NGTL 0TB30001944 ZAMA LAKE SUMMARY 06 - 12 - 116 - 06 - 6 1.35 NOVA - NGTL 0TB30001945 WATERTON NO.1/WATERTON NO.2 SU 00 - 24 - 004 - 01 - 5 0.81 NOVA - NGTL 0TB30001947 BRAZEAU / BRAZEAU EAST SUMMARY 00 - 12 - 046 - 14 - 5 0.89 NOVA - NGTL 0TB30001949 RIMBEY/WESTEROSE SUMMARY 00 - 32 - 043 - 01 - 5 0.86 NOVA - NGTL 0TB30001963 COUSINS B & C SALES (SUMMARY) 00 - 14 - 013 - 06 - 4 0.89 NOVA - NGTL 0TB30002003 COLEMAN 00 - 12 - 008 - 05 - 5 0.06 NOVA - NGTL 0TB30002005 WILDCAT HILLS 16 - 15 - 026 - 05 - 5 0.81 NOVA - NGTL 0TB30002007 EAST CALGARY 00 - 03 - 026 - 29 - 4 0.64 NOVA - NGTL 0TB30002008 CROSSFIELD 00 - 03 - 030 - 02 - 5 0.81 NOVA - NGTL 0TB30002009 WESTEROSE 00 - 32 - 043 - 01 - 5 0.86 NOVA - NGTL 0TB30002010 MINNEHIK-BUCK LAKE 00 - 01 - 046 - 07 - 5 0.87 NOVA - NGTL 0TB30002012 WINDFALL 00 - 08 - 060 - 15 - 5 0.97 NOVA - NGTL 0TB30002013 KAYBOB 05 - 03 - 064 - 19 - 5 1.06 NOVA - NGTL 0TB30002014 WILLESDEN GREEN 00 - 03 - 042 - 07 - 5 0.81 NOVA - NGTL 0TB30002016 FERRIER 00 - 20 - 039 - 07 - 5 0.90 NOVA - NGTL 0TB30002017 CROSSFIELD WEST 00 - 02 - 030 - 03 - 5 0.81 NOVA - NGTL 0TB3

29 of 41


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LOCATION


PIPELINE COMPANY

ID


0002018 CARSON CREEK 00 - 22 - 061 - 12 - 5 1.14 NOVA - NGTL 0TB30002019 WILSON CREEK 04 - 28 - 043 - 04 - 5 0.96 NOVA - NGTL 0TB30002020 KAYBOB SOUTH 00 - 12 - 062 - 20 - 5 1.02 NOVA - NGTL 0TB30002022 JUDY CREEK 14 - 25 - 064 - 11 - 5 1.32 NOVA - NGTL 0TB30002024 BRAZEAU EAST 00 - 12 - 046 - 14 - 5 0.89 NOVA - NGTL 0TB30002026 QUIRK CREEK 00 - 04 - 021 - 04 - 5 0.81 NOVA - NGTL 0TB30002027 KAYBOB 11-36 06 - 27 - 063 - 19 - 5 1.06 NOVA - NGTL 0TB30002028 SIMONETTE 12 - 05 - 063 - 25 - 5 1.17 NOVA - NGTL 0TB30002029 WASKAHIGAN 00 - 07 - 064 - 23 - 5 0.99 NOVA - NGTL 0TB30002030 STURGEON LAKE SOUTH 03 - 02 - 069 - 22 - 5 1.22 NOVA - NGTL 0TB30002031 GOLD CREEK 00 - 26 - 067 - 05 - 6 1.03 NOVA - NGTL 0TB30002032 BURNT TIMBER 00 - 13 - 030 - 07 - 5 0.81 NOVA - NGTL 0TB30002033 SIMONETTE NORTH 00 - 05 - 063 - 25 - 5 1.17 NOVA - NGTL 0TB30002034 VIRGINIA HILLS 09 - 17 - 064 - 13 - 5 1.35 NOVA - NGTL 0TB30002035 KAYBOB SOUTH #3 13 - 10 - 059 - 18 - 5 0.95 NOVA - NGTL 0TB30002036 JUMPING POUND WEST 12 - 18 - 025 - 04 - 5 0.81 NOVA - NGTL 0TB30002037 GILBY WEST 00 - 06 - 040 - 03 - 5 0.90 NOVA - NGTL 0TB30002040 LEAFLAND 00 - 21 - 040 - 05 - 5 1.03 NOVA - NGTL 0TB30002043 BELLOY 00 - 21 - 078 - 01 - 6 1.27 NOVA - NGTL 0TB30002044 DUNVEGAN 00 - 03 - 081 - 04 - 6 1.17 NOVA - NGTL 0TB30002046 PIONEER 00 - 34 - 054 - 14 - 5 0.89 NOVA - NGTL 0TB30002047 HOTCHKISS 00 - 34 - 093 - 01 - 6 1.35 NOVA - NGTL 0TB30002049 ETA LAKE 00 - 07 - 051 - 11 - 5 0.90 NOVA - NGTL 0TB30002050 WHITEMUD RIVER 00 - 33 - 087 - 02 - 6 1.35 NOVA - NGTL 0TB30002053 KEG RIVER 00 - 18 - 102 - 02 - 6 1.35 NOVA - NGTL 0TB30002054 HOTCHKISS NORTH 00 - 26 - 094 - 02 - 6 1.35 NOVA - NGTL 0TB30002055 WHITEMUD EAST 00 - 32 - 087 - 01 - 6 1.35 NOVA - NGTL 0TB30002056 WHITEMUD WEST 00 - 33 - 087 - 02 - 6 1.35 NOVA - NGTL 0TB30002059 HINES CREEK 14 - 35 - 085 - 03 - 6 1.35 NOVA - NGTL 0TB30002060 ZAMA LAKE 06 - 12 - 116 - 06 - 6 1.35 NOVA - NGTL 0TB3

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METER STATION


LOCATION


PIPELINE COMPANY

ID


0002063 CLEAR HILLS 00 - 36 - 086 - 26 - 5 1.26 NOVA - NGTL 0TB30002064 HAIG RIVER EAST 00 - 29 - 104 - 02 - 6 1.35 NOVA - NGTL 0TB30002065 HOTCHKISS EAST 00 - 06 - 094 - 01 - 6 1.35 NOVA - NGTL 0TB30002066 BASSET LAKE WEST 00 - 07 - 108 - 06 - 6 1.35 NOVA - NGTL 0TB30002068 KEG RIVER EAST 00 - 33 - 101 - 01 - 6 1.35 NOVA - NGTL 0TB30002070 CLARK LAKE 00 - 19 - 060 - 18 - 5 1.00 NOVA - NGTL 0TB30002071 NITON 00 - 18 - 054 - 12 - 5 0.92 NOVA - NGTL 0TB30002075 WHITELAW 00 - 33 - 081 - 01 - 6 1.25 NOVA - NGTL 0TB30002076 TEEPEE CREEK 00 - 02 - 074 - 04 - 6 1.35 NOVA - NGTL 0TB30002079 GARRINGTON EAST 00 - 17 - 034 - 03 - 5 0.88 NOVA - NGTL 0TB30002081 EAGLE HILL 00 - 08 - 034 - 03 - 5 0.90 NOVA - NGTL 0TB30002082 TANGENT 00 - 20 - 080 - 24 - 5 1.35 NOVA - NGTL 0TB30002084 DUNVEGAN WEST 07 - 15 - 082 - 05 - 6 1.32 NOVA - NGTL 0TB30002085 BASSET LAKE SOUTH 00 - 01 - 107 - 04 - 6 1.35 NOVA - NGTL 0TB30002086 HAIG RIVER 00 - 33 - 104 - 05 - 6 1.35 NOVA - NGTL 0TB30002087 JOSEPHINE 00 - 36 - 082 - 10 - 6 1.32 NOVA - NGTL 0TB30002088 PIONEER EAST 00 - 16 - 055 - 13 - 5 1.01 NOVA - NGTL 0TB30002089 PASS CREEK 00 - 22 - 060 - 19 - 5 0.99 NOVA - NGTL 0TB30002093 PADDLE PRAIRIE 01 - 06 - 105 - 22 - 5 1.35 NOVA - NGTL 0TB30002094 HOTCHKISS NORTHEAST B 00 - 29 - 094 - 25 - 5 1.35 NOVA - NGTL 0TB30002095 HOTCHKISS NORTHEAST C 12 - 29 - 094 - 25 - 5 1.35 NOVA - NGTL 0TB30002096 WASKAHIGAN EAST 00 - 18 - 065 - 23 - 5 1.17 NOVA - NGTL 0TB30002097 EAGLESHAM 00 - 13 - 077 - 26 - 5 1.08 NOVA - NGTL 0TB30002098 PADDLE PRAIRIE SOUTH 00 - 12 - 103 - 24 - 5 1.35 NOVA - NGTL 0TB30002099 ROSEVEAR SOUTH 00 - 11 - 054 - 15 - 5 0.94 NOVA - NGTL 0TB30002103 FOURTH CREEK 00 - 13 - 082 - 08 - 6 1.35 NOVA - NGTL 0TB30002104 RAT CREEK 05 - 36 - 048 - 11 - 5 0.84 NOVA - NGTL 0TB30002105 BELLOY WEST 06 - 18 - 078 - 02 - 6 1.16 NOVA - NGTL 0TB30002107 VALHALLA 00 - 29 - 075 - 09 - 6 1.18 NOVA - NGTL 0TB30002108 CHINCHAGA 00 - 24 - 096 - 05 - 6 1.28 NOVA - NGTL 0TB3

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METER STATION


LOCATION


PIPELINE COMPANY

ID


0002110 DIXONVILLE NORTH 00 - 12 - 087 - 01 - 6 1.32 NOVA - NGTL 0TB30002111 LOBSTICK 13 - 15 - 053 - 13 - 5 0.88 NOVA - NGTL 0TB30002112 WILLESDEN GREEN NORTH 13 - 33 - 042 - 07 - 5 0.81 NOVA - NGTL 0TB30002115 FERRIER SOUTH A 00 - 20 - 039 - 07 - 5 0.90 NOVA - NGTL 0TB30002116 TONY CREEK NORTH 00 - 16 - 064 - 21 - 5 1.11 NOVA - NGTL 0TB30002117 BOTHA 00 - 18 - 096 - 03 - 6 1.33 NOVA - NGTL 0TB30002118 BURNT RIVER 08 - 20 - 076 - 09 - 6 1.15 NOVA - NGTL 0TB30002119 BLUEBERRY HILL 00 - 24 - 079 - 11 - 6 1.35 NOVA - NGTL 0TB30002120 WEST PEMBINA SOUTH 00 - 28 - 049 - 11 - 5 0.87 NOVA - NGTL 0TB30002121 TANGENT B 16 - 20 - 080 - 24 - 5 1.35 NOVA - NGTL 0TB30002123 WATINO 02 - 14 - 077 - 25 - 5 1.33 NOVA - NGTL 0TB30002124 WOKING 00 - 30 - 075 - 04 - 6 1.35 NOVA - NGTL 0TB30002126 HAY RIVER 00 - 04 - 113 - 04 - 6 1.35 NOVA - NGTL 0TB30002127 HAIG RIVER NORTH 01 - 17 - 105 - 01 - 6 1.35 NOVA - NGTL 0TB30002128 LOVET CREEK 07 - 19 - 094 - 03 - 6 1.35 NOVA - NGTL 0TB30002129 GRANADA 00 - 18 - 052 - 11 - 5 0.97 NOVA - NGTL 0TB30002132 BEAR RIVER 12 - 16 - 075 - 10 - 6 1.35 NOVA - NGTL 0TB30002133 WARRENSVILLE 08 - 14 - 085 - 25 - 5 1.35 NOVA - NGTL 0TB30002134 KSITUAN RIVER 00 - 02 - 079 - 08 - 6 1.29 NOVA - NGTL 0TB30002136 ANTE CREEK SOUTH 00 - 04 - 066 - 23 - 5 1.35 NOVA - NGTL 0TB30002137 SLOAT CREEK 00 - 32 - 098 - 07 - 6 1.35 NOVA - NGTL 0TB30002138 BOYER EAST 00 - 10 - 102 - 24 - 5 1.35 NOVA - NGTL 0TB30002139 DONNELLY 00 - 01 - 077 - 21 - 5 1.35 NOVA - NGTL 0TB30002140 HEART RIVER 00 - 11 - 077 - 16 - 5 1.35 NOVA - NGTL 0TB30002143 BAY TREE 00 - 20 - 078 - 12 - 6 1.35 NOVA - NGTL 0TB30002144 MCLENNAN 00 - 22 - 079 - 20 - 5 1.35 NOVA - NGTL 0TB30002145 HARO RIVER NORTH 00 - 23 - 105 - 03 - 6 1.35 NOVA - NGTL 0TB30002146 JACKSON CREEK 02 - 26 - 033 - 06 - 5 0.81 NOVA - NGTL 0TB30002147 WITHROW 00 - 34 - 040 - 04 - 5 0.85 NOVA - NGTL 0TB30002148 RAMBLING CREEK 00 - 21 - 090 - 04 - 6 1.35 NOVA - NGTL 0TB3

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METER STATION


LOCATION


PIPELINE COMPANY

ID


0002149 MINNEHIK-BUCK LAKE B 00 - 01 - 046 - 07 - 5 0.87 NOVA - NGTL 0TB30002151 LASTHILL CREEK 00 - 29 - 040 - 06 - 5 0.81 NOVA - NGTL 0TB30002152 CODNER 00 - 31 - 039 - 05 - 5 0.90 NOVA - NGTL 0TB30002153 PROGRESS 00 - 36 - 077 - 10 - 6 1.18 NOVA - NGTL 0TB30002157 TANGHE CREEK 11 - 29 - 096 - 11 - 6 1.30 NOVA - NGTL 0TB30002158 WEMBLEY 11 - 19 - 073 - 08 - 6 1.13 NOVA - NGTL 0TB30002160 WATER VALLEY 00 - 28 - 029 - 04 - 5 0.81 NOVA - NGTL 0TB30002164 HENDERSON CREEK 11 - 34 - 079 - 12 - 6 1.30 NOVA - NGTL 0TB30002165 SNEDDON CREEK 07 - 08 - 080 - 12 - 6 1.33 NOVA - NGTL 0TB30002166 RAY LAKE WEST 11 - 20 - 087 - 05 - 6 1.35 NOVA - NGTL 0TB30002168 PASS CREEK WEST 00 - 19 - 060 - 19 - 5 0.97 NOVA - NGTL 0TB30002169 HOWARD CREEK EAST 09 - 34 - 077 - 06 - 6 1.35 NOVA - NGTL 0TB30002170 SILVERWOOD 08 - 25 - 077 - 06 - 6 1.35 NOVA - NGTL 0TB30002171 WILSON CREEK SOUTHEAST 09 - 21 - 043 - 04 - 5 0.96 NOVA - NGTL 0TB30002172 NITON NORTH 05 - 28 - 054 - 12 - 5 0.96 NOVA - NGTL 0TB30002173 POISON CREEK 13 - 05 - 055 - 11 - 5 1.04 NOVA - NGTL 0TB30002174 HENDERSON CREEK SOUTHEAST 11 - 19 - 079 - 11 - 6 1.31 NOVA - NGTL 0TB30002175 BIG PRAIRIE 00 - 08 - 077 - 16 - 5 1.35 NOVA - NGTL 0TB30002176 BIGORAY RIVER 00 - 18 - 052 - 11 - 5 0.97 NOVA - NGTL 0TB30002177 BENBOW SOUTH 10 - 23 - 057 - 19 - 5 1.06 NOVA - NGTL 0TB30002178 FOURTH CREEK SOUTH 07 - 16 - 081 - 09 - 6 1.35 NOVA - NGTL 0TB30002179 LEEDALE 05 - 20 - 041 - 04 - 5 0.81 NOVA - NGTL 0TB30002181 BUTTE 13 - 14 - 037 - 06 - 5 0.81 NOVA - NGTL 0TB30002182 BOTHA EAST 07 - 03 - 096 - 02 - 6 1.35 NOVA - NGTL 0TB30002185 PEMBINA WEST 01 - 32 - 047 - 10 - 5 0.86 NOVA - NGTL 0TB30002188 CARSON CREEK EAST 02 - 03 - 061 - 11 - 5 1.26 NOVA - NGTL 0TB30002189 VALHALLA EAST 01 - 12 - 075 - 09 - 6 1.22 NOVA - NGTL 0TB30002190 GORDONDALE RECEIPT 00 - 12 - 079 - 12 - 6 1.22 NOVA - NGTL 0TB30002191 PROGRESS EAST 00 - 22 - 078 - 09 - 6 1.20 NOVA - NGTL 0TB30002192 NOTIKEWIN RIVER 10 - 18 - 092 - 02 - 6 1.35 NOVA - NGTL 0TB3

33 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0002193 RAY LAKE SOUTH 00 - 22 - 087 - 07 - 6 1.35 NOVA - NGTL 0TB30002197 DOE CREEK 03 - 03 - 081 - 13 - 6 1.35 NOVA - NGTL 0TB30002198 FOURTH CREEK WEST 10 - 11 - 082 - 09 - 6 1.32 NOVA - NGTL 0TB30002199 FOULWATER CREEK 13 - 01 - 101 - 13 - 6 1.35 NOVA - NGTL 0TB30002200 ALDER FLATS SOUTH 00 - 09 - 045 - 08 - 5 0.81 NOVA - NGTL 0TB30002201 RAINBOW LAKE SOUTH 00 - 06 - 109 - 07 - 6 1.35 NOVA - NGTL 0TB30002204 TANGHE CREEK #2 11 - 29 - 096 - 11 - 6 1.30 NOVA - NGTL 0TB30002207 WEBSTER 02 - 26 - 074 - 04 - 6 1.35 NOVA - NGTL 0TB30002208 TANGENT EAST 05 - 03 - 079 - 24 - 5 1.35 NOVA - NGTL 0TB30002209 CYNTHIA #2 00 - 21 - 049 - 11 - 5 0.85 NOVA - NGTL 0TB30002210 DIXONVILLE NORTH #2 00 - 12 - 087 - 01 - 6 1.15 NOVA - NGTL 0TB30002211 RASPBERRY LAKE 05 - 01 - 064 - 17 - 5 1.18 NOVA - NGTL 0TB30002213 RAMBLING CREEK EAST 10 - 29 - 090 - 02 - 6 1.35 NOVA - NGTL 0TB30002214 WOLVERINE RIVER 08 - 15 - 098 - 16 - 5 1.35 NOVA - NGTL 0TB30002216 KEG RIVER NORTH 09 - 28 - 103 - 04 - 6 1.35 NOVA - NGTL 0TB30002217 BOTHA WEST 02 - 16 - 098 - 05 - 6 1.35 NOVA - NGTL 0TB30002218 NOTIKEWIN RIVER NORTH 08 - 14 - 093 - 01 - 6 1.30 NOVA - NGTL 0TB30002219 HINES CREEK WEST 10 - 23 - 085 - 04 - 6 1.35 NOVA - NGTL 0TB30002220 BOULDER CREEK 06 - 24 - 072 - 18 - 5 1.35 NOVA - NGTL 0TB30002221 CADOTTE RIVER 10 - 15 - 084 - 14 - 5 1.35 NOVA - NGTL 0TB30002222 BEAR CANYON WEST 16 - 07 - 084 - 12 - 6 1.24 NOVA - NGTL 0TB30002223 LAST LAKE 07 - 06 - 084 - 25 - 5 1.18 NOVA - NGTL 0TB30002224 TWO CREEKS 08 - 04 - 063 - 16 - 5 1.34 NOVA - NGTL 0TB30002227 VALHALLA #2 03 - 29 - 075 - 09 - 6 1.18 NOVA - NGTL 0TB30002228 MARSH HEAD CREEK 00 - 28 - 059 - 22 - 5 1.01 NOVA - NGTL 0TB30002229 TWO CREEKS EAST 06 - 12 - 063 - 15 - 5 1.35 NOVA - NGTL 0TB30002233 DEBOLT 01 - 18 - 071 - 03 - 6 1.27 NOVA - NGTL 0TB30002235 SLIMS LAKE 12 - 22 - 087 - 09 - 6 1.35 NOVA - NGTL 0TB30002236 MUSKEG CREEK 05 - 11 - 109 - 08 - 6 1.35 NOVA - NGTL 0TB30002237 MILLERS LAKE 16 - 04 - 056 - 17 - 5 0.94 NOVA - NGTL 0TB3

34 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0002239 SILVERWOOD NORTH 00 - 26 - 078 - 06 - 6 1.27 NOVA - NGTL 0TB30002241 JONES LAKE NORTH 01 - 03 - 077 - 07 - 6 1.26 NOVA - NGTL 0TB30002242 NIOBE CREEK 09 - 15 - 074 - 08 - 6 1.21 NOVA - NGTL 0TB30002244 DEEP VALLEY CREEK SOUTH 11 - 03 - 060 - 25 - 5 0.97 NOVA - NGTL 0TB30002247 PETE LAKE SOUTH 16 - 19 - 073 - 26 - 5 1.15 NOVA - NGTL 0TB30002248 WEBSTER NORTH 16 - 09 - 075 - 04 - 6 1.35 NOVA - NGTL 0TB30002249 LENNARD CREEK 12 - 23 - 107 - 06 - 6 1.35 NOVA - NGTL 0TB30002250 CLEAR HILLS NORTH 13 - 35 - 087 - 01 - 6 1.15 NOVA - NGTL 0TB30002251 FONTAS RIVER 02 - 28 - 102 - 11 - 6 1.35 NOVA - NGTL 0TB30002252 RAT CREEK WEST 06 - 31 - 048 - 12 - 5 0.91 NOVA - NGTL 0TB30002253 SNIPE LAKE 07 - 22 - 070 - 20 - 5 1.35 NOVA - NGTL 0TB30002254 DORIS CREEK NORTH 02 - 23 - 064 - 06 - 5 1.31 NOVA - NGTL 0TB30002256 BISON LAKE 15 - 05 - 095 - 15 - 5 1.35 NOVA - NGTL 0TB30002259 LATHROP CREEK 16 - 11 - 088 - 13 - 6 1.27 NOVA - NGTL 0TB30002260 PASTECHO RIVER 10 - 02 - 077 - 05 - 5 1.35 NOVA - NGTL 0TB30002261 RUSSELL CREEK 00 - 03 - 096 - 10 - 5 1.35 NOVA - NGTL 0TB30002263 ZAMA LAKE #2 06 - 12 - 116 - 06 - 6 1.35 NOVA - NGTL 0TB30002264 SNOWFALL CREEK 13 - 06 - 104 - 12 - 6 1.35 NOVA - NGTL 0TB30002265 RAT CREEK SOUTH 16 - 35 - 048 - 12 - 5 0.88 NOVA - NGTL 0TB30002266 CHINCHAGA WEST 00 - 24 - 096 - 05 - 6 1.35 NOVA - NGTL 0TB30002267 JONES LAKE 01 - 07 - 075 - 07 - 6 1.15 NOVA - NGTL 0TB30002268 FRAKES FLATS 01 - 26 - 068 - 25 - 5 1.10 NOVA - NGTL 0TB30002272 JONES LAKE EAST 08 - 17 - 075 - 07 - 6 1.21 NOVA - NGTL 0TB30002273 MIRAGE 10 - 02 - 079 - 08 - 6 1.29 NOVA - NGTL 0TB30002276 SHEKILIE RIVER NORTH 11 - 04 - 119 - 12 - 6 1.35 NOVA - NGTL 0TB30002277 HUNT CREEK 03 - 32 - 091 - 08 - 5 1.35 NOVA - NGTL 0TB30002278 HAY RIVER SOUTH 11 - 31 - 111 - 04 - 6 1.35 NOVA - NGTL 0TB30002279 JONES LAKE #2 01 - 07 - 075 - 07 - 6 1.15 NOVA - NGTL 0TB30002280 PETE LAKE 03 - 26 - 074 - 01 - 6 1.30 NOVA - NGTL 0TB30002281 SAND CREEK 06 - 25 - 045 - 10 - 5 0.88 NOVA - NGTL 0TB3

