gas royalty calculation information bulletin - april 2002 · for determining multiple gas valuation...

ENERGY

Petroleum Plaza – North Tower 9945 – 108 Street Edmonton, Alberta Canada T5K 2G6 02-04

GAS ROYALTY CALCULATION INFORMATION BULLETIN

April 2002

A. PRICING RATES AND TRANSPORTATION INFORMATION Pricing, Royalty Rates and Transportation Information – February 2002........................................... 2 B. NOTICES

Important Notice .................................................................................................................................. 2 Unit Operating Cost Rates (UOCR) .................................................................................................... 2

C. MONTHLY INFORMATION February 2002 Royalty Due May 31.................................................................................................... 3 March 2002 OAS and VA4 Due May 15 ............................................................................................ 3 Interest Rate April 2002....................................................................................................................... 4 January Provisional Assessment Charge ........................................................................................... 4 January Penalty Charges .................................................................................................................... 4 Alberta Royalty Tax Credit Program Quarterly Rate ...........................................................................4 D. INFRASTRUCTURE DATA CHANGES Client ID Listing ................................................................................................................................... 4 Projects/Blocks.................................................................................................................................... 5 Struck Clients ...................................................................................................................................... 5 Operator Changes............................................................................................................................... 6 New EUB Plants .................................................................................................................................. 6 Nova Tolls – Multiple Gas Reference Prices....................................................................................... 6 E. REMINDERS

Receive the Gas Royalty Calculation Information Bulletin Electronically ........................................... 6 Monthly Sulphur Corporate Average Price Calculation – VA4 Form .................................................. 6 Capital Cost Allowance Reporting (AC2-V2) for New Facility Cost Centres (FCC)............................ 7 Submission of Production Year 2001 Allowable Cost (AC) and Corporate Average Price

Calculation (VA) Forms ....................................................................................................................... 8 Weighted Average Aggregator Overhead Marketing and Administration Charges (OMAC) .............. 8 Annual Weighted Average Gas Reference Price................................................................................ 8 2002 Select Prices .............................................................................................................................. 9 Historical Pricing and Royalty Data..................................................................................................... 9

F. PRINCIPLES AND PROCEDURES Updates ............................................................................................................................................... 9 G. POINTS OF CONTACT Department of Energy Hotline & Internet ............................................................................................ 9 Gas Royalty Calculation .................................................................................................................... 10 Calgary Information Centre .............................................................................................................. 10 Alberta Royalty Tax Credit Information ............................................................................................ 10

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

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

INFORMATION BULLETIN – April 2002

A. PRICING RATES AND TRANSPORTATION INFORMATION

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

B. NOTICES

Important Notice

Implementation of the Petroleum Registry of Alberta in October 2002 represents significant changes in how industry operators and non-operators will report and retrieve oil and gas information in the future. This article outlines how gas related non-operator/royalty payers will operate within the Internet based Registry system. 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 will be able to obtain this information online through the Registry. There are significant advantages to the non-operator, industry as a whole and the Crown in using the Registry. Saving time and access to the data of record are two advantages industry partners will achieve when exchanging information through the Registry. As an example, the Registry allows users quicker access to viewing their allocations from operators online. Under the current system, this involves the mailing or faxing of information, which may take weeks to reach the intended parties. The Registry allows non-operators to view their allocations, as soon as operators submit this information to the database. In addition to this, the Registry will have “Crown Royalty Invoice” and “Crown Royalty Details” available in several formats online. This means that non-operators will be able to view and download/print their invoice package as soon as it is available. They will also be able to summarize this data in the manner of their choosing. The Registry will contain a majority of the other material sent by the Department of Energy, which allows non-operators immediate access to “Crown Notices”. Detailed information about this and other benefits of reporting and retrieving information through the Registry will be outlined over the coming months in this and other publications. For more information about use of the Petroleum Registry of Alberta, please call (403) 297-6111 (Calgary), 1-800-992-1144 (other locations), or e-mail [email protected]. Additional information about the Registry can also be found on its web site at www.petroleumregistry.gov.ab.ca.

Unit Operating Cost Rates (UOCR)

The Department calculated the 2002 Unit Operating Cost Rates (UOCR) for the following two types:

• Designated Facilities

2• Plant Type Facilities

mailto:[email protected]

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


We will use the 2002 Unit Operating Cost Rates for the first time in the February 2002 Invoice, issued in April 2002. See Attachment 7 for the 1998 to 2002 Unit Operating Cost Rates. If you have any questions regarding the 2002 UOCR, please contact Ray Khan at (780) 415-2673, or Renée Matsuba (780) 422-9166.

C. MONTHLY INFORMATION

February 2002 Royalty Due May 31

• Royalty clients are to remit the total amount payable shown on the May 2002 Statement of Account by May 31, 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 May 2002 Statement of Account shows your amount payable as of the Statement issue date. It includes any outstanding balances from your previous statement, your February 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 February 2002 if it is paid in full by May 31, 2002.

• 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.

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

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• 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 April 2002 The Department of Energy’s interest rate for April 2002 is 4.75%.

January Provisional Assessment Charge

The net Provisional Assessment Charge for the January 2002 billing period was $16,169,590.85. This includes $77,582,863.51 in first time provisional assessments and ($61,413,272.66) in reversals of provisional assessments for all production periods.

January Penalty Charges The following are the Penalty Charges by form type for the January 2002 billing period:

FORM Penalties Charged AC2 $18,500 AC4 $0 AC5 $15,300 GR2 $0 NGL1 $0 VA2 $0 VA3 $0 VA4 $200 Total Charged $34,000 Total Reversed ($50,100)

Net Penalties Charged for 2002/01 $(16,100)

Alberta Royalty Tax Credit Program Quarterly Rate

For the second quarter of 2002, the Alberta Royalty Tax Credit rate will be .2500. This rate is based on a royalty tax credit reference price of $238.03 per cubic metre. The Alberta Royalty Tax Credit rates for the past year were:

First Quarter, 2002 .2500 Fourth Quarter, 2001 .2500 Third Quarter, 2001 .2500 Second 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 4

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


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

The following projects/blocks have been set up or terminated since April 2002. If further information is required on these or any other projects, please contact Isabelle Warwa at (780) 422-8966.

