GAS ROYALTY CALCULATION INFORMATION BULLETIN January 2003

Transcription

1 ENERGY Petroleum Plaza North Tower Street Edmonton, Alberta Canada T5K 2G6 GAS ROYALTY CALCULATION INFORMATION BULLETIN January 2003 A. PRICING RATES AND TRANSPORTATION INFORMATION Pricing, Royalty Rates and Transportation Information November B. NOTICES Update on Royalty and Related Information Review Initiative for the Proposed Operating Cost Regime Change... 2 Provisional Assessment Notice... 3 Revised ISC Reporting Table... 4 Department of Energy SAF/OAF (Allocations) Deadlines and Ensure Complete Report... 4 C. MONTHLY INFORMATION November 2002 Royalty Due February December 2002 VA4 Due February December 2002 Production Reporting... 5 Interest Rate January October Provisional Assessment Charge... 5 October 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 Revised Registry Heat Ranges... 8 Well Groups... 8 Remaining Useful Life (RUL) Form... 8 Alberta Natural Gas and Natural Gas Liquids Royalty (NGL) Framework Changes... 9 Update 1998 Audits in Progress Close-out for Operations Commercial Storage Scheme Reporting Clarification of Services Available on ETS After Registry Implementation F. PRINCIPLES AND PROCEDURES Updates G. POINTS OF CONTACT Petroleum Registry of Alberta Department of Energy Hotline & Internet Gas Royalty Calculation Calgary Information Centre Alberta Royalty Tax Credit Information PLEASE ENSURE YOUR PRODUCTION ACCOUNTANTS RECEIVE A COPY OF THIS DOCUMENT. Internet Address:

2 A. PRICING RATES AND TRANSPORTATION INFORMATION For Pricing, Royalty Rates and Transportation Information for November 2002, refer to Attachments 1, 1A, 2, 2A, and 3. B. NOTICES Update on Royalty and Related Information Review Initiative for the Proposed Operating Cost Regime Change In January 1998, the Royalty and Related Information Review (RRIR) task force, a joint industry-government initiative, recommended changes to the administration of Crown royalties and the reporting of upstream production information. One of the key recommendations of the task force was the development of a central registry that would contain key gas and oil information. A second was to look at consolidating the reporting that was required by the Energy and Utilities Board and the Department of Energy. These two recommendations have now been realized with the recent inception of the Petroleum Registry of Alberta (the Registry). The final recommendation was to look at a number of reporting and administrative changes mainly associated with the reporting and calculation of Allowable Costs. The RRIR committee, also consisting of industry and Ministry representatives, was formed to further explore in detail the various changes under this recommendation. One of the suggestions from the task force was to review the current unit operating cost rate (UOCR) deduction regime. The RRIR group has now concluded that operating cost deductions might be more appropriately aligned with actual cost experience, rather than through today s unit operating cost rate deduction. However, the group agreed that while actual cost reporting would be the most accurate, it would create too much of an administrative burden to report actual costs for every facility cost centre. After a lengthy consultative process, the committee has recommended a hybrid model where processing costs (costs associated with facilities that are classified by the EUB as gas plants that extract sulphur or liquids from gas) would be based on actual cost experience, while gathering and compression costs would be based on a unit rate. The gathering and compression unit rate will be determined from an annual cost survey. The cost survey will obtain a statistically representative sample of actual operating costs from gathering systems and compression facilities in the province from which unit rates for geographic regions with similar resource and cost characteristics will be determined. To ensure objectivity, it was agreed that a third party consultant should be hired to select the statistical sample and compile the information. The Department is in the process of seeking tenders to develop this cost survey. An impact study is required by the Department before proceeding on the hybrid recommendation of the RRIR Committee. Operators of facilities that meet the reporting criteria are required to assist the Department in gathering the information for the impact study. The Department intends to complete the impact study by June 30, In order to be able to evaluate the potential royalty impact of the hybrid proposal on processing facilities, operators of these processing facilities as defined above will be asked to report their actual operating costs for a sample-reporting period to be determined by the RRIR committee. 2

