Gas Royalty Calculation Information Bulletin - August 2002 · GAS ROYALTY CALCULATION INFORMATION BULLETIN August 2002 A. PRICING RATES AND TRANSPORTATION INFORMATION Pricing, Royalty

ENERGY

Petroleum Plaza – North Tower 9945 – 108 Street Edmonton, Alberta Canada T5K 2G6 02-08

GAS ROYALTY CALCULATION INFORMATION BULLETIN

August 2002

A. PRICING RATES AND TRANSPORTATION INFORMATION Pricing, Royalty Rates and Transportation Information – June 2002.................................................. 2 B. NOTICES Access to Department of Energy Royalty Reports Before and After Implementation of the Petroleum

Registry of Alberta............................................................................................................................... 2 Revised Registry ISC Reporting Table ............................................................................................... 4 C. MONTHLY INFORMATION June 2002 Royalty Due September 30 ............................................................................................... 4 July 2002 OAS and VA4 Due September 15 ..................................................................................... 5 Interest Rate August 2002................................................................................................................... 5 May Provisional Assessment Charge ................................................................................................. 5 May Penalty Charges .......................................................................................................................... 5 Alberta Royalty Tax Credit Program Quarterly Rate ........................................................................... 6 D. INFRASTRUCTURE DATA CHANGES Client ID Listing ................................................................................................................................... 6 Projects/Blocks.................................................................................................................................... 6 Struck Clients ...................................................................................................................................... 6 Operator Changes............................................................................................................................... 7 New EUB Plants .................................................................................................................................. 7 Nova Tolls – Multiple Gas Reference Prices....................................................................................... 7 E. REMINDERS Royalty Payers Only............................................................................................................................ 7 Alberta Natural Gas and Natural Gas Liquids Royalty (NGL) Framework Change ............................ 9 Late Filing Penalty Changes ............................................................................................................. 15 RMF3 Calculation and Examples ...................................................................................................... 15 Royalty Payers Only.......................................................................................................................... 17 Royalty Deposit Adjustment .............................................................................................................. 19 F. PRINCIPLES AND PROCEDURES Updates ............................................................................................................................................. 19 G. POINTS OF CONTACT Department of Energy Hotline & Internet .......................................................................................... 19 Gas Royalty Calculation .................................................................................................................... 19 Calgary Information Centre .............................................................................................................. 20 Alberta Royalty Tax Credit Information ............................................................................................ 20

PLEASE ENSURE YOUR PRODUCTION ACCOUNTANTS RECEIVE A COPY OF THIS DOCUMENT.

Internet Address: www.energy.gov.ab.ca

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

INFORMATION BULLETIN – August 2002

A. PRICING RATES AND TRANSPORTATION INFORMATION

For Pricing, Royalty Rates and Transportation Information for June 2002, refer to Attachments 1, 2, 2A, and 3.

B. NOTICES

Access to Department of Energy Royalty Reports Before and After Implementation of the Petroleum Registry of Alberta Implementation of the Petroleum Registry of Alberta will impact many of the reporting processes between the oil and gas industry and the Department of Energy. The following outlines how clients currently access Oil and Gas Royalty reports and how they will access them after implementation of the Registry. There are three aspects in handling these reports:

• a delivery mechanism, • a re-direction mechanism (sending one client’s reports to another client) • format options.

All of these mechanisms are affected by the implementation of the Registry. Delivery Mechanisms Prior to Registry:

• Electronic Transfer System (ETS) account (internet mailbox) - Applicable to Gas and Oil clients

• Tape/CDs (for UDF formats only) - Applicable to Gas clients only • Mail - Applicable to Gas and Oil clients

After Registry:

• Registry internet mailbox - Applicable to Gas and Oil clients • Mail (for Royalty Payers Only) – Applicable to Gas clients only

Re-direction Mechanisms Prior to Registry:

• Within ETS, specification by the client of another client’s ETS account as the recipient. - Applicable to Gas and Oil clients

• Within MRIS, specification of another recipient for Tape/CDs (for UDF formats only), or an alternative to the client’s default address for mail - Applicable to Gas clients only

After Registry:

• Specification by the client of security access to their Registry internet mailbox by another client - Applicable to Gas and Oil clients

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Electronic Formats Prior to Registry:

• UDF (for a specific subset of reports) - Applicable to Gas clients only • Text - Applicable to Gas and Oil clients • PDF - Applicable to Gas and Oil clients

After Registry:

• UDF (for a specific subset of reports) - Applicable to Gas clients only • Text - Applicable to Gas and Oil clients • PDF - Applicable to Gas and Oil clients • CSV (for a specific subset of reports) - Applicable to Gas clients only

To learn more about the “specific subset of reports” read Department of Energy Information Bulletin 02-06A at: www.energy.gov.ab.ca Client Options Regarding Delivery Mechanism Prior to Registry:

• Clients can choose to receive their reports through the ETS delivery mechanism by obtaining an ETS account with that option from the DOE Client Registry. Within ETS, clients can select from a list of Gas Royalty report types which ones they want to receive through ETS.

Otherwise, by default, Oil clients receive mail. Gas clients will receive mail and Tape/CDs (for UDF formats only).

After Registry:

• Clients cannot choose ETS – the Registry is now the delivery mechanism. Clients cannot select which report types to receive through the Registry and have others delivered by Tape/CDs and mail.

• Gas clients who are ‘Royalty Payers Only’ also get their reports (all types) delivered by mail, unless they are receiving a UDF format. They can choose to not receive mail by requesting to the DOE Gas Royalty Calculation Unit that they receive reports only through the Registry.

Client Options Regarding Re-direction Prior to Registry:

• Within ETS, clients can choose to redirect each selected report type to a different ETS account holder.

Gas clients receiving mail can request the DOE Gas Royalty Calculation Unit to specify a different Tape/CD recipient or mailing address for each report type. (Note: this does not apply to Oil clients)

After Registry:

• Within the Registry, clients can choose to allow access to their reports by other Registry users, but cannot selectively grant access by report type.

Gas clients who are ‘Royalty Payers Only’ cannot choose a different mailing address for their report types – all reports will be mailed to their address as recorded on the Registry.

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Client Options Regarding Electronic Format – This section pertains to Gas clients only Prior to Registry:

• Clients can choose to receive the UDF format (for a specific subset of reports) through a request to the DOE Gas Royalty Calculation Unit. Once this choice is made, other formats are not provided.

Otherwise, by default, clients receive the other formats (text or PDF).

After Registry:

• The same as prior to the Registry, clients can choose to receive the UDF format (for a specific subset of reports) through a request to the DOE Gas Royalty Calculation Unit. Once this choice is made other formats are not provided. Those receiving UDF prior to the Registry will continue to receive them, without having to make a request to the DOE.

Otherwise, by default, clients receive the other formats. This is the same as prior to the Registry, except the other formats include CSV for a specific subset of reports.