PROJECT/BLOCK NAME

EFFECTIVE

DATE

TERMINATION

DATE

OPERATOR

STREAM

ID Provost Cummings X2X Project No 1 Mar. 2002 0026 A02325

Pembina Cardium Project No 130 Apr. 2002 0060 A65796 Chin Coulee Sawtooth B Project No 1 Feb. 2002 0WZ9 A02898

Long Coulee Glauconitic YY Block No 1 Mar. 2002 0DP4 A02899

Leduc-Woodbend Glauconitic D Project No 2 Apr. 2002 0026 A02900

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:

Company Name Client ID Struck Date ARKOMA ENERGY INC 0A31 March 2, 2002 BELFAST PETROLEUM INC 0P75 March 2, 2002 COENERGY TRADING COMPANY 0XR7 March 2, 2002 COSEKA RESOURCES LIMITED 0N17 March 2, 2002 SIERRA TRINITY INC 0033692 March 2, 2002

Company Name Client ID Revived Date WW BECKER OIL AND GAS LTD 0R48 March 20, 2002

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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

Receive the Gas Royalty Calculation Information Bulletin Electronically

The Gas Royalty Calculation Information Bulletin is now available by electronic delivery. To subscribe, please go to www.energy.gov.ab.ca. Note: There is no charge for subscribing or limit to the number of recipients. Clients who elect to receive the Information Bulletin electronically will not receive a mailed paper copy.

Monthly Sulphur Corporate Average Price Calculation – VA4 Form

Royalty clients with an annual sulphur production of 30,000 tonnes or greater in the production year 2001 are required to file VA4 forms monthly, beginning with the January 2002 production month. The VA4 form is due on or before the 15th day of the second month following the respective production month. A royalty client whose annual sulphur production is less than 30,000 tonnes may choose to file the VA4 forms monthly beginning with January’s production month; however, if this choice is made, the client must file VA4 forms for the entire year. The Department will use the VA4 forms to determine each client’s monthly Sulphur Corporate Average Price (S-CAP) and the monthly Sulphur Default Price. We calculate each month’s Sulphur Default Price as the weighted average unit value of all arms length sales for all clients who filed VA4 forms for that month. The Department will value and invoice the Crown royalty share of sulphur production monthly, using the respective S-CAP price for clients who file VA4 forms and the Sulphur Default Price for clients who choose not to file VA4 forms. The VA4 form is subject to $100 in late filing penalties for each month or part of the month the form is past due.

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

http://www.energy.gov.ab.ca/OurBusiness/1070.asp


Royalty clients who file monthly VA4 forms must file annual VA3 forms. The VA3 form remains the primary sulphur valuation tool and the S-CAP determined from each VA3 will replace the entire year’s monthly prices determined from the VA4 forms. The VA3 is due on or before April 15th of the year following the year of production. Interest is charged/paid on the Crown royalty difference when adjusting from monthly to annual valuation. The VA3 form is subject to a one-time $1,000 late filing penalty. The following royalty clients must submit VA4 forms effective with the production year 2002, which includes any pricing information for each of its consolidated/amalgamated entities:

Client ID Client Name Client ID Client Name 0017 Imperial Oil Resources 0JT1 ExxonMobil Canada Energy 0039 Talisman Energy Inc. 0JT3 Nexen Canada Ltd. 0045 Chevron Canada Limited 0KT5 Canadian 88 Energy Corp. 0054 Suncor Energy Inc. 0N00 Prime West Energy Inc. 0060 BP Canada Energy Company 0N80 Canadian Hunter Exp. Ltd.

0102419 Devon Canada 0NP6 PCC Energy Inc. 0246 Petro-Canada 0PF8 Hunt Oil Company of Canada 0BL1 Burlington Resources Canada Ltd. 0R46 Husky Oil Operations Limited 0BM8 Rio Alto Exploration Ltd. 0T03 Shell Canada Limited 0CW8 Compton Petroleum Corp. 0T82 Canadian Forest Oil Ltd. 0E21 AEC West Ltd. 0TC5 Vintage Petroleum Canada Inc. 0FW6 Conoco Canada Resources Ltd. 0WC8 Devon AXL 0G30 Arc Resources Ltd. 0XE2 PanCanadian Pet/PC O&G

Capital Cost Allowance Reporting (AC2-V2) for New Facility Cost Centres (FCC)

To ensure that the Department correctly calculates capital cost allowance for a new FCC, the operator must follow the following procedures:

Eligible capital costs incurred up to the start-up date should be entered in both fields 2.1 and 2.2. Initial capital cost identified in 2.1 and 2.2 must also be clearly identified in Part 3 and must not be included in field 2.3. Eligible capital costs incurred subsequent to start-up should be included in field 2.3 only. For capital additions identified in Part 3, identify each Authorization for Expenditure (AFE) or provide a breakdown of capital as the description. The total capital addition on line 3.4 should not be reflected on field 2.3 for a new facility cost center. If the capital for a new FCC includes amounts transferred from a terminated FCC (the previous FCC), then:

• field 2.1 should include the Cumulative Allowable Capital Dec 31 (field 2.4), • field 2.2 should include the Allowable Capital Cost After Depreciation (field 2.7)

from the previous FCC before termination. Where the capital added to a new FCC is transferred from an existing FCC that is not terminated then the transferred capital should be included in field 2.3. The capital transferred must also be removed from the existing FCC at the same time.

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Submission of Production Year 2001 Allowable Cost (AC) and Corporate Average Price Calculation (VA) Forms Royalty clients are advised that Allowable Cost forms (AC2, AC3, AC4, and AC5) and Corporate Average Price Calculation forms (VA2 and VA3) for the 2001 production year can be submitted to the Department for processing. The form due dates are as follows:

Form Due Date AC4 March 31, 2002 AC2 April 15, 2002 VA2 April 15, 2002 VA3 April 15, 2002 AC5 May 15, 2002 AC3 May 15, 2002

Appendix C of the Natural Gas Royalty Guidelines, September 1, 2001, outlines the form edits for paper submission documents. Electronic form filers should check the Department’s Internet site for electronic form edits.

Gas royalty payers and their service providers can use the Department’s Internet site to retrieve PDF and text versions of the gas royalty reports such as the Gas Royalty Invoice, Statement of Account, Turnaround Reports, and form reject reports. Clients with reports in UDF and DDF formats can also retrieve their files on the Internet. The following Internet web site identifies all of the Department of Energy’s E-transfer systems.

www.energy.gov.ab.ca

If you are amending a facility cost centre operator or setting up a new 2001 facility cost centre, please submit your AC1 document in a timely manner to ensure that you can file your AC4 or AC2 documents without penalty.

Weighted Average Aggregator Overhead Marketing and Administration Charges (OMAC)

For Gas Corporate Average Price (CAP) filers, when determining the netback value, the weighted average OMAC type charges may be deducted for sales to non-designated aggregators. The Weighted Average Aggregator OMAC ($/GJ) for 2001 is $0.021. For further information, see Chapter III, Section 1.1.3 and 1.4.1 of the Principles and Procedures.