3 Complete details as to the information required and the reporting format will be forwarded in writing to the affected processing facility operators in the upcoming months. The royalty impact of the move to a cost survey for gathering and compression will be evaluated through analysis of the information provided by operators selected to participate in the survey by the third party consultant. Complete details of the information required and the reporting format will also be forwarded in writing to the affected gathering and compression facility operators in the upcoming months. Additional details will be communicated on the proposed operating cost regime changes in future Information Bulletins. This notification is intended to ensure that all facility operators and royalty clients are aware of the ongoing discussions between the Department and representatives of the Canadian Association of Petroleum Producers (CAPP) and Small Explorers and Producers Association of Canada (SEPAC) regarding operating cost procedures. For further information you may contact: RoseAnn Summers, (780) or Dave van Kampen, Industry Committee Member (403) or Cory Heerensperger, Industry Committee Member (403) Provisional Assessment Notice The provisional royalty compensation (provisional assessment) for post Registry implementation production periods is triggered from reporting discrepancies in the Stream Allocation Factor (SAF) and Owner Allocation Factor (OAF) submissions. If operators fail to correct the reporting errors that are identified on the Department of Energy (DOE) Ensure Complete report by the DOE allocation submission deadline, the volumes in error are then subject to provisional royalty compensation. Royalty clients who correct their SAF/OAF reporting errors prior to the 15 th of the following month will also have any related current period interests (CPI) waived. Note: For the October production period, filing deadline for CPI reversal was extended to January 22. Refer to the DOE SAF/OAF (Allocations) Deadlines section of this Bulletin. Royalty clients who correct their SAF/OAF reporting errors will have any provisional assessment charges and related prior period interest charges reversed. If a stakeholder believes the Provisional Assessment charges on their monthly Gas Royalty Invoice are incorrect; they should contact the Gas Royalty Client Services Help Desk at (780) The DOE will review, on a case-by-case basis, situations where clients believe a problem has occurred. If a charge is determined to be the result of performance/calculation errors with the Petroleum Registry of Alberta, or calculation errors with the Mineral Revenue Information System (MRIS), the DOE will reverse the provisional assessment and the corresponding interest. 3

4 Revised ISC Reporting Table The Department has revised the 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, to allow Common Stream Operators to file ISC receipts from out of province facilities. For a copy of the revised reporting table refer to Attachment 6. Department of Energy SAF/OAF (Allocations) Deadlines and Ensure Complete Report Due to the large number of clients who had difficulties accessing the Registry, the DOE extended the SAF/OAF submission deadline from January 15 to January 22, 2003, for the November production month invoice, produced in January 2003 calendar period. The DOE also extended the deadline for correcting provisional assessments related to the October 2002 production month to January 22. The distribution of the DOE Ensure Complete report was deferred to January 20. By extending the SAF/OAF deadline, DOE enabled Industry Clients more time to get their allocation data in and have their Crown Royalty charges assessed accurately, reducing the potential of high provisional assessment charges. C. MONTHLY INFORMATION November 2002 Royalty Due February 28 Royalty clients are to remit the total amount payable shown on the February 2003 Statement of Account by February 28, 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 February 2003 Statement of Account shows your amount payable as of the Statement issue date. It includes any outstanding balances from your previous statement, your November 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 November 2002 if it is paid in full by February 28, 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. 4

5 December 2002 VA4 Due February 18 The VA4 documents for the production month of December 2002 are due in the Department offices by February 18, NOTE: If the due date (15 th ) falls on a non-business day, the next business day will apply as the due date for VA4 documents. December 2002 Production Reporting December 2002, and subsequent production reporting is submitted through the Registry. The deadline for submission of SAF, OAF, and Volumetrics is posted in the Registry Reporting Calendar at: Changes to this calendar will be posted on the Registry web site home page in Broadcast Messages. Interest Rate January 2003 The Department of Energy s interest rate for January 2003 is 5.50%. October Provisional Assessment Charge The net Provisional Assessment Charge for the October 2002 billing period was $232,148, This includes $267,167, in first time provisional assessments and ($35,019,152.06) in reversals of provisional assessments for all production periods. October Penalty Charges The following are the Penalty Charges by form type for the October 2002 billing period: FORM Penalties Charged AC2 $64,000 AC4 $0 AC5 $19,200 GR2 $0 NGL1 $0 VA2 $0 VA3 $0 VA4 $0 Total Charged $83,200 Total Reversed ($20,900) Net Penalties Charged for 2002/10 $62,300 5

6 Alberta Royalty Tax Credit Program Quarterly Rate For the first quarter of 2003, the Alberta Royalty Tax Credit rate will be This rate is based on a royalty tax credit reference price of $ per cubic metre. The Alberta Royalty Tax Credit rates for the past year were: Fourth Quarter, Third Quarter, Second Quarter, First Quarter, If you have any questions, please contact Kent Nelson of Tax Services at (780) , ext 250. D. INFRASTRUCTURE DATA CHANGES Client ID Listing The Client ID listing can be found on the Internet at the following address: The listing, which is updated monthly for active clients, also includes clients who are inactive, struck, or terminated since January Please note the Client ID listing (Post Registry) corresponds with the implementation of the Registry. For effective dates of active and amalgamated clients prior to September 1, 2002, please refer to the Client ID listing (Pre Registry). If you require information before January 1998 regarding the status of a Client ID, please call the Gas Royalty Client Services Helpdesk at (780) 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 February 2003 Information Bulletin. If further information is required on any other projects, please contact Isabelle Warwa at (780) 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)