For more information about Gas Reports, please contact the Gas Royalty Client Services Help Desk at (780) 427-2962. For more information about Oil Reports, please contact Karen Langpap at (780) 422-9047. Revised Registry ISC Reporting Table The Department has updated the Registry ISC Reporting Table included in the July 2002 Gas Royalty Information Bulletin as part of the Alberta Natural Gas and Natural Gas Liquids Royalty (NGL) Framework Change. The updated table is included in Attachment 7.

C. MONTHLY INFORMATION

June 2002 Royalty Due September 30

• Royalty clients are to remit the total amount payable shown on the September 2002 Statement of Account by September 30, 2002. 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 September 2002 Statement of Account shows your amount payable as of the Statement issue date. It includes any outstanding balances from your previous statement, your June 2002 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 June 2002 if it is paid in full by September 30, 2002.

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

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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.

July 2002 OAS and VA4 Due September 15 The OAS and VA4 documents for the production month of July 2002 are due in the Department offices by September 15, 2002.

NOTE:

• If the due date (15th) falls on a non-business day, the next business day will apply as the due date for OAS and VA4 documents.

• The OAS due date specified by the Department is the date by which the required OAS data must be received in the Department.

• Keying services require sufficient time to process and transmit the data by the Department’s due date. Contact your keying agent for the respective cut-off dates.

• For EDI clients, the receipt date is when Value-Added Network (i.e. GE) receives the transmission.

• The importance of timely receipt of OAS data by your service provider and the Department is critical to ensure accurate royalty calculation and prevention of provisional assessment.

Interest Rate August 2002 The Department of Energy’s interest rate for August 2002 is 5.50%. May Provisional Assessment Charge

The net Provisional Assessment Charge for the May 2002 billing period was $12,458,616.15. This includes $60,559,076.57 in first time provisional assessments and ($48,100,460.42) in reversals of provisional assessments for all production periods. May Penalty Charges The following are the Penalty Charges by form type for the May 2002 billing period:

FORM Penalties Charged AC2 $44,900 AC4 $0 AC5 $48,300 GR2 $0 NGL1 $0 VA2 $0 VA3 $0 VA4 $0 Total Charged $93,200 Total Reversed ($110,500)

Net Penalties Charged for 2002/05 $17,300

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Alberta Royalty Tax Credit Program Quarterly Rate

For the third quarter of 2002, the Alberta Royalty Tax Credit rate will be .2500. This rate is based on a royalty tax credit reference price of $249.61 per cubic metre. The Alberta Royalty Tax Credit rates for the past year were:

Second Quarter, 2002 .2500 First Quarter, 2002 .2500 Fourth Quarter, 2001 .2500 Third Quarter, 2001 .2500

If you have any questions, please contact Kent Nelson of Tax Services at (780) 427-9425, ext 250.

D. INFRASTRUCTURE DATA CHANGES

Client ID Listing The Client ID listing can be found on the Internet at the following address:

www.energy.gov.ab.ca

The listing, which is updated monthly, includes Clients, which are active, struck, and terminated since January 1997. If you require information before January 1997 regarding the status of a Client ID, please call the Gas Royalty Calculation Helpdesk at (780) 427-2962. The Department would like to remind those browsing the site to note the effective and termination dates of the Client IDs.

Projects/Blocks

Projects/Blocks information will be updated in the September 2002 Information Bulletin. If further information is required on any other projects, please contact Isabelle Warwa at (780) 422-8966.

Struck Clients Clients must ensure that the OAS and all other 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 and revived clients:

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http://www.energy.gov.ab.ca/NaturalGas/743.asp


Company Name Client ID Struck Date Brooks Oil & Gas Ltd. 0NE1 July 2, 2002 Cowtown Explorations Ltd. 0ME1 July 17, 2002 Fort Smith Exploration Ltd. 0RH9 July 12, 2002 Marpat Resources Ltd. 0J4C July 26, 2002 North American Trust Company 0K5L July 24, 2002 Sand Exploration Ltd. 0KH6 July 2, 2002 Sereda Oils Ltd. 0M3D July 2, 2002

Company Name Client ID Revived Date Edisto Canada, Inc. 0RC4 July 25, 2002

Operator Changes EUB Facility Operator changes are listed in Attachment 4.

New EUB Plants New EUB plants and corresponding plant types and transportation regions are listed in Attachment 5.

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 in Attachment 6 and on the Department Internet site at:

www.energy.gov.ab.ca E. REMINDERS

Royalty Payers Only (Companies and individuals that are not operators of facilities, but do currently receive information from industry partners, or invoices, statements and other correspondence from the Department of Energy (DOE) have been deemed “Royalty Payers Only” by the Petroleum Registry of Alberta) 7-Digit to 4-Character Code Conversion Complete Cross Reference Table (new 4-character codes which replaces existing 7-digit codes) Now Available!

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Due to implementation of the Petroleum Registry of Alberta in October 2002, the Ministry of Energy is enacting a process to create a standard 4-character reporting code for all companies/individuals. Currently, any royalty payer who sends or receives information from the Department of Energy (DOE) with a 7-digit Royalty Client Code will be issued a new 4-character Business Associate (BA) identifier. The complete table of all converted 7-digit client IDs to the new standardized 4-character ID is now available at:

• The Petroleum Registry web site: www.petroleumregistry.gov.ab.ca • The Department of Energy web site: www.energy.gov.ab.ca

Prior to October 2002, either the 7-digit or 4-character code can be used in making submissions to the DOE. However, royalty payers should realize that the DOE’s output documentation from these submissions will only display the new 4-character BA identifier for that royalty client. The DOE will accept the new 4-character identifier after August 1, 2002 for those clients who wish to make changes to their systems before Registry implementation. Applying for a New Code After the Registry is up and running, companies and/or individuals will be able to use the system to request a 4-character BA identifier. An application form can be submitted via the Registry, with a hard copy letter (with signature) requesting the new identifier be sent to the DOE’s Client Registry group. Royalty clients without access to the Registry can submit a written request for a 4-character BA identifier to the DOE’s Client Registry group. Written requests can be made to:

Alberta Department of Energy Client Registry 9945 108 Street, 3rd Floor Edmonton, AB T5K 2G6 Fax: 780-422-9522

To obtain more information about securing a new BA code, please contact the Client Registry at (780) 422-1395. Note: In addition to the 4-character BA identifier, any industry client who wishes to conduct business through the Registry must also have a User Security Administrator who will manage company User IDs and passwords. To learn more about this process, read the Registry User Security Administrator (USA): Set-up Process story in this bulletin or go to the Registry web site at: www.petroleumregistry.gov.ab.ca. Registry User Security Administrator (USA): Set-up Process A guiding principle of the Registry is that “the data must be secure”. A key component of the Registry’s application security is the role of User Security Administrator (USA). Each company or individual, also known as a Business Associate (BA), who requires access to the Registry, must assign an individual to perform the role of USA. The USA has the responsibility for setting up and managing security for all users of the Registry for that BA. It is very important for each BA to secure a USA ID and password. Without it, a BA will not have access to the Registry.