Annual Weighted Average Gas Reference Price

The Annual Weighted Average Gas Reference Price for 2001 is $5.111. This price is used in the calculation to determine the 2001 minimum price for the Gas Corporate Average Price.

8

http://www.energy.gov.ab.ca/OurBusiness/1076.asp


2002 Select Prices

The following are the select prices for pentanes and old and new vintages of natural gas and ethane for the year 2002.

2002 Select Prices

Natural Gas ($/GJ) Old Gas 0.372 New Gas 1.252

Ethane ($/GJ) Old Ethane 0.372 New Ethane 1.252

Pentanes($/m3) 45.30

Historical Pricing and Royalty Data A listing of historical royalty related data for information purposes was published in the February 2002 Information Bulletin and can be found on the Internet at the following address:

www.energy.gov.ab.ca F. PRINCIPLES AND PROCEDURES

Updates

Please replace or add the following pages within your copy of the Gas Royalty Principles and Procedures – September 2001 Edition with the enclosed updates: Chapter III, Section 3.2 Adding or Amending Monthly Crown Share of Cost Allowance Estimates p. 3-1 Chapter IV, Section 2.4 Registering a Single Well of Injection Scheme p. 2-17 to 2-24 Chapter IV, Section 4.4 Preparing a Monthly Sulphur Corporate Average Price p. 4-13 Appendix P Forms p. YECO

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.

9

http://www.energy.gov.ab.ca/NaturalGas/BUL_2002-2003/IB2002-02.pdf#page=20

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


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.

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

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INFORMATION BULLETIN – April 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

APR

MAY

JUN

JUL

AUG

SEPT

OCT

NOV

DEC

DETAIL OF THE FEBRUARY 2002 GAS REFERENCE PRICE SELECT PRICE 2002 Weighted Average Price of Alberta 3.115 $/GJ New Gas

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

Pentanes ($per m3)

Deductions: Intra – Alberta Transportation 0.315 $/GJ 1.252 0.372 45.30

Marketing Allowance 0.031 $/GJ New Ethane($per GJ)

Old Ethane ($per GJ)

Price Before Pipeline Factor 2.769 $/GJ 1.252 0.372

Pipeline Fuel/Loss Factor 0.988 Price before Special Adjustment 2.736 $/GJ

Special Adjustment 0.000 $/GJ Price before 2% amendment limitation or rounding 2.736 $/GJ Weighted Average Reference Weighted Average OMAC Amendments:Carry forward (from previous RP month) -0.004 $/GJ Price ($/GJ) ($/GJ) Prior Period Amendment Adjustment (current RP month) -0.024 $/GJ

5.111 0.021 Calculated RP after Amendments 2.708 $/GJ FEBRUARY 2002 Reference Price 2.71 $/GJ Difference = value carried forward to next RP month -0.002 $/GJ

Adjusted IATD (before Prior Period Amendments) 0.311 $/GJ ANNUAL SULPHUR DEFAULT PRICE Prior period Amendments (IATD and Pipeline Fuel Loss) 0.000 $/GJ 1996 1997 1998 1999 2000 Adjusted IATD (after Prior Period Amendments) 0.311 $/GJ $11.45 $9.98 $6.01 $10.54 $10.99


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

APR

MAY

JUN

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 – April 2002 ATTACHMENT 2A

PRIOR PERIOD AMENDMENT EFFECTS

NGL REFERENCE PRICES FEBRUARY 2002

Propane Butane Pentanes

Price before amendments 88.143828 133.585975 202.389613

Opening Rollover (from prior business month) 0.000639 0.002070 0.002793

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 88.14 133.59 202.39

TRANSPORTATION ALLOWANCES FEBRUARY 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) 0.002500 -0.002936 0.003748 00.1467 0.004611 0.001989 -0.001612 0.000442 -0.000411 0.003858 -0.002865 0.000404

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 0.014707 0.000000 0.000000 0.000000 0.000000 0.000000

Total Amendment Effect 0.002500 -0.002936 0.003748 0.001467 0.004611 0.001989 0.013095 0.000442 -0.000411 0.003858 -0.002865 0.000404

Calculated Transp. Differential 10.241004 12.315988 15.905760 19.026957 9.410950 4.635237 7.910490* 11.269690 9.869722 17.045920 24.664433 9.890592

Calculated Transp. Differential after Total

Amendments

10.243504 12.313052 15.909508 19.028424 9.415561 4.637226 7.923585* 11.270132 9.869311 17.049778 24.661568 9.890996

Published Transportation Allowance 10.24 12.31 15.91 19.03 9.42 4.64 7.92* 11.27 9.87 17.05 24.66 9.89 * 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

APR

MAY

JUN

JUL

AUG

SEPT

OCT

NOV

DEC

INFORMATION BULLETIN - April 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-1055 TOM BROWN EDSON STELLARTON RESOURCE MANAGEMENT INC 0WL9 TOM BROWN RESOURCES LTD 0A0L 2001-02AB-GP-1247 TOM BROWN EDSON STELLARTON ENERGY CORPORATION 0L29 TOM BROWN RESOURCES LTD 0A0L 2001-02AB-GP-1578 MARATHON SHOULDICE SUMMIT RESOURCES LIMITED 0L06 MARATHON CANADA LIMITED 0AL2 2002-02AB-GP-1622 CELSIUS WHITECOURT CANOR ENERGY LTD 0MT5 CELSIUS ENERGY RESOURCES LTD 0TT7 2002-01AB-GP-1884 PETROBANK JUMPBUSH BARRINGTON PETROLEUM LTD 0HM7 PETROBANK ENERGY AND RESOURCES LTD 0TH8 2002-01AB-GS-2279 CELSIUS COUNTESS CANOR ENERGY LTD 0MT5 CELSIUS ENERGY RESOURCES LTD 0TT7 2002-01AB-GS-2552 TOM BROWN EDSON STELLARTON ENERGY CORPORATION 0L29 TOM BROWN RESOURCES LTD 0A0L 2001-02AB-GS-2690 CELSIUS THORNHILD CANOR ENERGY LTD 0MT5 CELSIUS ENERGY RESOURCES LTD 0TT7 2002-01AB-GS-2777 CELSIUS NESTOW CANOR ENERGY LTD 0MT5 CELSIUS ENERGY RESOURCES LTD 0TT7 2002-01AB-GS-2779 CELSIUS NESTOW CANOR ENERGY LTD 0MT5 CELSIUS ENERGY RESOURCES LTD 0TT7 2002-01AB-GS-3073 ALTAGAS ANTELOPE LAKEWOOD ENERGY INC 0LJ7 ALTAGAS SERVICES INC 0TF9 2000-01AB-GS-3236 KEYSPAN SYLVAN LAKE CRESTAR ENERGY INC 0NL2 KEYSPAN ENERGY CANADA INC 0YD9 2002-02AB-GS-3617 CELSIUS WHITECOURT CANOR ENERGY LTD 0MT5 CELSIUS ENERGY RESOURCES LTD 0TT7 2002-01AB-GS-4101 TOM BROWN CARROT CK S STELLARTON ENERGY CORPORATION 0L29 TOM BROWN RESOURCES LTD 0A0L 2001-02AB-GS-4102 TOM BROWN CARROT CK STELLARTON ENERGY CORPORATION 0L29 TOM BROWN RESOURCES LTD 0A0L 2001-02AB-GS-4125 PETROBANK JUMPBUSH BARRINGTON PETROLEUM LTD 0HM7 PETROBANK ENERGY AND RESOURCES LTD 0TH8 2002-01AB-GS-4242 HUSKY OIL PLEASANT RENAISSANCE ENERGY LTD 0BN9 HUSKY OIL OPERATIONS LIMITED 0R46 2001-01AB-GS-4863 CONNACHER ISLAY 8-12 SOUTHWARD ENERGY LTD 0DR2 CONNACHER OIL AND GAS LIMITED 0A9H 2002-02AB-GS-4899 KEYSPAN MODESTE 10-2 GGS CONOCO CANADA RESOURCES LIMITED 0FW6 KEYSPAN ENERGY CANADA INC 0YD9 2002-03AB-GS-6371 RIO ALTO GEORGE 16-30 GGS CANADIAN NATURAL RESOURCES LIMITED 0HE9 RIO ALTO EXPLORATION LTD 0BM8 2001-11