7 The following is a list of struck, dissolved, revived and cancelled clients: Company Name Client ID Struck Date Alberta Ltd. 0D3F December 2, Alberta Ltd. 0ZH7 November 2, 2002 Benex Enterprises Inc. 0KT9 November 2, 2002 Forest Oil Corporation 0254 November 2, 2002 Inland Pacific Energy Services Ltd. 853B December 2, 2002 International Reef Resources Ltd. 0P38 December 2, 2002 Keltic Resources Ltd. 0H4R November 2, 2002 Kinetic Holdings Limited 0P9A November 2, 2002 Leigh Resource Corporation 0H9G November 2, 2002 Lone Butte Energy Inc. 0J0P November 2, 2002 Minefund Development Corporation 0K2E November 2, 2002 Mitchell & Associates Ltd November 2, 2002 MTA International Marketing Group Ltd. 0T94 December 2, 2002 PGE Resource Corporation 0MG1 December 2, 2002 Tirol Inc November 2, 2002 Town Development Corporation Ltd. 0N3D November 2, 2002 Turnkey Well Abandonments Inc. 0C78 December 2, 2002 Company Name Client ID Dissolved Date Altrade Canada Inc. 0ZJ3 December 12, 2002 Canstates Gas Marketing Ltd. 0LA4 October 24, 2002 Oil & Gas Techno Service Ltd. 0G27 December 13, 2002 Company Name Client ID Revived Date Alberta Ltd. 0R7J December 6, 2002 Dangerfield Resources Inc. 0JZ1 December 11, 2002 Kalta Energy Corp. 0YH2 October 30, 2002 McGinnis Petroleum Services Ltd. 0TT3 December 3, 2002 Rimrock Drilling Ltd. 0Z02 October 22, 2002 Company Name Client ID Cancelled Date Stringroad Resources Inc. 0M6R December 2, 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 on the Department Internet site at: 7

8 E. REMINDERS Revised Registry Heat Ranges The Department has updated the Registry ISC Heat Ranges table included in the town hall training sessions as part of the Alberta Natural Gas Liquids Royalty (NGL) Framework Change. ISC heat range reporting will be monitored by the Department over the next few months and additional changes or updates may occur. The updated table is included in Attachment 7. Well Groups For production periods October 2002 and beyond, well group reporting in the Registry is only applicable for non-consolidated well groups (projects, blocks, non-unit gas, non-unit oil, nonunit spacing, joint operating agreements). For production periods prior to October 2002, these entities are reported on the Owner Activity Statement (OAS) with a letter A preceding the well group number e.g. AB WG A For Registry reporting, the A must be removed such that the reporting would look like: AB WG A complete listing of non-consolidated well groups is now available on the Department s Internet site at: Remaining Useful Life (RUL) Form Information Letter (IL) indicates that in cases where the estimated useful life of a new or existing Facility Cost Centre is less than 10 years, royalty clients must file supporting documentation with their Facility Cost Centre Setup/Change (AC1) application. In cases where the estimated useful life of a new or existing Facility Cost Centre is greater than 10 years, royalty clients are expected to retain supporting documentation and submit it for review at the Department s request. This supporting documentation, required by the Department, in cases where the estimated useful life was either greater or less than 10 years, had to include information that was certified by an accredited engineer. This requirement has not changed and the Department reserves the right to request backup for any changes to the RUL. However, we have introduced a new form, Remaining Useful Life (RUL) Form, which replaces the engineer s report. Our engineers have helped us create this form to ensure that all the backup information provided by industry is consistent. Please refer to Attachment 6 of the December 2002 Gas Royalty Calculation Information Bulletin for a copy of this form. If you have any questions, please contact the Client Services Help Desk at (780)