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METER STATION


LOCATION


PIPELINE COMPANY

ID


0002284 STEEN RIVER 06 - 22 - 122 - 02 - 6 1.35 NOVA - NGTL 0TB30002286 CHICKADEE CREEK WEST 10 - 04 - 063 - 15 - 5 1.35 NOVA - NGTL 0TB30002287 LAFOND CREEK 02 - 23 - 093 - 07 - 5 1.35 NOVA - NGTL 0TB30002288 KIDNEY LAKE 04 - 14 - 091 - 04 - 5 1.35 NOVA - NGTL 0TB30002289 DARLING CREEK 04 - 27 - 095 - 06 - 5 1.35 NOVA - NGTL 0TB30002290 GODS LAKE 12 - 10 - 090 - 03 - 5 1.35 NOVA - NGTL 0TB30002291 ALDER FLATS #2 16 - 31 - 045 - 08 - 5 0.81 NOVA - NGTL 0TB30002292 ZAMA LAKE #3 06 - 12 - 116 - 06 - 6 1.35 NOVA - NGTL 0TB30002296 COUNTESS SOUTH #2 07 - 02 - 018 - 15 - 4 0.52 NOVA - NGTL 0TB30002297 DORIS CREEK SOUTH 01 - 27 - 063 - 06 - 5 1.35 NOVA - NGTL 0TB30002364 BROWNVALE SALES 00 - 18 - 082 - 25 - 5 1.24 NOVA - NGTL 0TB30002700 MAHASKA WEST 06 - 25 - 056 - 14 - 5 1.01 NOVA - NGTL 0TB30002701 WHITBURN EAST 11 - 26 - 079 - 09 - 6 1.23 NOVA - NGTL 0TB30002702 MAHASKA 04 - 18 - 057 - 12 - 5 1.11 NOVA - NGTL 0TB30002704 BLUE RAPIDS 12 - 35 - 047 - 10 - 5 0.83 NOVA - NGTL 0TB30002705 CHESTER CREEK 07 - 30 - 094 - 16 - 5 1.35 NOVA - NGTL 0TB30002706 MCLEAN CREEK 16 - 04 - 085 - 08 - 6 1.35 NOVA - NGTL 0TB30002707 WINAGAMI LAKE 16 - 17 - 077 - 17 - 5 1.35 NOVA - NGTL 0TB30002708 ASSUMPTION 13 - 33 - 110 - 04 - 6 1.35 NOVA - NGTL 0TB30002709 BOOTIS HILL 07 - 34 - 120 - 12 - 6 1.35 NOVA - NGTL 0TB30002710 MCMILLAN LAKE 08 - 27 - 077 - 03 - 5 1.25 NOVA - NGTL 0TB30002711 MUSREAU LAKE 05 - 25 - 062 - 06 - 6 1.26 NOVA - NGTL 0TB30002712 DOE CREEK SOUTH 09 - 22 - 080 - 13 - 6 1.35 NOVA - NGTL 0TB30002713 MARLOW CREEK 09 - 17 - 122 - 20 - 5 1.35 NOVA - NGTL 0TB30002714 NOEL LAKE SOUTH 00 - 33 - 060 - 09 - 5 1.13 NOVA - NGTL 0TB30002715 ROD LAKE 07 - 33 - 092 - 20 - 4 1.35 NOVA - NGTL 0TB30002716 DUNVEGAN WEST #2 07 - 15 - 082 - 05 - 6 1.32 NOVA - NGTL 0TB30002717 DEMMITT #2 15 - 18 - 074 - 12 - 6 1.27 NOVA - NGTL 0TB30002718 CULP #2 04 - 22 - 078 - 23 - 5 1.35 NOVA - NGTL 0TB30002719 DREAU 12 - 28 - 077 - 22 - 5 1.31 NOVA - NGTL 0TB3

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METER STATION


LOCATION


PIPELINE COMPANY

ID


0002720 MANIR 16 - 36 - 076 - 04 - 6 1.26 NOVA - NGTL 0TB30002721 BROWNVALE NORTH 08 - 36 - 082 - 26 - 5 1.12 NOVA - NGTL 0TB30002722 GILMORE LAKE 10 - 29 - 071 - 23 - 5 1.14 NOVA - NGTL 0TB30002723 JACKPOT CREEK 01 - 28 - 122 - 22 - 5 1.35 NOVA - NGTL 0TB30002724 CROOKED LAKE WEST 06 - 17 - 063 - 22 - 5 0.98 NOVA - NGTL 0TB30002725 ROSSBEAR LAKE 11 - 28 - 095 - 12 - 5 1.35 NOVA - NGTL 0TB30002727 CATTAIL LAKE METER STATION 13 - 13 - 073 - 26 - 5 1.05 NOVA - NGTL 0TB30002728 OWL LAKE SOUTH 15 - 20 - 094 - 12 - 6 1.29 NOVA - NGTL 0TB30002729 FARIA 08 - 05 - 104 - 03 - 6 1.35 NOVA - NGTL 0TB30002731 CROWELL 10 - 27 - 078 - 19 - 5 1.35 NOVA - NGTL 0TB30002732 MOUNTAIN LAKE 00 - 03 - 075 - 24 - 5 1.21 NOVA - NGTL 0TB30002734 ASSUMPTION #2 13 - 33 - 110 - 06 - 6 1.35 NOVA - NGTL 0TB30002735 CODESA 13 - 27 - 078 - 25 - 5 1.29 NOVA - NGTL 0TB30002736 COPTON CREEK 13 - 10 - 062 - 08 - 6 1.22 NOVA - NGTL 0TB30002737 LALBY CREEK 04 - 21 - 078 - 20 - 5 1.35 NOVA - NGTL 0TB30002738 CALAIS 15 - 16 - 069 - 22 - 5 1.08 NOVA - NGTL 0TB30002739 KEPPLER CREEK 00 - 28 - 092 - 17 - 5 1.35 NOVA - NGTL 0TB30002740 STOWE CREEK 14 - 30 - 091 - 01 - 6 1.18 NOVA - NGTL 0TB30002742 OWL LAKE SOUTH #2 15 - 20 - 094 - 12 - 6 1.29 NOVA - NGTL 0TB30002743 CALLUM CREEK 01 - 24 - 012 - 02 - 5 0.81 NOVA - NGTL 0TB30002744 BALLATER #2 00 - 21 - 077 - 21 - 5 1.35 NOVA - NGTL 0TB30002745 NARRAWAY RIVER 10 - 08 - 062 - 10 - 6 1.29 NOVA - NGTL 0TB30002746 OWL LAKE SOUTH #3 15 - 20 - 094 - 12 - 6 1.29 NOVA - NGTL 0TB30002747 TANGHE CREEK #3 11 - 29 - 096 - 11 - 6 1.30 NOVA - NGTL 0TB30002748 KEMP RIVER 01 - 28 - 102 - 03 - 6 1.35 NOVA - NGTL 0TB30002749 CRANBERRY LAKE #2 09 - 20 - 085 - 18 - 5 1.35 NOVA - NGTL 0TB30002750 MARSH HEAD CREEK WEST 07 - 16 - 059 - 24 - 5 0.96 NOVA - NGTL 0TB30002751 HUNT CREEK #2 03 - 32 - 091 - 08 - 5 1.35 NOVA - NGTL 0TB30003001 BOUNDARY LAKE SOUTH 08 - 14 - 085 - 13 - 6 1.24 NOVA - NGTL 0TB30003008 CLEARDALE 00 - 33 - 085 - 11 - 6 1.33 NOVA - NGTL 0TB3

37 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0003009 NEPTUNE 08 - 14 - 085 - 13 - 6 1.24 NOVA - NGTL 0TB30003052 COLEMAN SALES 00 - 04 - 008 - 04 - 5 0.81 NOVA - NGTL 0TB30003058 LUNDBRECK-COWLEY SALES 00 - 07 - 007 - 02 - 5 0.81 NOVA - NGTL 0TB30003062 EAST CALGARY B SALES 00 - 03 - 026 - 29 - 4 0.81 NOVA - NGTL 0TB30003105 CRANBERRY LAKE SALES 08 - 20 - 085 - 18 - 5 1.35 NOVA - NGTL 0TB30003112 FALHER SALES 08 - 06 - 078 - 20 - 5 1.35 NOVA - NGTL 0TB30003113 TWINLAKES CREEK SALES 04 - 04 - 092 - 05 - 5 1.35 NOVA - NGTL 0TB30003304 FORESTBURG SALES 00 - 34 - 040 - 16 - 4 0.85 NOVA - NGTL 0TB30003330 CARSTAIRS INTERCONNECTION 00 - 15 - 030 - 02 - 5 0.81 NOVA - NGTL 0TB30003368 NOEL LAKE SALES 00 - 01 - 062 - 08 - 5 1.16 NOVA - NGTL 0TB30003405 RIM-WEST SALES 00 - 32 - 043 - 01 - 5 0.86 NOVA - NGTL 0TB30003406 REDWATER SALES 00 - 29 - 057 - 21 - 4 1.35 NOVA - NGTL 0TB30003424 GRANDE CENTRE SALES 13 - 13 - 062 - 02 - 4 1.35 NOVA - NGTL 0TB30003425 WOOD RIVER SALES 01 - 17 - 043 - 23 - 4 1.08 NOVA - NGTL 0TB30003438 REDWATER B SALES 00 - 29 - 057 - 21 - 4 1.35 NOVA - NGTL 0TB30003439 SHEERNESS SALES 00 - 32 - 028 - 13 - 4 0.81 NOVA - NGTL 0TB30003454 PENHOLD NORTH SALES 00 - 19 - 037 - 27 - 4 0.81 NOVA - NGTL 0TB30003471 BLUE RIDGE EAST SALES 15 - 23 - 059 - 11 - 5 1.11 NOVA - NGTL 0TB30003481 SAWRIDGE SALES 00 - 30 - 072 - 04 - 5 1.35 NOVA - NGTL 0TB30003489 ATUSIS CREEK SALES 12 - 19 - 027 - 24 - 4 0.81 NOVA - NGTL 0TB30003605 LEMING LAKE SALES 00 - 32 - 065 - 04 - 4 1.35 NOVA - NGTL 0TB30003611 HERMIT LAKE SALES 12 - 36 - 071 - 07 - 6 1.20 NOVA - NGTL 0TB30003860 JANUARY CREEK INTERCONNECTION 00 - 26 - 054 - 14 - 5 0.94 NOVA - NGTL 0TB30003861 DEMMITT #2 INTERCONNECTION 15 - 18 - 074 - 12 - 6 1.27 NOVA - NGTL 0TB30003862 SEVERN CREEK INTERCONNECTION 00 - 03 - 010 - 23 - 4 0.81 NOVA - NGTL 0TB30003864 JOFFRE INTERCONNECTION 12 - 29 - 038 - 25 - 4 0.87 NOVA - NGTL 0TB30003866 CARBON INTERCONNECTION 00 - 16 - 029 - 22 - 4 0.81 NOVA - NGTL 0TB30003868 ALBERTA MONTANA BORDER INTERCO 00 - 11 - 001 - 26 - 4 0.49 NOVA - NGTL 0TB30003871 WESTLOCK SALES INTERCONNECTION 00 - 24 - 060 - 24 - 4 1.35 NOVA - NGTL 0TB30003880 AECO INTERCONNECTION 00 - 35 - 012 - 06 - 4 0.81 NOVA - NGTL 0TB3

38 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0003883 COALDALE LATERAL JUNCTION 00 - 19 - 009 - 19 - 4 0.81 NOVA - NGTL 0TB30003884 COALDALE SOUTH LATERAL JUNCTIO 00 - 15 - 008 - 20 - 4 0.81 NOVA - NGTL 0TB30003885 CHIP LAKE JUNCTION 00 - 29 - 053 - 10 - 5 0.88 NOVA - NGTL 0TB30003889 MITSUE SALES INTERCONNECTION 00 - 30 - 072 - 04 - 5 1.35 NOVA - NGTL 0TB30003897 CROSSFIELD EAST INTERCONNECTIO 00 - 24 - 028 - 01 - 5 0.81 NOVA - NGTL 0TB30003915 HAMILTON LAKE SUMMARY 08 - 34 - 034 - 06 - 4 1.23 NOVA - NGTL 0TB30003916 VETERAN SUMMARY 00 - 29 - 034 - 08 - 4 1.23 NOVA - NGTL 0TB30003917 WHITEMUD WEST/WHITEMUD RIVER S 10 - 33 - 087 - 02 - 6 1.35 NOVA - NGTL 0TB30005003 LIEGE 00 - 29 - 092 - 20 - 4 1.35 NOVA - NGTL 0TB30005004 SALESKI 00 - 36 - 086 - 19 - 4 1.35 NOVA - NGTL 0TB30005005 GRANOR 07 - 25 - 083 - 18 - 4 1.21 NOVA - NGTL 0TB30005007 HOUSE RIVER 00 - 33 - 079 - 14 - 4 1.35 NOVA - NGTL 0TB30005012 BOIVIN CREEK 00 - 01 - 082 - 17 - 4 1.35 NOVA - NGTL 0TB30005021 MACKAY RIVER 00 - 21 - 089 - 21 - 4 1.35 NOVA - NGTL 0TB30005022 DUNKIRK RIVER 12 - 31 - 094 - 18 - 4 1.35 NOVA - NGTL 0TB30005025 GREW LAKE 00 - 27 - 090 - 20 - 4 1.35 NOVA - NGTL 0TB30005026 ALGAR LAKE 00 - 21 - 084 - 15 - 4 1.35 NOVA - NGTL 0TB30005027 THICKWOOD HILLS 01 - 07 - 088 - 18 - 4 1.09 NOVA - NGTL 0TB30005028 GREW LAKE EAST 15 - 30 - 090 - 19 - 4 1.35 NOVA - NGTL 0TB30005083 LIEGE NORTH 01 - 10 - 094 - 21 - 4 1.35 NOVA - NGTL 0TB30005402 COALDALE SOUTH B 00 - 15 - 008 - 20 - 4 0.84 NOVA - NGTL 0TB30005409 CHIP LAKE 00 - 29 - 053 - 10 - 5 0.88 NOVA - NGTL 0TB30076418 Murray Lake North - 21 - 010 - 07 - 4 1.00 NOVA - NGTL 0TB30076426 Topland 09 - 02 - 063 - 07 - 5 1.28 NOVA - NGTL 0TB30077682 Sharrow South #2 16 - 10 - 020 - 02 - 4 0.81 NOVA - NGTL 0TB30077684 Serviceberry Creek 11 - 17 - 026 - 22 - 4 0.81 NOVA - NGTL 0TB30077685 KERSEY 04 - 15 - 028 - 26 - 4 0.81 NOVA - NGTL 0TB30078204 Chancellor Interconnection 02 - 24 - 023 - 20 - 4 0.81 NOVA - NGTL 0TB30078786 Bowell South #2 - 24 - 013 - 09 - 4 0.86 NOVA - NGTL 0TB30078788 Tudor 11 - 17 - 026 - 22 - 4 0.60 NOVA - NGTL 0TB3

39 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0079440 Hartell South 01 - 05 - 019 - 02 - 5 0.81 NOVA - NGTL 0TB30079511 Sawn Lake 14 - 13 - 091 - 13 - 5 1.35 NOVA - NGTL 0TB30079847 Ksituan River East # 2 08 - 07 - 079 - 06 - 6 1.35 NOVA - NGTL 0TB30079881 Basset Lake 16 - 35 - 107 - 04 - 6 1.35 NOVA - NGTL 0TB30079882 Pakan Lake 01 - 18 - 057 - 11 - 4 1.18 NOVA - NGTL 0TB30079884 Amisk South 02 - 16 - 041 - 08 - 4 1.26 NOVA - NGTL 0TB30080205 Marsh Head Creek West #2 07 - 16 - 059 - 24 - 5 0.96 NOVA - NGTL 0TB30080213 Ekwan 10 - 15 - 111 - 12 - 6 1.35 NOVA - NGTL 0TB30080769 Parker Creek 07 - 18 - 069 - 02 - 5 1.35 NOVA - NGTL 0TB30081141 Snuff Mountian 09 - 01 - 066 - 25 - 5 1.00 NOVA - NGTL 0TB30081331 Clear Prairie 08 - 36 - 086 - 10 - 6 1.35 NOVA - NGTL 0TB30081332 Hughenden East 16 - 08 - 041 - 07 - 4 1.15 NOVA - NGTL 0TB30081629 Sylvan Lake East # 2 16 - 19 - 038 - 01 - 5 0.84 NOVA - NGTL 0TB30082578 Harper Creek 16 - 29 - 071 - 01 - 6 1.14 NOVA - NGTL 0TB30082579 Poe 08 - 04 - 049 - 15 - 4 0.89 NOVA - NGTL 0TB30082632 Linden - 25 - 030 - 25 - 4 0.81 NOVA - NGTL 0TB30082700 North Hangingstone 11 - 10 - 084 - 10 - 4 1.35 NOVA - NGTL 0TB30082701 Burnt Pine 04 - 20 - 083 - 11 - 4 1.35 NOVA - NGTL 0TB30082702 Hangingstone 05 - 16 - 082 - 12 - 4 1.35 NOVA - NGTL 0TB30082703 Thornbury Mariana 04 - 04 - 081 - 13 - 4 1.35 NOVA - NGTL 0TB30082704 Thornbury East 15 - 12 - 080 - 13 - 4 1.35 NOVA - NGTL 0TB30082705 Thornbury East 12 - 14 - 079 - 12 - 4 1.35 NOVA - NGTL 0TB30082706 Clyden 08 - 22 - 076 - 12 - 4 1.35 NOVA - NGTL 0TB30082707 Leismer #2 16 - 23 - 077 - 09 - 4 1.35 NOVA - NGTL 0TB30082708 Leismer #1 16 - 23 - 077 - 09 - 4 1.35 NOVA - NGTL 0TB30082709 Thornbury North 07 - 13 - 080 - 14 - 4 1.35 NOVA - NGTL 0TB30082710 Thornbury West 05 - 28 - 079 - 14 - 4 1.35 NOVA - NGTL 0TB30082711 North Duncan 16 - 13 - 077 - 15 - 4 1.35 NOVA - NGTL 0TB30082712 Corrigal Lake Simmons 04 - 01 - 073 - 17 - 4 1.35 NOVA - NGTL 0TB30082713 Wander Tower 09 - 30 - 072 - 14 - 4 1.35 NOVA - NGTL 0TB3

40 of 41


METER STATION


LOCATION


PIPELINE COMPANY

ID


0082714 Calling Lake Simmons 13 - 34 - 069 - 17 - 4 1.35 NOVA - NGTL 0TB30082880 Spotted Creek 12 - 35 - 041 - 23 - 4 1.05 NOVA - NGTL 0TB30800088 POUCE COUPE NORTH RUN #1 04 - 17 - 080 - 12 - 6 0.03 WESTCOAST (ALBERTA) 01350800089 NORTH POUCE-COUPE 04 - 17 - 080 - 12 - 6 0.03 WESTCOAST (ALBERTA) 01350800093 SOUTH POUCE COUPE 07 - 32 - 077 - 11 - 6 0.03 WESTCOAST (ALBERTA) 01350800131 SOUTH POUCE SALES 13 - 12 - 078 - 13 - 6 0.03 WESTCOAST (ALBERTA) 01350800132 ARKOMA POUCE COUPE 04 - 17 - 080 - 12 - 6 0.03 WESTCOAST (ALBERTA) 01350800335 POUCE COUPE RUN 3 09 - 28 - 080 - 13 - 6 0.03 WESTCOAST (ALBERTA) 01350800348 POUCE COUPE RUN 1 01 - 08 - 080 - 13 - 6 0.03 WESTCOAST (ALBERTA) 01350800497 PROGRESS 01 - 01 - 078 - 10 - 6 0.03 WESTCOAST (ALBERTA) 01350800526 POUCE COUPE RUN 2 09 - 28 - 080 - 13 - 6 0.03 WESTCOAST (ALBERTA) 01350800528 POUCE-COUPE SALES 16 - 07 - 078 - 11 - 6 0.03 WESTCOAST (ALBERTA) 01350800533 FARMINGTON 11 - 24 - 079 - 11 - 6 0.03 WESTCOAST (ALBERTA) 01350803315 BOUNDARY LAKE SOUTH 02 - 16 - 085 - 13 - 6 0.03 WESTCOAST (ALBERTA) 0135

41 of 41

INFORMATION BULLETIN – December 2004 ATTACHMENT 6 1. EUB Facilities for AC2 filings

AB GP 0001004 AB GP 0001322 AB GP 0001697 AB GS 0003030 AB GP 0001007 AB GP 0001360 AB GP 0001698 AB GS 0003692 AB GP 0001024 AB GP 0001364 AB GP 0001892 AB GS 0003739 AB GP 0001034 AB GP 0001403 AB GP 0001895 AB GS 0004088 AB GP 0001056 AB GP 0001427 AB GP 0001960 AB GS 0004226 AB GP 0001060 AB GP 0001455 AB GP 0001975 AB GS 0004263 AB GP 0001067 AB GP 0001497 AB GP 0001997 AB GS 0004274 AB GP 0001084 AB GP 0001506 AB GS 0002282 AB GS 0004364 AB GP 0001134 AB GP 0001520 AB GS 0002323 AB GS 0004432 AB GP 0001139 AB GP 0001522 AB GS 0002369 AB GS 0004510 AB GP 0001141 AB GP 0001524 AB GS 0002382 AB GS 0004568 AB GP 0001144 AB GP 0001548 AB GS 0002443 AB GS 0004583 AB GP 0001147 AB GP 0001629 AB GS 0002570 AB GS 0004649 AB GP 0001149 AB GP 0001634 AB GS 0002700 AB GS 0004686 AB GP 0001156 AB GP 0001668 AB GS 0002751 AB GS 0006055 AB GP 0001296 AB GP 0001692 AB GS 0002800 AB GP 0001316 AB GP 0001696 AB GS 0002988

2. OFSG Wells

AB WI 100 01 28 036 03 W5 00 AB WI 100 13 34 020 25 W4 00 AB WI 100 02 06 046 0 1W5 00 AB WI 100 14 17 066 21 W5 00 AB WI 100 02 14 052 07 W5 00 AB WI 100 14 18 038 17 W4 00 AB WI 100 02 16 009 17 W4 00 AB WI 100 14 22 038 03 W4 00 AB WI 100 05 28 042 02 W4 00 AB WI 100 14 36 032 03 W5 00 AB WI 100 05 30 071 06 W6 00 AB WI 100 16 15 033 03 W5 00 AB WI 100 06 11 052 11 W5 00 AB WI 102 01 29 042 02 W4 00 AB WI 100 06 11 075 12 W6 00 AB WI 102 04 07 043 01 W4 00 AB WI 100 06 17 066 21 W5 00 AB WI 102 05 06 043 01 W4 00 AB WI 100 06 31 073 06 W6 00 AB WI 102 10 16 009 17 W4 00 AB WI 100 07 10 075 12 W6 00 AB WI 103 02 33 042 02 W4 00 AB WI 100 10 02 032 02 W5 00 AB WI 1B2 04 22 038 03 W4 00 AB WI 100 10 36 032 03 W5 00 AB WI 1C0 04 22 038 03 W4 00 AB WI 100 11 30 071 06 W6 00

3. EOR Schemes

Rainbow Keg River A Rainbow Keg River EEE Rainbow Keg River E Rainbow South Keg River E Rainbow Keg River G Rainbow South Keg River G Rainbow Keg River H Rainbow Keg River F Project #11 Rainbow Keg River O Rainbow South Keg River B Project #1

Alberta Natural Gas Royalty Chapter I, Section 3 –Process Summary Principles and Procedures, 2003

December 2004 Ch. I, Sec. 3 p.3

Facility Operators file three submissions: • Two to report allowable costs*(capital on AC2 submission, operating on AC4

submission); and • One to claim Sulphur Emission Control Assistance Program (SECAP) annual

operating costs (SECAP 595 submission).