NEW PLANTS

EUB FACILITY CODE

FACILITY NAME

TRANSPORTATION REGION

PLANT TYPE

PLANT TYPE

EFFECTIVE DATE

AB-GP-1831 HUSKY HAIG RIVER STEEN 01-17 3 2 2002-02

AB-GS-6388 RUBICON MONTAG 12-5 3 1 2002-02

AB-GS-6387 HUSKY STEEN GATHERING 01-17 3 1 2002-02

AB-GS-6389 DENISON 1 EL ET AL 103 KNAPPEN 2 1 2002-02

AB-GS-6390 CNRL MATZWIN DEEP 06-10 2 1 2002-03

AB-GS-6392 PENN WEST DRYDEN CREEK 9-29 GGS 3 1 2002-03

AB-GS-6393 CANADIAN HUNTER LEDDY 11-05 3 1 2002-02

AB-GS-6394 APACHE FOX GLOVE 14-29 3 1 2002-03

AB-GS-6395 PANCANADIAN SEVERN STANDARD 06-17 2 1 2002-03

AB-GS-6396 HUSKY DENY KISKIU 14-09 4 1 2002-04

AB-GS-6397 HUSKY CARIBB CREEK 01-17 3 1 2002-03

AB-GS-6399 HUSKY ASSUMPTION 14-03 3 1 2002-03

AB-GS-6400 HUSKY CARIBB CREEK 01-01 3 1 2002-03

INFORMATION BULLETIN-April 2002 Multiple Gas Valuation Factors ATTACHMENT 6

Facility ID

Facility Operator

IDProduction

PeriodBilling 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 Factor Effective Date

Meter Factor Termination

DateAB-GP-1831 0R46 2002/02/01 2002/02/01 1.13 NOVA 2127 1.13 2002/02/01 3000-01-01 2001/10/01 3000-01-01AB-GS-3664 0TR8 2001/07/01 2002/02/01 1.09 NUL 501378 1.09 2001/07/01 3000-01-01 2001-07-01 2001/10/01 AB-GS-3664 0TR8 2001/07/01 2002/02/01 0.55 NOVA 1378 0.55 Yes 2001/07/01 3000-01-01 2001-07-01 2001/10/01 AB-GS-3664 0TR8 2001/10/01 2002/02/01 1.13 NUL 501378 1.13 2001/07/01 3000-01-01 2001/10/01 3000-01-01AB-GS-3664 0TR8 2001/10/01 2002/02/01 0.58 NOVA 1378 0.58 Yes 2001/07/01 3000-01-01 2001/10/01 3000-01-01AB-GS-6371 0BM8 2001/11/01 2002/02/01 1.13 NOVA 2084 1.13 2001/11/01 3000-01-01 2001/10/01 3000-01-01AB-GS-6371 0BM8 2002/01/01 2002/02/01 1.13 NOVA 2084 1.13 2001/11/01 3000-01-01 2001/10/01 3000-01-01

Injection and Reproducing Facility Ties

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


DESIGNATED AND PLANT TYPE UNIT OPERATING COST RATES

EUB FACILITY

ID FACILITY NAME 1998 1999 2000 2001 2002

1002 N EVIS 19.48 25.58 32.13 30.75 17.49 1004 H OMEGLEN-RIMBEY 5.30 8.79 14.32 11.49 13.26 1020 CARSTAIRS 18.64 -2.40 20.22 20.69 29.22 1022 CESSFORD 8.79 7.35 7.81 8.08 9.10 1034 WINDFALL 13.47 23.53 12.85 20.82 71.40 1037 JUMPING POUND 14.46 9.97 16.21 19.15 13.87 1042 KARR 9.40 8.73 20.94 17.87 21.72 1045 BONNIE GLEN 13.77 9.45 12.52 16.24 8.53 1047 MINNEHIK-BUCK LAKE 1.69 17.33 21.76 17.33 22.82 1050 CROSSFIELD -0.82 25.77 11.43 17.91 29.96 1054 WILDCAT HILLS 11.54 14.79 1.13 9.13 23.90 1056 WATERTON 12.17 26.45 20.16 22.64 30.04 1058 KAYBOB 13.51 11.44 11.23 17.05 15.12 1060 HARMATTAN ELKTON 10.68 11.59 29.46 31.26 42.92 1069 JUDY CREEK 25.95 19.27 18.49 29.60 15.28 1074 BONNIE GLEN 5.61 10.56 4.53 6.53 16.93 1079 CROSSFIELD EAST 28.63 35.14 0.94 20.04 17.19 1084 EDSON 1.81 10.38 9.03 11.30 14.88 1097 GHOST PINE 4.09 6.15 13.59 9.99 1.13 1105 RAINBOW 9.15 6.02 8.18 4.74 15.29 1107 KAYBOB #1 17.55 18.03 12.50 23.35 46.94 1108 BRAZEAU RIVER 13.37 14.57 33.80 20.68 17.26 1131 BURNT TIMBER 14.93 4.98 15.79 9.15 15.61 1132 MARTEN HILLS 7.47 6.59 11.40 20.86 30.21 1133 STRACHAN (B) 4.84 11.08 10.72 10.61 17.40 1141 STRACHAN 6.99 8.54 8.54 15.50 5.11 1144 KAYBOB SOUTH 22.42 13.31 13.09 31.30 30.86 1147 SINCLAIR 16.66 -2.11 13.85 25.42 4.60 1169 DUNVEGAN 9.35 6.11 16.97 9.53 18.84 1173 RICINUS (B) 5.11 6.41 6.44 5.92 8.60 1292 WAPITI 6.37 7.49 3.85 5.45 8.13 1350 ELMWORTH 7.35 6.41 8.48 10.08 25.26 1351 ELMWORTH 6.28 6.49 8.75 10.11 4.33 1360 BANSHEE 4.86 7.53 3.88 7.48 12.66 1458 BRAZEAU RIVER 6.63 9.27 17.49 38.91 0.43 1520 WEMBLEY 9.79 9.55 15.95 15.53 41.21 1522 HAMBURG 5.38 5.61 8.16 7.12 11.24 1662 CAROLINE 13.25 8.98 11.64 10.49 20.11