9 Alberta Natural Gas and Natural Gas Liquids Royalty (NGL) Framework Change The Department's Information Letter and Gas Royalty Calculation June Information Bulletn, 02-06A introduced the Alberta Natural Gas and Natural Gas Liquids (NGL) Royalty Framework Change. This change initiative is effective with October 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. As indicated in the July 2002 Information Bulletin 02-07, 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 In-Stream Components (ISC) content within the royalty-triggered gas. Gas Royalty Rate (GR%) GR% = MiR%(MiQ)+ ER%(EiQ)+ PR%(PiQ)+ BR%(BiQ)+ PPR%(PPiQ) MiQ + EiQ + PiQ + BiQ+ PPiQ Where: GR% = Crown royalty rate for Gas MiR%* = Royalty rate for Methane ISC ER%* = Royalty rate for Ethane PR%* = Royalty rate for Propane BR%* = Royalty rate for Butanes PPR%* = Royalty rate for Pentanes Plus MiQ = Quantities of Methane ISC contained in the gas EiQ = Quantities of Ethane ISC contained in the gas PiQ = Quantities of Propane ISC contained in the gas BiQ = Quantities of Butanes ISC contained in the gas PPiQ = Quantities of Pentanes Plus ISC contained in the gas * The royalty formulas for Methane ISC, Ethane, Propane, Butanes and Pentanes Plus are described below. Methane ISC (C1-IC) Royalty Rate (MiR%) MiR% = 15(SP) + 40(PP-SP) PP Where: MiR% = Crown royalty rate for Methane ISC SP = New Methane ISC Select Price or Old Methane ISC Select Price for the year containing the production month, according to whether the gas is new gas or old gas, respectively PP = Methane ISC Par Price prescribed for the production month The minimum Crown royalty rate for New or Old Methane ISC is 15%. The maximum Crown royalty rate for New Methane ISC is 30% and Old Methane ISC is 35%. 9

10 Ethane (C2) Royalty Rate (ER%) ER% = 15(SP) + 40(PP-SP) PP Where: R% = Crown royalty rate for Ethane SP = New Ethane Select Price or Old Ethane Select Price for the year containing the production month, according to whether the ethane is new ethane or old ethane, respectively PP = Ethane Par Price for the production month The minimum Crown royalty rate for New or Old Ethane is 15%. The maximum Crown royalty rate for New Ethane is 30% and Old Ethane is 35%. Propane (C3) Royalty Rate (PR%) PR% = 15(SP) + 40(PP-SP) PP Where: R% = Crown royalty rate for Propane SP = Propane Select Price for the year in which the production month occurs PP = Propane Par Price for the production month The minimum Crown royalty rate for Propane is 15%. The maximum Crown royalty rate for Propane is 30%. Butanes (C4) Royalty Rate (BR%) BR% = 15(SP) + 40(PP-SP) PP Where: BR% = Crown royalty rate for Butanes SP = Butanes Select Price for the year in which the production month occurs PP = Butanes Par Price for the production month The minimum Crown royalty rate for Butanes is 15%. The maximum Crown royalty rate for Butanes is 30%. Pentanes Plus (C5) Royalty Rate (PPR%) PPR% = 22(SP) + RF(PP-SP) PP Where: PPR% = Crown royalty rate for Pentanes Plus SP = Pentanes Plus Select Price for the year in which the production month occurs RF = New Pentanes Plus royalty factor or Old Pentanes Plus royalty factor for the year in which the production month occurs, according to whether the pentanes plus are new pentanes plus or old pentanes plus PP = Pentanes Plus Par Price for the production month The minimum Crown royalty rate for New or Old Pentanes Plus is 22%. The maximum Crown royalty rate for New Pentanes Plus is 35% and Old Pentanes Plus is 50%. 10

11 Par Price Definitions: Product Par Price Methane ISC Par Price Ethane Par Price Propane Par Price Butanes Par Price Pentanes Plus Par Price Definition Previous production month s Methane ISC Reference Price Previous production month s Ethane ISC Reference Price Previous production month s Propane ISC Reference Price Previous production month s Butanes ISC Reference Price Previous production month s Pentanes Plus Reference Price less Previous production month s Weighted Average Transportation Allowance for Spec Pentanes plus Notes on Methane ISC, Ethane, Propane and Butanes Select Prices The Select Price for Methane ISC, Ethane, Propane and Butanes is a $/gj price. The Old/New Methane ISC Select Prices and Old/New Ethane Select Prices are the same. The Propane and Butanes Select Prices are the same as the New Methane ISC Select Price. Notes on Pentanes Plus Select Prices The Pentanes Plus Select Price is different from the Methane ISC, Ethane, Propane and Butanes Select Prices. The Pentanes Plus Select Price is a $/m 3 price. Update Audits in Progress In accordance with statutory requirements and royalty recalculation guidelines as documented in Information Letter 97-25, non-operator partners are advised that certain 1998 capital cost and custom processing adjustment factor (CPAF) and reporting discrepancy audits are currently in progress. Completion of the audits and royalty recalculations/assessments, if required, will occur in For a complete listing of the affected EUB Facilities, refer to Attachment 8. Clients are also reminded that in accordance with Information Letter 97-25, amendments received by the Department in the fourth year following the production year may be subject to audit. If the amendments are received late in the fourth year and insufficient time is available for the Department to commence a review of the amendments prior to the end of the year, the Department reserves the right to commence the audit at the beginning of the fifth year. If you have any questions, please contact Chris Lawton of the Compliance & Assurance group at (403) Close-out for Operations Production Year 2000 As prescribed by the Natural Gas Royalty Regulation, 1994, 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 has been established. Normally two years after the end of a production year, that 11