The SAF and OAF are standard formats for industry to report gas facility allocations as developed for the Registry. The SAF/OAF are industry-generated submissions that provide the pivotal volume/ ownership information upon which the Crown natural gas royalty administration depends. These submissions report volumetric and ownership information at the stream level for batteries, gathering systems*, processing plants, and injection facilities for Crown royalty related allocations. Submissions of the SAF/OAF must be made on the Registry. Volumetric reporting on S and OAS documents is replaced by Volumetric, SAF and OAF submissions in the Registry. The Volumetric submission identifies the volumetric activities at a facility. The SAF submissions allocate the volumetric activity quantity to producing streams. The OAF submission allocates the stream quantities to owners.

3.3 Crown Royalty Monthly Invoice

The following figure depicts the once only, as required, monthly and annual reporting of the petroleum and natural gas industry (Royalty Clients, Facility Operators, Pipelines/Common Stream Operators, and Designated Purchasers), and the flow of information as it relates to the monthly Gas Royalty Invoice Package.

3.4 Release of Royalty and Related Information

To maintain the confidentiality of royalty information client specific information will be released, to a third party, only with the written consent of the royalty client. If a royalty client has a third party preparing royalty submissions on their behalf, they must ensure the department receives written notice, from the royalty client, authorizing the release of royalty information.

Alberta Natural Gas Royalty Chapter I, Section 3 –Process Summary Principles and Procedures, 2003

June 2003 Ch. I, Sec. III p.4

Purchasers and Storers

Facility Operators

Royalty Clients

Registry

VA1

RMF1, RMF3

RMF2, RMF2-T

Once only

As required

AC2, AC4, 595

AC3, AC5

NGL100

Ministry Series 600

Calculate Reference Prices and Allowances

Dynamic OAF, SAF

PW1, VA4

Annually

Monthly

Calculate Crown Royalty Share Calculate Waivers and Exemptions

Value Net Crown Royalty Share

Calculate Allowable Costs

Gas Royalty Invoice Pkg., Statement of Account, Invoice

Pipelines/Common Stream Operators

Volumetrics

Department

AC1, Static OAF, SAF

RGA

VA2, VA3, GR2

Exhibit A

Alberta Natural Gas Royalty Chapter II, Section 1-Alberta’s Royalty Share of Gas and Gas Products Principles and Procedures, 2003

December 2003 Ch. II, Sec.1 p.9

Table 1

There are separate Crown royalty rates for "old" or "new" vintage. (For information on how to calculate the Crown royalty rate, please refer to Ch. III, Sec. 7.5).

1.9.2 Vintage A.R. 220/2002 Sch. 7 The vintage of gas is determined by the date of discovery, or first production from the pool*. Generally speaking:

• New gas is gas obtained from a pool; • Discovered on or after January 1, 1974; or • Discovered before January 1, 1974, if no gas or other gas products from

that pool had been sold or consumed for some useful purpose before January 1, 1974;

• Old gas is gas that does not qualify as new gas.

The Minister may determine that gas obtained from a well event or unit is only partly new gas and may assign a vintage between 0% new and 100% new if:

• Production from a single well event is obtained from more than one pool; and

• One or more of the pools were known to exist before January 1, 1974 1.10 Crown Royalty Rate for Methane ISC (C1-IC)

The Crown royalty rates for Methane ISC are calculated each month according to the prescribed formula that provides price sensitivity (Methane ISC Par Price*) and distinguishes between old Methane ISC* and new Methane ISC* (Vintage and Select Prices*). (For information on how to calculate the Crown royalty rate, please refer to Ch. III, Sec.7.5).

Product Gas ConversionHeat

ConversionC2-SP 0.28132 66.065C2-MX 0.28132 66.065C3-SP 0.27201 93.936C3-MX 0.27201 93.936C4-SP 0.23331 121.406C4-MX 0.23331 121.406C5-SP 0.2057 149.363C5-MX 0.2057 149.363

SUL 0.7375 23.784



1.10.1 Methane ISC Par Price and Select Prices The Methane ISC Par Price for a production month is the Methane ISC Reference Price for the current production month (prior to January 2004, the Methane ISC Par Price was equal to the previous month’s Methane ISC Reference Price). An Old Methane ISC Select Price* and a New Methane ISC Select Price* is determined by the Minister for each year. The Select Prices apply to all production months in that year. (For further information on Select Prices, please refer to the Department’s website at www.energy.gov.ab.ca). The Department will publish the Methane ISC Par Price, the Old Methane ISC Select Price and the New Methane ISC Select Price in an Information Letter on the 15th day of the second month following the production month to which they will apply. If this day falls on a weekend or a holiday, the next business day will apply. The Methane ISC Par Price, Old Methane ISC Select Price and New Methane ISC Select Price that are established for a production month will not be changed retroactively. Calculation of the Methane ISC Par Price is subject to an independent audit conducted on behalf of the petroleum and natural gas industry.

1.10.2 Methane ISC Vintage Unless the Minister determines otherwise, the vintage of Methane is the same as the gas with which it is produced and from which it is recovered.

1.10.3 Old Methane ISC Royalty Rate (C1-IC) A.R. 220/2002 Sch.1 - S. (1)(2) The Crown royalty rate for old Methane ISC in a month, expressed as a percentage of the Crown interest share, is calculated as:

RR% = 15(MSP) + 40(MPP - MSP) MPP

WHERE: RR% = the Crown royalty rate for old Methane ISC. MSP = the old Methane ISC select price prescribed by the Minister for the

production month. MPP = the Methane ISC par price prescribed by the Minister for the production

month. The minimum Crown royalty rate for old Methane ISC is 15%. The maximum Crown royalty rate for old Methane ISC is 35%.



1.10.4 New Methane ISC Royalty Rate (C1-IC)

A.R. 220/2002 Sch.1-S. (1)(2) The Crown royalty rate for new Methane ISC in a month, expressed as a percentage of the Crown interest share, is calculated as:

RR% = 15(MSP) + 40(MPP - MSP) MPP

WHERE: RR% = the Crown royalty rate for new Methane ISC. MSP = the new Methane ISC select price prescribed by the Minister for the

production month. MPP = the Methane ISC par price prescribed by the Minister for the production

month. The minimum Crown royalty rate for new Methane ISC is 15%. The maximum Crown royalty rate for new Methane ISC is 30%

1.10.5 Low Productivity Well Allowance* A.R. 220/2002 Sch. 1 – S. 3(1) The Crown royalty rates for both old and new Methane will be reduced for well events that:

• Are classified by the EUB as a gas well* event, or an oil well event and • Have a monthly average daily gas production rate of less than 16.9 103m3 per

day for gas well events; or • Have a monthly average daily production rate under 0.15 m3 per day of oil and

16.9 103m3 of gas for an oil well event. Average Daily Production* (ADP) for gas is calculated as:

volume of natural gas obtained in the month from the gas event (in 103m3) …divided by…

number of hours of operation of the well in the month …multiplied by…

24 Average Daily Production (ADP) for oil is calculated as:

volume of oil obtained in the month from the oil event (in m3) …divided by…


24



The Crown royalty rate for a well event that qualifies for low productivity (for either old or new gas) is calculated as:

R% = RC - (RM - 5%) x (16.9 - ADP) 2

16.9 2[ ]

WHERE: R% = the Crown royalty low productivity rate for gas. RC = the Crown royalty rate that would apply if the royalty is calculated at either

the old or new Methane royalty rate (whichever is applicable) for the production month.

RM = the old or new Methane royalty rate (whichever is applicable) for the production month.

ADP = the average daily production of gas for the well event for the production month (in 103m3).

Refer to Ch. III, Sec. 7.6.1 for an example of low productivity calculation.

1.11 Crown Royalty Rate for Ethane

1.11.1 Calculation Criteria The Crown royalty share for Ethane is a percentage (the Crown royalty rate) of the Crown interest share of production. The Crown royalty rates for Ethane are calculated each month according to the prescribed formula that provides price sensitivity (Ethane Par Price*) and distinguishes between old Ethane* and new Ethane* (Vintage and Select Prices*). Ethane, which is measured in m3, is converted to a gas equivalent heat content and the Crown royalty rate for Ethane is applied to m3 and GJ volumes. (For information on how to calculate the Crown royalty rate, please refer to Ch. III, Sec.7.5).

1.11.2 Ethane Par Price and Select Prices The Minister determines an Ethane Par Price for each production month, which is the Ethane Reference Price for the current production month (prior to January 2004, the Ethane Par Price was equal to the previous month’s Ethane Reference Price). An Old Ethane Select Price* and a New Ethane Select Price* is determined by the Minister for each year. The Select Prices apply to all production months in that year. (For further information on Select Prices, please refer to the Department’s website at www.energy.gov.ab.ca). The Department will publish the Ethane Par Price, the Old Ethane Select Price and the New Ethane Select Price in an Information Letter on the 15th day of the second month



following the production month to which they will apply. If this day falls on a weekend or a holiday, the next business day will apply. The Ethane Par Price, old Ethane Select Price and new Ethane Select Price that are established for a production month will not be changed retroactively. Calculation of the Ethane Par Price is subject to an independent audit conducted on behalf of the petroleum and natural gas industry.

1.11.3 Ethane Vintage A.R. 220/2002 Sch. 7 (2) Unless the Minister determines otherwise, the vintage of Ethane is the same as the gas with which it is produced and from which it is recovered.

1.11.4 Old Ethane Royalty Rate A.R. 220/2002 Sch. 2 - S. (2) The Crown royalty rate for old Ethane in a month, expressed as a percentage of the Crown interest share, is calculated as:

RR% = 15(ESP) + 40(EPP - ESP)

EPP

WHERE: RR% = the Crown royalty rate for old Ethane. ESP = the old Ethane select price prescribed by the Minister for the production

month. EPP = the Ethane par price prescribed by the Minister for the production month.

The minimum Crown royalty rate for old Ethane is 15%. The maximum Crown royalty rate for old Ethane is 35%.

1.11.5 New Ethane Royalty Rate A.R. 220/2002 Sch. 2-S. (2) The Crown royalty rate for new Ethane in a month, expressed as a percentage of the Crown interest share, is calculated as:

RR% = 15(ESP) + 40(EPP - ESP)

EPP

WHERE: RR% = the Crown royalty rate for new Ethane.



ESP = the new Ethane select price prescribed by the Minister for the production month.

EPP = the Ethane as par price prescribed by the Minister for the production month. The minimum Crown royalty rate for new Ethane is 15%. The maximum Crown royalty rate for new Ethane is 30%

1.11.6 Low Productivity Well Allowance* A.R. 220/2002 Sch. 2 - S. (3) The Crown royalty rates for both old and new Ethane will be reduced for well events that:

• Are classified by the EUB as a gas well* event, or an oil well event; and • Have a monthly average daily gas production rate of less than 16.9 103m3 per

day for gas well events; or • Have a monthly average daily production rate under 0.15 m3 per day of oil and

16.9 103m3 of gas for an oil well event. Average Daily Production* (ADP) for gas is calculated as:

volume of natural gas obtained in the month from the gas event (in 103m3) …divided by…


24 Average Daily Production (ADP) for oil is calculated as:

volume of oil obtained in the month from the oil event (in m3) …divided by…


24 The Crown royalty rate for a well event that qualifies for low productivity (for either old or new ethane) is calculated as:

R% = RC - (RM - 5%) x (16.9 - ADP) 2

16.9 2[ ]

WHERE: R% = the Crown royalty low productivity rate for Ethane. RC = the Crown royalty rate that would apply if the royalty is calculated at either the

old or new Ethane royalty rate (whichever is applicable) for the production month.



RM% = the old or new Methane royalty rate (whichever is applicable) for the production month.

ADP = the average daily production of gas for the well event for the production month (in 103m3).

Refer to Ch. III, Sec. 7.6.1 for an example of low productivity calculation.

1.12 Crown Royalty Rate for Propane 1.12.1 Calculation Criteria

A.R. 220/2002 Sch. 3 - S. (1) The Crown royalty rate for Propane is calculated each month according to a prescribed formula that provides price sensitivity (Propane Par Price* and Propane Select Price*).

1.12.2 Propane Par Price and Select Prices

The Minister determines a Propane Par Price for each production month, which is the Propane ISC Reference Price for the current production month (prior to January 2004, the Propane Par Price was equal to the previous month’s Propane ISC Reference Price). The Minister determines a Propane Select Price for each year. The Select Price applies to all production months in that year. (For further information on Select Prices refer to the Department’s website at www.energy.gov.ab.ca). The Department will publish the Propane Par Price and the Propane Select Price in an Information Letter on the 15th day of the second month following the production month to which they will apply. If this day falls on a weekend or a holiday, the next business day will apply. The Propane Par Price and Propane Select Price that are established for a production month will not be changed retroactively. Calculation of the Propane Par is subject to an independent audit conducted on behalf of the petroleum and natural gas industry.

1.12.3 Propane Vintage Unless the Minister determines otherwise, there is no new or old vintage designation for Propane.



1.12.4 Propane Royalty Rate

The Crown royalty rate for propane in a month, expressed as a percentage of the Crown interest share, is calculated as:

RR% = 15(PSP) + 40(PPP - PSP)

PPP

WHERE: RR% = the Crown royalty rate for Propane. PSP = the Propane select price prescribed by the Minister for the production month. PPP = the Propane par price prescribed by the Minister for the production month. The minimum Crown royalty rate for Propane is 15%. The maximum Crown royalty rate for Propane is 30%

1.13 Crown Royalty Rate for Butanes

1.13.1 Calculation Criteria A.R. 220/2002 Sch. 4 – S. (1) The Crown royalty rate for Butanes is calculated each month according to a prescribed formula that provides price sensitivity (Butanes Par Price* and Butanes Select Price*).

1.13.2 Butanes Par Price and Select Prices The Minister determines a Butanes Par Price for each production month, which is the Butanes ISC Reference Price for the current production month (prior to January 2004, the Butanes Par Price was equal to the previous month’s Butanes ISC Reference Price). The Minister determines a Butanes Select Price for each year. The Select Price applies to all production months in that year. (For further information on Select Prices refer to the Department’s website at www.energy.gov.ab.ca). The Department will publish the Butanes Par Price and the Butanes Select Price in an Information Letter on the 15th day of the second month following the production month to which they will apply. If this day falls on a weekend or a holiday, the next business day will apply. The Butanes Par Price and Butanes Select Price that are established for a production month will not be changed retroactively. Calculation of the Butanes Par Price is subject to an independent audit conducted on behalf of the petroleum and natural gas industry.



1.13.3 Butanes Vintage

Unless the Minister determines otherwise, there is no new or old vintage designation for Butanes.

1.13.4 Butanes Royalty Rate The Crown royalty rate for Butanes in a month, expressed as a percentage of the Crown interest share, is calculated as:

RR% = 15(BSP) + 40(BPP - BSP)

BPP

WHERE: RR% = the Crown royalty rate for Butanes. BSP = the Butanes select price prescribed by the Minister for the production month. BPP = the Butanes par price prescribed by the Minister for the production month. The minimum Crown royalty rate for Butanes is 15%. The maximum Crown royalty rate for Butanes is 30%

1.14 Crown Royalty Rate for Pentanes-Plus A.R. 220/2002 Sch. 5 - S. (1) The Crown royalty rates for Pentanes-plus are calculated each month according to a prescribed formula that provides price sensitivity (Pentanes Par Price* and Select Price*) and distinguishes between old and new Pentanes-plus* (Vintage and Royalty Factor). There is a separate Crown royalty rate for old and new Pentanes-plus.

1.14.1 Pentanes Par Price, Select Price and Royalty Factors The Minister determines a Pentanes Par Price for each production month, which is the Pentanes Reference Price for the current production month (prior to January 2004, the Pentanes Par Price was equal to the previous month’s Pentanes ISC Reference Price), minus an allowance for transportation. The deduction for transportation is calculated as the volume-weighted average of the four regional Transportation Allowances* for specification pentanes-plus in the applicable production month (refer to Ch. III, Sec. 2.3.1). The Minister determines:

• A Pentanes Select Price* for each year, and this Select Price for a year applies to all production months of that year.

• An Old Pentanes-plus* Royalty Factor and a New Pentanes-plus Royalty Factor for each year, which will apply to all production months of that year.



The Department will publish the Pentanes Par Price and Pentanes Select Price in an Information Letter on or before the 15th day of the second month following the production month to which they will apply. If this date falls on a weekend or holiday, the next business day will apply. The Pentanes Par Price, Pentanes Select Price, Old Pentanes-plus Royalty Factor and New Pentanes-plus Royalty Factor that are established for a production month will not be changed retroactively. Calculation of the Pentanes Par Price is subject to an independent audit conducted on behalf of the petroleum and natural gas industry.

1.14.2 Pentanes-Plus Vintage A.R. 220/2002 Sch. 7 - S. (3) Unless the Minister determines otherwise, effective January 1, 1994, the vintage of Pentanes-plus is the same as the gas with which it is produced and from which it is recovered.

1.14.3 Old Pentanes-Plus Royalty Rate A.R. 220/2002 Sch. 5 - S. (1) The Crown royalty rate for old Pentanes-plus in a month, expressed as a percentage of the Crown interest share, is calculated as:

R% = 22(SP) + RF(PP - SP) PP

WHERE: R% = the Crown royalty rate for old Pentanes-plus. SP = the Pentanes select price prescribed by the Minister for the production month. RF = the old Pentanes-plus royalty factor (currently set at 50) prescribed by the

Minister for the production month. PP = the Pentanes par price prescribed by the Minister for the production month to

which the Crown royalty rate applies. The minimum Crown royalty rate for old Pentanes-plus is 22%. The maximum Crown royalty rate for old Pentanes-plus is 50%.

1.14.4 New Pentanes-Plus Royalty Rate A.R. 220/2002 Sch. 5 - S. (1) The Crown royalty rate for new Pentanes-plus in a month, expressed as a percentage of the Crown interest share, is calculated as:



R% = 22(SP) + RF(PP - SP) PP

WHERE: R% = the Crown royalty rate for new Pentanes-plus. SP = the Pentanes select price prescribed by the Minister for the production month. RF = the new Pentanes-plus royalty factor (currently set at 35) prescribed by the

Minister for the production month. PP = the Pentanes par price prescribed by the Minister for the production month to

which the Crown royalty rate applies. The minimum Crown royalty rate for new Pentanes-plus is 22%. The maximum Crown royalty rate for new Pentanes-plus is 35%.

1.15 Crown Royalty Rate for Sulphur A.R. 220/2002 Sch. 6 - S. (2) The Crown royalty rate for sulphur, expressed as a percentage of the Crown interest share, is 162/3% (16.66667).

1.16 Crown Royalty Rate for Other Products A.R. 220/2002 S. 17 (4) The Crown royalty rate for other products, expressed as a percentage of the Crown interest share, is 30%. These products are:

• Carbon dioxide; • Nitrogen; • Helium; and • Light ends*

Alberta Natural Gas Royalty Chapter II, Section 10 –Amalgamations and Consolidations Principles and Procedures, 2003

December 2004 Ch II, Sec.10 p.1

10. Amalgamations and Consolidations

10.1 Amalgamations (Mergers)

In the event of an amalgamation, the Department is notified through the publication of said amalgamation in the Gazette or the company may forward a copy to the Department for its records. If an Amalgamation is effective on the first day of the month, the Department will process the amalgamation in that production month. If the amalgamation is effective after the first of the month, then the Department will process the amalgamation in the production month following the effective date. An invoice consolidation is completed at the time of the amalgamation and is effective in the same production period as described for amalgamations.

10.1.1 Reporting

The resulting company in the amalgamation may continue to use the amalgamatee’s royalty ID until the established date is reached. The established date is an agreed upon date between amalgamator, EUB and DOE. This date is to be within six-months of the amalgamation date. After the established date, the amalgamatee’s royalty ID cannot file and the rules for consolidation no longer apply. New documents or amendments that affect months prior to the amalgamation will still be accepted.

10.1.2 Valuation

If the gas valuation structure of the royalty clients consists of both CAP and Reference Price, the gas valuation of the amalgamating parties will revert to the Reference Price effective the first month of the year following amalgamation. (Refer to Ch. II, Sec. 3.4.2). If the gas valuation structure of the royalty clients consists of only CAP, the gas valuation of the amalgamating parties shall remain CAP as long as their eligibility is maintained. (Refer to Ch. II, Sec. 3.4.3).

10.1.3 VA2, VA3 and VA4 Forms The amalgamator for the amalgamated entity is responsible for submitting VA2, VA3 and VA4 forms for all amalgamated companies. To do this, they must compile all information for the affected companies and place the combined totals on a VA2/VA3/VA4 form. The VA2/VA3 totals apply for the whole year of amalgamation, regardless of which month the amalgamation took place. The calculated annual Gas Corporate Average Price (CAP) and monthly/annual Sulphur Valuation Price (Sulphur Corporate Average Price (S-CAP) or Sulphur Default Price) will be the same for all companies within the amalgamation. If the gas

Alberta Natural Gas Royalty Chapter II, Section 10 –Amalgamations and Consolidations Principles and Procedures, 2003

June 2003 Ch II, Sec.10 p.2

valuation structure for all the amalgamating parties consists of CAP, the calculated Corporate Gas Factor (CGF) will be the same for all companies within the amalgamation. Only one VA2, VA3 and VA4 form is required, including any amended forms, under the name and ID of the amalgamator for the amalgamated entity (refer to Ch. IV, Sec. 3.2; Ch. IV, Sec. 4.1 and Ch. IV, Sec. 4.2).

10.1.4 Allowable Costs After the amalgamation date, all royalty clients in the amalgamation may continue to report and receive allowable costs. The amalgamation affects the Corporate Effective Royalty Rate (CERR) calculation.

10.1.4.1 CERR for the Amalgamation Year From the amalgamation date to the end of the year, the amalgamator's CERR will be used to estimate the allowable costs for deduction from the royalty amount of all the amalgamating parties. If the amalgamator does not have a CERR, the Provincial Average CERR for the year of amalgamation will be used to estimate the allowable costs for deduction from the royalty amount of all the amalgamating parties. For the amalgamator, the actual CERR for the year of amalgamation will be determined by including all the amalgamator's volumes for the year, as well as the volumes of all amalgamating parties after the amalgamation date. For a member of the consortium (excluding the amalgamator), the actual CERR for the year of amalgamation will be a weighted average CERR based on an individual rate calculated before amalgamation and the amalgamator's rate.

10.1.4.2 CERR for the Post-Amalgamation Years For all the amalgamating parties, the CERR estimate for the year following the amalgamation will be determined by including all the volumes for each member of the consortium for the amalgamation year. This CERR will be the basis of determining the following year's allowable estimated costs for the amalgamated clients. The actual CERRs for the years after amalgamation for all the amalgamating parties will be determined by including all the volumes for each member of the consortium for the year. These CERRs will become the estimates for the following years.

Alberta Natural Gas Royalty Chapter III, Section 1-Valuing Raw Gas, and Residue Gas (Pricing Calculation) Principles and Procedures, 2003

September 2003 Ch. III, Sec.1 p.1

1 Valuing Raw Gas and Residue Gas (Pricing Calculation) 1.1 Raw Gas and Residue Gas Valuation 1.1.1 Raw Gas

The Crown’s share of raw gas is valued at the Facility Average Price (FAP) of the sales location identified on the RGA submission, except when the raw gas sale is subsequently processed in which case it is assessed at the raw gas average royalty rate and 80% of the Gas Reference Price. If the raw gas sale is subsequently used for lease fuel it is assessed at the raw gas average royalty rate (RARR%) and 100% of the Gas Reference Price. Raw gas that is injected is valued at the FARR% of the injection facility and the FAP of the reproducing facility.