PLANT TYPES 1 2 3 4 5

DESCRIPTIONS Dry Gas - Dehy/Comp/GS – Sale Wet Gas w/Dehy,Comp,C3+ Extr Dry Gas w/ Sul Removal Wet Gas w/ Sul Removal Dry and Wet Gas w/ Sul Recov

6.09 6.89 5.30

10.64 9.23

6.39 7.22 5.24

10.71 13.27

6.99 8.08 8.27

11.78 13.21

8.34 8.96 8.41

13.89 15.70

8.80 8.76

10.05 11.32 15.65

INFORMATION BULLETIN - April 2002

2002 UNIT OPERATING COST RATES (UOCR)

ATTACHMENT 7

Compressing ($/103m3)

Gathering ($/103m3)

Processing ($/103m3)

AB-GP-1002 DUKE MIDSTREAM NEVIS 17.49 6.22 4.97 6.30AB-GP-1004 GULF HOMEGLEN-RIMBEY 13.26 3.67 3.76 5.83AB-GP-1020 ANDERSON CARSTAIRS 29.22 9.18 5.63 14.41AB-GP-1022 CRESTAR CESSFORD 9.10 0.79 2.04 6.27AB-GP-1034 AMOCO WINDFALL 71.40 14.54 29.15 27.71AB-GP-1037 SHELL JUMPING POUND 13.87 2.89 2.45 8.53AB-GP-1042 RIO ALTO KARR 21.72 2.42 8.79 10.51AB-GP-1045 ESSO BONNIE GLEN 8.53 0.00 0.20 8.33AB-GP-1047 PENN WEST MINNEHIK-BUCK LAKE 22.82 5.29 4.57 12.96AB-GP-1050 WASCANA CROSSFIELD 29.96 1.04 9.50 19.42AB-GP-1054 PETRO-CAN WILDCAT HILLS 23.90 1.46 3.21 19.23AB-GP-1056 SHELL WATERTON 30.04 6.62 5.48 17.94AB-GP-1058 PARAMOUNT KAYBOB 15.12 7.00 3.83 4.29AB-GP-1060 NOVAGAS HARMATTAN ELKTON 42.92 6.50 3.98 32.44AB-GP-1069 ESSO JUDY CREEK 15.28 3.80 1.05 10.43AB-GP-1074 ESSO BONNIE GLEN 16.93 4.21 0.00 12.72AB-GP-1079 PRIMEWEST CROSSFIELD EAST 17.19 2.42 2.21 12.56AB-GP-1084 TALISMAN EDSON 14.88 2.32 4.24 8.32AB-GP-1097 CONOCO GHOST PINE 1.13 0.13 0.49 0.51AB-GP-1105 HUSKY RAINBOW 15.29 1.21 1.49 12.59AB-GP-1107 AMOCO KAYBOB S #1 46.94 5.22 14.34 27.38AB-GP-1108 GULF BRAZEAU RIVER 17.26 5.67 4.03 7.56AB-GP-1131 SHELL BURNT TIMBER 15.61 1.92 4.30 9.39AB-GP-1132 AMOCO MARTEN HILLS 30.21 10.55 12.46 7.20AB-GP-1133 GULF STRACHAN (B) 17.40 4.62 4.16 8.62AB-GP-1141 HUSKY STRACHAN 5.11 0.78 1.84 2.49AB-GP-1144 CHEVRON KAYBOB SOUTH 30.86 7.04 9.78 14.04AB-GP-1147 AEC SINCLAIR 4.60 0.70 1.87 2.03AB-GP-1169 ANDERSON DUNVEGAN 18.84 2.55 1.79 14.50AB-GP-1173 AMOCO RICINUS (B) 8.60 2.74 1.96 3.90AB-GP-1292 AMOCO WAPITI 8.13 3.61 3.11 1.41AB-GP-1350 CDN HUNTER ELMWORTH 25.26 18.75 4.45 2.06AB-GP-1351 ANDERSON ELMWORTH 4.33 2.07 1.57 0.69AB-GP-1360 PETRO CAN BANSHEE 12.66 2.19 3.02 7.45AB-GP-1458 ATCO MIDSTREAM BRAZEAU RIVER 0.43 0.04 0.06 0.33AB-GP-1520 CRESTAR WEMBLEY 41.21 6.95 9.94 24.32AB-GP-1522 APACHE HAMBURG 11.24 2.37 2.65 6.22AB-GP-1662 SHELL CAROLINE 20.11 4.25 0.91 14.95

PLANT TYPES DESCRIPTIONS

2002 UOCR

($/103m3)1 Dry Gas - Dehy/Comp/GS - Sale 8.80 4.91 3.45 0.442 Wet Gas w/Dehy,Comp,C3+ Extr 8.76 1.40 2.26 5.103 Dry Gas w/ Sul Removal 10.05 2.27 1.90 5.884 Wet Gas w/ Sul Removal 11.32 1.89 1.54 7.895 Dry and Wet Gas w/ Sul Recov 15.65 1.54 2.39 11.72

DELAYERED RATES

DELAYERED RATES

EUB FACILITY ID FACILITY NAME

2002 UOCR

($/103m3)

Chapter III, Section 3 – Alberta’s Royalty Share of Cost Allowances

3 Alberta's Royalty Share of Cost Allowances 3.1 Crown Share of Cost Allowances�

3.1.1 Monthly Calculation The Department deducts the Crown share of Cost Allowance each month as a reduction from the Crown royalty payable in that month. The monthly deduction is unique to each royalty client, and is calculated as:

(Unit Operating Cost Rate …multiplied by… energy adjusted gas equivalent volume of

Crown royalty gas and gas products) for the royalty client’s Crown royalty share at each EUB facility in the month

…plus… Crown Share of Capital Cost Allowance paid to the royalty client for the preceding

year …divided by…12 …plus…

Crown Share of Custom Processing Cost Allowance paid to the royalty client for the preceding year …divided by… 12

For 1994, the implementation year, the estimated monthly Crown share of Capital Cost Allowances and Crown share of Custom Processing Cost Allowances (net of estimated Crown share of Operating Cost Allowances) was calculated using 1993 information reported to the Department. For 1995 and onwards, the estimated monthly Crown share of Capital Cost Allowances is based on the previous year’s actual Capital Cost Allowance and Capital Cost Allowance Reallocation costs reported on the AC2 and AC3 forms respectively. The estimated monthly Crown share of Custom Processing Allowances will be based on the previous year’s actual Custom Processing Fees paid reported on the AC5 form, net of allowed operating costs.