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



Before the Registry begins operation in October 2002, it must:

• Collect the information for the individual assigned the role of USA. The Registry can create the initial information about the BA from existing EUB or DOE files, but does not have any information about the USA.

• The Registry must then communicate the USA’s Registry User ID and password back to the USA in a secure manner.

The USA Set-up Procedure When the Registry team begins its ramp-up to implementation in the first week of September 2002, BA information, including USA information, will be the first set of data loaded into the database. The objective of the Registry team is to collect all USA information from July 1st to August 30th, 2002. However, a system will be in place to capture any USA data that arrives from September 1st to 30th, 2002. The process to obtain a USA is outlined on the Registry web site (www.petroleumregistry.gov.ab.ca). If you have any questions about this process, please contact the Registry offices at (403) 297-6111(Calgary) or 1-800-992-1144 (other locations) or e-mail [email protected]. When the Registry is operational, new BAs will request a BA USA ID and Password through a Registry online function called Request BA Application. A BA can also manage existing BA USA information through a Registry online function called Request a BA Change. If a BA USA is required after the BA ID has been issued, contact the DOE’s Client Registry at (780) 422-1395. Note: At the time of implementation of the Petroleum Registry of Alberta (Phase 1 – October 2002) the general public will not have access to public data on the Registry. Only those individuals who have a legitimate business reason for using the Registry will be issued the USA ID, which will allow them access to public and secure data in the Registry. All public information on the Registry can be obtained from existing Ministry of Energy sources, either on the DOE or Energy and Utilities Board (EUB) web sites or via EUB’s Data Dissemination program. Alberta Natural Gas and Natural Gas Liquids Royalty (NGL) Framework Change The Department’s Information Letter 2002-19 and Gas Royalty Calculation June Information Bulletin, 02-06A introduced the Alberta Natural Gas and Natural Gas Liquids (NGL) Royalty Framework Change. This change initiative is expected to be effective with September 2002 production, along with the implementation of the Petroleum Registry of Alberta (the Registry). Refer to the Gas Royalty Calculation June Information Bulletin, 02-06A for information on the Registry. This article addresses the following key outcomes of the Alberta Natural Gas and NGL Royalty Framework Change: • Volumetric Submission of In Stream Components • In Stream Component Product List

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• Facility Average Royalty Rate Calculation and Supporting Details • Low Productivity Allowance Adjustment • Raw Gas Average Royalty Rate Calculation and Supporting Details • Facility Average Price Calculation and Supporting Details • ISC Balancing and Discrepancy Notice • Default Royalty Variables and Supporting Details • Royalty Calculation and Crown Royalty Detail Report

Volumetric Submission of In Stream Components (ISC) Volumetric information on in stream components (ISC) in the gas stream is used by the Crown to determine the appropriate component weightings in the calculation of the ‘facility average’ royalty rate and ‘facility average’ price that will be used to assess gas royalty under the Natural Gas and NGL Royalty Framework Change. Basically, ISC information is required on volumetric information that is a royalty trigger. See In Stream Component Product List and Product Codes included in this article for the complete list of ISC products. The ISC volumetric information, where required, is submitted to the Registry, like all the other volumetric submissions. The ISC is submitted as an additional link to the Gas volumetric information. Both volume and energy (where applicable) must be reported. The reporting is to three decimal places for desired precision. The aggregate ISC volume and energy must equal the Gas volume and energy, or the Registry will reject both the Gas and ISC submissions. There is a volumetric tolerance on the Gas and ISC totals. The tolerance on volume difference is +/- 0.100. The tolerance on energy difference is +/- 1.000. Refer to the Registry Training Modules (available via the Registry web site http://www.petroleumregistry.gov.ab.ca) for details on volumetric submissions to the Registry. ISC information is primarily required from pipeline operators. In some cases, meter station operators or their common stream operators, facility operators and sellers of raw gas are also required to report. The Registry ISC Reporting Table in Attachment 7 identifies the submitters and their volumetric reporting requirements. ISC reporting is only required for the receipts and dispositions identified in the Attachment 7. In Stream Component Product List and Product Codes Industry has identified the following list of potential in stream components present in a gas stream, with Methane, Ethane ISC, Propane ISC, Butanes ISC and Pentanes Plus ISC being the primary ISC products. Remaining products are the inerts. Operators are required to report the components that their current metering equipments are able to measure. There is no requirement for operators to install new equipments to satisfy the molecular level defined in the product list.

ISC Product Name ISC Product Code Methane C1-IC Ethane ISC C2-IC Propane ISC C3-IC Butanes ISC C4-IC Pentanes Plus ISC C5+-IC Carbon Dioxide ISC C02-IC Helium ISC HE-IC Hydrogen ISC H2-IC Nitrogen ISC N2-IC Oxygen ISC O2-IC Sulphur ISC SUL-IC Hydrogen Sulphide ISC H2S-IC

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Facility Average Royalty Rate (FARR%) Calculation and Supporting Details Under the Natural Gas and NGL Royalty Framework Change, the Department calculates the gas royalty rate at the facility level. This Facility Average Royalty Rate (FARR%) is the weighted average royalty rate based on the ISC content within the royalty-triggered gas. Gas production with Old vintage will be assessed at the Old FARR%. Gas production with New vintage will be assessed at the New FARR%. Royalty triggered gas production at a facility, with some exceptions, will be assessed at FARR%. See ‘Points to remember for FARR% and FAP calculations’ in this article for exceptions. • Old FARR% =

Sum of (ISC Product Energy times ISC Product Old R%) Divided by

Sum of ISC Product Energy

• New FARR% = Sum of (ISC Product Energy times ISC Product New R%)

Divided by Sum of ISC Product Energy

The Department will publish ISC product royalty rates in the monthly Gas Royalty Calculation Information Bulletins. The Old/New vintage for the ISC products will be consistent with Old/New vintage for the extracted products. Methane, Ethane ISC and Pentanes Plus ISC have Old/New vintage. Propane and Butanes do not have Old/New vintage. The facility average royalty rates will not be generated until invoice calculation. Royalty clients will receive supporting details on the FARR% calculations in their monthly invoice package. The July 2002 Information Bulletin contains a sample of the FARR% Supporting Details that royalty clients will receive. Low Productivity Well Allowance The low productivity well allowance continues to apply to gas and ethane production that meet the low productivity criteria. Refer to the September 1, 2001 edition of the Alberta Natural Gas Royalty Principles and Procedures on Low Productivity Well Allowance for eligibility. The low productivity rate adjustment for Gas and Ethane will be calculated using the royalty rate for Methane.

For Gas and Ethane production eligible for low productivity well allowance, the crown royalty rate is calculated as: R% = RC - (RM – 5) x (16.9 – ADP)2 16.92 RC is the Methane Old/New royalty rate if production is Gas and the Ethane Old/New royalty rate if production is Ethane. ADP is the average daily production of natural gas from the well event for the production month (in 103m3).

RM is the Old/New royalty rate for Methane.