1.1.2 Residue Gas

The Crown’s share of residue gas is valued at the FAP of the facility for a company using the Reference Price Valuation method. A company on the Reference Price valuation method with Grandfathered long-term contracts should refer to Ch. II, Sec. 3.3. A company on the Corporate Average Price (CAP) valuation method uses its own sales for the year subject to a minimum annual price calculation.

1.2 Facility Average Price (FAP) FAP is the facility reference price less the facility gas transportation adjustment. The FAP is equivalent to the Net Gas Reference Price at a facility. The facility reference price is the aggregate (weighted) Gas Reference Price that is calculated using ISC published reference prices and the ISC content within the royalty-triggered gas. The facility gas transportation adjustment is the Transportation Allowance for gas at a facility. It is a weighted average calculation using published Meter Station Factors, published Adjusted Intra-Alberta Transportation Deductions (AIATD) for all ISCs, and the ISC content within the royalty-triggered gas. The FAP for a month is calculated as:

Facility Reference Price for the month …minus…

Facility Gas Transportation Cost Allowance for the month A.R. 220/2002 Sch.1, S.4


December 2004 Ch. III, Sec.1 p.2

STEP 1: The facility reference price is an aggregate gas reference price. The facility reference price is calculated as:

Sum of (ISC Product Energy times ISC Product Reference Price) for the month … Divided by…

Sum of ISC Product Energy for the month STEP 2: The Facility Gas Transportation Adjustment is calculated as:

[Royalty Trigger Factor minus 1] for the month … Multiplied by…

Facility Adjusted IATD for the month STEP 3: The Royalty Trigger Factor is calculated as:

Sum of (ISC Product Energy times Meter Station Factor) for the month … Divided by…

Sum of ISC Product Energy STEP 4: The Facility Adjusted IATD is calculated as:

Sum of (ISC Product Energy times Adjusted IATD of ISC) for the month … Divided by…

Sum of ISC Product Energy For a sample of the FAP calculation or exceptions to FAP refer to Appendix D.

1.3 Calculation of the Gas Reference Price

The Gas Reference Price for a month is calculated as:

Weighted Average Price of Alberta Gas for the month …minus…

Transportation Cost Allowance for the month …minus…

Weighted Average Marketing Allowance for the month …minus…

Pipeline Fuel/Loss Allowance for the month …plus or minus…

Adjustment for Prior Period Amendments for the month



Procedures for reporting and calculating the Gas Reference Price (refer to Appendix D) are described in the "Ministry Natural Gas Reporting Guide". A.R. 220/2002 S.6 (1) The Department will publish the production month's Gas Reference Price in an Information Letter on the 15th day of the second month following the production month, unless the 15th day is a weekend or a holiday; in which case, the next business day will apply. The Gas Reference Price that is established for a month will not be changed retroactively. A.R. 220/2002 S.33

The calculation of the Gas Reference Price is subject to an independent audit conducted on behalf of the petroleum and natural gas industry.

1.3.1 Weighted Average Price of Alberta Gas

The weighted average price of Alberta gas for a month is calculated as:

(Value of gas consumed in Alberta in the month …plus…

Value of gas exported from Alberta in the month) …divided by…

(Gas consumed in Alberta [GJ] …plus… gas exported from Alberta [GJ] in the month)

The value of gas consumed in Alberta is calculated in three steps using information reported by large volume end-users* (LVE) and designated distributors* (DD), including buy/sell end-users of the designated distributors. For purposes of this calculation, transactions are separated into non-associated* (dispositions to persons not associated with the seller) and associated* (dispositions to persons associated with the seller). STEP 1:

Value of LVE non-associated transactions in the month (as reported to the Ministry)

…plus… Value of LVE associated transactions in the month (GJ …multiplied by… weighted

average non-associated LVE inlet price) …equals…

Value of LVE transactions for the month



STEP 2:

Value of DD non-associated transactions in the month (as reported to the Ministry) …plus…

Value of DD associated transactions in the month (GJ …multiplied by… weighted average non-associated DD inlet price)

…equals… Value of DD transactions for the month

STEP 3:

Value of LVE transactions in the month …plus…

Value of DD transactions in the month …equals…

Value of gas consumed in Alberta for the month The value of gas exported from Alberta is also calculated in three steps, using information reported by the owner of the gas at the point of removal*. Reporting is based on five designated removal points: Coleman, Empress, James/McNeill, Provost and "Other". ("Other" includes transactions from all export points other than the four specified locations.) Transactions are separated into "non-associated" and "associated" in the same manner as for gas consumed in Alberta. Refer to Appendix D for more details on the calculation of Gas Reference Price. STEP 1:

Value of non-associated exports at the removal point in the month (GJ …multiplied by… price

at the Alberta border, for each owner) for all owners at the removal point …divided by…

Total non-associated exports at the removal point in the month (GJ) for all owners …equals…

weighted average price at the removal point for the month STEP 2:

(Non-associated exports at the removal point in the month (GJ) for all owners …plus…

Associated exports at the removal point in the month (GJ) for all owners) …multiplied by…

Weighted average price at the removal point for the month …equals…

Value of gas exported at the removal point for the month



STEP 3:

Value of gas exported at each removal point, summed for all removal points …equals…

Value of gas exported from Alberta in the month (excess demand charges included)

That weighted average price is calculated as:

([Value of associated and non-associated gas exported at all other removal points] …plus… [value of non-associated gas exported

at the removal point in question]) …divided by…

([Quantity (GJ) of associated and non-associated gas exported at all other removal points] …plus… [quantity (GJ) of non-associated gas exported

at the removal point in question])

For the period January 1996 to April 2004, associated dispositions of a removal point are valued up to the non-associated dispositions of the removal point. For May 2004 and future periods, associated dispositions at a removal point are valued up to twice the non-associated dispositions of the removal point. The excess of associated dispositions to non-associated dispositions is excluded from the value of gas exported from Alberta and subsequently valued at the gas reference price. For the same periods, similar processes apply for the large volume end-users and designated distributors.

1.3.2 Transportation Cost Allowance

The intra-Alberta transportation* cost allowance for a month is calculated as:

Alberta cost of service for the month …divided by…

Alberta net billable receipts (GJ) for the month

Refer to Appendix D for more information.

1.3.3 Weighted Average Marketing Allowance

The Weighted Average Marketing Allowance is a deduction in the calculation of the monthly gas reference price. It is comprised of the Valuation Point Adjustment*(VPA), Aggregator Overhead Marketing and Administration Charges (OMAC) Adjustment, and the Producer Direct Marketing Allowance. The following principles apply: • The Department calculates the VPA as the average difference between

purchases and sales prices obtained for companies identified as marketers. This



is multiplied by the percentage that marketers were of the total gas dispositions (for 1994 only) and the total gas removals from Alberta (for 1995 and onwards), in the previous year. (For 1994 only, volumes purchased by marketers are net of the purchased portion of net injection calculated using the latest year for which that data is available.) For 1994, the average difference is deemed to be 10¢/GJ. The Department will calculate future average differences based on surveys of marketers.

• The Aggregator OMAC Adjustment* rate is determined by the Department each month as a proxy* for the overhead, marketing and administration charges of recognized aggregators*. The rate will be the weighted average OMAC type deduction of the designated large aggregators multiplied by the total percentage that the recognized aggregators volumes were of the total gas dispositions (for 1994 only), and the total gas removals from Alberta (for 1995 and onwards) in the previous year.

• The Producer Direct Marketing Allowance is determined by the Department to reflect the cost of marketing direct sales of natural gas by producers. This allowance has been implemented on a go-forward basis effective with the May 2004 production month. Refer to Appendix D for details of the calculation methodology.

1.3.4 Pipeline Fuel/Loss Allowance

The pipeline fuel/loss allowance for a month is calculated as:

(Weighted Average Price of Alberta Gas …minus… Transportation Cost Allowance …minus… VPA and Aggregator OMAC Charges Adjustment) for the

month …multiplied by…

(1.0 …minus… [Alberta net billable receipts …divided by… Alberta gross billable receipts ]) for the month

1.3.5 Adjustment for Prior Period Amendments

If the Ministry receives amendments to previous period reporting from companies upon whom it depends for the information used in calculating the Gas Reference Price, the Ministry will calculate an adjustment to the current month’s Gas Reference Price. The adjustment is calculated in the manner described in Appendix D. The maximum adjustment for any current month’s Reference Price is an amount equal to 2% of the Gas Reference Price before amendments are considered. Any amount that is over the 2% limit is carried forward to the next succeeding Reference Price month. Amendments that are reported and included as adjustments in this manner are those which result from reporting errors or omissions by the reporting company.



If the adjustments result from re-determinations or re-allocations by a Facility Operator, pipeline company, producer or customer, the reporting company includes these adjustments in its reports for the delivery month in which they are transacted, and not for the production month to which the adjustments apply.

1.4 ISC Reference Prices

The ISC Reference Price calculation utilizes the principles and information collection mechanism of the Gas Reference Price (Refer to Gas Reference Price – Ch. III, Sec. 1.3 and Appendix D). Some additional principles are followed:

1) ISC quantities in the ISC Reference Price calculations are determined from reported Gas Reference Price quantities based on the percentage of each ISC in the gas stream.

2) ISCs that are consumed as gas are valued at reported gas prices. 3) Gas Transportation Costs are adjusted based on the ISC gigajoule content in

a volume of gas. 4) The Alberta large volume end-user pool is split into a mainline straddle plant

pool and other Alberta large volume end-user pool. The shrinkage value of the gas extracted at mainline straddle plants is used in the calculation of all ISCs except methane (C1).

The ISC Reference Prices for a month is calculated as:

Weighted Average Price of ISC for the month …minus…

Alta. Transportation Cost Allowance of ISC for the month …minus…

Weighted Average Marketing Allowance (Gas RP) for the month …minus…

Pipeline Fuel/Loss Allowance for the month …plus or minus…

Adjustment for Prior Period Amendments for the month Refer to Appendix D for more details on the ISC Reference Price calculations. A.R. 220/2002 S. 6 (2)(3)(4)(5)(6)(7) The Department will publish the production month's ISC Reference Prices in an Information Letter on the 15th day of the second month following the production month, unless the 15th day is a weekend or a holiday; in which case, the next business day will apply. The ISC Reference Prices that are established for a month will not be changed retroactively. A.R. 220/2002 S. 33


June 2003 Ch. III, Sec.1 p.8

The calculation of ISC Reference Prices is subject to an independent audit conducted on behalf of the Petroleum and Natural Gas Industry.

1.5 Facility Average Transportation Allowances

A.R. 220/2002 Sch.1 - S.5 The Department deducts a facility average Transportation Allowance from the facility average Reference Prices (Aggregate Gas Reference Price), as part of its calculation of the Facility Average Price (FAP), used to value the Crown's royalty share of raw gas and residue gas. The facility average Transportation Allowance represents the difference between the average Alberta Transportation Cost Allowances that are deducted in the Gas Reference Price calculations, and Alberta transportation costs calculated for a specific facility. A unique Transportation Allowance is calculated for each royalty trigger point that is connected to a meter station of an included pipeline. Generally, the Department includes a pipeline if it has access to the ex-Alberta market and has published tolls and tariffs. Where a royalty trigger point is not connected to a meter station of an included pipeline, the facility average Transportation allowance is zero. The Facility Average Transportation Allowance can be positive or negative depending on whether the calculated transportation costs for a facility are greater than or less than the Alberta average transportation costs. The Transportation Allowance is calculated monthly as follows:

Intra-Alberta Transportation Deduction (for each ISC Product)

multiplied by... Pipeline Fuel/loss factor (for each ISC Product)

...equals... Adjusted Intra-Alberta Transportation Deduction (AIATD for each ISC Product)

...plus or minus... AIATD prior period amendments (for each ISC Product)

...multiplied by... ISC specific heat

...equals... ISC specific weighted AIATD

...sum all... total weighted ISC AIATD

...divided by... total facility heat

...equals... Facility AIATD

...multiplied by... Royalty Trigger Factor ... minus ... one



The Department calculates the Royalty Trigger Factor by weight averaging the meter station factors based on actual volumetric dispositions (refer to Appendix E). Meter Station factors are generally calculated once a year from information submitted by included pipelines for the delivery month of April. Meter Station Factors calculated using April information are used for the subsequent October through September production period. Once a factor is established for a meter station, it cannot be amended retroactively. Consequently, the six months lag period enables the Department to validate the information prior to its use. For information regarding the calculation of the meter station factor refer to Appendix E. A Transportation Allowance that is calculated for a royalty trigger point for a production month can be changed retroactively but only where the change is due to a recalculated royalty trigger factor resulting from revised volumetric information. The ISC product Adjusted Intra-Alberta Transportation Deduction (AIATD) that is established for a month will not be changed retroactively. If the Department receives amendments to the information used to calculate the ISC product AIATD, the Department will calculate an adjustment to the current month's ISC product AIATD. The full amount of any adjustment will be included in the current month's ISC AIATD calculation. The Department will publish the production month's AIATD in an Information Letter on the 15th day of the second month following the production month, unless the 15th day is non-business day; in which case, the next business day will apply. The Department will publish meter station factors in an Information Letter on December 15th of each year, unless the 15th day is a non-business day; in which case, the next business day will apply. The Department will also publish new meter station factors in an Information Letter during the year as required. The Department will publish royalty trigger factors by December 27th of each year, unless the 27th day is a non-business day; in which case, the next business day will apply. The Department will also publish new or revised royalty trigger factors during the year as required.

1.6 Calculation of the Grandfathered Price

The Department will invoice the monthly Crown royalty share of grandfathered contracts* using the Gas Reference Price. A final accounting and corporate royalty account adjustment, to reflect the grandfathered price, is made annually. The Department will adjust the Crown royalty share of grandfathered contracts as follows:



Monthly Crown Royalty Quantity in GJ

...multiplied by... (Monthly Gas Reference Price ...minus... monthly Netback Selling Price)

The Department will honour dedicated reserves specified in a qualifying contract and identified in the application. The Crown interest and vintage of dedicated reserves is obtained from the stream ID. Where there is no reserve dedication*, or the royalty client fails to identify the reserve dedication in its application, deliveries under a contract are deemed to be supplied at the royalty client’s weighted average Crown interest and vintage calculated monthly as a composite factor which is the product of:

Royalty client’s total Crown Royalty Share (in GJ) of raw gas, residue gas and ethane for the production month

…divided by… Royalty client’s total Alberta production (in GJ) of raw gas, residue gas and

ethane for the production month

1.7 Calculation of the Gas Corporate Average Price

A royalty client who has a valid CAP election must determine and report its CAP annually by April 15th of the year following the year of production. (Refer to Ch. II, Sec. 3.4 and Ch. IV, Sec. 3.2). A.R. 220/2002 Sch.1 - S.9 (2) A royalty client’s CAP for a year is calculated as follows:

(Value of sales to non-associates at the plant gate netback value …plus…

Value of sales to associates valued at the associate’s CAP, netted back to the plant gate

…plus… Value of sales to associates where a CAP cannot be determined, valued at

the Gas Reference Price for the month in which the transaction occurs …plus…

Proprietary consumption and other "fair-value(1) transactions" valued at the Gas Reference Price in effect for the month in which the transaction is made)

…divided by… Total GJs of raw gas, residue gas and ethane included in the above transactions

Raw gas sales are included at actual netback value. Raw gas used as off-site fuel (which otherwise would require processing) or transferred to out of province gas plants for processing only (deemed as raw gas sales) is included in the royalty client’s CAP calculation at 80% of the Reference price. Ethane sales are included at actual netback value. (This does not include light ends.)



There should be no transportation cost deductions on gas used for proprietary consumption and valued at the Gas Reference Price. The Gas Reference Price is an average Alberta netback price after deductions for both intra and ex-Alberta transportation charges. Bad Debts are not allowable deductions in the calculations of the Gas Corporate Average Price. "Fair-value" transactions includes swaps* and exchanges*. The Department considers that a contract meets the definition of an exchange or swap whenever a person passes title of gas or gas products to another person in return for non-cash consideration, all or in part. Royalty clients should be aware this definition is all-inclusive and applies to transportation service contracts wherever and whenever the terms of the agreement provide for the exchange of products at one location for products at another location. NOTE: If raw gas is used as off-site fuel or is delivered to an out-of-province

facility for processing, this will be deemed as a raw gas sales and UOCR will not be allowed as a deduction in calculating Crown royalty.

1.7.1 Plant Gate Netback Value

The plant gate netback value for sales to non-associates is the sum of:

Value of sales transactions to non-associates …minus…

Intra-Alberta transportation costs incurred on the subject transactions (including demand

and reservation charges on pipelines in existence on December 31, 1993) …minus…

Ext-Alberta transportation costs incurred on the subject transactions (including demand and reservation charges on pipelines in existence on December 31, 1993) net of any

revenue from brokered transportation capacity

References to ‘demand and reservation charges’ relate to the standard firm service demand charges. In situations where a demand charge is a penalty for non-performance (there are no subject royalty transactions from which costs can be deducted) the cost will not be recognized as an allowable transportation cost deduction. Demand charges however for non-performance resulting from shipments of gas temporarily interrupted by normal field maintenance are allowable transportation costs. Transportation costs do not include costs for a sales line connecting the plant to a pipeline.



“Take or pay costs” are not allowable deductions in the calculation of the Gas Corporate Average Price. Sales to recognized aggregators are included in the netback price* plus the unit cost of intra-Alberta storage (aggregators must disclose the storage charge on invoices to suppliers). For the designated large aggregators, the actual amount of the OMAC-type charges may be deducted. For other recognized aggregators, the weighted average of OMAC-type charges for the large aggregators may be deducted. The Department will publish the weighted average of OMAC-type charges annually for the large aggregators. Marketing fees (the cost of marketing gas sold directly by producers) other than OMAC-type charges identified above are not allowable deductions in the calculation of the Gas Corporate Average Price. Proceeds from hedging transactions are not included in the CAP calculation. The Department’s policy is to exclude hedging gains and losses from the determination of Crown royalty share of residue gas. Hedging transactions are intended to reduce the risk of price changes or currency fluctuations with respect to the sale of gas or products. These are financial transactions that are separate and distinct from sales contracts requiring physical delivery of gas or products. If a sale contract is a fixed price contract but labelled a forward sale, the sales transactions could be included in the CAP calculation. However, if some aspect of the sale is hedged to minimize the effects of price swings to either the commodity or foreign exchange market it should be excluded. Brokered volumes are included at the actual sales value minus any actual transportation costs that have been incurred after the brokered volumes were acquired. The actual costs for the brokered volumes however cannot be deducted.

1.7.2 Sales to Associates Valued at the Associate’s CAP

Where sales to an Associate are valued at the Associate’s CAP, and that Associate is a United States-based corporation or ext-Alberta (within Canada) based corporation, the Associate’s CAP is calculated as:

(Value of sales from Associate’s total North American arm’s-length sales …minus…

Transportation costs incurred on those sales) …divided by…

Total GJs included in the same sales transactions



The total plant gate netback value for sales to this type of Associate is calculated as:

(Total GJs sold to the Associate …multiplied by… Associate’s CAP) …minus…

Intra-Alberta transportation costs incurred on the sales, where the costs are not included

in the Associate’s CAP calculation …minus…

Ext-Alberta transportation costs incurred on the sales, where the costs are not included

in the Associate’s CAP calculation

Where sales to an Associate are valued at the Associate’s CAP, and that Associate is an Alberta-based corporation, the Associate’s CAP is calculated in the same manner as the CAP of the royalty client.

1.7.3 Minimum Price for the Gas Corporate Average Price

A.R. 220/2002 Sch. 1 - S. 9 (3) The Department calculates the annual weighted average of Gas Reference Prices as:

The sum of values (monthly Gas Reference Price …multiplied by… [intra-Alberta consumption

...Plus... ext-Alberta deliveries, in GJ]) for each production month in the year …divided by…

The sum of volumes (intra-Alberta consumption ...plus.... ext-Alberta deliveries, in GJ) for all

production months in the year Price and quantity (GJ) data are taken from the information collected by the Ministry for the monthly Gas Reference Price calculation. The Department publishes the annual weighted average of Gas Reference Prices in Gas Royalty Calculation Information Bulletin on or before March 1st of the year, following production to which the prices relate.

1.7.4 Correcting the CAP for Adjustments to Sales or Costs

Where a royalty client receives adjustments to either the sales or costs relating to transactions that are included in the CAP calculation of a previous year, treatment of the adjustments will vary according to the circumstances of the case. If: • The recalculated CAP, including all adjustments for which the CAP has not

previously been changed, is greater or less than the unadjusted CAP by an amount equal to or greater than 5% of the unadjusted CAP; or



• The royalty client has subsequently elected to use the Gas Reference Price method in a year following the year to which the adjustment relates;

Then: • The royalty client must file a recalculated CAP for the adjusted year with the

Department; and • The Department will re-calculate and invoice a Crown royalty adjustment to the

royalty client; unless • The unadjusted CAP is less than 90% of the weighted average of Gas Reference

Prices for the year and the recalculated CAP is also less than 90%, in which case the Department will not invoice a Crown royalty adjustment.

If: • The recalculated CAP is within 5% of the unadjusted CAP, Then: • The royalty client must include the adjustments in the CAP calculation for the

year in which the adjustments are received; unless • The royalty client requests that the Minister adjust his CAP and recalculate

Crown royalty for the year to which the adjustment relates and the Minister approves the request, in which case the recalculation will be made.

1.8 Monthly Gas Corporate Average Price Estimate 1.8.1 Calculation of the Monthly CAP Estimate

Each royalty client with a valid CAP election calculates the CAP annually. The Department values and invoices each CAP royalty client’s monthly raw gas, residue gas and ethane Crown royalty share using an estimated CAP that is:

Gas Reference Price for the month …multiplied by…

the royalty client’s Corporate Gas Factor for the year A royalty client’s Corporate Gas Factor for a year is calculated as:

the royalty client’s CAP for the previous year …divided by…

the weighted average of Gas Reference Prices for the same year …subject to…

a minimum Corporate Gas Factor of 0.9

The Department calculates the Corporate Gas Factor and reports it to each royalty client who has a valid CAP election each year.



If a person becomes a new royalty client, and has a valid CAP election, the Department will set that royalty client’s Corporate Gas Factor for the first year at 1.0. Effectively, the Department will value and invoice that royalty client’s monthly raw gas, residue gas and ethane Crown royalty share in its first year as a royalty client using the Gas Reference Price. After the first year, the CAP client’s valuation price will be calculated as described above. For further information, refer to Ch. II, Sec. 3.4 and Ch. IV, Sec. 3.2.

Alberta Natural Gas Royalty Chapter III, Section 2-Valuing Gas Products Principles and Procedures, 2003

December 2004 Ch. III Sec.2 p.1

2. Valuing Gas Products 2.1 Valuing Crown Share of Ethane

The net unit price at which the Department values and invoices the monthly Crown royalty share of Ethane is the Ethane Reference less the transportation allowance for the Ethane. As the current time, the Ethane Reference Price is prescribed to be the same as the Ethane ISC Reference Price (see Appendix D for calculation details). The transportation allowance for the Ethane is determined by multiplying the Facility Royalty Trigger Factor minus 1 by the Ethane ISC AIATD (see Appendix E for calculation details).

2.2 Valuing Crown Share of Propane and Butanes 2.2.1 Valuation Criteria

The net unit price at which the Department values and invoices the monthly Crown royalty share of propane and butanes is:

Propane/Butanes Reference Price (subject to a Floor Price*) …minus…

Transportation (by region) …minus…

Fractionation Allowance*(for propane/butanes, contained in an NGL mix)

2.2.2 Propane and Butanes Reference Prices

The Department calculates Propane and Butanes Reference Prices as the weighted average of prices paid for non-field purchases of specification product in the Edmonton area. (Refer to the description of the Edmonton Area in Appendix Q). The monthly Propane Reference Price and Butanes Reference Price are calculated as follows:

total value of propane/butanes non-field purchase transactions reported in the month in the Edmonton area.