A person who becomes a new royalty client after December 31, 1993, must submit a request in writing to the Department for an estimated monthly Crown share of Capital Cost Allowances and Crown share of Custom Processing Cost Allowances for the first year of operation. (Refer to Ch III, Sec. 3.2)

For new royalty clients, the Corporate Effective Royalty Rate (CERR)* is the Provincial Average from the previous year. The Provincial Average CERR is determined once a year in the calendar month of June. The Department publishes this rate in the monthly Gas Royalty Information Bulletin. (Refer to Ch III, Sec. 3.18)

*For definition, please see Appendix N - Glossary April 1, 2002 ALBERTA NATURAL GAS ROYALTY Ch III, Page 3-1

Chapter III, Section 3 – Alberta’s Royalty Share of Cost Allowances

3.2 Adding or Amending Monthly Crown Share of Cost Allowance Estimates�

If a royalty client’s business in a year changes significantly so that the Crown share of Capital Cost Allowance, or Crown share of Custom Processing Cost Allowance from the preceding year is no longer relevant, the royalty client may request in writing to the Department for an adjustment to his monthly estimate. The following lists identify the supporting documentation required to support the requested change and, if approved, the Department will use the new information in its calculation of the monthly deduction on a prospective basis:

Capital cost estimates: • Effective date of acquisition or disposition • AC1 form(s) to set up new Facility Cost Centre(s) (FCC) • Existing FCC Ids for working interest owner acquisitions, disposition, or capital

additions • Previous year’s closing allowable capital cost, allocation percent and Remaining

Useful Life (RUL) for each FCC • Monthly Capital Cost Allowance Estimate Adjustment Worksheet accompanied

with Authorization For Expenditure (AFE) for new set-ups and capital additions • A total corporate adjustment amount before Corporate Effective Royalty Rate

(CERR) by royalty client

NOTE: The Department provides a Monthly Capital Cost Allowance Estimate Adjustment Worksheet to assist royalty clients when requesting an adjustment to their monthly estimated capital cost allowance. (Refer to Appendix P)

Custom processing cost estimates: • Effective date of acquisition or disposition • Owner Activity Statement/RMF2 volume allocations • A copy of the custom processing fees paid, i.e. Invoices or statements • For each facility, the calculations of the Custom Processing Fees net of

Operating Cost Reductions (dependant on ownership status), Enhanced Oil Recovery and Royalty Paid Bank recaptures

• A total corporate adjustment amount before CERR by royalty client

NOTE: The Department provides a Monthly Custom Processing Estimate Adjustment Worksheet to assist royalty clients when requesting an adjustment to their monthly estimated custom processing allowance. (Refer to Appendix P)

If approved, the Department will process requests received up to and including the last day of a calendar month, on the next month’s invoice. The Department will not make retroactive adjustments if such requests are received late or they do not provide sufficient information for approval.

3.2.1 Annual Adjustment from Estimate to Actual S.17(4)� � Annually, the Department calculates:

• the difference between the estimated Crown share of Capital Cost Allowances deducted during the year and the actual Crown share of Capital Cost Allowances calculated for each royalty client, and

*For definition, please see Appendix N - Glossary April 1, 2002 ALBERTA NATURAL GAS ROYALTY Ch III, Page 3-2

Chapter IV, Section 2 - Volumetric Reporting of Mineral Activity

09/01/99

PROV TYPE

STREAM ID

PRODUCT NAME

100% TOTAL

TOTAL CROWN %

2.2(1) SETUP (2) CHANGE

UPDATE CODE

CLIENT INFORMATION

2.10 CROWN % 2.9 W.I.O.% 2.8 CLIENT NAME 2.7 CLIENT ID

TERMINATION DATE

PRODUCT NAME

CODE

2.3

2.1

1.2

MO. 2.6

YR. YR. MO. 2.5

EFFECTIVE DATE 2.4

WORKING INTEREST OWNERSHIP (W.I.O.) PART 2:

( ) TELEPHONE

1.5 CONTACT PERSON

1.4

MO. DY. YR. 1.3 DATE PREPARED

OPERATOR ID OPERATOR NAME1.1

PART 1:

SINGLE WELL/INJECTION SCHEMESETUP/CHANGE

RMF3

ENERGY

*For definition, please see Appendix N - Glossary April 1, 2002 ALBERTA NATURAL GAS ROYALTY Ch IV, Page 2-17


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

SINGLE W ELL/INJECTION SCHEM ESETUP/CHANGE

RM F3 (CONTINUATION)

PART 3:

3.1NAME SCHEME ID

3.3

YR MO. 3.5

PART 4: UNIQUE W ELL IDS W IT HIN AN INJECTIO N SCHEME 4.6 PAG E OF

UPD ATE CODE: (1) SETUP (2) CHANGE

4.2 UPDATECODE

4.3 UNIQ UE W ELL ID 4.4 EFFECT IVE D AT E 4.5 T ERMIN AT ION

W1W1W1

W1W1W1W1W1

W1W1W1W1

W1W1

W1

W1

W1W1W1

W1

4.1 FIELD/PO OL CODE

INJECT ION SCH EM E INFOR M ATIO N

3.2

INJECTIO N FAC IL IT Y ID 3.4

NAME

UPD AT E CODE

(1) SET UP (2) C HANG E

3.8 INJECTIO N SCH EM E T YPE

ENH ANCED O IL RECOVERY SC HEME

COMM ERC IAL ST ORAGE SCHEME

CYCLING SCH EM E

STO RAGE SCHEME

PRESSURE M AINTENANCE SCHEME

OT HER

3.6 EFFECT IVE D ATE 3.7 TERMIN ATIO N D ATE

YR MO .