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Raw Gas Average Royalty Rate (RARR%) Calculation and Supporting Details Facility average royalty rates will be used to assess gas royalty, but there are some exceptions. Raw gas sales that are subsequently processed and raw gas sales that are subsequently used for lease fuel are assessed at the raw gas average royalty rate (RARR%), rather than FARR%. The raw gas average royalty rate is based on the ISC factors identified by the seller on the Raw Gas Allocation (RGA) submission, rather than the ISC composition of the royalty trigger quantities at the facility. The RGA is a new Registry submission that is filed when there are ownership changes of gas quantities within the royalty network. Refer to Appendix N of the September 1, 2001 edition of the Alberta Natural Gas Royalty Principles and Procedures for the definition of royalty network. Refer to the Gas Royalty Calculation June Information Bulletin, 02-06A for raw gas reporting information.

Only ISC factors from Methane, Ethane ISC, Propane ISC, Butanes ISC and Pentanes Plus ISC are included in the RARR% calculation. Raw gas sales with Old vintage will be assessed at the Old RARR%. Raw gas sales with New vintage will be assessed at the New RARR%.

• Old RARR% =

Sum of (ISC Product Factor on RGA times ISC Product Old R%) Divided by

Sum of ISC Product Factor on RGA

• New RARR% = Sum of (ISC Product Factor on RGA times ISC Product New R%)

Divided by Sum of ISC Product Factor on RGA

The raw gas average royalty rates will not be generated until invoice calculation. Royalty clients will receive supporting details on the RARR% calculations in their monthly invoice package. The July 2002 Information Bulletin contains a sample of the RARR% Supporting Details that royalty clients will receive. Facility Average Price (FAP) Calculation and Supporting Details Under the Natural Gas and NGL Royalty Framework Change, the valuation price for gas will be calculated at the facility level. This Facility Average Price (FAP) is the weighted average reference price based on the ISC content within the royalty-triggered gas, less the facility gas transportation deduction. 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. • FAP =

Facility Reference Price Minus

Facility Gas Transportation Adjustment

o Facility Reference Price = Sum of (ISC Product Energy times ISC Product Reference Price)


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o Gas Transportation Adjustment = [Royalty Trigger Factor minus 1]

Multiply by Facility Adjusted IATD

o Royalty Trigger Factor =

Sum of (ISC Product Energy times Meter Station Factor) Divided by

Sum of ISC Product Energy

o Facility Adjusted IATD = Sum of (ISC Product Energy times Adjusted IATD of ISC)


The Department will publish ISC product-pricing information in the monthly Gas Royalty Calculation Information Bulletins. The facility reference prices will not be generated until invoice calculation. Royalty clients will receive supporting details on the FAP calculations in their monthly invoice package. A sample of the FAP Supporting Details that royalty clients will receive is included in the July 2002 Information Bulletin.

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 (this occurs very rarely).

• 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: o� Raw gas sale subsequently processed is assessed at raw gas average royalty rate and

80% of Gas Reference Price. o� Raw gas sale subsequently used for lease fuel is assessed at raw gas average royalty rate

and 100% of Gas Reference Price.

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ISC Balancing and Discrepancy Notice Gas deliveries from a plant to a pipeline meter station are subject to royalties. The ISC quantities of the gas deliveries may be reported by the meter station operator or its common stream operator, rather than by the operator of the linked pipeline. Refer to the Registry Training Modules (available via Registry web site http://www.petroleumregistry.gov.ab.ca) for common stream operator reporting in the Registry Volumetric Submission process for information on meter station operator and common stream operator reporting.

An ISC balancing process will occur at pipeline meter stations to ensure there are no volumetric discrepancies between the ISC allocations reported at the pipeline meter station and the ISC allocations reported at the linked pipeline. The ISC allocations at the pipeline meter stations affect the component weightings in the FARR% and FAP calculations. The ISC balancing process will compare the ISC product receipts to the ISC product dispositions at each pipeline meter station. ISC Product discrepancies will be reported on a discrepancy notice (Monthly Statement of ISC Imbalances at Meter Stations) that will be sent to the meter station operator or its common stream operator (as submitter of the ISC receipts) approximately 35 days following the production month. Failure to correct the discrepancy will result in the product quantity being valued at C5+-IC R% and C5+-IC Reference Price in the FARR% and FAP calculations. The July 2002 Information Bulletin contains a sample of the ISC discrepancy notice to the meter station or common stream operators. Default Royalty Variables and Supporting Details Certain situations may necessitate the use of default royalty variables by the Crown for royalty assessment. Currently, when default royalty variables are used, clients receive notification in the Defaults Report, which is included in the monthly invoice package. The following new default situations will be added to the Defaults Report because of the Natural Gas and NGL Royalty Framework Change.

Information on Defaults Report Default Situation Default Item Form Default Description ISC balancing discrepancy Facility Averages Volumetric ISC Imbalance: C5+-IC No FARR% calculated, ISC not available FARR Volumetric ISC not filed: C1-IC No FAP calculated, ISC not available FAP Volumetric ISC not filed: GRP No FAP calculated at reproducing facility, ISC not available

FAP Volumetric ISC not filed at Reproducing Facility: FAP at IF

No RARR% calculated, RGA not available RARR RGA RGA not filed: FARR The July 2002 Information Bulletin contains a sample of the Default Report that royalty clients will receive if the Department has used default royalty variables in their royalty assessment.

Royalty Calculation and Crown Royalty Detail Report The Natural Gas and NGL Royalty Framework Change has resulted in the assessment of gas royalty using facility average royalty rates and facility average prices (adjusted for transportation), and in some cases, using raw gas average royalty rates and 80% or 100% of gas reference prices. There is no change to the Crown Royalty Detail Report, or its User Defined File (UDF), because of this change initiative. However, the Crown Royalty Detail Volumetric Report and the Crown Royalty UDF are impacted by the developments of the Registry. Refer to the Gas Royalty Calculation June Information Bulletin, 02-06A for information on Gas Crown Invoice Changes.

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Late Filing Penalty Changes The Business Design Team recommended that a Penalty Review Committee consisting of Department and Industry representatives be formed to review the penalty process. The objective of the Penalty Review Committee was to examine the current penalty process, identify the common reasons for penalty occurrences and recommend changes to enhance the penalty process. The recommendations made must be consistent with the stated objective of the penalty process, which is to ensure timely and accurate reporting while maintaining the interest of both the department and Industry. Evaluation Criteria: The review of potential options and recommendations made to improve the penalty process were evaluated against the following criteria:

• Timeliness and accuracy of information is maintained • Interests of the Department and Industry clients (including third parties) are maintained. • Administrative burden of penalties is reduced for both the Department and Industry.

Penalty Changes: As a result of the recommendations of the Penalty review Committee, the following changes will be made to late filing penalty. These changes are effective for the filing of the 2002 production year annual allowable cost forms. AC2 Form – Capital Cost Allowance:

• Move the due date from April 15 to April 30 of the year following the production year to which the form relates.