…divided by… total volumes reported for the same purchase transactions

Major purchasers of propane and butanes, designated by the Minister, provide price and volume information on the NGL-100 submission by the 10th day of the second month following the production month to which they apply. If the 10th day falls on a non-business day, the next business day will apply. For NGL-100 reporting instructions, refer to Appendix Q.


June 2003 Ch. III Sec.2 p.2

If the Department receives amendments to information filed by designated purchasers, for a previous period, the Department will: • Include the adjustments in calculating the Propane Reference Price and/or the

Butanes Reference Price for the month in which the amendments are received, up to a maximum of 2% (10% for January 1998 forward) of the respective Reference Price calculated before the adjustments are applied; and,

• Carry forward any amounts above the maximum to the following month(s).

Amendments that are reported and included as adjustments in this manner are those that result from reporting errors or omissions by the reporting company.

If the adjustments result from re-determinations or re-allocations by a Facility Operator, pipeline company, producer or customer, the reporting company includes these adjustments in its reports for the delivery month in which they are transacted, and not for the production month to which the adjustments apply. If the information required to calculate either the Propane Reference Price or the Butanes Reference Price, or both, is not received by the prescribed date, the Minister will determine the Reference Price(s). The Department publishes the Propane Reference Price and the Butanes Reference Price in an Information Letter on the 15th day of the second month following the production month to which the Reference Price applies. If the 15th day falls on a non-business day, then the next business day will apply. The Propane Reference Price and Butanes Reference Price established for a month will not change retroactively. The calculation of the Propane Reference Price and the Butanes Reference Price are subject to an independent audit conducted on behalf of the Petroleum and Natural Gas Industry.

2.2.3 Propane and Butanes Floor Prices

The Department calculates Floor Prices for propane and butanes to protect the Crown against inappropriately depressed prices in the Edmonton market. In any month where the Floor Price of either propane or butanes exceeds the Reference Price for the same product, and the Minister determines that there is no valid market reason for the disparity, the Reference Price(s) will be the same as the Floor Price(s). (Refer to Appendix E).

The Propane Floor Price is calculated from prices posted for specification propane at Conway, Kansas, netted back to Edmonton by deducting transportation and storage costs (using tariffs based on regular rates for four months and incentive rates for eight months each year). The Propane Floor Price is 90% of the price netted back from Conway.


December 2004 Ch. III Sec.2 p.7

2.4.3 Special Pentanes Processing Allowance

A.R. 220/2002 S. 6 (9)(c) The Department deducts a Special Pentanes Processing Allowance from the Pentanes Reference Price as part of its calculation of the price at which it will value the Crown Royalty Share of pentanes plus. This allowance is provided on a case-by-case basis, if approved by the Minister, for specified streams of pentanes, which are:

• Produced in significant quantities; • Forced to be strictly segregated in transportation and processing; • Extremely sour in nature; and, • Consistently valued at a price significantly less than the Pentanes

Reference Price. Royalty clients may request in writing to the Department for approval of Special Pentanes Processing Allowance. The Department publishes the Special Pentanes Processing Allowances in an Information Letter by the 15th day of the second month following the production month to which the allowances apply. If the 15th day falls on a non-business day, the next business day will apply. The Special Pentanes Processing Allowance established for a month will not change retroactively. NOTE: The Crown will review this allowance, and the qualification of the

streams for this allowance, periodically (Refer to Appendix N – Glossary for definition of special pentanes).

2.5 Valuing Sulphur 2.5.1 Monthly Reporting

All royalty clients having annual sulphur production of 30,000 tonnes or more (based on previous year’s production) must file VA4 submissions monthly to determine their Sulphur Corporate Average Price (S-CAP). The submission is filed on a “best efforts” basis, i.e., using the best information available at the time of filing. The Department notifies the royalty clients who are in this category. Amendments to VA4 submissions are not required but may be submitted to amend any production month(s) within the current production year. If you are amending previous production year(s), a VA3 must used. Those royalty clients whose annual sulphur production is less than 30,000 tonnes (based on previous year’s production) may choose to file VA4 submission monthly and then, must continue to file for the entire year. (Refer to Ch. IV, Sec. 4.2). The


June 2003 Ch. III Sec.2 p.8

Department values and invoices the Crown royalty share of sulphur production monthly using the royalty client’s S-CAP.For royalty clients who are not required and, therefore, choose not to file VA4 submissions, the Department will use a Sulphur Default Price to value the Crown royalty share of monthly sulphur production. A month’s Sulphur Default Price is the weighted average unit value of all arms’ length sales reported on the VA4 submissions by royalty clients. The Sulphur Default Price is also used in valuing monthly sulphur for provisional assessment. (Refer to Ch. III, Sec. 8.1.3). The VA4 submissions must be filed on or before the 15th day of the second month following the production month to which the S-CAP applies. If the 15th day falls on a non-business day, the next business day will apply.

2.5.1.1 Monthly Sulphur Corporate Average Price Calculation

A royalty client’s S-CAP for a month is calculated using the following for that month: Net revenue at the plant gate from arms’ length sales of Alberta gas-plant-produced sulphur

…divided by… *Total tonnes of sulphur included in the above transactions

…subject to… A minimum S-CAP of $0.00 (zero)

Royalty clients must report their own volumes of plant-produced sulphur. This does not include other producer's share of sulphur, if royalty clients are also marketing other producer's share of sulphur. If a royalty client’s VA4 results in a negative unit value, the price used will be $0.00; and the royalty client will be allowed to carry forward and add the volumes and values to the following month’s sales data to calculate that month’s S-CAP. The net revenue from sales of Alberta gas-plant-produced sulphur in a month is the:

value of sales of Alberta gas-plant-produced sulphur in the month …minus…

transportation cost incurred in the month for sulphur …minus…

costs incurred in the month for transportation-related storing, loading and handling of the sulphur (costs incurred in the month that are not eligible for “GCA”

Allowable Costs)

If a royalty client has no sales for a production month, the Department still requires the VA4 submission identifying no sales and will apply the monthly Sulphur Default price to that royalty client.

Alberta Natural Gas Royalty Chapter III, Section 3-Alberta’s Royalty Share of Cost Allowances Principles and Procedures, 2003


3.8 Re-Allocation of Capital Cost Allowance A.R. 220/2002 S. 20 (15) A royalty client may allocate the allowable capital costs that arise in relation to its facility capital costs to one or more royalty clients that are owners of that facility, own natural gas or gas products processed at that facility, or pay royalty compensation on behalf of an owner of that facility. The Department must receive the AC3 submission, allocating Capital Cost Allowance to other royalty clients, by May 15th of the year following the production year to which the costs relate. (Refer to Ch. IV, Sec. 5.3). The Department calculates the Crown share of Capital Cost Allowance payable to each royalty client for a production year as:

(total Capital Cost Allowance allocated from all Facility Cost Centres for the year

…minus… total Capital Cost Allowance allocated to other royalty clients for the year)

…multiplied by… royalty client’s Corporate Effective Royalty Rate for the year

3.9 Calculating Annual Unit Operating Costs

For the purpose of establishing unit operating cost rates facilities are classified as two types: • Designated Facilities* are those that:

• Include one or more facilities with an EUB-approved design capacity greater than 3,000 103m3 per day; and were operational at January 1, 1994. (Refer to the list of Designated Facilities provided in Appendix I).

• Plant Type Facilities* are those that:

• Were operational at January 1, 1994, and which have an EUB-approved design capacity that is 3,000 103m3 per day or less; and

• Facilities of any design capacity that becomes operational on, or after January 1, 1994.

A.R. 220/2002 S. 20 (12)(b) Operators of a Facility Cost Centre tied to the Designated Facility are required to report annual operating costs on the AC4 submission to the Department. The Department must receive an AC4 submission on or before March 31st of the year following the production year to which the costs relate. Operators of a Facility Cost Centre tied to a Plant Type Facility are not required to report operating costs to the department on an AC4 submission.

Alberta Natural Gas Royalty Chapter III, Section 3-Alberta’s Royalty Share of Cost Allowances Principles and Procedures, 2003


3.10 Annual Allowable Operating Costs

Annual allowable operating costs and non-allowable operating costs are described in Appendix H. The Minister may approve additions/deletions to the list of allowable costs or require additions/deletions to the list of non-allowable costs. Where such an addition/deletion is approved or required, the Department:

• Will announce the change in an Information Letter; and • Will include that change in the next update of the Guidelines.

The amount of an allowable operating cost is either: • The amount paid, net of any recoverable tax (e.g., GST), in an arm’s-

length transaction; or • The amount paid, net of any recoverable tax (e.g., GST), in a non-arm’s-

length* transaction if the Department agrees that the amount is fair.

3.11 Calculating Crown Share of Operating Cost Allowances

The Department calculates the Crown share of Operating Cost Allowances monthly. They are calculated separately for each royalty client at each EUB facility through which the royalty client gathers, compresses or processes gas and gas products. A royalty client’s monthly Crown share of Operating Cost Allowances for an EUB facility is calculated as:

Royalty client’s Crown royalty share of energy adjusted gas equivalent volumes

at the plant gate of the EUB facility for the month (including gas and products sent to approved injection and cycling schemes)

…multiplied by… unit operating cost rate for the EUB facility in the month

A royalty client’s total Operating Cost Allowances for a month is the sum of the calculated Crown share of Operating Cost Allowances for all of the EUB facilities in which the royalty client participates.

3.12 Unit Operating Cost Rates

The Department calculates Unit Operating Cost Rates in the production year to which they apply. There are two types of Unit Operating Cost Rates (UOCR): • Designated Facility Rates — one unique UOCR for each Designated Facility

that is operational in the year; and • Plant Type Rates — one unique UOCR for each of the five plant types, as

follows:

Alberta Natural Gas Royalty Chapter III, Section 4-Other Programs Administered with Natural Gas Royalty Principles and Procedures, 2003

December 2003 Ch.III, Sec.4 p.1

4 Other Programs Administered with Natural Gas Royalty

4.1 Valuing and Reporting Field Condensate The monthly Crown royalty share of field condensate is valued using the Pentanes Reference Price in effect for the production month, reduced by the applicable Transportation Allowances for pentanes plus, propane, and butane contained in a natural gas liquids mix. Chapter III, Sec. 2.3.2 provides a description of the business rules for Pentanes Reference Price. Chapter III, Sec.2.4.1 provides a description of the business rules for Regional Transportation Allowances. The following process is in effect until the calculation of condensate royalty is automated and included in the monthly Crown Royalty invoice, as part of future enhancements: • The Department determines the monthly Crown royalty share of condensate

under Schedules 2 and 3 of the Petroleum Royalty Regulation and values it using the Pentanes Reference Price in effect for the production month, reduced by the applicable regional transportation allowance for pentanes plus, propane, and butane contained in a natural gas liquid mix.

• The Condensate Royalty Invoice is issued by the last day of the second month following the production month. Payment is due on or before the last day of the third month following the production month. For example, the invoice for production month of January 2002 will be issued by March 31, 2002. Payment will be due April 30, 2002. Interest is charged on late payments from the due date.

• Each operator receives one invoice for all the batteries they operate, together with documentation supporting the condensate royalty calculation, including a production report for the wells in each battery, and a Royalty Share Calculation report for each battery.

4.1.2 Allowable Costs for Field Condensate There are no Allowable Costs applicable to field condensate, as no compressing, gathering or processing will have taken place.

4.2. Sulphur Emission Control Assistance Program (SECAP) Royalty clients participating in the Sulphur Emission Control Assistance Program will see the benefit granted under SECAP as a line item appearing on the royalty client’s royalty invoice under the Credits portion of the invoice.



4.2.1 Application Procedures The plant operator may apply for SECAP by completing the application form, (Form 595) after receiving approval from the EUB to build a new facility or utilize an eligible process in an existing facility. (Refer to Ch. IV, Sec. 6.1). The SECAP application should be sent directly to the attention of:

Manager, Royalty Billing Gas Development Alberta Energy Petroleum Plaza, North Tower 8th Floor, 9945 – 108 Street Edmonton, Alberta T5K 2G6

To expedite the approval process and prior to the actual SECAP submission, a process flow diagram and site diagram (including mass flow and stream composition) of the sulphur emission control equipment and connected facilities should be submitted to the department. The approved processes will be identified to the SECAP applicant prior to the supporting documentation submission date. Royalty clients may also submit plans to be reviewed by the Department for new capital expenditures relating to SECAP prior to actual capital outlays. Approved eligible processes will be identified and confirmed to be eligible for SECAP credits. The following supporting documentation for the approved processes must be submitted with Form 595 to be considered complete: • A detailed listing of major equipment with an original cost in excess of

$100,000.00; • Approval For Expenditures (AFE’s); • Copies of invoices, purchase orders and work orders in support of all items

where the individual cost exceeds $1,000.00 for the approved processes; • Identification of the major equipment that each expense claimed for additions,

repairs or maintenance relates to; • A detailed listing of major chemicals used in the approved process; • Allocation percentages for common costs claimed for SECAP (including but not

limited to heat, power, fuel, electricity and plant turnaround costs). Include a brief description of the cost allocation methodology and provide supporting data for the allocations.

Incorrect applications or incomplete applications will be returned. Resubmission of returned applications must be received within the required timeframes as outlined in the Benefits section of the guidelines for capital cost



expenditures and operating costs. An application for extension of these deadlines must also be received within this timeframe.

4.2.2 Eligible Equipment Sulphur Recovery Facilities • Only sulphur facilities that recover sulphur from the acid gas stream by

oxidation are eligible. Examples of eligible facilities are the Claus, Sulfeen and Lo-Cat units. Dehydration and Amine Unit processes are non-eligible;

• Equipment for use in an approved process at the eligible plant; • Sulphur recovery requirement for small gas plants: Facilities are required to

remove at least 70% of equivalent sulphur from the acid gas stream; • Sulphur recovery requirements for large grandfathered plants: Sulphur recovery

equipment must increase sulphur recovery and achieves the sulphur recovery criteria established by the EUB in ID 2001-3.

Acid Gas Disposal Facilities • Where the acid gas is removed at the eligible plant, certain facilities for the

injection of acid gas into an underground formation are eligible. This includes incremental costs of converting production wells and related facilities to acid gas injection;

• Pipeline and related facilities, where acid gas removed at the eligible plant is transported by pipeline from the eligible plant to another plant for processing;

• Only acid gas disposal facilities that achieve the sulphur recovery criteria established by the EUB are eligible.

4.2.3 Eligible Costs

The department will assess the reasonableness of all costs in determining eligible costs. Eligible costs include: • Capital and operating costs incurred for equipment used in an eligible process. • Capital costs must be incurred before costs are eligible; • Approved equipment must be installed and operational before costs are eligible. • Capital Costs incurred between May 1, 2001 and May 1, 2006 that increases

sulphur recovery for equipment used in an eligible process at a large grandfathered gas plant;

• Costs incurred by the original purchaser for transactions among connected parties;

• Cost of conversion of existing equipment is eligible if equipment is dedicated to the approved process;

• Cost of used approved equipment will be determined on a fair market value basis;


June 2003 Ch.III, Sec.4 p.4

• If existing sulphur emission control equipment is replaced the cost of new equipment, less salvage value of old, is eligible;

• For small gas plants, expenses incurred in operating and maintaining approved equipment that handles the acid gas stream, including labour, materials, parts and supplies. Large grandfathered gas plants are not eligible for operating costs.

Eligible capital costs and operating costs for approved equipment shall be reduced by the extent of: • Amounts reimbursed under the policy of insurance; • Salvage value of equipment replaced by new approved equipment; • Any grant or benefit provided by Government of Alberta or the Government of

Canada or any agency of either Government if the Minister is satisfied that the grant or benefit is referable to the approved equipment in whole or in part or referable to the operation or maintenance of the approved equipment.

4.2.4 Non-Eligible Costs

Include but are not limited to the following: • Capital costs that have not been approved by the DOE as part of the eligible

process; • Capital costs, repairs and maintenance, chemical waste disposal and waste pits,

and turnaround costs relating to an unapproved process. (e.g. amine unit, dehydration process);

• Operating costs related to non-eligible capital costs; • Capital costs of equipment at an approved plant that has not commenced

operation; • Capital costs or operating expenses that are not actually incurred; • Administration, management or financing costs; • EUB Administration fees; • Depreciation; • Cost of borrowed money that is deductible from income under Section 21 of the

Income Tax Act (Canada); • Amounts that would be deductible under the Income Tax Act (Canada) or the

Income Tax Regulations under the Act as a capital cost of property; • Capital costs/operating expenses claimed under the Allowable Cost program.

(The operator must select either SECAP or Allowable Costs. The operator’s decision on the choice of program will be final);

• Expenses incurred for salaries or benefits paid to an employee or fee payable to a contractor for services that are not directly related to the operation and maintenance of the approved equipment for the acid gas stream;

• Property taxes; • Insurance for property or vehicles; • Capital costs relating to road, bridges, walkways and fences;


June 2003 Ch.III, Sec.4 p.5

• Operating costs relating to road lease maintenance; • Indirect charges or deemed allocations from Head Office or other ex-plant gate

locations; • Soil monitoring/testing not specifically related to the acid gas stream; • Mobile telecommunication equipment; • Sulphur block and sulphur pit; • Sulphur loading facilities; • Incinerators and flare stacks; • Noise abatement testing expenses; • Operating expenses that may be regarded as having occurred by or for the

benefit of the gas plant owner in relation to approved equipment in respect of: • The use of property in which another person has an interest and with

whom the operator, the gas plant owner or any co-owner of the gas plant is connected;

• The acquisition of any materials, parts or supplies from another person with whom the operator, the gas plant owner or any co-owner of the gas plant is connected;

• The payment of compensation for the performance of a service for his benefit by any other person with whom the operator, the gas plant owner or any co-owner of the gas plant is connected to the extent that the expense exceeds the least of those amounts, each of which is the aggregate of the expenditures incurred by another person with whom the operator, the gas plant owner or any co-owner of the gas plant is connected.

4.2.5 Connected Person

A person is connected to another person if: (i) The person and that other person are not dealing at arm’s length; (ii) The person has an equity percentage in that other person that is not less than

10% or; (iii) Where the person is a corporation, the corporation and the other person are

linked by another person who has an equity percentage in each of them of not less than 10%.

Information regarding eligible facilities and eligible processes can be obtained by contacting:

Manager, Royalty Billing Gas Development Alberta Energy Petroleum Plaza, North Tower 8th Floor, 9945 – 108 Street Edmonton, AB T5K 2G6 Telephone: (780) 422-6684

Alberta Natural Gas Royalty Chapter III, Section 7-Levying and Collecting Natural Gas Royalty Principles and Procedures, 2003


7 Levying and Collecting Natural Gas Royalty

7.1 Levy and Collection - Overview

The Department will establish a Gas Account for each royalty client. Charges will be recorded in the client’s Gas Account for the following:

• Royalty is the net royalty amount due as described on the monthly Invoice; • Royalty Deposit is the royalty client's royalty deposit and any adjustments to the

deposit as described on the monthly Invoice; • Interest is the prior period and current period interest charges as described on the

monthly Invoice and the Statement of Account; • Penalties are the monthly and annual penalty charges levied against a royalty client as

described on the monthly Invoice; • Fees for services provided by the Department may be charged, as described on the

monthly Invoice. The Department will submit a Statement of Account, an Invoice and Crown Royalty Detail statements to each royalty client for each billing period in which there are gas royalty transactions or in which the royalty client has other than a "zero balance" in his Gas Account with the Department. The Department will issue the Invoice and the Crown Royalty Detail statements to each royalty client on or before the last day of the second month following each production month. The Department will issue separately the Statement of Account to each royalty client on or before the 15th day of the third month following each production month. Royalty clients are liable for payment of the amount owed to the Crown on each invoice received from the Department on or before the last calendar day of the third month following the production month to which the invoice relates. If the due date falls on a non-business day, payments will be accepted on the next business day. NOTE: The December production month invoice issued in February is due on or

before the Department’s last business day in March. A description of the business rules relating to royalty client accounts, application of payments, interest payable/receivable, and account collection is provided in Ch. II, Sec. 6.

Alberta Natural Gas Royalty Chapter III, Section 7-Levying and Collecting Natural Gas Royalty Principles and Procedures, 2003


7.2 Preparing a Payment Remittance

METHOD OF PAYMENT There are four methods for remitting Crown natural gas royalty payments:

• By cheque, through the mail, or by courier; • By direct deposit, using a Rapidtrans deposit slip; • By electronic funds transfer; or • By automatic debit.

A payment remittance that is less than $5,000 may be made using any one of the four methods. A payment remittance that is $5,000 or more must be made by either direct deposit, automatic debit, or electronic funds transfer. All remittances must be made payable to the Minister of Finance, Province of Alberta. Remittances by direct deposit must be made using a Rapidtrans deposit slip (a sample of the Rapidtrans deposit slip and the bank locations at which they may be used is provided in Appendix K). Remittances made by electronic funds transfer must be directed to the account of the Minister of Finance, Account 09-35603, at the Canadian Imperial Bank of Commerce. Clients electing to remit payment by automatic debit submissions must sign an agreement with the Department. (Refer to Appendix K, for a Pre-Authorized Automatic Debit Payment Agreement sample). The deadline for an automatic debit submissions to the Department, is the 5th last business day of a month. Rapidtrans deposit slips may be obtained from the Department by contacting the Gas Royalty Calculation Unit or the Calgary Information Centre at the address or telephone number listed in Appendix L. INFORMATION REQUIRED The following information is required in remitting payment:

• Payment date; • Name of the payer; • Name of each royalty client on whose behalf the payment is made; • The four-character client ID assigned by the Department to that royalty client; • Account code and associated account number assigned by the Department to that

royalty client to which the payment is to be credited, “G94 XXXXXX" (refer to Appendix J, for a list of applicable revenue account codes);

• Dollar amount of the payment or payments (if remittance is made on behalf of the royalty client for more than one revenue account, each account code, number and payment must be listed separately); and

Alberta Natural Gas Royalty Chapter IV, Section 2-Volumetric Reporting of Mineral Activity Principles and Procedures, 2003

June 2003 Ch. IV, Sec.2 p.11

2.3 Registering a Single Well or Injection Scheme RMF3 FORM - SINGLE WELL/INJECTION SCHEME SETUP/CHANGE PURPOSE Facility Operators must use the RMF3 to register the initial set-up, change the set-up, or terminate:

• A Well (a single well event) that has a Crown interest greater than 0% but less than 100%;

• A Non-Consolidated Well Group consisting of Joint Operating Agreements, Non-Unit Gas, Non-Unit Spacing, Non-Unit Oil (solution gas), and projects that have Crown interest of greater than 0% but less than 100%; or

• An Injection Scheme.

For the single well portion of the RMF3, the form is not required if all the working interest owners’ Crown percentage* is the same as the well(s)'s Crown percentage. A description of the business rules governing the responsibility to register a Well/Well Group is provided in Ch. II, Sec. 1.6.1. A description of the business rules that must be satisfied to establish an Injection Scheme is provided in Ch. II, Sec. 1.5. TIMING A completed RMF3 form must be received by the Department on or before the last day of the month following the production month to which the form applies. CONSEQUENCES OF NON-COMPLIANCE The RMF3 form will not be processed if a Facility Operator fails to satisfy the reporting requirements for registering a Well/Well Group or Injection Scheme. AMENDING A SINGLE WELL/WELL GROUP/INJECTION SCHEME SETUP/CHANGE

• For amendments to Single Well or to Non-Consolidated Well Group information, Parts 1 and 2 must always be completed in full.

• For amendments to Injection Scheme information, Part 1 must always be completed in full and Parts 3 and 4 must be completed as required.

Alberta Natural Gas Royalty Chapter IV, Section 2-Volumetric Reporting of Mineral Activity Principles and Procedures, 2003

December 2004 Ch. IV, Sec 2 p.12

RMF3 FORM - COMPLETION INSTRUCTIONS PART 1: CLIENT INFORMATION THIS SECTION OF THE FORM MUST BE COMPLETED FOR ALL RMF3 SUBMISSIONS. 1.1 OPERATOR ID - The four-character EUB operator code that identifies

the Facility Operator submitting the form. 1.2 OPERATOR NAME - The full name of the Facility Operator whose

code appears in field 1.1.