12 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: Rejection Notices Reconciliation Summary Report Reconciliation Detail Letters 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 2000: Production Year Primary Documents Secondary Documents Close-Out Date Close-Out Date January 15, 2003 March 17, 2003 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 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. Copy of letter from the operator to affected partner(s) advising of completion of rework. 5. Estimated dollar impact. 6. 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 the client will be notified by 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. 12

13 YECO forms or written requests together with the applicable royalty documents must be submitted to: Gas Royalty Calculation Client Services Help Desk 8th Floor, North Petroleum Plaza Street Edmonton, Alberta T5K 2G6 Commercial Storage Scheme Reporting Effective with the implementation of the Registry (production period October 2002), volumetric activities are no longer reported on the Owner Activity Statement (OAS). Instead, the volumetric stream and owner allocation are reported in the Volumetrics, Stream Allocation Factors (SAF) and Owner Allocation Factors (OAF) submissions in the Registry. The volumetric activity reported on the SAF and OAF does not meet all the reporting requirements for Commercial Storage activity. Consequently, Gas Royalty Calculation has developed the Commercial Storage Activity Report to be completed monthly by the Owner/Operator of Commercial Storage Facilities, commencing October 2002 production month. Completed Commercial Storage Activity Reports are to be received by the Department on or before the 15th day of the second month following the production month. For a copy of the Commercial Storage Activity Report, refer to Attachment 9. Should you have any questions or concerns, please contact Joey Dennis at (780) or Michaelann Russell at (780) Clarification of Services Available on ETS After Registry Implementation Please note that the October 2002 Information Bulletin stated AC2 & AC4 Submissions "Verification reports will remain on ETS. The ETS verification report lists the file received and the number of forms that ETS has successfully processed. Output files created from ETS submission are all directed to the Registry. Revalidation, turnaround and rejection notices on ETS all say, "Your output has been delivered to the Registry". 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 January

14 G. POINTS OF CONTACT Petroleum Registry of Alberta The Petroleum Registry of Alberta Service Desk can be reached at: Department of Energy Hotline & Internet Prices, Royalty Rates, and Transportation Information are available on the Department of Energy Internet address or hotline: (403) In addition, both the Gas Royalty Calculation Information Bulletin and Information Letter are also available on the Internet address: Note: The sulphur price can be accessed by calling the Department of Energy hotline at (403) 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) Fax: (780) or (780) Alberta Toll Free: (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. Calgary Information Centre 3 rd Floor, th Avenue S.W. Calgary, Alberta T2P 3W2 Telephone (403) Fax (403) Alberta Royalty Tax Credit Information Alberta Tax and Revenue Administration Tax Services Telephone: (780) Alberta Toll Free: Fax: (780) For further information, please contact Angelina Leung at (780) ext 251. Attachments David Breakwell Director, Gas Royalty Calculation Gas and Markets Development 14

15 2002 GAS AND ISC PRICES ATTACHMENT 1 MONTH Gas Reference Price ($/GJ) JAN 3.17 FEB 2.71 MAR 3.23 APR 3.91 MAY 3.91 JUN 3.54 JUL 3.17 AUG 2.93 SEPT 3.51 Gas Par Price ($/GJ) Methane ISC Reference Price ($/GJ) Methane ISC Par Price ($/GJ) Ethane ISC Reference Price ($/GJ) Propane ISC Reference Price ($/GJ) Pentanes Butane ISC plus ISC Reference Reference Price ($/GJ) Price ($/GJ) OCT Natural Gas and NGLs Select Prices for 2002 Commodity New Gas Old Gas New Methane Old Methane New Ethane Old Ethane Propane Butane Pentanes plus Pre-October Production Post-October Production $/GJ n/a $/GJ n/a n/a n/a $/GJ $/GJ $/GJ $/GJ $/GJ $/GJ n/a n/a $/GJ $/GJ $/m $/m3 NOV Royalty Factors for Pentanes plus DEC Base Marginal Base Marginal The Gas Par Price no longer exists under the NGL Framework changes. New Pentanes Old Pentanes DETAIL OF THE NOVEMBER 2002 GAS AND ISC REFERENCE PRICES Gas Methane C2-IC C3-IC C4-IC C5-IC Weighted Average Price of Alberta Deductions: Intra Alberta Transportation Marketing Allowance Price Before Pipeline Factor Pipeline Fuel/Loss Factor Price before Special Adjustment Special Adjustment Price before 2% amendment limitation or rounding Amendments: Carry forward (from previous RP month) Prior Period Amendment Adjustment (current RP month) Calculated RP after Amendments NOVEMBER 2002 Reference Price Difference = value carried forward to next RP month Adjusted IATD (before Prior Period Amendments) Prior period Amendments (IATD and Pipeline Fuel Loss) Adjusted IATD (after Prior Period Amendments)