• Grant 15 days grace period for penalty levy if the AC2 form was received on or before April 30 of the year following the production year to which the form relates but was rejected because of MRIS edits.

AC4 Form – Annual Allowable Operating Cost:

• Reduce the penalty from $1000 per year to $ 200 per year for failing to file a valid AC4 form on or before March 31 of the year following the production year to which the form relates.

AC5 Form – Allowable Cost, Custom Processing Fees Paid:

• Assess the penalty of $100 per month or part of a month on the receipt of the AC5 form after the due date of May 15 of the year following the production year to which the form relates, rather than the current penalty of $100 per month or part of a month for failing to file the expected AC5 form by the prescribed due date.

• Grant 15 days grace period for penalty levy if the AC5 form was received on or before May 15 of the year following the production year to which the form relates but was rejected because of MRIS edits.

RMF3 Calculation and Examples The RMF3 document allows operators of a well, that has a Crown interest greater than 0% but less than 100%, to report the working interest % and Crown interest % for the working interest owners. The Crown Share % for each client will be used in the royalty calculation instead of the Provincial Crown interest% for the well.

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Here are three calculation rules that apply to an RMF3 document:

• Total Working Interest Owner % must equal 100. • WIO% multiplied by the Crown% must equal the Crown Share for each client. • Total Crown Share must equal the Total Crown % reported in Field 2.6.

Note: The Crown Share is not reported on the RMF3 – the Department will calculate the Crown Share for each client by multiplying Field 2.9 by Field 2.10, and ensure that the Total Crown Share for the well agrees with the Provincial Crown interest % for the well. The following examples are provided for clarification when calculating the Crown % when completing an RMF3 document (field 2.10): Example 1. Well is 75% Crown, 25% Freehold. Total spacing for the well is 256 hectares. Client A holds 64 hectares (25%) which are 100% Crown. Client B holds 64 hectares (25%) which are 100% Crown. Client C holds 64 hectares (25%) which are 100% Freehold. Client D holds 64 hectares (25%) which are 100% Crown. RMF3 should be filed as:

(2.7) Client (2.9) WIO% (2.10) Crown % Calculated Crown Share A 25.00 100.00 25.00 B 25.00 100.00 25.00 C 25.00 0.00 0.00 D 25.00 100.00 25.00

Total 100.00 75.00 Example 1a. Client D acquires Client C’s share of the property. Revised ownership is: Client A holds 64 hectares (25%) which are 100% Crown. Client B holds 64 hectares (25%) which are 100% Crown. Client D now holds 128 hectares (50%) which are 50% Crown. {Crown % = (64.0 / 128.0) x100}. Revised RMF3 should be filed as:

(2.7) Client (2.9) WIO% (2.10) Crown % Calculated Crown Share % A 25.00 100.00 25.00 B 25.00 100.00 25.00 D 50.00 50.00 25.00

Total 100.00 75.00

Example 2. Well is 25% Crown, 75% Freehold. Total spacing for well = 256 hectares Client A holds 18.944 hectares (7.40%) which are 100% Crown. Client B holds 139.904 hectares (54.65%) of which 39.168 are Crown hectares. {Crown % = (39.168/139.904) x100}. Client C holds 91.264 hectares (35.65%) which are 100% Freehold. Client D holds 5.888 hectares (2.30%) which are 100% Crown.

16


RMF3 should be filed as:

(2.7) Client (2.9) WIO% (2.10) Crown % Calculated Crown Share % A 7.40 100.0000000 7.40 B 54.65 27.9963403 15.30 C 35.65 0.0000000 0.00 D 2.30 100.0000000 2.30

Total 100.00 25.00 Example 2a. Client B acquires Client C’s share. Client B now holds 231.168 hectares (90.30%) Crown hectares for Client B = 39.168 ha. The new Crown Interest for Client B = (39.168/231.168) x 100 = 16.9435216% Revised RMF3 should be filed as:

(2.7) Client (2.9) WIO% (2.10) Crown% Calculated Crown Share %A 7.40 100.0000000 7.40 B 90.30 16.9435216 15.30 D 2.30 100.0000000 2.30

Total 100.00 25.00

Royalty Payers Only (Companies and individuals that are not operators of facilities, but do currently receive information from industry partners, or invoices, statements and other correspondence from the Department of Energy have been deemed “Royalty Payers Only” by the Petroleum Registry of Alberta) Ease of Use The Petroleum Registry of Alberta has been designed to make it easier for stakeholders to receive and submit data to Industry partners and the Ministry of Energy. To increase ease of use of the Registry, free “Royalty Payers Only” training modules are being developed and will be posted to the Registry web site by the end of July. To obtain a training ID and password for these modules, visit the “Online Industry Training” section in the Training area of the Registry web site at www.petroleumregistry.gov.ab.ca. A major benefit of using the Registry is eliminating paper from the process, as users will have the capability of electronically submitting and receiving data through the Registry from their computer at home or office. Royalty payers who do not have their own computer can use any computer with Internet access. One location that provides computers with Internet access to the public is the local library. Below is a list of the minimum client technical configuration for any computer used to access the Registry. Hardware - Pentium 133 Mhz - 32 MB Win 95/98 or 64 MB for Microsoft Windows NT or 2000

17



Software - Microsoft Windows 95/98/NT 4.0/2000/XP - Internet Explorer 4.0+ or Netscape 4.0+ (both support 128bit encryption) - JavaScript enabled - Screen size 800x600 Networking - Internet Access at 28.8 kbps or greater There is also a minimum requirement that users of the Registry have 128-bit encryption built into their Internet browser. Without this level of encryption, a user will not be able to access the work area of the Registry. This encryption level provides security for those using the system and the information contained in the Registry. To ensure that your browser version has 128 bit encryption, or if you just want to upgrade your browser, we have included instructions for this upgrade.

For Netscape

• Go to www.netscape.com • Click the “New Download” Button. • Click the “Netscape Communicator Series” link. • Click the “English” link. • Click the “Windows 95, 98, NT, or 2000” link. • Click the “4.79 latest version” link. • Choose either the “base” or “complete” link and click it. • Click the “Download It Now” button. • Follow the instructions on the page.

For Internet Explorer

• Go to www.microsoft.com/windows/ie/default.asp • Click the “Downloads” button. • Click the “Microsoft Internet Explorer 6” link. • Click the “Go” button at the far right side of the screen. • Follow the instructions on the page. A reminder: Users must have a minimum of version four of their browser (Netscape or Internet Explorer) to use the Registry. As a company or individual that will perform work processes, or communicate within the Registry, you must also be identified as a 'Business Associate' (BA). Any royalty payer who sends or receives information from the Ministry of Energy already has a 7 digit Royalty Client Code. These 7-digit codes have been converted into new four-digit Business Associate codes. Refer to the Department of Energy web site: www.energy.gov.ab.ca/gmd/images/MasterList.pdf

18

http://www.netscape.com/

http://www.microsoft.com/windows/ie/default.asp



Royalty Deposit Adjustment The royalty deposit recalculation for 2002 is the lesser of 1/6 of a client's net royalty for 2001 and the amount determined by multiplying the current deposit maintained by the client by a price factor. The factor of (1.00) was calculated by dividing the current year long-term gas reference price for 2002 ($3.50) by the long-term gas reference price used in the 2001 ($3.50) calculation.