1.3 DATE PREPARED - The numeric year, month, and day on which the RMF3 form is prepared.

1.4 CONTACT PERSON - The name of the person whom the Department

can contact concerning the information on the form.

1.5 TELEPHONE - The telephone number, including area code of the contact person.

PART 2: WORKING INTEREST OWNERSHIP (W.I.O.)* This section of the form:

• Must be completed for all single wells and injection schemes that have a Crown interest of greater than 0% but less than 100%;

• Must be completed for joint operating agreements (JOAs), non-unit gas, non-unit spacing, non-unit oil (solution gas), and projects that have less than 100% Crown.

• Is not required to be completed if all the working interest owners' Crown interest is the same as that of the well's or injection scheme's Crown interest.

2.1 STREAM ID - The identifier assigned by the EUB or the Department to

the Well Event or Well Group (WG) (explained above) that is the subject of the report. The first four letters comprising the Provincial Code and Stream ID type must be indicated before the identification code.

2.2 UPDATE CODE - Enter a "1" in this field if the form is submitted to set up a new Well or Well Group or a "2" if the form is submitted to change or terminate an existing Well or Well Group.

Alberta Natural Gas Royalty Chapter IV, Section 3-Valuing Raw Gas, Residue Gas and Ethane Principles and Procedures, 2003

December 2004 Ch. IV, Sec.3 p.7

• END-USER - a company that purchases gas for the purpose of consumption*, either as fuel or as a raw material in its business operations, and which is not an aggregator, a marketer or a producer.

2.2 GROSS ANNUAL SALES VALUE - Total value (in Canadian dollars)

from the sales reported in column 2.1, by type of purchaser. Storage costs deducted in the netback price paid by an aggregator must be added back to the value of the sale.

2.3 TRANSPORTATION · INTRA-ALBERTA - Total cost incurred by the

royalty client to transport the gas reported in column 2.1 within Alberta, including demand charges and CO2 extraction management service fees.

2.4 TRANSPORTATION · EX-ALBERTA - Total cost incurred by the

royalty client to transport the gas reported in column 2.1 outside Alberta, including demand charges, net of any revenue received from brokered pipeline capacity.

2.5 NET ANNUAL SALES VALUE - The sum (Gross Annual Value of

Sales …minus…intra-Alberta Transportation …minus… ex-Alberta Transportation) by type of purchaser for all sales reported in column 2.1.

PART 3: SALES TO ASSOCIATES (WITH A CAP) 3.1 CLIENT ID - The four-character client ID for the person who is an

associate of the royalty client. 3.2 CLIENT NAME - The full name of the person who is an associate of the

royalty client.

3.3 TOTAL GJs - Total sales (in gigajoules) to each associate who is identified in columns 3.1 and 3.2 during the production year, which is to be valued at that associate's CAP.

3.4 CAP - The Gas Corporate Average Price of each associate identified in

columns 3.1 and 3.2. If an associate is not a royalty client, attach a schedule (using the non-royalty client's VA2 form) substantiating the CAP calculation. If the associate is a royalty client, the Department will verify that associate’s CAP based on his VA2 submission. The business rules for calculating the CAP of an associate are described in Ch II, Sec. 3.4.

3.5 TOTAL VALUE - The product of (Total GJs …multiplied by… CAP) for

each associate.

Alberta Natural Gas Royalty Chapter IV, Section 3-Valuing Raw Gas, Residue Gas and Ethane Principles and Procedures, 2003

June 2003 Ch. IV, Sec.3 p.8

PART 4: OTHER DISPOSITIONS 4.1 TYPE 1 - Total gas sales (in gigajoules) during the production year, by

month, to all associates who do not have a CAP. The business rules for determining whether or not an associate must calculate a CAP are described in Ch. II, Sec. 3.4.2. A royalty client who is uncertain about valuing sales to associates should seek an advance ruling from the Department.

4.2 TYPE 2 - Total gas (in gigajoules) used for proprietary consumption

(including raw gas) during the production year, by month, by the royalty client in their operations. Consumed means gas used as fuel in an industrial process.

4.3 TYPE 3 - Total gas otherwise disposed of (in gigajoules) during the

production year, by month, without an arm’s-length sales transaction.

4.4 TOTAL GJs - The sum of Type 1 ...plus... Type 2 ...plus... Type 3 "Other Dispositions" [in gigajoules] for each month during the production year.

4.5 REFERENCE PRICE - The published Gas Reference Price for each

month during the production year. See monthly Gas Royalty Information Bulletin.

4.6 TOTAL VALUE- The sum of the product (Total GJs ...multiplied by...

Reference Price) for each month of the production year.

PART 5: CAP CALCULATION

5.1 $ PER GJ - The total value of (sum of all values shown in columns 2.5, 3.5 and 4.6) …divided by… the total quantity (sum of all gigajoules shown in columns 2.1, 3.3 and 4.4), calculated to the nearest one-tenth of a cent.

PART 6: CERTIFICATION

6.1 AUTHORIZED SIGNATURE - The signature of the authorized signing

officer for the royalty client who is responsible for the information submitted.

6.2 NAME OF CORPORATE SIGNING OFFICER - The full name of the

authorized signing officer whose signature appears in field 6.1. 6.3 TITLE OF CORPORATE SIGNING OFFICER - The position title of the

authorized signing officer whose signature appears in field 6.1. 6.4 DATE - The date on which the authorized signing officer signed the VA2

form. Form provided for illustration purposes only. All required forms are provided in Appendix P.

Alberta Natural Gas Royalty Chapter IV, Section 5 Alberta’s Royalty Share of Allowable Costs Principles and Procedures, 2003

November 2004 Ch. IV, Sec.5 p.13

5.2.1 Preparing an Annual Capital Cost Allowance Report for Production Years 1997 through 2003

AC2-V2 FORM - CAPITAL COST ALLOWANCE

PURPOSE Operators of Facility Cost Centres (FCC Operators) must use the AC2-V2 form to report: a) Changes in the allowable capital cost at a Facility Cost Centre over a production

year; b) Calculation of Capital Cost Allowances for a Facility Cost Centre for a

production year; and c) Allocation of the Capital Cost Allowances for a production year to the royalty

clients at the Facility Cost Centre.

For b) and c), the FCC operator should submit the AC2-V2 form as at December 31st of the production year. A description of the business rules associated with determining changes to allowable capital costs and calculating Capital Cost Allowances is provided in Ch. III, Sec.3.4 - 3.8. FULLY DEPRECIATED FCC Facility Cost Centre (FCC) Operators must continue to file AC2 forms even after the RUL of the FCC becomes zero. As long as an FCC is active, AC2 forms are required to identify Capital Cost Allowance Distribution Percentages and Custom Processing Adjustment Factors for the FCC. Filing AC2 forms will also prevent operating cost recaptures for those royalty clients who have an ownership interest in the FCC. Capital additions to a fully depreciated FCC will be amortized over a deemed useful life of one year. Clients should consider setting up additional FCC codes if a major capital expansion is added at a previously depreciated facility for the purposes of processing new reserves. The RUL for the new FCC would be based on the new reserves in accordance with Ch. III, Sec.3.5. NEW FCC PROCEDURES In order to ensure that annual capital costs are calculated correctly for new facility cost centres, the following procedures must be followed: Eligible capital costs incurred prior to start-up for any new FCC should be entered in both fields 2.1 and 2.2. If amounts are transferred from previous FCC(s), field 2.1



should include the Cumulative Allowable Capital, Dec 31 (field 2.4) and field 2.2 should include the Allowable Capital Cost After Depreciation, Dec 31 (field 2.7) balances from the last AC2 filed prior to termination of the previous FCC. Capital additions coded in this manner must be clearly identified in Part 3 and must not be included in field 2.3. For new FCC’s, Part 3 should include a detailed breakdown of capital expenditures including Authorization For Expenditures (AFE) identification where possible. Eligible capital costs incurred subsequent to start-up for any new FCC should be included in field 2.3 only. If amounts are transferred from an existing FCC that is not terminated, the transferred capital must be clearly identified in Part 3 and must be included in field 2.3. The corresponding capital must also be removed from the existing FCC at the same time. NOTE: Operating costs will not be allowed as a deduction on raw gas sales

that are eligible for 80% Gas Reference Price valuation. TIMING The Department must receive a system acceptable AC2-V2 form on or before April 30th of the year following the production year to which the form relates. CONSEQUENCES OF NON-COMPLIANCE The penalty for failing to file an AC2-V2 Form by its due date is a penalty of $100 per month or part of a month until the form is received. If the form is not received, no capital cost allowance will be allocated to the Facility Cost Centre for the production year to which the form relates. The Department will grant a 15 days grace period for penalty levy if the AC2-V2 form was received on or before April 30th of the year following the production year to which the form relates but was rejected because of MRIS edits, and the corrected system acceptable AC2-V2 form is received with in the grace period. Refer to Ch. II, Sec 7.3. ELECTRONIC SUBMISSION OF AC2-V2 The functionality to submit and receive AC2-V2 data electronically through the Electronic File Transfer process is available to clients. A copy of the Handbook on Electronic File Transfer is available on the Department of Energy Internet site. The Handbook addresses the AC2-V2 electronic file transfer business and technical processes, business rules, administrative, technical requirements, and validation edits details for electronic filing.



5.2.2 Preparing an Annual Capital Cost Allowance Report for Production Years 2004 and Onwards

AC2-V3 FORM - CAPITAL COST ALLOWANCE

PURPOSE Operators of Facility Cost Centres (FCC Operators) must use the AC2-V3 form to report: a) Changes in the allowable capital cost at a Facility Cost Centre over a production

year; b) Calculation of Capital Cost Allowances for a Facility Cost Centre for a

production year; and c) Allocation of the Capital Cost Allowances for a production year to the royalty

clients at the Facility Cost Centre.

For b) and c), the FCC operator should submit the AC2-V3 form as at December 31st of the production year. A description of the business rules associated with determining changes to allowable capital costs and calculating Capital Cost Allowances is provided in Ch. III, Sec.3.4 - 3.8. FULLY DEPRECIATED FCC Facility Cost Centre (FCC) Operators must continue to file AC2 forms even after the RUL of the FCC becomes zero. As long as an FCC is active, AC2 forms are required to identify Capital Cost Allowance Distribution Percentages and Custom Processing Adjustment Factors for the FCC. Filing AC2 forms will also prevent operating cost recaptures for those royalty clients who have an ownership interest in the FCC. Capital additions to a fully depreciated FCC will be amortized over a deemed useful life of one year. Clients should consider setting up additional FCC codes if a major capital expansion is added at a previously depreciated facility for the purposes of processing new reserves. The RUL for the new FCC would be based on the new reserves in accordance with Ch. III, Sec.3.5. NEW FCC PROCEDURES In order to ensure that annual capital costs are calculated correctly for new facility cost centres, the following procedures must be followed:



Eligible capital costs incurred prior to start-up for any new FCC should be entered in both fields 2.1 and 2.2. If amounts are transferred from previous FCC(s), field 2.1 should include the Cumulative Allowable Capital, Dec 31 (field 2.4) and field 2.2 should include the Allowable Capital Cost After Depreciation, Dec 31 (field 2.7) balances from the last AC2 filed prior to termination of the previous FCC. Capital additions coded in this manner must be clearly identified as Start-up Costs (CODE "S") in Part 3 and must not be included in field 2.3. For new FCC’s, Part 3 should include a detailed breakdown of capital expenditures including An Authorization For Expenditure (AFE) where possible. Eligible capital costs incurred subsequent to start-up for any new FCC should be included in field 2.3 only. If amounts are transferred from an existing FCC that is not terminated, the transferred capital must be clearly identified as Transfers (CODE "T") in Part 3 and must be included in field 2.3. The corresponding capital must also be removed from the existing FCC at the same time. NOTE: Operating costs will not be allowed as a deduction on raw gas sales

that are eligible for 80% Gas Reference Price valuation. TIMING The Department must receive a system acceptable AC2-V3 form on or before April 30th of the year following the production year to which the form relates. CONSEQUENCES OF NON-COMPLIANCE The penalty for failing to file an AC2-V3 Form by its due date is a penalty of $100 per month or part of a month until the form is received. If the form is not received, no capital cost allowance will be allocated to the Facility Cost Centre for the production year to which the form relates. The Department will grant a 15 days grace period for penalty levy if the AC2-V3 form was received on or before April 30th of the year following the production year to which the form relates but was rejected because of MRIS edits, and the corrected system acceptable AC2-V3 form is received with in the grace period. Refer to Ch. II, Sec 7.3. ELECTRONIC SUBMISSION OF AC2-V3 The functionality to submit and receive AC2-V3 data electronically through the Electronic File Transfer process is available to clients. A copy of the Handbook on Electronic File Transfer is available on the Department of Energy Internet site. The Handbook addresses the AC2-V3 electronic file transfer business and technical processes, business rules, administrative, technical requirements, and validation



edits details for electronic filing. This filing option is non-mandatory. However, facility operators who wish to submit the AC2-V3 form electronically, either for themselves or through contract operators and service providers must comply with the business rules stated in the Handbook. All electronic files received by midnight of the 30th of each month are processed and reflected in the next month’s issue of the Gas Royalty Invoice Process Overview • The Department will accept either manual or direct electronic receipt of AC2-V3

with Industry direct electronic data submission costs to be borne by Industry. • All Royalty Clients have the option of submitting the AC2-V3 data

electronically. If a company chooses to submit the AC2-V3 form in this manner, it must do so for all future production years.

• For electronic AC2-V3 data submission by Industry, the Department will transmit data back electronically.

• For electronic submission of form data: • Industry will transfer a file housing AC2-V3 data via File Transfer

Protocol (FTP) to the Department. • The Department will process file data nightly (except during invoice

run – 5 days). • The Department will send an email to the FCC operator (the individual

responsible for submitting AC2-V3 form) to allow the operator to check file status in the company output directory on the Department’s FTP site.

• Output directory on the Registry will contain either a Turnaround Document (for accepted data) or Rejection Notices (for rejected data).

AMENDING AN ANNUAL CAPITAL COST ALLOWANCES REPORT An amended AC2-V3 form must be completed in full in the same manner as an initial AC2-V3 form.

AC2-V3 FORM - COMPLETION INSTRUCTIONS PART 1: IDENTIFICATION 1.1 FACILITY CODE

• PROV. - the province in which the facility is located; Alberta (AB). • EUB FAC. TYPE - the type of facility; gas plant (GP) or gathering

system (GS). • EUB FACILITY CODE - the unique 7-digit code assigned by the EUB,

which identifies the facility.



RETURN ON AVERAGE CAPITAL

2.8 AVERAGE CAPITAL - The sum of (Allowable Capital Cost, January 1

shown in field 2.2 ...plus... Allowable Capital Cost After Depreciation, December 31 shown in field 2.7) ...divided by... 2.

2.9 LAND - The original capital cost of the site on which the Facility Cost

Centre is located. Land costs refer only to land that was purchased and does not relate to leases or surface rights access costs. (For allowable cost purposes, the value of land does not change.)

2.10 AVERAGE SPARE PARTS INVENTORY - The sum of (spare parts

inventory at the beginning of the period ...plus... spare parts inventory at the end of the period) ...divided by... 2. Spare parts inventory must be determined annually and reflect the actual purchase cost of the inventory.

2.11 TOTAL - The sum of Average Capital (field 2.8) ...plus... Land (field 2.9)

...plus... Average Spare Parts Inventory (field 2.10).

CAPITAL COST ALLOWANCE 2.12 RETIREMENTS - Enter the absolute (positive) amount for retirements

(CODE "R") included in field 3.4. 2.13 DEPRECIATION - Enter the amount shown as Depreciation /12 at field

2.6. 2.14 RETURN ON AVERAGE CAPITAL /12 - Total Average Capital (field

2.11) ...multiplied by... 0.15 (15% rate of return).

If the Facility Cost Centre started operations at other than January 1st, or terminated operations at other than December 31st of the production year, enter the number of months of operation in the space provided ( /12) and multiply the product obtained in the above calculation by the resulting fraction (e.g., 9/12).

2.15 CAPITAL COST ALLOWANCE - The sum of Retirements (field 2.12)

...plus... Depreciation (field 2.13) ...plus... Return on Average Capital (field 2.14).

2.16 REMAINING USEFUL LIFE (Years) - Indicate the remaining useful life

of the Facility Cost Centre in years. FCC operators must continue to file AC2 forms even after the remaining useful life of the FCC becomes zero, if the FCC is still active.



PART 3: CAPITAL ADJUSTMENTS (AMOUNTS MUST BE TO THE NEAREST

DOLLAR) 3.1 DESCRIPTION OF ADJUSTMENTS - A description of each allowable

capital addition, disposition, retirement, transfer or start-up cost by significant category. Small additions should be grouped under the heading "miscellaneous."

If the AC2-V3 form is for a new facility, capital adjustments must indicate the descriptions of the start-up costs shown as Cumulative Allowable Capital, January 1st, or in field 2.1, as well as capital additions, dispositions, retirements and transfers after the commencement of the operation. If the space provided is not sufficient, attach a continuation page.

3.2 FCC CODE - The Facility Cost Centre code(s) related to the amount(s) for transfers (CODE "T") included in field 3.4.

3.2 TYPE - For each item entered in field 3.1; identify the type of transaction

as Addition (A), Disposition (D), Retirement (R), Transfer (T) or Start-up Cost (S).

3.3 AMOUNT OF CAPITAL ADJUSTMENTS - Enter the actual cost of each

Capital Addition, Transfer or Start-up Cost, or net book value of each Disposition or Retirement described in field 3.1. (Start-up Costs and Capital Additions are positive, while Transfers may be either positive or negative. Dispositions and Retirements are negative.)

3.4 TOTAL - Enter the sum of all of the allowable costs entered in field 3.4,

including the allowable costs recorded on any attached schedule that may be required.

NOTE: Please state, “continuation page(s) are attached”, on the bottom line

of field 3.1, if applicable. PART 4: CAPITAL COST ALLOWANCE ALLOCATIONS 4.1 CLIENT ID - The four-character client ID assigned by the Department to

the owner or designated royalty client to whom capital cost allowances is allocated.

4.2 CLIENT NAME - The full name of the owner or designated royalty client

who’s Client ID appears in field 4.1.

December 2004 Appendix D-1

GAS REFERENCE PRICE

INTRA-ALBERTACONSUMER

PRICE

EX-ALBERTA BORDER

PRICE

INTRA-ALBERTACONSUMPTION

WEIGHTEDAVERAGE PRICEOF ALBERTA GAS

EX-ALBERTA DELIVERIES

INTRA-ALBERTATRANSPORTATION

VALUATIONPOINT

ADJUSTMENT

AGGREGATOROMAC

ADJUSTMENT

WEIGHTED AVERAGEMARKETINGALLOWANCE

less

less

equals

AVERAGE FIELD NETBACK PRICE

PIPELINE FUEL/LOSS FACTOR

GAS REFERENCE PRICE

ADJUSTMENTS FOR PRIOR PERIODAMENDMENTS FOR THE MONTH

multiplied by

plus or minus

equals

PRODUCER DIRECT

MARKETING ALLOWANCE


1. For ex-Alberta transactions, actual transportation costs net of any revenue resulting from brokered capacity (including demand and reservation charges) are deducted from sales value to determine the value reported at the export point. For ex-Alberta Gas Local Distribution Companies (LDCs) actual intra-Alberta transportation costs net of any revenue resulting from brokered capacity are added to intra-Alberta purchase value to determine the value reported at the export point.

2. The allowances for transporting gas in Alberta are: • a deduction for intra-Alberta transportation fees, and • a factor to recognize the costs of pipeline fuel consumption and gas loss.

The Intra-Alberta Transportation deduction is calculated using the Alberta Costs of Service, which is defined as Nova's cost-of-service plus costs incremental to Nova from the other Included Pipelines. The Alberta Costs of Service is divided by Alberta net billable receipts, which is defined as Nova's net billable receipts plus net billable receipts of the other Included Pipelines that are incremental to Nova's net billable receipts. Effective January 2003, Nova’s Costs of Service also includes CO2 Management Service Billings, which are required to produce marketable gas. The Pipeline Fuel/Loss Factor uses Alberta net billable receipts divided by Alberta gross billable receipts, all information coming from the Included Pipelines. The Department calculates both allowances for each production month.

The reference price calculation does not include deductions for take-or-pay costs. The Department and industry will negotiate the treatment of such costs if and when it becomes necessary to do so.

3. The Weighted Average Marketing Allowance is a weighted average of marketing costs incurred for producers' sales to three purchaser groups:

• marketers, • aggregators, and • end users or distributors

The adjustments attributable to each of these groups have been classified as follows: • Valuation Point Adjustment (VPA) - is calculated as the average difference between purchases

and sales prices obtained for companies identified as marketers by the Department. This is multiplied by the total gas removals from Alberta in the previous year. Future average differences will be calculated based on Department surveys of marketers;

• Aggregator OMAC Adjustment rate is determined by the Department each month as a proxy for the overhead, marketing and administration charges of recognized aggregators. The rate will be the weighted average OMAC type deduction of the designated large aggregators multiplied by the total gas removals from Alberta in the previous year; and

• Producer Direct Marketing Allowance – rate is determined by the Department annually and is comprised of the VPA and Aggregator OMAC Adjustment. Calculation methodology is provided on page D3.

4. Adjustments for Prior Period Amendments for the Month are calculated as follows:

i. For every delivery month amended in the current month's Gas Reference Price business period: • Recalculate the Gas Reference Price before adjustments for prior period amendments

and rounding; • Compare the recalculated Gas Reference Price to the previous business period's Gas

Reference Price; • Multiply the unit difference ($/GJ), by the total Gas Reference Price Quantity (GJ), as

at the current business period, to generate an amendment value ($).


ii. The sum of all months' amendment values plus the opening rollover balance divided by the current month's Gas Reference Price quantity equals the current month's Prior Period Amendment Adjustment.

iii. The maximum Prior Period Amendment Adjustment included in any current Reference Price month is an amount equal to, plus or minus 2% of the Gas Reference Price before the Prior Period Amendment Adjustment. Any amount that is over the 2% limit is carried forward to the next succeeding Reference Price month.

Alberta Gas Reference Price

Calculation Methodology Producer Direct Marketing Allowance

1. The producer direct marketing allowance will be calculated annually like the VPA (Value

Point Adjustment). 2. Producer direct sales supplied from proprietary gas would receive an allowance equal to the

aggregators OMAC (Overhead, Marketing and Administration Charge) (If the aggregators OMAC were not available any longer, an annual survey of marketers providing fee for service to producers would be instituted).

3. Producer sales supplied by 3rd party purchases would be given an allowance equal to the VPA. 4. To minimize additional reporting burden along with administration and auditing, the

Department will use existing information sources to calculate the percentage of proprietary versus 3rd party supply. This calculation would divide total field purchases (APMC 601) by total Alberta production to derive the percentage of gas production sold in the field. This percentage would be used as a proxy for the percentage of producers’ total sales that are supplied from 3rd party purchases. The difference (percentage of gas production not sold in the field) would be used as a proxy for the percentage of gas sold directly by producers to end users including distributors.

5. The market share percentage for aggregators, marketers and producers selling direct would continue to be calculated once a year using Gas Reference Price removal information.

6. The following is an example of what the calculation might look like:

Market Share Allowance Aggregators (OMAC) 10% .02 $/GJ existing Marketer (VPA) 46% .05 $/GJ existing Producers Direct 44% {28% X .05 $/GJ} .03 $/GJ new

{72% X .02 $/GJ} Total 100% .04 $/GJ

Reasons for Methodology

• It uses marketing cost information from non-producer sources, which ensures impartiality. • The aggregators OMAC is a reasonable proxy for producers selling their own production

directly to end users. Under contracts with aggregators, producers receive a price netback from the market less marketing type costs (OMAC).