16 ATTACHMENT 1A 2002 NATURAL GAS LIQUIDS PRICES MONTH Ethane Reference Price ($/GJ) Ethane Par Price ($/GJ) Propane Reference Price ($/m3) Propane Par Price ($/GJ) Propane Floor Price ($/m3) Butane Reference Price ($/m3) Butane Par Butane Floor Price ($/GJ) Price ($/m3) Pentanes plus Reference Price ($/m3) Pentanes plus Par Price ($/m3) Sulphur Default Price ($ per tonne) JAN FEB MAR APR MAY JUN JUL AUG SEPT OCT NOV DEC ANNUAL SULPHUR DEFAULT PRICE 1997 $ $6.01 $10.54 $10.96 $0.30

17 ATTACHMENT NGL TRANSPORTATION ALLOWANCE AND DEDUCTIONS MONTH PENTANES PLUS (a) PROPANE AND BUTANE (b) PENTANES PLUS, PROPANE & BUTANE (c) REGION REGION REGION FRAC. ALLOW. (per m3) JAN * FEB MAR APR 8.41 MAY 6.40 JUN 8.33 JUL AUG 9.35 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.

18 ATTACHMENT 2A. PRIOR PERIOD AMENDMENT EFFECTS NGL REFERENCE PRICES NOVEMBER 2002 Propane Butane Pentanes Price before amendments Opening Rollover (from prior business mth) Prior Period Amendment Adj. (NGL-1) Prior Period Amendment Adj. (NGL-100) Published Reference Price TRANSPORTATION ALLOWANCES NOVEMBER 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) Prior Period Amendment Adj. (NGL1) Prior Period Amendment Adj. (NGL-100) Total Amendment Effect Calculated Transp. Differential * Calculated Transp. Differential after Total Amendments * Published Transportation Allowance * *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.

19 ATTACHMENT ROYALTY RATES GAS OLD GAS NEW METHANE- METHANE- ETHANE - ETHANE - PENTANES - PENTANES - (GOL) (GNE) OLD NEW OLD NEW PROPANE BUTANES OLD NEW MONTH ( % per GJ) (% per GJ) (% per GJ) (% per GJ) (% per GJ) (% per GJ) (% per m 3 ) (% per m 3 ) (POL) (PNE) (% per m 3 ) (% per m 3 ) JAN FEB MAR APR MAY JUN JUL AUG SEPT OCT NOV DEC 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.