F. PRINCIPLES AND PROCEDURES

Updates

The Department updates the Alberta Natural Gas Royalty Principles and Procedures manual when there is a major change in relevant policy or legislation, and regularly to incorporate information published in Information Letters and Information Bulletins. Please include any inserts provided in this section of the monthly Information Bulletin in your copy of the Principles and Procedures. There is no new information to incorporate for August 2002.

G. POINTS OF CONTACT

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: www.energy.gov.ab.ca

Note: The sulphur price can be accessed by calling 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 Calculation

Gas Royalty Calculation can be reached at:

Telephone: (780) 427-2962 Fax: (780) 427-3334 or (780) 422-8732

Alberta Toll Free: 310-0000 (Please do not dial “1” or “780”.) 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.

19

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


Calgary Information Centre 3rd Floor, 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: 310-0000 Fax: (780) 427-5074

For further information, please contact Angelina Leung at (780) 427-9425 ext 251.

David Breakwell Director, Gas Royalty Calculation Gas and Markets Development

Attachments

20

INFORMATION BULLETIN – August 2002 ATTACHMENT 1

2002 PRICES

MONTH

GAS REF

PRICE ($ per GJ)

GAS PAR

PRICE ($ per GJ)

ETHANE

REFERENCE PRICE

($ per GJ)

ETHANE

PAR PRICE

($ per GJ)

PENTANES

REF PRICE

($ per m3)

PENTANES

PAR PRICE

($ per m3)

PROPANE

REF PRICE

($ per m3)

PROPANE

FLOOR PRICE

($ per m3)

BUTANE

REF PRICE

($ per m3)

BUTANE FLOOR PRICE

($ per m3)

SULPHUR DEFAULT

PRICE ($ PER

TONNE)

JAN 3.17 3.20 3.17 3.20 192.56 179.80 88.15 62.44 125.51 100.92 4.25

FEB 2.71 3.17 2.71 3.17 202.39 182.71 88.14 61.67 133.59 85.58 2.08

MAR 3.23 2.71 3.23 2.71 238.61 188.93 115.54 89.46 151.29 120.48 6.81

APR 3.91 3.23 3.91 3.23 266.20 228.29 127.52 119.33 165.92 142.78 4.43

MAY 3.91 3.91 3.91 3.91 267.65 255.79 125.63 109.72 161.03 132.84 6.94

JUN 3.54 3.91 3.54 3.91 251.58 257.71 105.48 96.77 149.66 130.06 8.67

JUL

AUG

SEPT

OCT

NOV

DEC

DETAIL OF THE JUNE 2002 GAS REFERENCE PRICE SELECT PRICE 2002 Weighted Average Price of Alberta 3.841 $/GJ New Gas

($per GJ) Old Gas ($per GJ)

Pentanes ($per m3)

Deductions: Intra – Alberta Transportation 0.287 $/GJ 1.252 0.372 45.30

Marketing Allowance 0.028 $/GJ New Ethane($per GJ)

Old Ethane ($per GJ)

Price Before Pipeline Factor 3.526 $/GJ 1.252 0.372

Pipeline Fuel/Loss Factor 0.986 Price before Special Adjustment 3.477 $/GJ

Special Adjustment 0.000 $/GJ Price before 2% amendment limitation or rounding 3.477 $/GJ Weighted Average Reference Weighted Average OMAC Amendments:Carry forward (from previous RP month) 0.172 $/GJ Price ($/GJ) ($/GJ) Prior Period Amendment Adjustment (current RP month) -0.015 $/GJ

5.111 0.021 Calculated RP after Amendments 3.634 $/GJ JUNE 2002 Reference Price 3.54 $/GJ Difference = value carried forward to next RP month 0.094 $/GJ

Adjusted IATD (before Prior Period Amendments) 0.283 $/GJ ANNUAL SULPHUR DEFAULT PRICE Prior period Amendments (IATD and Pipeline Fuel Loss) 0.000 $/GJ 1997 1998 1999 2000 2001 Adjusted IATD (after Prior Period Amendments) 0.283 $/GJ $9.98 $6.01 $10.54 $10.96 $0.30


ATTACHMENT 2 2002

TRANSPORTATION ALLOWANCE AND DEDUCTIONS

PENTANES PLUS (a)

PROPANE AND BUTANE (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 2.74 10.49 15.00 17.89 7.94 1.71 5.94* 6.39 9.99 15.92 15.26 7.81 8.75

FEB 10.24 12.31 15.91 19.03 9.42 4.64 7.92* 11.27 9.87 17.05 24.66 9.89 8.75

MAR 11.82 7.51 11.69 11.92 6.47 3.08 5.43* 7.48 13.28 16.64 27.47 16.61 8.75

APR 8.41 8.99 15.55 13.48 -0.40 -5.55 -2.00* 3.54 7.46 11.14 18.38 7.57 8.75

MAY 6.40 9.39 16.71 12.61 6.36 -1.34 3.93* 7.52 8.86 15.73 15.95 8.55 8.75

JUN 8.33 13.56 15.24 13.94 1.93 4.12 2.66* 6.28 7.76 12.24 18.61 5.92 8.75

JUL

AUG

SEPT

OCT

NOV

DEC

(a) Pentanes Plus obtained as a specification gas product, (b) Propane and Butane 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 – August 2002 ATTACHMENT 2A

PRIOR PERIOD AMENDMENT EFFECTS

NGL REFERENCE PRICES JUNE 2002

Propane Butane Pentanes

Price before amendments 105.486102 149.660795 251.583901

Opening Rollover (from prior business month) -0.004615 -0.003080 -0.001448

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 105.48 149.66 251.58

TRANSPORTATION ALLOWANCES JUNE 2002

Pentanes Plus Propane and Butane 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) 0.004762 0.001438 -0.001977 -0.003496 0.003273 0.003960 -0.001492 -0.000307 -0.004166 -0.002825 -0.001031 0.003994

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 0.000000 0.000000 0.000000 0.000000 0.000000 -0.008803 0.000000 0.000000 0.000000

Total Amendment Effect 0.004762 0.001438 -0.001977 -0.003496 0.003273 0.003960 -0.001492 -0.000307 -0.012969 -0.002825 -0.001031 0.003994

Calculated Transp. Differential 8.324182 13.558888 15.239980 13.946533 1.926345 4.117369 2.659013* 6.281203 7.775604 12.238896 18.611389 5.918316

Calculated Transp. Differential after Total

Amendments

8.328944 13.560326 15.238003 13.943037 1.929618 4.121329 2.657521* 6.280896 7.762635 12.236071 18.610358 5.922310

Published Transportation Allowance 8.33 13.56 15.24 13.94 1.93 4.12 2.66* 6.28 7.76 12.24 18.61 5.92 * 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.