• The VPA is calculated as the difference between a marketer’s purchase price and his sales price, adjusted for transportation and fuel. The VPA is also a reasonable proxy for a producer conducting similar business.


• The method for determining the split between proprietary and 3rd party purchases is very approximate. Improving on this method would require additional reporting and auditing, as well as complex allocations, which are not desirable.


The following chart shows how the Department calculates the intra-Alberta consumers' price from monthly arm's-length purchases by designated Local Distribution Companies (LDCs) and Large Volume End-users.

GAS CONSUMED IN ALBERTA

EOR INJECTIONPIPELINE

FUEL/LOSS/OTHER

RESIDENTIAL,COMMERCIAL,INDUSTRIAL &SHRINKAGE

SMALL CONSUMPTION

NON-LDC SUPPLY LARGE VOLUME

END-USERSNON-LDC SUPPLY

DEPT. DESIGNATED DISTRIBUTORS - LDC

SUPPLY

ARM’S-LENGTH PURCHASES

NON-ARM’S-LENGTH

PURCHASESARM’S-LENGTH

PURCHASES

NON-ARM’S-LENGTH

PURCHASESBUY/SELLS AT

FRANCHISE

Price Quantity Quantity Quantity Price Quantity Price Quantity

WEIGHTED AVERAGE PRICE END-USER

QUANTITYDISTRIBUTOR

QUANTITYWEIGHTED

AVERAGE PRICE

END-USER VALUE DISTRIBUTOR

VALUE

INTRA-ALBERTACONSUMPTION


PRICE

June 2003 Appendix D-6

This chart shows how the Ministry calculates the ex-Alberta border price from arm’s-length transactions reported by companies removing gas from Alberta. The distinct calculation for ex-Alberta Gas LDCs.

GAS EXPORTED FROM ALBERTA

GAS REMOVED FROM ALBERTA AND OWNED BY AN EX-ALBERTA LDC

GAS REMOVED FROM ALBERTA AND OWNED BY A COMPANY WHO IS NOT AN EX-ALBERTA LDC

Gas Acquired Within Alberta Gas Dispositions Outside Alberta

NON-ARM’S LENGTH SUPPLY

ARM’S LENGTH

PURCHASES

GAS SOLD ARM’S LENGTH

GAS NOT SOLD ARM’S LENGTH

QUANTITY QUANTITY VALUE

ARM’S LENGTH

PURCHASES

EMPRESS REMOVAL POINT

JAMES/MCNEIL REMOVAL POINT

COLEMAN REMOVAL POINT

OTHER REMOVAL POINT

QUANTITY VALUE QUANTITY VALUE QUANTITY QUANTITY VALUE VALUE

WEIGHTED AVERAGE

PRICE

WEIGHTED AVERAGE

PRICE

WEIGHTED AVERAGE

PRICE

WEIGHTED AVERAGE

PRICE

TOTAL QUANTITY

TOTAL QUANTITY

TOTAL QUANTITY

TOTAL QUANTITY

TOTAL LDC REMOVAL QUANTITY

EX-ALBERTA LDC REMOVAL

VALUE

EX-ALBERTA LDC REMOVAL

PRICE

TOTAL REMOVALSFROM ALBERTA

WEIGHTED EX-ALBERTA BORDER PRICE

TOTAL NON- LDC

REMOVAL QUANTITY

EX-ALBERTA NON – LDC REMOVAL

VALUE

EX-ALBERTA NON – LDC REMOVAL

PRICE

REMOVAL POINT EMPRESS

JAMES MCNEILL

COLEMAN

OTHER


ISC REFERENCE PRICES


PRICE

EX-ALBERTABORDER

PRICE

INTRA-ALBERTA CONSUMPTION

WEIGHTEDAVERAGE PRICEOF ALBERTA GAS

EX-ALBERTA DELIVERIES

INTRA-ALBERTATRANSPORTATION

VALUATION POINT

ADJUSTMENT

AGGREGATOR OMAC

ADJUSTMENT WEIGHTED AVERAGE

MARKETINGALLOWANCE

less

less

equals

AVERAGE FIELD NETBACK PRICE

PIPELINE FUEL/LOSS FACTOR

ISC REFERENCE PRICE

ADJUSTMENTS FOR PRIOR PERIOD AMENDMENTS FOR THE MONTH

multiplied by

plus or minus

equals

PRODUCER DIRECT

MARKETING ALLOWANCE

September 2003 Appendix D-8

ISC Reference Price Calculation Details

1. The ISC Reference Price calculation utilizes the principles and information collection mechanism of the Gas Reference Price (refer to Ch. III, Sec I). Some additional principles are followed:

a) ISC quantities in the ISC Reference Price calculations are determined from reported Gas Reference

Price quantities based on the percentage of each ISC in the gas stream. b) ISCs that are consumed as gas are valued at reported gas prices. c) Gas Transportation Costs are adjusted based on the ISC gigajoule content in a volume of gas. d) The Alberta large volume end-user pool is split into a mainline straddle plant pool and other Alberta

large volume end-user pool. The shrinkage value of the gas extracted at mainline straddle plants is used in the calculation of all ISCs except methane (C1).

2. Alberta mainline straddle plant NGL production is collected from mainline straddle plant operators and used

to determine Alberta shrinkage consumption quantities for each of C2, C3, C4 and C5+ used in the calculation of the C2, C3, C4 and C5+ ISC Reference Prices. The average of all arm's length shrinkage supply costs ($/GJ) at the Alberta mainline straddle plants will be used to value all reported heat content removed from the gas stream as reported by large volume end-users at all mainline straddle plants. Any excess quantities of associated dispositions to non-associated dispositions are excluded from the calculation and therefore, do not contribute to the calculation of the reference prices.

3. Ex-Alta arm's length sales quantity and sales value are reported at the first point of sale as well as Canadian

and U.S. transportation costs and fuel gas from the Alberta border to the point of sale.

4. The component makeup of the stream at each point of removal from Alberta is calculated from pipeline information. This information is used to breakdown the Alberta quantities reported removed from Alberta by gas owners into components C1, C2, C3, C4, and C5+.

5. The component makeup of gas delivered for consumption within Alberta (non-shrinkage excluding storage) is

obtained from a monthly report submitted by NGTL. This information is used as a proxy for all quantities consumed in Alberta (excluding heat content removed at mainline straddle plants) as reported by large volume end-users and designated distributors for system gas consumption.

6. Ex-Alberta transportation costs, including fuel gas, are allocated at each border point to C1, C2, C3, C4, C5+

on a percentage of volumes that each product represents of those five in the stream. The ex-Alberta transportation costs allocated to each product by volume are then divided by the total gigajoules of each product in the stream to determine a $/GJ ex-Alberta transportation charge for each product. The unit ($/GJ) ex-Alberta transportation charge is deducted from the sales price to determine the netback price of each product at the Alberta border.

7. The intra-Alberta transportation deduction in each ISC Reference Price is calculated from the Intra Alberta

Transportation Deduction (IATD) in the Gas Reference Price calculation. The Gas IATD is adjusted in a similar manner to ex-Alberta transportation costs, using the ISC component makeup of field receipts of the included pipelines.

September 2003 Appendix D-9

Facility Average Price (FAP) Calculation and Supporting Details The valuation price for gas is calculated at the facility level. This Facility Average Price (FAP) is the facility aggregate (weighted) average reference price based on the ISC content within the royalty-triggered gas, less the facility gas transportation allowance. Refer to Ch. III, Sec 1. Royalty triggered gas production at a facility, with some exceptions, will be assessed at FAP. See 'Points to remember for FARR% and FAP calculations' for exceptions.

Points to remember for FARR% and FAP calculations:

• Same ISC product energy is used in calculation • ISC product energy refers to the ISC dispositions at the charge facility that are royalty triggers.

However, if charge facility is an injection facility, ISC product energy refers to the ISC receipts rather than the dispositions.

• Injection Credits are valued at the FARR% of the injection facility and the FAP of the reproducing facility.

• Only C1-IC, C2-IC, C3-IC, C4-IC, C5+-IC product energies are used in calculation. • Facility averages are different each production month because they are based on volumetric

submissions and published royalty variables (royalty rates, reference prices, adjusted intra-Alberta transportation deductions, meter station factors). Once calculated and invoiced for a production month, facility averages will only change for that facility and production month if amendments are processed for volumetrics and meter station factors.

• The Crown Royalty calculation of raw gas that is injected is valued at the FARR% of the injection facility and the FAP of the reproducing facility.

• Exceptions to FARR% and FAP: Raw gas sale subsequently processed is assessed at raw gas average royalty rate and 80% of

Gas Reference Price. Raw gas sale subsequently used for lease fuel is assessed at raw gas average royalty rate

and 100% of Gas Reference Price.

Appendix I – Operating Cost Centres – Unit Operating Cost Rates

December 2004

Appendix I-7

2003 Designated and Plant Type Unit Operating Cost Rates

DELAYERED RATES

EUB FACILITY ID

NAME UOCR COMPRESSING

GATHERING

PROCESSING

AB-GP-0001002 DUKE MIDSTREAM NEVIS 31.02 8.72 10.83 11.47 AB-GP-0001004 KEYSPAN HOMEGLEN-RIMBEY 24.67 6.90 8.20 9.57 AB-GP-0001020 DEVON CARSTAIRS 40.89 10.31 10.03 20.55 AB-GP-0001022 CRESTAR CESSFORD 12.10 1.50 3.68 6.92 AB-GP-0001034 AMOCO WINDFALL 21.33 5.13 10.52 5.68 AB-GP-0001037 SHELL JUMPING POUND 24.22 5.72 3.73 14.77 AB-GP-0001042 RIO ALTO KARR 2.17 0.35 1.22 0.60 AB-GP-0001045 IMPERIAL BONNIE GLEN 14.12 0.00 0.23 13.89 AB-GP-0001047 MINNEHIK-BUCK LAKE 20.88 6.27 5.34 9.27 AB-GP-0001050 WASCANA CROSSFIELD 51.51 1.37 1.71 48.43 AB-GP-0001054 PETRO-CAN WILDCAT HILLS 1.75 0.21 0.39 1.15 AB-GP-0001056 SHELL WATERTON 45.80 10.30 8.61 26.89 AB-GP-0001058 PARAMOUNT KAYBOB 35.67 13.43 12.70 9.54 AB-GP-0001060 SOLEX HARMATTAN ELKTON 38.92 8.40 3.20 27.32 AB-GP-0001069 PENGROWTH JUDY CREEK 24.51 7.34 1.97 15.20 AB-GP-0001074 IMPERIAL BONNIE GLEN 11.28 3.77 0.00 7.51 AB-GP-0001079 PRIMEWEST CROSSFIELD EAST 23.26 3.70 3.85 15.71 AB-GP-0001084 TALISMAN EDSON 20.98 4.46 5.47 11.05 AB-GP-0001097 CONOCO GHOST PINE 19.93 1.99 15.59 2.35 AB-GP-0001105 HUSKY RAINBOW 13.33 0.85 0.12 12.36 AB-GP-0001107 AMOCO KAYBOB S #1 22.77 3.44 8.60 10.73 AB-GP-0001108 KEYSPAN BRAZEAU RIVER 22.85 5.96 7.74 9.15 AB-GP-0001131 SHELL BURNT TIMBER 14.95 2.67 4.47 7.81 AB-GP-0001132 AMOCO MARTEN HILLS 24.73 7.96 10.01 6.76 AB-GP-0001133 KEYSPAN STRACHAN (B) 18.47 4.16 4.61 9.70 AB-GP-0001141 HUSKY STRACHAN 15.50 4.89 4.16 6.45 AB-GP-0001144 CHEVRON KAYBOB SOUTH 24.00 6.01 7.23 10.76 AB-GP-0001147 AEC SINCLAIR 15.31 2.32 4.51 8.48 AB-GP-0001169 DEVON DUNVEGAN 8.54 1.26 3.62 3.66 AB-GP-0001173 AMOCO RICINUS (B) 11.43 4.01 2.65 4.77 AB-GP-0001292 AMOCO WAPITI 8.28 4.32 3.02 0.94 AB-GP-0001350 CDN HUNTER ELMWORTH 1.18 0.88 0.16 0.14 AB-GP-0001351 DEVON ELMWORTH 10.19 4.74 3.88 1.57 AB-GP-0001360 PETRO-CAN HANLAN 7.85 0.95 2.39 4.51 AB-GP-0001458 ATCO MIDSTREAM BRAZEAU 15.10 1.22 3.76 10.12 AB-GP-0001520 CRESTAR WEMBLEY 17.94 4.26 4.70 8.98 AB-GP-0001522 APACHE HAMBURG 6.69 1.37 0.83 4.49 AB-GP-0001662 SHELL CAROLINE 17.59 3.34 0.84 13.41

Plant Types 1 10.09 5.63 3.95 0.51 2 9.35 1.49 2.41 5.45 3 10.34 2.33 1.95 6.06 4 14.82 2.47 2.02 10.33 5 14.13 1.39 2.15 10.59

Appendix O – User Guide to Client Invoicing

June 2003 Appendix O-1

This Appendix features samples of:

Statement of Account................................................................................................................. O-2 Invoice ....................................................................................................................................... O-3 Crown Royalty Detail Calculation............................................................................................. O-4 Crown Royalty Detail Volumetric ............................................................................................. O-5 Low Productivity Calculation .................................................................................................... O-6 Default Report………………………………………………………………………………….O-7 Facility Average Royalty Rate…………………………………………………………………O-8 Facility Average Price................................................................................................................ O-9 Raw Gas Average Royalty Rate………………………………………………………………O-10 Ensure Complete Process Results ............................................................................................ O-11 Outstanding Provisional Assessment Discrepancies................................................................ O-12 PA Summary Report ................................................................................................................ O-13


December 2004 Appendix O-2

STATEMENT OF ACCOUNT ENERGY

ROYALTY PAYER INFORMATION REGULATORY AGENCY INFORMATION CODE: 1234 ISSUER: ALBERTA DEPARTMENT OF ENERGY NAME: PARENT COMPANY ISSUE DATE: 2003-05-13 ADDRESS: XXXXXXXXXXXXXXXXXXX STATEMENT NUMBER: ####### CALGARY, AB ACCOUNT NUMBER: G94 XXXXXX CANADA

X9X 9X9

ROYALTY DEPOSIT ACCOUNT

OPENING $ ADJUSTMENT $ CLOSING $

85,833.33 0.00 85,833.33

ACCOUNT SUMMARY TOTAL $ OPENING BALANCE 350,000.00 PAYMENT APPLIED: 2003/04/29 TXN ID XXXXXXX (150,000.00) CURRENT INVOICE CHARGES: 2003/02/01 INVOICE NUMBER XXXXXX PRIOR PERIOD CHARGES $: 62,949.00 CURRENT PERIOD CHARGES $: 283,500.00 346,449.00 TRANSFER IN FROM: G94 ###### APPLIED 2003/4/30 TXN ID XXXXXXX (75,000.00) PAYMENT APPLIED: 2003/05/07 TXN ID XXXXXXX (100,000.00) CURRENT PERIOD INTEREST POSTED: 2003/05/07 TXN ID XXXXXXX

PRINCIPAL $ FROM TO INTEREST RATE INTEREST AMOUNT $ 125,000.00 2003/05/01 2003/05/07 6.00% 143.84 143.84

CLOSING BALANCE $371,592.84 PROVISIONAL ASSESSMENT NOT SUBJECT TO CPI 20,000.00 CURRENT PERIOD INTEREST ACCRUED BUT UNPOSTED TO 2003/05/13 5.07 PRINCIPAL $ FROM TO INTEREST RATE INTEREST AMOUNT $ PER DIEM AMOUNT $ 5,143.84 2003/05/08 2003/05/13 6.00% 5.07 0.84359 AMOUNT PAYABLE AS OF: 2003/05/13 $371,597.91 COLLECTION NOTICE: PLEASE NOTE YOUR CLOSING BALANCE INCLUDES CHARGES PAST DUE WHICH ARE ACCRUING ADDITIONAL INTEREST UNTIL PAYMENT IS RECEIVED. MESSAGE(S): CHEQUES PAYABLE TO MINISTER OF FINANCE, PROVINCE OF ALBERTA @ 9945-108 ST, EDMONTON, AB T5K 2G6. CHEQUES ARE ALSO ACCEPTED AT 3RD FLOOR MONENCO PLACE 801-6 AVE SW, CALGARY, AB. ACCOUNT INQUIRIES MAY BE DIRECTED TO 780/###-#### OR GAS ROYALTY CALCULATION AT 780/427-2962. CC: ALBERTA TREASURY, TAX AND REVENUE ADMINISTRATION Reference Number: 1234567


June 2003 Appendix O-11

ENSURE COMPLETE PROCESS RESULTS ENERGY

Issue Date: 2002-12-31 11:56 PM Royalty Payer Code: 1234

Royalty Client: 1234 Name: Parent Company Name: Parent Company Address: XXXXXXXXXXXXXXXXX

Billing Period: 2002-11 Calgary, AB X9X 9X9

Production Period

Stream Id

Product

Activity

From/To

Cascade Facility

Owner ID

Volume

Error/Comment

Facility Id: AB-GP-0001005 2002-10 GAS DISP AB-MS-0004500 100.0 MISSING SAF 2002-11 AB-BT-0001234 GAS DISP AB-MS-0009700 AB-GP-0001500 100.0 MISSING SAF (CASCADE) 2002-11 AB-UN-07777 GAS DISP AB-MS-0007892 30.0 MISSING OAF 2002-11 AB-WI-1000580800117W400 GAS DISP AB-MS-0007892 0123 200.0 INVALID OWNER ID 2002-11 AB-WG-04567 C5-SP PROC 10.0 INVALID STREAM ID Facility Id: AB-GP-0001010 REQUIRED ALLOCATIONS COMPLETE Facility Id: AB-GP-0001101 2002-11 GAS DISP AB-MS-0004545 50.0 MISSING SAF Facility Id: AB-MS-0700001 2002-11 GAS DIFF 5,200.0 METER DIFF AT METER STATION Facility Id: AB-MS-0700002 2002-11 GAS 12,000.0 UNALLOCATED CSO VOLUME Reference Number: 1234567


December 2004 Appendix O-12

OUTSTANDING PROVISIONAL ASSESSMENT DISCREPANCIES

ENERGY

Issue Date: 2002-12-31 As of Billing Period: 2002-11 Royalty Payer Code: 1234

Royalty Client: 1234 Name: Parent Company Name: Parent Company Address: XXXXXXXXXXXXXXXXX

Calgary, AB X9X 9X9

Facility

Production Period

Billing Number

Invoice Number

Discrepancy Type

Product

Quantity

Discrepancy

Energy

Discrepancy

Provisional Assessment

Charges

Prior Period

Interest AB-GP-0001250 2002-11 2002-11 1123456789 MISSING SAF GAS 25,000.0 1,025,000 $1,269,975.00 $0.00 2002 Sub-Total $1,269,975.00 $0.00 Total for Facility AB-GP-0001250 $1,269,975.00 $0.00 Total for Royalty Client 1234 $1,269,975.00 $0.00 Total for Royalty Payer 1234 $1,269,975.00 $0.00

Reference Number: 1234567

Appendix G – Allowable and Non-Allowable Capital Costs

December 2004 Appendix G-1

Overview

The Minister may approve additions/deletions to the list of allowable costs or require additions to the list of non-allowable costs. Where such an addition/deletion occurs, the Department:

• Will announce the addition directly to the applicant and in an Information Letter; and • Will include that addition in the next update of the Guidelines.

Allowable Capital Costs

Eligible capital costs incurred in Alberta include those costs pertaining to assets that can be directly attributed to the gathering, compression or processing of natural gas and related gas by-products. Costs incurred outside the royalty network are not considered eligible.

The total capital cost includes charges that can be directly attributed to the particular project including, but not limited to: engineering, design, construction, testing and implementation. Eligible capital costs are generally incurred on-site; however, other costs such as in-house engineering may be allowed if the charges are directly related to the specific capital project being claimed.

Capital charges only become eligible for inclusion as an allowable cost on or after the first day that the capital commences commercial production of gas and/or related gas by-products.

Where the use of capital assets is shared between eligible and ineligible activities, Facility Cost Centre (FCC) operators are permitted to include a portion of the total costs as an allowable capital expenditure. A reasonable allocation methodology should be used to establish the portion to be included for Allowable Cost purposes. The Department will review the allocation methodology and has final approval. Allocation between eligible and ineligible activities may be based on the reasonable pro-ration of inputs/outputs including, but not limited to: production volumes, kilowatt hours, horsepower, labour time spent, distance, fuel consumed, property or other tax assessments.

Leases

Where an eligible asset is leased, the costs associated with the lease may be considered either an operating expense or a capital expense in nature. The Department will make this determination of the type of lease using Generally Accepted Accounting Principles (GAAP). Under these principles, a lease would normally be considered a capital expense if substantially all of the benefits and risks associated with the property is transferred to the lessee.

Financing charges pertaining to the lease are not eligible as an Allowable Capital Cost.



The following are examples of allowable capital costs incurred in Alberta identified by the Minister, as referenced in Ch III, Sec. 3.4. The attached facility schematic represents an approximate illustration of the capital assets, which are generally considered eligible for Allowable Costs. If a particular asset or activity is not identified in the diagram or in the list below clarification as to eligibility can be obtained by contacting the Gas Royalty Client Services.

Air strips located on site. Aircraft are not included.

Capital leases (see leases).

Automatic equipment for gathering, compressing and processing facilities. Communication controls for eligible capital assets. Field or inlet compression facilities required to meet gathering system or plant inlet pressure

specifications. Construction overhead as specified in joint venture agreements (normally 5-3-1), or in the

absence of a joint venture agreement or where an FCC is owned 100%, overhead on construction is allowed at a maximum rate of 1% of direct capital costs.

Corrosion protection. Electrical generation equipment where the output is used to operate eligible capital assets.

Please refer to Information Letter 2001-34 Energy Efficiency Credit Program (EECP) for restrictions.

Cost of easements or rights-of-way. Effluent basins and facilities for handling and disposal of fresh water used in processing. Maintenance of emergency flare stacks and relief facilities including wellsite flare stacks. Fire fighting and safety equipment. Fuel lines for gathering, compression and processing facilities. Gas recovery related costs occurring after the point of final separation of solution gas from

oil. Installed costs of gathering lines to the plant or field compressor from gas wells, or from the

point of final separation for solution gas from oil. Actual or imputed interest or other financing costs, not exceeding the prime rate of interest

posted monthly by the Department of Energy, will be allowed as part of the cost of new facility and capital additions to an existing facility up to the production start-up date. Interest on construction is calculated monthly during the construction period using the current months approved interest rate multiplied by the accumulated capital cost amount incurred from the previous month. Interest is not compounded.

Line heaters at well heads and on gathering systems. Meter runs and measurement equipment including buildings. On-site training facilities. Pollution monitoring and seepage detection equipment. Process license fees. Processing facilities. Processing and engineering studies that relate directly to the process used or eligible asset

acquired. Roads, bridges, walkways and fences for compressing and processing facilities only. Separators, dehydrators, scrubbers, and any other eligible assets related to non-associated

gas.



Storage tanks for field separated liquids (other than oil and water), chemicals or other substances required for gathering, compression and processing activities.

Sulphur-forming facilities (prilling, slaters and remelters). Vehicles and mobile equipment. Warehouses, laboratories and plant offices. Water treatment facilities if water is used for processing.

Non-Allowable Capital Costs

The following are the non-allowable capital costs approved by the Minister, as referenced in Ch III, Section 3.4:

Capital assets dedicated to the production function including drilling equipment or other down-hole equipment.

Capital costs incurred prior to the point of final separation of solution gas from oil.

Assets used for handling field condensate downstream of the point where condensate royalty has already been paid.

Crude oil equipment including transportation and storage facilities, separators, vehicles, dehydrators, scrubbers, boots, and any other facilities or equipment relating to oil.

Assets located outside of the royalty network.

Assets located outside of Alberta.