20 INFORMATION BULLETIN - January 2003 FACILITY OPERATOR CHANGE FORM OC1 ATTACHMENT 4 Facility ID Facility Name Previous Operator ID Previous Operator Name Current Operator ID Current Operator Name ABGP PANCDN COUNTESS 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP ALTANA BLACK BUTTE 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP PANCDN WAYNE-ROSEDALE 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP REAL RESOURCES WEST PROVOST 0LT2 REAL RESOURCES INC. A032 REAL RESOURCES ABGP PANCDN WAYNE-ROSEDALE 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP PANCDN WINTERING HILLS 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP AEC SINCLAIR 0R61 ALBERTA ENERGY COMPANY LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP PANCDN FERRYBANK 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP PANCDN COUNTESS 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP PANCDN BASSANO 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP AEC MCLEOD 0R61 ALBERTA ENERGY COMPANY LTD. 0CW8 COMPTON PETROLEUM CORPORATION ABGP PANCDN STRATHMORE 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP CONOCO MAJEAU LAKE 0FM5 CONOCOPHILLIPS CANADA LIMITED 0JL8 APACHE CANADA LTD ABGP NORCEN PROVOST 0031 ANADARKO CANADA CORPORATION 0Z0H HARVEST OPERATIONS CORP ABGP PANCDN ALDERSON 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP AEC ENCHANT (CANCELLED) 0R61 ALBERTA ENERGY COMPANY LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP CONOCO HOTCHKISS 0FM5 CONOCOPHILLIPS CANADA LIMITED 0MD6 BONAVISTA PETROLEUM LTD ABGP OPAL CLIVE 0TH2 PROVIDENT ENERGY LTD. 0Y9R MUSTANG RESOURCES INC ABGP RANGER HUSSAR 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP * PANCDN ENTICE 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP PANCDN ENTICE 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP * PANCDN VERGER 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP * PANCDN MORLEY 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP * PANCDN BASHAW 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP AEC HILL 0R61 ALBERTA ENERGY COMPANY LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP PANCDN HUSSAR 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP CONOCO JOARVIE 0FM5 CONOCOPHILLIPS CANADA LIMITED 0JL8 APACHE CANADA LTD ABGP PANCDN ALDERSON 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP CONOCO WESTLOCK 0FM5 CONOCOPHILLIPS CANADA LIMITED 0JL8 APACHE CANADA LTD ABGP BEST PACIFIC WILLESDEN GREEN 0NZ8 BEST PACIFIC RESOURCES LTD. 0TD9 ADVANTAGE OIL & GAS LTD ABGP * AEC SUFFIELD 0R61 ALBERTA ENERGY COMPANY LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP PANCDN HALKIRK 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP AEC HOOLE 0R61 ALBERTA ENERGY COMPANY LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP Effective Date Page 1 of 2

21 INFORMATION BULLETIN - January 2003 FACILITY OPERATOR CHANGE FORM OC1 ATTACHMENT 4 Facility ID Facility Name Previous Operator ID Previous Operator Name Current Operator ID Current Operator Name ABGP PANCDN BADGER 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP PANCDN COUNTESS 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP PANCDN PROVOST 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP ENCANA PEORIA AND SHANE XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP ENCANA VERGER XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP PCR BANTRY NORTH 1-8 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP AEC EAST CYPRESS 8-3 0R61 ALBERTA ENERGY COMPANY LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP CONCO SUTTON FM5 CONOCOPHILLIPS CANADA LIMITED 0MD6 BONAVISTA PETROLEUM LTD ABGP PCP COUNTESS 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP AEC HARO R61 ALBERTA ENERGY COMPANY LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP AEC SUFFEILD A2 SOLUTION GAS PLANT F 0R61 ALBERTA ENERGY COMPANY LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP PANCANADIAN VERGER XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP * PANCDN PROVOST-DAVID 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP PANCDN CAVALIER 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP PANCANADIAN WEMBLEY 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP PANCDN WAYNE-ROSEDALE 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP AEC SADDLE HILLS 0R61 ALBERTA ENERGY COMPANY LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP AEC SADDLE HILLS 0R61 ALBERTA ENERGY COMPANY LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP PANCDN VERGER 0XE2 PANCANADIAN PET/PC O & G DEV. LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP ABGP CONOCO AKUINU 0FM5 CONOCOPHILLIPS CANADA LIMITED 0JL8 APACHE CANADA LTD ABGP AEC PEDIGREE 0R61 ALBERTA ENERGY COMPANY LTD. 0D7E ENCANA OIL & GAS PARTNERSHIP Effective Date Page 2 of 2

22 INFORMATION BULLETIN - January 2003 ATTACHMENT 5 NEW PLANTS EUB FACILITY CODE FACILITY NAME TRANSPORTATION REGION PLANT TYPE PLANT TYPE EFFECTIVE DATE AB-GP Joffre Ethane Extraction Plant AB-GS Taurus GGS and Comp W AB-GS Star Oil 9-27 Compressor Station AB-GS Northrock w6 GGS AB-GS Northrock w6 GGS AB-GS MRL 7-29 GGS TO Atco MS AB-GS Enterra Bindloss GGS AB-GP NRK Brewster W AB-GP Probe Leduc Gas Processing Facility AB-GS Anadarko Grizzly 7-7 GGS AB-GS Marathon Carbon AB-GS Halkirk W4 Compressor Stat AB-GS Mancal Girouxville Gas GS

23 ATTACHMENT 6 Registry ISC Reporting Table (Revised Feb 2003) 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 or 637 Pipeline Operator, or Common Stream Operator AB MS sub type 631 or 637 where Registry auto population is not elected REC AB/BC/SK Any Mainline Straddle Plant Operator Field Straddle Plant Operator Injection Facility Operator Battery, Gathering System or Gas Plant Operators Battery, Gathering System or Gas Plant Operator Battery, Gathering System or Gas Plant Operators Raw Gas Sellers AB GP sub type Mainline Straddle REC AB BT, AB GS, AB GP AB GP sub type REC AB BT, AB GS, AB Field Straddle GP AB IF REC AB/BC/SK Any AB BT, GS, or GP DISP Any non reporting AB MS/PL AB BT, GS, or GP DISP AB RE, AB CO, AB IN, AB EG, AB R1, AB R2 AB BT, GS, or GP DISP Any non AB location 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