ATTACHMENT 3

2002

ROYALTY RATES

MONTH

GAS - OLD (GOL)

(per GJ)

GAS – NEW (GNE)

(per GJ)

ETHANE – OLD

(per GJ)

ETHANE – NEW

(per GJ)

PENTANES - OLD

(POL) (per m3)

PENTANES - NEW

(PNE) (per m3)

JAN 35.00000 30.00000 35.00000 30.00000 42.94549 31.72469

FEB 35.00000 30.00000 35.00000 30.00000 43.05785 31.77686

MAR 35.00000 28.45018 35.00000 28.45018 43.28640 31.88297

APR 35.00000 30.00000 35.00000 30.00000 44.44391 32.42039

MAY 35.00000 30.00000 35.00000 30.00000 45.04124 32.69772

JUN 35.00000 30.00000 35.00000 30.00000 45.07819 32.71487

JUL

AUG

SEPT

OCT

NOV

DEC

INFORMATION BULLETIN – August 2002 FACILITY OPERATOR CHANGE FORM OC1 ATTACHMENT 4

EUB FACILITY FACILITY NAME PREVIOUS OPERATOR NAME PREVIOUS

CLIENT ID CURRENT OPERATOR NAME CURRENT CLIENT ID

EFFECTIVE DATE

AB-GP-1020 BONAVISTA CARSTAIRS DEVON CANADA 0F3F BONAVISTA PETROLEUM LTD 0MD6 2002-06

AB-GP-1060 SOLEX GAS HARMATTAN ELKTON NOVAGAS CANADA LTD 0TA4 SOLEX GAS PROCESSING CORP 0C5F 2002-06

AB-GP-1083 BONAVISTA HARMATTAN-ELKTON DEVON CANADA 0F3F BONAVISTA PETROLEUM LTD 0MD6 2002-06

AB-GP-1197 NCE PETROFUND PROVOST 4-16 GAS PLANT NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06

AB-GP-1289 NCE FERRIER NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06

AB-GP-1603 NCE PEMBINA NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06

AB-GP-1608 ONYX FENN WEST 14-18 GP ALBERTA ENERGY COMPANY LTD 0R61 ONYX OIL & GAS LTD 0X1G 2002-06

AB-GP-1614 NCE PETROFUND THREE HILLS CK NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06

AB-GP-1787 NCE PETROFUND PEMBINA 10-14 NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06

AB-GP-1811 SOLEX GAS HARMATTAN-ELKTON NOVAGAS CANADA LTD 0TA4 SOLEX GAS PROCESSING CORP 0C5F 2002-06

AB-GP-1872 NCE PETROFUND PROVOST 16-12 NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06

AB-GP-1894 NCE PETROFUND PROVOST 16-32 GAS PLANT NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06

AB-GP-1985 INTEGRA MANASKA 4-18 GREY WOLF EXPLORATION INC 0TH6 INTEGRA RESOURCES LTD 0YB3 2002-07

AB-GS-2205 DUKE MIDSTREAM NEVIS DUKE ENERGY FIELD SERVICES CANADA LTD 0YK3 DUKE ENERGY MIDSTREAM SERVICES

CANADA LTD 0ZK9 2002-01

AB-GS-2236 BONAVISTA CARSTAIRS DEVON CANADA 0F3F BONAVISTA PETROLEUM LTD 0MD6 2002-06 AB-GS-2335 BONAVISTA HARMATTAN-ELKTON DEVON CANADA 0F3F BONAVISTA PETROLEUM LTD 0MD6 2002-06 AB-GS-2554 NCE PETROFUND PROVOST 1 NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06 AB-GS-2602 FOX MEDICINE HAT HILDA GGS FOX ENERGY CORPORATION 0RZ3 EOG RESOURCES CANADA INC 0K13 2002-06

AB-GS-2789 EOG O&G HILDA RAMARRO RESOURCES INC 0GG4 EOG RESOURCES CANADA INC 0K13 2002-06

AB-GS-2832 DUKE MIDSTREAM BUFFALO DUKE ENERGY FIELD SERVICES CANADA LTD 0YK3 DUKE ENERGY MIDSTREAM SERVICES


AB-GS-2882 NCE PETROFUND BLOOD NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06

AB-GS-2944 DUKE MIDSTREAM FENN-BIG VALLEY DUKE ENERGY FIELD SERVICES CANADA LTD 0YK3 DUKE ENERGY MIDSTREAM SERVICES 0ZK9 2002-01

AB-GS-2951 NCE TURIN NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06

AB-GS-2998 EOG CESSFORD RAMARRO RESOURCES INC 0GG4 EOG RESOURCES CANADA INC 0K13 2002-06

AB-GS-3061 MONOLITH EYREMORE MURPHY CANADA EXPLORATION COMPANY 0MY7 MONOLITH ENERGY PARTNERSHIP 0W9E 2002-04

AB-GS-3064 EOG CESSFORD RAMARRO RESOURCES INC 0GG4 E0G RESOURCES CANADA INC 0K13 2002-06

AB-GS-3285 CHEVRON BRAZEAU RIVER ENERPRO MIDSTREAM INC 0A7R CHEVRON CANADA LIMITED 0045 2001-10

AB-GS-3330 NCE PEMBINA NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06

AB-GS-3398 ONYX OIL FENN WEST GGS ALBERTA ENERGY COMPANY LTD 0R61 ONYX OIL & GAS LTD 0X1G 2002-06

AB-GS-3443 CNRL PHILP ROZSA PETROLEUM LTD 0DP3 CANADIAN NATURAL RESOURCES LIMITED 0HE9 2002-05

Page 1 of 2

INFORMATION BULLETIN – August 2002 FACILITY OPERATOR CHANGE FORM OC1 ATTACHMENT 4

EUB FACILITY FACILITY NAME PREVIOUS OPERATOR NAME PREVIOUS

CLIENT ID CURRENT OPERATOR NAME CURRENT CLIENT ID

EFFECTIVE DATE

AB-GS-3460 NCE PETROFUND THREEHILLS NCE RESOURCES GROUP INC 0PR8 NCE PETROLFUND CORP 0MH4 2002-06 AB-GS-3524 PROVIDENT CRAIGMYLE DEVON CANADA 0F3F PROVIDENT ACQUISITIONS L P 0X0T 2002-05