W1

W1

W1

W1

W1W1W1W1W1

4.7 UNIT /W G CODE

3.9 CROW N INT EREST

09/01/9

ENERGY



2.5 Owner Activity Statement (OAS)

PREPARING AN OWNER ACTIVITY STATEMENT

The Owner Activity Statement (OAS) is a natural gas industry report introduced by the Partner Regulatory Information Data Exchange (PRIDE) initiative. PRIDE was a collaborative industry and multi-government initiative focused on re-engineering the requirements of industry to industry and industry to government reporting. The Alberta Department of Energy was a participating member of PRIDE.

The Department agreed with the reporting requirements established by PRIDE for the OAS and has adopted them for reporting purposes, subject to the business rules required to provide acceptable assurance that the Crown royalty share is correctly determined and collected. The business rules relating to determining the Crown royalty share are outlined in Ch II, Sec. 1 and 2. The business rules that deal directly with the Department’s requirements for OAS reporting are described in Ch. II, Sec 1., Ch. II, Sec. 1.7. and Ch. II, Sec. 2.3.3.

RECONCILING AN OWNER ACTIVITY STATEMENT

The Department reconciles OAS reports to EUB volume information and to other OAS reports with which they are associated. The following is a summary level schematic of the reconciliation process.

Yes Yes

No No

EUBDOCUMENTS

VOLUMESASSIGNED TO

FACILITYOPERATORS

OASDOCUMENTS

VOLUMESALLOCATEDTO OWNERS

ARE ALLFACILITY VOLUMES

ASSIGNED?

ARE ALLVOLUMES ASSIGNEDTO ROYALTY ENTITY

OWNERS?

CALCULATE ANDINVOICE

CROWN ROYALTY

CALCULATEPROVISIONAL

ROYALTY

CALCULATEPROVISIONAL

ROYALTY

�

The business rules for volume allocations and OAS responsibility are described in Ch II, Sec. 1.3, Ch II, Sec. 1.4 and Ch II, Sec. 2.3.

The volume reconciliation process is described in detail in Appendix A.



2.6 OAS Reporting 2.6.1 Timing

Completed OAS documents must be received by the Department on or before the 15th day of the second month following the production month.

Consequence of Non-Compliance A facility operator who fails to submit the completed OAS by the due date may be charged a penalty of $1,000 for each month or part of a month during which the failure continues. The penalty is calculated from the due date until the report is received by the Department. The penalty will be charged to the operator responsible for submitting the OAS, and will be reported on his Invoice. The operator will also be subject to provisional assessment. The Department has not thus far implemented OAS penalties.

If an upstream facility operator (cascading facility operator) does not submit an OAS report by the due date, that operator will not be charged a penalty, but will be provisionally assessed on the Crown share of the volumes.

2.6.2 Reporting Level All OAS volumes must be reported at the highest level (i.e., well/well group (both consolidated/non-consolidated), unit or injection scheme (refer to Ch II,Sec.1.6.1)). Holiday wells and OFSG must be reported as single wells to receive the benefits.

2.6.3 Production from Injection Schemes

All producing wells in an EOR scheme (identified on the RMF3 form) must be reported on the OAS with the EOR (injection) scheme number in the Stream ID column, and not a Well/Well Group/Unit number. This is necessary in order to recapture the operating costs on indigenous volumes. For non-EOR injection-related production volumes, the Stream ID will depend on whether or not the producing wells were set up on the RMF3 under their respective injection scheme number. For producing wells set up on the RMF3, the Stream ID on the OAS must indicate the injection scheme number. For those producing wells not set up on RMF3, the Stream ID must be the well, well group, or unit.

2.6.4 OAS Reporting Requirements

TO ASSESS GAS ROYALTY, THE DEPARTMENT RELIES ON DATA OBTAINED FROM INDUSTRY'S OAS REPORTING SYSTEM. BASED ON PRIDE RELEASE 3 DATED JUNE 6, 1994, THE DEPARTMENT WILL RELY ON THE FOLLOWING:

a) At facilities where previously unsold, unprocessed gas is throughput without processing :

• all sales and exchange sales must be reported; • all transfers of unsold gas to Mainline Straddle Plants, transportation

facilities, Oil Sands Projects and similar facilities outside of royalty network must be reported; and

• all transfers of unsold gas to facilities where products can be injected must be reported.

b) At facilities where previously unsold gas stream is processed:

• all lease fuel sales or deemed lease fuel sales (i.e., ineligible lease fuel) must be reported as processed or sale volumes on gas plant's OAS, or gas gathering system's OAS, respectively;



• all processing must be reported net of fuel. All NGL product mixtures extracted during processing must be reported at a component level;

• all transfers of unsold gas to facilities other than Mainline Straddle Plants and transportation facilities must be reported;

• all transfers of unsold gas to transportation facilities which subsequently returns to the network for use as eligible fuel (i.e., returned fuel) must be reported; and

• all transfers of unsold gas to facilities where gas and gas products can be injected must be reported.

c) At facilities where previously unsold processed gas is throughput without further processing: • all lease fuel sales or deemed lease fuel sales (i.e., ineligible lease fuel) must

be reported as processed or sale volumes on gas plant's OAS, or gas gathering system's OAS, respectively;

• all eligible fuel quantities must be reported; • all flare and vented quantities must be reported; • all measurement differences between stream receipt and delivery quantities

must be reported; • all transfers of unsold gas must be reported; • all transfers of unsold gas to transportation facilities which subsequently

returns to the network for use as eligible fuel (i.e., returned fuel) must be reported; and

• all transfers of unsold gas to facilities where gas and gas products can be injected must be reported.

At the end of OAS cascading, all of the above must be reported at a Well/Well Group/Unit/Injection Scheme level.

d) At facilities where gas and gas products can be injected: • all quantities of gas and gas products received for the purpose of injection

must be reported, indicating the purpose and target injection scheme ID; • all quantities of NGL product mixtures received for the purpose of injection

must be reported at a component level; • all transfers of unsold product from these facilities must be reported; and • all sales of product from these facilities must be reported.

e) Also:

• all quantities of gas and gas products received from Field Straddle Plants and transportation facilities must be reported;

• all sales of gas within royalty network (batteries, gathering systems, gas plants, field straddle plants if gas is unprocessed) must be reported, indicating the destination of the product movement. Sales of unprocessed gas indicating a "processing" facility as the destination will be valued at 80% of Gas Reference Price. Should other situations warrant the 80% valuation, clients may identify these to the Department for review. If justified, an adjustment to the valuation will be made;

• all purchases of gas within royalty network (batteries, gathering systems, gas plants, field straddle plants if gas is unprocessed) must be reported, indicating the destination of the product movement; and



• all exchanges of gas within royalty network (batteries, gathering systems, gas plants, field straddle plants if gas is unprocessed) must be reported indicating the destination of the product movement.

f) The OAS reporting for gas dispositions (sales and transfers) at a processing plant that are not processed at the plant (i.e., flow-through volumes) must be differentiated from the gas dispositions, which are processed at the plant. Flow-through volumes must carry a different stream ID than the volumes being processed at the plant, and must not be cascaded to the same upstream facility.

g) Gas dispositions at a gathering system should be reported on the OAS activity as a "Transfer" or "Sale" with the appropriate destination of the product movement. Liquid products produced at a gathering system (e.g., pentanes) are to be reported on the OAS activity as "Process".

h) Operators who submit OAS documents for more than one owner must begin the page numbering at page one for each new owner. Page numbering is specific to operator, facility, owner, and production month.