24 INFORMATION BULLETIN - January 2003 ATTACHMENT 7 ISC Heat Range Table ISC Product Code ISC Product Description Heat Value Range C1-IC Methane ISC C2-IC Ethane ISC C3-IC Propane ISC C4-IC Butanes ISC C5+-IC Pentanes Plus ISC CO2-IC Carbon Dioxide ISC H2-IC Hydrogen ISC H2S-IC Hydrogen Sulphide ISC HE-IC Helium ISC N2-IC Nitrogen ISC O2-IC Oxygen ISC SUL-IC Sulphur ISC

25 ATTACHMENT 8 1. EUB Facility Code AB GP AB GP AB GP AB GS AB GP AB GP AB GP AB GS AB GP AB GP AB GP AB GS AB GP AB GP AB GP AB GS AB GP AB GP AB GP AB GS AB GP AB GP AB GP AB GS AB GP AB GP AB GP AB GP AB GP AB GS AB GP AB GP AB GS Paper annual forms that were rejected by DOE because of incorrect facility identifiers Operator ID Form Type EUB Facility Code Facility Cost Centre 0002 AC2 AB GP AC2 AB GP AC AC2 AB GP AC2 AB GP A 0026 AC2 AB GP B 0026 AC2 AB GP C 0026 AC2 AB GP D 0031 AC AC AC AC2 AB GP AC5 0DF3 AC2 AB GP A 0E21 AC5 0FC2 AC2 AB GP FC2 AC2 AB GP FC2 AC2 AB GP FC2 AC2 AB GP FW6 AC5 0HF7 AC5 0J6Z AC5 0JT1 AC2 AB GP L31 AC2 AB GP H 0L31 AC2 AB GP K 0L31 AC2 AB GP L 0L31 AC2 AB GP M 0L31 AC2 AB GP P 0L31 AC2 AB GP A 0L31 AC2 AB GP A 0L31 AC5 0LF3 AC5 0MX4 AC5 0PM2 AC5 0R89 AC2 AB GS G 0R89 AC5 0TC5 AC5 0WE1 AC2 AB GP WE1 AC2 AB GP F

26 ATTACHMENT Volumetric Discrepancies Operator ID EUB Facility Code Operator ID EUB Facility Code 0002 AB GP K13 AB GP AB GP K13 AB GS AB GP K13 AB GS AB GP K13 AB GS AB GS LR8 AB GP BK8 AB BT LR8 AB GP BK8 AB GP LR8 AB GP BK8 AB GP LR8 AB GP BK8 AB GP LR8 AB GP BK8 AB GP LR8 AB GP BK8 AB GP LR8 AB GP BK8 AB GP LR8 AB GP BK8 AB GP LR8 AB GS BK8 AB GP P54 AB BT BK8 AB GP P54 AB GP BK8 AB GP P54 AB GP BK8 AB GS P54 AB GS BK8 AB GS R61 AB GS BK8 AB GS R61 AB GS BK8 AB IF R61 AB IF BP8 AB BT T65 AB GP BP8 AB BT T65 AB GP BP8 AB GP TM9 AB IF BP8 AB GP WC8 AB GP BP8 AB GP WC8 AB GP BP8 AB GP WC8 AB GP BP8 AB GP WC8 AB GP BP8 AB GP WC8 AB GP BP8 AB GP WC8 AB GP BP8 AB GS WC8 AB GP BP8 AB GS WC8 AB GP BP8 AB GS WC8 AB IF CW9 AB GP WE1 AB GP CW9 AB GS WE1 AB GP CW9 AB GS WJ5 AB GP G30 AB BT WJ5 AB GP G30 AB BT WJ5 AB GP G30 AB BT WJ5 AB GP G30 AB GP WJ5 AB GS G30 AB GP Invalid Well Identifiers on OAS documents that triggered Provisional Assessment charges, and/or injection credit recalculations Operator ID EUB Facility Code 0039 AB GP AB GP AW4 AB GS K13 AB GS K13 AB GS K13 AB GS NH1 AB GP WC8 AB GS WC8 AB IF Potential royalty recalculations as a result of 1998 well application status changes, and/or well ID changes.