AB-GS-3564 DUKE MIDSTREAM FENN BIG VALLEY DUKE ENERGY FIELD SERVICES CANADA LTD 0YK3 DUKE ENERGY MIDSTREAM SERVICES


AB-GS-3567 DUKE MIDSTREAM STETTLER DUKE ENERGY FIELD SERVICES CANADA LTD 0YK3 DUKE ENERGY MIDSTREAM SERVICES


AB-GS-3570 DUKE MIDSTREAM CLIVE 4-15 DUKE ENERGY FIELD SERVICES CANADA LTD 0YK3 DUKE ENERGY MIDSTREAM SERVICES


AB-GS-3629 CNRL BEAU LINDBERG MURPHY CANADA EXPLORATION COMPANY 0MY7 CANADIAN NATURAL RESOURCES

LIMITED 0HE9 2002-05

AB-GS-3894 DUKE MIDSTREAM NEVIS (SWEET) DUKE ENERGY FIELD SERVICES CANADA LTD 0YK3 DUKE ENERGY MIDSTREAM SERVICES


AB-GS-3904 NCE PETROFUND VALHALLA NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06 AB-GS-3908 PROVIDENT CESSFORD DEVON CANADA 0F3F PROVIDNET ACQUISTIONS L P 0X0T 2002-05

AB-GS-3970 DUKE MIDSTREAM FENN WEST DUKE ENERGY FIELD SERVICES CANADA LTD 0YK3 DUKE ENERGY MIDSTREAM SERVICES


AB-GS-3998 NCE RESOURCES PREVO CRESTAR ENERGY INC 0NL2 NCE RESOURCES GROUP INC 0PR8 1999-06 AB-GS-3998 NCE PETROFUND PREVO NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06 AB-GS-4111 NCE PETROFUND GARRINGTON NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06 AB-GS-4374 NCE PETROFUND PROVOST NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06

AB-GS-4386 PETROBANK SHEKILIE CUBE ENERGY CORP 0BL9 PETROBANK ENERGY AND RESOURCES LTD 0TH8 2002-01

AB-GS-4397 NCE PETROFUND BLOOD NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06 AB-GS-4422 NCE PETROFUND EYREMORE NCE RESOURCES GROUP INC 0RP8 NCE PETROFUND CORP 0MH4 2002-06 AB-GS-4445 NCE PETROFUND PROVOST NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06 AB-GS-4474 ANADARKO ET AL HIGH PRAIRIE CLARINET RESOURCES LTD 0RP8 ANADARKO CANADA ENERGY LTD 0PW9 2001-12 AB-GS-4502 NCE PETROFUND MAGRATH NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06 AB-GS-4507 EOG CESSFORD NORTH RAMARRO RESOURCES INC 0GG4 E0G RESOURCES CANADA INC 0K13 2002-06 AB-GS-4620 INTEGRA MANASKA 4-18 GREY WOLF EXPLORATION INC 0TH6 INTEGRA RESOURCES LTD 0YB3 2002-07 AB-GS-4684 RANCHGATE LEO GATHERING SYSTEM BAYTEX ENERGY LTD 0RL9 RANCHGATE OIL AND GAS LIMITED 0C3D 2002-06 AB-GS-4742 FOGO RESOURCES FT SASK SHININGBANK ENERGY LTD 0TR8 FOGO RESOURCES INC 0C8W 2002-01 AB-GS-4856 NCE PETROFUND MCINTYRE NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06 AB-GS-6093 BONAVISTA HARMATTAN WEST GGS DEVON CANADA 0F3F BONAVISTA PETROLEUM LTD 0MD6 2002-06 AB-GS-6235 RIO ALTO WOKING 16-9 BAYTEX ENERGY LTD 0RL9 RIO ALTO EXPLORATION LTD 0BM8 2002-04 AB-GS-6299 NCE PETROFUND PEMBINA 102/10-14 NCE RESOURCES GROUP INC 0PR8 NCE PETROFUND CORP 0MH4 2002-06 AB-GS-6384 NAL STURGEON LK 12-15 CRESTAR ENERGY INC 0NL2 NAL RESOURCES LIMITED 0TM9 2002-02

Page 2 of 2


NEW PLANTS

EUB FACILITY CODE

FACILITY NAME

TRANSPORTATION REGION

PLANT TYPE

PLANT TYPE

EFFECTIVE DATE

AB-GP-1800 AEC SUFFEILD A2 SOLUTION GAS FACILITY 2 1 2000-08

AB-GS-6460 BRIGUS BOW ISLAND COMPRESSOR 14-08 2 1 2002-07

AB-GS-6461 ATLAS MCGREGOR LAKE 5-5 2 1 2002-06

AB-GS-6462 SAMSON KAKWA 16-36 4 1 2002-07

AB-GS-6463 DEVON WILLESDN GREEN 11-23 1 1 2002-07

AB-GS-6464 GNEL PADDLE RIVER 2-15 GGS 1 1 2002-07

AB-GS-6465 HUSKY 2-3 1 1 2002-07

AB-GS-6466 VISTA SEAFORD GGS 4 1 2002-07

INFORMATION BULLETIN - August 2002 ATTACHMENT 6

Facility ID

Facility Operator

IDProduction

Period Billing Period

Royalty Trigger Factor

Pipeline Operator

Meter Station ID

Meter Station Factor

Deleted Tie Facility to

Meter Tie Date

Facility to Meter

Termination Date

Meter Station Effective Date

Meter Station Termination

DateAB-GS-6384 0TM9 2002-02-01 2002-06-01 1.09 NOVA 2268 1.09 2002-02-01 3000-01-01 2001-10-01 3000-01-01AB-GS-6405 0XE2 2002-04-01 2002-06-01 0.52 NOVA 1839 0.52 2002-04-01 3000-01-01 2002-04-01 3000-01-01

There are no changes to this month's Injection and Reproducing Facility Ties Report

Multiple Gas Valuation Factors

Injection and Reproducing Facility Ties


Registry ISC Reporting Table (Revised)

For activity at reporting facility and from/to location, submitter must report ISC, along with the Gas volumetric submission to the Registry.

Submitter Reporting Facility

Activity From/To Location

Pipeline Operator

AB PL REC AB MS sub type 631

Pipeline Operator, or Common Stream Operator

AB MS where Registry auto population is not elected

REC AB BT, AB GS, AB GP

Mainline Straddle Plant Operator

AB GP sub type Mainline Straddle


Field Straddle Plant Operator

AB GP sub type Field Straddle


Injection Facility Operator

AB IF REC AB BT, AB GS, AB GP

Battery, Gathering System or Gas Plant Operators

AB BT, GS, or GP

DISP Any non reporting AB MS/PL

Battery, Gathering System or Gas Plant Operator

AB BT, GS, or GP

DISP AB RE, AB CO, AB IN, AB EG, AB R1, AB R2

Battery, Gathering System or Gas Plant Operators

AB BT, GS, or GP

DISP Any non AB location

Raw Gas Sellers

Report ISC factors of raw gas stream on RGA Submission

AB Alberta BT Battery CO Commercial DISP Disposition EG Electrical Generation GP Gas Plant GS Gathering System IF Injection Facility IN Industrial MS Meter Station PL Pipeline RE Residential REC Receipt R1/R2 Residential Pipeline

Documents

Gas Royalty Calculation Information Bulletin - August 2002 · GAS ROYALTY CALCULATION INFORMATION BULLETIN August 2002 A. PRICING RATES AND TRANSPORTATION INFORMATION Pricing, Royalty