Capital costs that are deemed, indirect or estimated.

Gas or by-product loading facilities, railway spur lines, storage vessels, or other facilities beyond the plant gate or downstream of the royalty trigger point.

Housing unless located directly at the plant site.

Other capital assets that are not directly attributable to gathering, compressing and processing functions as they relate to natural gas and gas related by-products.

Lines, compressors, wells and other significant facilities or equipment relating to the injection function.

Off-site depots for vehicles and equipment servicing more than one facility.

Off-site training facilities.

Down hole, wellhead, protection, controlling, servicing, testing, salt water, and other production facilities or equipment relating to the production function.

Capital assets approved under the Sulphur Emission Control Assistance Program (SECAP), C02 Projects Royalty Credit Program or Gas Processing Efficiency Assistance Program (GPEAR) must be removed from the Allowable Cost claim.

Roads, bridges, walkways and fences for wellhead and gathering facilities.



Oil Well

Oil Well

LineHeater

Treater Oil Dispositionto Pipeline

BatteryFlare

Sepa

rato

r

CompressorFuel

Gas Well

ProducedWater

C4

Raw Gas

to Flare 1

BatteryFlare

Acid GasIncinerator

Acid GasInjection Well

CompressorStationFlare

Sepa

rato

rSe

para

tor

Sepa

rato

r

Gas Well

ProducedWater

LineHeater

Sepa

rato

r

EmulsionReceipts

ProducedWater

VRU

To VRU

To VRU

m

m

m

m

m

m

m

Inle

tSe

para

tor

Liqu

idSt

abili

zer

m

m

C2

C3 PropaneDispositionm

C5+

EthaneDispositionm

ButaneDisposition

mPentanesDisposition

FractionationProcess

Swee

teni

ng

Deh

ydra

tion

Ref

riger

atio

n

m

Produced Waterto Injection Well

Dehy

drat

ion

mm

Sepa

rato

r

m

m

m

m

m

mm

m

Sepa

rato

r

ProducedEmulsion

m

BatteryFlare

Oil Well

Air Strip

m

SulphurRecovery

SulphurStorage

LineHeater

Gas Battery

Gas Battery

ProducedWater

RecombinedCondensate

Oil Battery

Oil Battery

GasEffluent

GasEffluent

Raw G

as to Gas G

athering

Raw Gas to Gas Gathering

Oil Satellite

Oil Satellite

Emulsion Receipts

ProducedOil

Raw Gas toGas Gathering

Raw Gas to Gas Gathering

Compressor Station /Gas Gathering System

Raw

Gas

to G

as G

athe

ring

Head

erH

eade

r

Gas Processing PlantPlant office, control room, pollutionmonitoring facilities, safety equipment,vehicles, lab facilities, training facilities.

Emulsion trucked toGas Processing Plant

ProducedWater

m

m

m

NaturalGas

Liquid(s)LoadingFacilities

Water toDisposal Well

SulphurLoadingFacilities

SulphurDisposition

Allowable Road

Nearest Secondary or M

ain Highw

ay

Allowable Bridge

Railw

ay Spur Lines

Emergency Gas Plant Flare 1

Gas Plant Fuel 1

Fuel to Field 1

m

m

m

m

$ Sales Gas Line 3

$

$

$

$

$m

m$

Non-Allow

able Bridge

BatteryFlare

m

Dehy

m

ProducedOil

Field

Condensate 2

PigLaunche

r

Pig Receiver

LEGEND

m - Measurement Device, SCADA / EFM Device,and/or equipment for well control and monitoring

$ - Product Valuation Point

- Liquid Sampler

- Storage Tank

- Storage Vessel

- Process Vessel (Not Fired)

- Process Vessel (Fired)

- Compression

Items that are GREY are Non-Allowable

Allowable Road

Allowable Bridge

SulphurForming

ESD

ESD

ESD

Oil Well

Oil Well

Water supplytreatmentfacilities

Items that are BLACK are Allowable

- Process Building

VRU - Vapour Recovery Unit or Vapour Gathering

- Emergency Shut Down ValveESD

Gas Well

NOTES1 - "Raw Gas to flare", "Gas Plant Flare", "Gas Plant Fuel", "Fuel to Field" subject toAppendix A. Clients can not claim the cost of these items as GCA if you alreadywaived the volume on SAF/OAF.2 - There is a distinction on the eligibility of condensate handling and trucking. Ifcondensate is “field condensate” under Section III-4-1 of the Guidelines and royaltywas paid that way, then there are no allowed costs for the trucking and handling ofthat condensate.3 - Sales Gas Line is eligible if the sales gas valuation point is outside plant gate4 - Chemical injectors and chemical storage tanks used for gas pipeline injection areAllowable. Chemical injectors and chemical storage tanks used for well injection areNon-Allowable.

Chemical injection 4including corrosion inhibitors

LiquidSweetening

Appendix H – Allowable and Non-Allowable Operating Costs

December 2004 Appendix H-1

Overview

The Minister may approve additions/deletions to the list of allowable costs or require additions to the list of non-allowable costs. Where such an addition/deletion occurs, the Department:

• Will announce the addition directly to the applicant and in an Information Letter; and • Will include that addition in the next update of the Guidelines.

Allowable Operating Costs

Generally, any eligible operating cost incurred in Alberta pertaining to the operation of an eligible capital asset (Appendix G) is eligible for Allowable Cost purposes.

Where operating costs are shared between eligible and ineligible activities, Facility Cost Centre (FCC) operators are permitted to include a portion of the total costs as an allowable operating cost. A reasonable allocation methodology must be used to establish the portion to be included for Allowable Cost purposes. The Department will review the allocation methodology and has final approval. Allocation between eligible and ineligible activities may be based on the reasonable proration of inputs/outputs including, but not limited to: production volumes, kilowatt hours, horsepower, labour time spent, distance, fuel consumed, property or other tax assessments.

Leases

Where an eligible asset is leased, the costs associated with the lease may be considered either an operating expense or a capital expense in nature. The Department will make this determination of the type of lease using Generally Accepted Accounting Principles (GAAP). Under these principles, a lease would normally be considered a capital expense, if substantially all of the benefits and risks associated with the property are transferred to the lessee.

Financing charges pertaining to the lease are not eligible as an Allowable Operating Cost

The following are examples of allowable operating costs incurred in Alberta identified by the Minister, as referenced in Ch III, Sec. 3.10. If a particular operating activity is not identified in the list below, clarification as to eligibility can be obtained by contacting the Gas Royalty Client Services.

Automotive. Chemicals. Contract services. Gain or loss on disposal of capital assets which are replaced. Insurance other than loss of revenue. Labour. Maintenance. Materials. Overhead and working capital allowances as specified by the Minister. Process licence royalties or fees. Property taxes. Purchased fuel gas for which royalty has already been paid. Repairs. Road maintenance for compressing and processing facilities. Service costs. Surface rentals. Transportation.

Appendix H – Allowable and Non-Allowable Operating Costs

December 2004 Appendix H-2

Utilities. Costs incurred to conduct eco-efficiency audits. Training costs incurred off-site provided the costs are directly attributable to the gathering,

compression and processing of natural gas and/or related by-products at a specific Facility Cost Centre.

Non-Allowable Operating Costs

The following are non-allowable operating costs approved by the Minister, as referenced in Ch III, Sec. 3.10:

EUB tax assessment. Compensatory payments to other well owners. Compensatory royalty payments. Custom processing fees, including management service fee for CO2 extraction. Loss of revenue insurance. Freehold mineral taxes. Operating costs associated with non-allowable capital costs. Operating costs that are deemed, indirect or estimated. Operating costs related to production, injection or oil functions. Petroleum and natural gas royalties. Production lease rentals. Road maintenance for gathering facilities. Operating costs incurred outside of the royalty network. Operating costs incurred outside of Alberta. Operating costs pertaining to capital assets approved under the Sulphur Emission Control

Assistance Program (SECAP), C02 Projects Royalty Credit Program or Gas Processing Efficiency Assistance Program (GPEAR) must be removed from the Allowable Cost claim.

ALLOWABLE COSTS FACILITY COST CENTRE

SETUP/CHANGE AC1-V2

ENERGY

PART 1: FACILITY COST CENTRE OPERATOR DETAIL

1.1 CHECK ONE: SETUP CHANGE 1.2 DATE PREPARED (yyyy-mm-dd) YR. MO. DY.

1.3 REASON FOR CHANGE 1.4 1.5

FACILITY COST CENTRE OPERATOR ID FACILITY COST CENTRE OPERATOR NAME

1.6 1.7 CONTACT PERSON TELEPHONE

PART 2: FACILITY COST CENTRE 2.5 REMAINING USEFUL LIFE (yrs)

2.1 2.2 PROV. FAC.TYPE EUB FACILITY CODE DESCRIPTION OF EUB FACILITY

2.3 2.4 FACILITY COST CENTRE CODE DESCRIPTION OF FACILITY COST CENTRE

2.6 EFFECTIVE DATE 2.7 TERMINATION DATE (yyyy-mm) YR. MO. (yyyy-mm) YR. MO.

2.8 ASSOCIATED EUB FACILITY CODE PROV. FAC.TYPE EUB FACILITY CODE

2.9 PREVIOUS FACILITY COST CENTRE CODE

2.10 REPORTED EUB FACILITY CODE 2.11 EFFECTIVE DATE (yyyy-mm) YR. MO.

PROV. FAC.TYPE EUB FACILITY CODE PROV. FAC.TYPE EUB FACILITY CODE

PART 3: CHANGE IN FACILITY COST CENTRE OPERATOR 3.3 EFFECTIVE DATE __________________ (yyyy-mm) YR MO

3.1 3.2 NEW FACILITY COST CENTRE OPERATOR ID NEW FACILITY COST CENTRE OPERATOR NAME

PART 4: FACILITY COST CENTRE OWNERSHIP 4.1 EFFECTIVE DATE __________________ (yyyy-mm) YR MO

4.2 CLIENT ID 4.3 FACILITY COST CENTRE OWNER NAME 4.4 % OWNERSHIP

100 00000% PART 5: THIS FACILITY COST CENTRE COMPRISES PART OF A:

5.1 FIELD COMPRESSION GATHERING PROCESSING

PART 6: SHUT IN/REACTIVATION 6.1 SHUT IN 6.2 EFFECTIVE YEAR

ALLOWABLE COSTS FACILITY COST CENTRE

SETUP/CHANGE AC1-V2 (PART 4 CONTINUATION)

ENERGY

PART 1: FACILITY COST CENTRE OPERATOR DETAIL

1.2 DATE PREPARED (yyyy-mm-dd) YR. MO. DY.

1.4 1.5 FACILITY COST CENTRE OPERATOR ID FACILITY COST CENTRE OPERATOR NAME


PART 2: FACILITY COST CENTRE

2.1 2.2 PROV. FAC.TYPE EUB FACILITY CODE DESCRIPTION OF EUB FACILITY

2.3 2.4 FACILITY COST CENTRE CODE DESCRIPTION OF FACILITY COST CENTRE

PART 4: FACILITY COST CENTRE OWNERSHIP CONTINUED

4.2 CLIENT ID 4.3 FACILITY COST CENTRE OWNER NAME 4.4 % OWNERSHIP

PAGE _____ of _____

ALLOWABLE COSTS

CAPITAL COST ALLOWANCE AC2-V3

PRODUCTION YEARS 2004 AND ONWARDS

ENERGY

PART 1: IDENTIFICATION

1.1 1.2 PROV. FAC. TYPE EUB FACILITY CODE FACILITY COST CENTRE (FCC) CODE

1.3 DESCRIPTION OF FACILITY COST CENTRE


1.6 PRODUCTION YEAR 1.7 DATE PREPARED

(YYYY-MM-DD) YR. MO. DY.


PART 2: CAPITAL COST ALLOWANCE CALCULATION ALLOWABLE RETURN ON CAPITAL COSTS ($) AVERAGE CAPITAL ($)

2.1 CUMULATIVE ALLOWABLE CAPITAL JAN 1 OR ___ 2.8 AVERAGE CAPITAL 2.2 ALLOWABLE CAPITAL COST JAN 1 OR ___ 2.9 LAND 2.3 CAPITAL ADJUSTMENTS (TOTAL OF A,D,R, AND T FROM PART 3) 2.10 AVERAGE SPARE PARTS INVENTORY 2.4 CUMULATIVE ALLOWABLE CAPITAL DEC 31 OR ___ 2.11 TOTAL 2.5 ALLOWABLE CAPITAL COST BEFORE DEPRECIATION DEC 31 OR ___ 2.6 DEPRECIATION ____ / 12 CAPITAL COST 2.7 ALLOWABLE CAPITAL COST AFTER DEPRECIATION DEC 31 OR ___ ALLOWANCE ($)

2.12 RETIREMENTS 2,13 DEPRECIATION 2.14 RETURN ON AVERAGE CAPITAL __/12 2.15 CAPITAL COST ALLOWANCE

2.16 REMAINING USEFUL LIFE (yrs)

PART 3: CAPITAL ADJUSTMENTS

3.1 DESCRIPTION OF ADJUSTMENTS 3.2 FCC CODE *3.3 TYPE 3.4 AMOUNT ($) *ADDITIONS/DISPOSITIONS/RETIREMENTS/TRANSFERS/START-UP COSTS 3.5 TOTAL

PART 4: CAPITAL COST ALLOWANCE ALLOCATIONS

4.1 CLIENT ID 4.2 CLIENT NAME 4.3 CAPITAL COST ALLOWANCE DISTRIBUTIONS %

4.4 CUSTOM PROCESSING ADJUSTMENT FACTOR %

4.5 TOTAL CAPITAL COST ALLOWANCE ALLOCATED 100.00000%

PAGE 1 OF _____

ALLOWABLE COSTS



ENERGY


1.1 1.2 PROV. FAC. TYPE EUB FACILITY CODE FACILITY COST CENTRE (FCC) CODE






PART 5: CUSTOM PROCESSING ADJUSTMENT FACTOR CALCULATION

5.3 UNIT 103m3 m3 t

5.1 CLIENT ID 5.2 CLIENT NAME 5.4 CUSTOM VOLUMES

5.5 TOTAL CUSTOM VOLUMES

5.6 TOTAL FACILITY COST CENTRE THROUGHPUT

5.7 CUSTOM PROCESSING ADJUSTMENT FACTOR % PAGE 2 of _____

ALLOWABLE COSTS



ENERGY


1.1 1.2 PROV. FAC.TYPE EUB FACILITY CODE FACILITY COST CENTRE (FCC) CODE






PART 3: CAPITAL ADJUSTMENTS CONTINUED

3.1 DESCRIPTION OF ADJUSTMENTS 3.2 FCC CODE *3.3 TYPE 3.4 AMOUNT ($)

PAGE 3 of _____

ALLOWABLE COSTS



ENERGY


1.1 1.2 PROV. FAC.TYPE EUB FACILITY CODE FACILITY COST CENTRE (FCC) CODE






PART 4: CAPITAL COST ALLOWANCE ALLOCATIONS CONTINUED

4.1 CLIENT ID 4.2 CLIENT NAME 4.3 CAPITAL COST ALLOWANCE DISTRIBUTIONS %

PAGE 4 of _____

CAPITAL COST ALLOWANCE AND CUSTOM PROCESSING VOLUME

REALLOCATIONS AC3-V2


ENERGY


1.1 1.2 PROV. FAC.TYPE EUB FACILITY CODE FACILITY COST CENTRE CODE


1.4 1.5 CLIENT ID CLIENT NAME

1.6 PRODUCTION YEAR 1.7 DATE PREPARED (YYYY-MM-DD) YR. MO. DY.


PART 2: CAPITAL COST ALLOWANCE REALLOCATIONS

2.1 CLIENT ID 2.2 CLIENT NAME 2.3 PERCENTAGE OF ORIGINAL ALLOCATION

PART 3: CUSTOM PROCESSING VOLUME REALLOCATIONS

3.1 CLIENT ID 3.2 CLIENT NAME 3.3 PERCENTAGE OF ORIGINAL ALLOCATION

ALLOWABLE COSTS OPERATING COSTS

AC4-V2 PRODUCTION YEARS 2004 AND ONWARDS ENERGY


1.1 1.2 PROV. FAC.TYPE EUB FACILITY CODE FACILITY COST CENTRE CODE





PART 2:

2.1 STANDARD ALLOWABLE OPERATING COSTS ($) (EXCEPT FOR UTILITIES IN 2.2) 2.2 CO-GENERATION UTILITIES

2.3 OTHER ALLOWABLES (DESCRIPTION) 2.4 OTHER ALLOWABLES (ACTUAL OPERATING COSTS) ($)

2.5 DIRECT ALLOWABLE OPERATING COSTS 2.6 OVERHEAD 2.7 DIRECT ALLOWABLE OPERATING COST & OVERHEAD 2.8 WORKING CAPITAL ALLOWANCE 2.9 TOTAL ALLOWABLE OPERATING COSTS

PART 3: OPERATING COST ALLOWANCE ALLOCATION (to be completed if operating costs are allocated among multiple delivery facilities)

3.1 PROV. FAC.TYPE EUB FACILITY CODE 3.2 OPERATING COST ALLOWANCE DISTRIBUTIONS %

3.3 TOTAL OPERATING COST ALLOWANCE ALLOCATED 100 00000%

ALLOWABLE COSTS CUSTOM PROCESSING FEES PAID

AC5-V3 PRODUCTION YEARS 2004 AND ONWARDS ENERGY





PART 2: NON OWNER IN FACILITY COST CENTRE(S) TIED TO EUB FACILITY

2.1 CUSTOM PROCESSING FEE PAID ($)

2.2 EUB FACILITY PROV. FAC. TYPE/CODE



PART 3: OWNER IN FACILITY COST CENTRE(S) TIED TO EUB FACILITY

3.5 CUSTOM SERVICES PAID



3.3 ENERGY-ADJUSTED GAS

EQUIVALENT VOLUME

3.4 EXCESS CAPACITY COMPRESSING GATHERING PROCESSING


AC5-V3 (PART 2 CONTINUATION) PRODUCTION YEARS 2004 AND ONWARDS ENERGY





PART 2: NON OWNER IN FACILITY COST CENTRE(S) TIED TO EUB FACILITY





PAGE _____ of _____


AC5-V3 (PART 3 CONTINUATION) PRODUCTION YEARS 2004 AND ONWARDS ENERGY





PART 3: OWNER IN FACILITY COST CENTRE(S) TIED TO EUB FACILITY

3.5 CUSTOM SERVICES PAID



3.3 ENERGY-ADJUSTED GAS

EQUIVALENT VOLUME

3.4 EXCESS CAPACITY COMPRESSING GATHERING PROCESSING

PAGE _____ of _____

INVOICE CONSOLIDATION CONCURRENCE FORM ICC1

Revised 2001-09-25

ENERGY

Written concurrence (agreement) from all affected parties must be attached to the letter requesting Invoice Consolidation.

The Consolidator

Royalty Client ID

Name of Royalty Client

Authorized Signature

Title of Corporate Signing Officer

Name of Corporate Signing Officer

Date

Effective Date of Consolidation Production Month (YYYY/MM)

We agree to consolidate invoices produced under our client name and ID and understand the royalty implications of invoice consolidation.

The Consolidatee

Royalty Client ID

Name of Royalty Client

Authorized Signature

Title of Corporate Signing Officer

Name of Corporate Signing Officer

Date

Effective Date of Consolidation Production Month (YYYY/MM)

Effective the consolidation date, we agree that individual invoices will not be produced under our company name and understand the royalty implications of invoice consolidation.

*If multiple business associates are to be included in the consolidation, additional concurrences for each client are required.

ENERGY

Petroleum Plaza – North Tower 9945 – 108 Street Edmonton, Alberta Canada T5K 2G6

2005 Alberta Energy

Gas Royalty Calculation Calendar

Note 1: If the due date falls on a non-business day, forms will be accepted on the next business day.

Note 2: Keying Service cut-off dates are estimated by the Department at five days before the OAS cut off. Please check with your keying service for specific dates on OAS paper and diskettes.

Note 3: 2001 production year becomes statute barred on December 31, 2005. ∗ 2002 close-out date (primary documents) January 17, 2005 ∗∗ 2002 close-out date (secondary documents) March 15, 2005

Sun Mon Tue Wed Thu Fri Sat 1

2 3 4 5 6 7 8

9 OAS cut-off keying service

10 NGL

11 12 13 14 15 VA4 SAF/OAF, RGA

16 17 * 18 19 20 21 22

23 24 25 26 27 28 29

30 31 RMF2, RMF3, PW1

2005

January

Sun Mon Tue Wed Thu Fri Sat 1 2 3 4 5

6 7 8 9 OAS cut-off keying service

10 NGL

11 12

13 14 15 SAF/OAF, VA4, RGA

16 17 18 19

20 21 Family Day

22 23 24 25 26

27 28 RMF2, RMF3, PW1

2005

February


AC1 2 3 4 5


10 NGL

11 12

13 14 15 ** VA4 SAF/OAF, RGA

16 17 18 19

20 21 22 23 24 25 Good Friday

26

27 28 Easter Monday

29 30 31 GR2, AC4, RMF2, RMF3, PW1

2005

March

Sun Mon Tue Wed Thu Fri Sat 1 2

3 4 5 6 7 8 9 OAS cut-off keying service

10 NGL

11 12 13 14 15 SAF/OAF, RGA VA2, VA3, VA4

16

17 18 19 20 21 22 23

24 25 26 27 28 29 30 RMF2, RMF3, PW1, AC2

2005

April

Sun Mon Tue Wed Thu Fri Sat 1 2 3 4 5 6 7

8 9 OAS cut-off keying service

10 NGL

11

12 13 14

15 AC3, AC5, VA4, SAF/OAF, RGA

16 17 18 19 20 21

22 23 Victoria Day

24 25 26 27 28

29 30 31 RMF2, RMF3, PW1

2005

May

Sun Mon Tue Wed Thu Fri Sat 1 2 3 4

5 6 7 8 9 OAS cut-off keying service

10 NGL

11

12 13 14 15 VA4, SAF/OAF, RGA

16 17 18

19 20 21 22 23 24 25

26 27 28 29 30 SECAP, RMF2, RMF3, PW1

2005

June


Canada Day 2

3 4 5 6 7 8 9 OAS cut-off keying service

10 NGL

11 12 13 14 15 VA4, SAF/OAF, RGA

16

17 18 19 20 21 22 23

24 25 26 27 28 29 30

31 RMF2, RMF3, PW1

2005

July


Civic Holiday 2 3 4 5 6

7 8 9 OAS cut-off keying service

10 NGL

11 12 13

14 15 VA4, SAF/OAF, RGA

16 17 18 19 20

21 22 23 24 25 26 27

28 29 30 31 RMF2, RMF3, PW1

2005

August

Sun Mon Tue Wed Thu Fri Sat 1 2 3

4 5 Labor Day


10 NGL

11 12 13 14 15 VA4, SAF/OAF, RGA

16 17

18 19 20 21 22 23 24

25 26 27 28 29 30 RMF2, RMF3, PW1

2005

September


2 3 4 5 6 7 8

9 OAS cut-off keying service

10 NGL Thanksgiving

11

12 13 14 15 VA4, SAF/OAF, RGA

16 17 18 19 20 21 22

23 24 25 26 27 28 29

30 31 RMF2, RMF3, PW1

2005

October

Sun Mon Tue Wed Thu Fri Sat 1 2 3 4 5


10 NGL

11 Remembrance Day

12

13 14 15 VA4, SAF/OAF, RGA

16 17 18 19

20 21 22 23 24 25 26

27 28 29 30 RMF2, RMF3, PW1

2005

November

Sun Mon Tue Wed Thu Fri Sat 1 2 3

4 5 6 7 8 9 OAS cut-off keying service

10 NGL

11 12 13 14 15 VA4, SAF/OAF, RGA

16 17

18 19 20 21 22 23 24

25 26 27 28 29 30 31 RMF2, RMF3, PW1

2005

December