I) Holiday wells must be reported as single wells on the OAS to receive holiday

benefits.

2.6.5 OAS Amendments

• OAS amendments for owners must be full form replacements. The filing date on the new OAS must be later than the filing date on the previous OAS; otherwise, the OAS will be rejected.

• If there is a retroactive change to a well's vintage or Crown interest and the well is no longer eligible to be included in the consolidated well group, then the OAS must be refiled to allocate volumes to the well and the consolidated well group. Failure to amend the OAS document will result in the rejection of an incorrect OAS detail line record(s) and provisional assessment. Also, the RMF1 form must be refiled to reflect the change in the consolidated well group

• Where an OAS was filed incorrectly (e.g., to a wrong owner), it can be deleted by refiling. The amending OAS should indicate identical header information but with a later "Date Prepared" date and must include one line of valid detail data with zero volumes.

2.7 Royalty Triggers and OAS Reporting Rules for Royalty Assessment

The Department adopted the reporting requirements established by PRIDE for the OAS for royalty assessment. Using the OAS data provided by facility operators, the Department assesses royalty at facilities for the owner of each product stream. Assessment is primarily based on what happens at a facility. Different royalty assessment methods are used depending on whether the previously unsold product stream is processed or unprocessed .

Please refer to Appendix B for a detailed illustration of Royalty Triggers and OAS Reporting Rules for Royalty Assessment.



2.8 OAS Reconciliation

An OAS reconciliation is done to ensure that quantities which should be accounted for according to EUB "S" data are reported on the OAS. In addition, OAS quantities subject to reconciliation that are cascaded to upstream facilities are accounted for by the operators of the upstream facility. Included in the OAS reconciliations are the sales to purchases reconciliation between the facility that reported the sales and the facility that reported the purchases. However:

• No "S" to OAS reconciliation will be performed for mainline straddle plants and fractionation plants; and

• No "S" to OAS reconciliation will be performed if the facility is a battery.

NOTE: OAS VOLUME RECONCILIATION TOLERANCE HAS BEEN ESTABLISHED TO AVOID ASSESSING INSIGNIFICANT RECONCILIATION DIFFERENCES.

Please refer to Appendix A for detailed examples of reconciliations.

2.9 Validation Rules - Owner Activity Statement (OAS)

All OAS transmissions will be subject to validation rules or edits established by the Department. These are also defined as the "Data Element Validation Rules" in the PRIDE manual. The objective of the edits is to ensure that OAS reporting does not contain any element, which will affect the correctness and accuracy of the calculation of Crown royalty.

The edits are divided into three categories. They are:

• edits which will result in rejecting the entire OAS;

• edits which will result in inactivation of the entire OAS; and

• edits which will result in rejecting the OAS line record.

A complete detail of all the validation rules are described in Appendix C.



Page No. 1

OWNER FAX NUMBER OWNER CONTACT PERSON OPERATOR CONTACT FAX NUMBER OPERATOR CONTACT PHONE NUMBER OPERATOR CONTACT PERSON FILING DATE PRODUCTION PERIOD

NAME TYPE PROV. CODE

ALLOCATOR OWNER

OPERATOR FACILITY PROVINCE

CODETYPEPROV.NETGROSSNETGROSSCODETYPEPROV.CODETYPEPROV.

DESTINATION ID HEAT CONTENT QUANTITY ACTIVITYPRODUCT

LOCATIONSTREAM CATEGORY

STREAM ID

OWNER ACTIVITY STATEMENT P R I D E

*For definition, please see Appendix N - Glossary

April 1, 2002 ALBERTA NATURAL GAS ROYALTY Ch IV, Page 2-24

Chapter IV, Section 4 - Valuing Gas Products

4.4 Preparing a Monthly Sulphur Corporate Average Price (S-CAP) Calculation

VA4 FORM - MONTHLY CORPORATE AVERAGE PRICE CALCULATION - SULPHUR

PURPOSE

All royalty clients having annual sulphur production of 30,000 tonnes or more (based on previous year’s production) must file VA4 forms monthly to determine their S-CAP. The Department will notify the royalty clients who are in this category.

Those royalty clients whose annual sulphur production is less than 30,000 tonnes may choose to file VA4 forms monthly effective January’s production month, and then, must continue to file VA4 forms for the entire year. New royalty clients who wish to file VA4 forms must file them effective the first production month in which they have sulphur allocation and then, must continue to file for the remainder of the year.

The Department values and invoices the Crown royalty share of sulphur production monthly using the royalty client’s S-CAP.

A description of the business rules associated with calculating the annual S-CAP is provided in Ch II, Sec. 3.5.3 and Ch III, Sec. 2.4.

TIMING

The Client Services Help Desk must receive a completed VA 4 form on or before the 15th day of the second month following the production month to which the S-CAP applies.

CONSEQUENCES OF NON-COMPLIANCE

Effective January 1999 the penalty of $1000 per month or part of a month for failing to file a VA4 form by its due date is replaced with a penalty of $100 per month or part of a month until the form is received.

The Crown royalty share of sulphur for the delinquent month will be valued and invoiced using that month’s Sulphur Default Price. Upon receipt of the VA4 form, the Crown royalty share of sulphur will be valued in the manner described in Ch II, Sec. 3.5.3 and Ch III, Sec. 2.4.1. Interest will be charged or paid on the difference between the value computed by using the Monthly Sulphur Default Price versus the S-CAP.

AMENDING MONTHLY SULPHUR CORPORATE AVERAGE PRICE

An amended VA4 form must be completed in full just as with an initial VA4 form.


Chapter IV, Section 4 - Valuing Gas Products

VA4 FORM - COMPLETION INSTRUCTIONS

PART 1: CLIENT DETAIL

1.1 CLIENT ID - The four-character EUB operator code or seven-character royalty client ID number assigned by the Department that identifies the royalty client.

1.2 CLIENT NAME - The full name of the royalty client for whom the information is submitted. �

1.3 PRODUCTION YEAR/MONTH - The production year and month to which the S-CAP information applies.

1.4 DATE PREPARED - The numeric year, month and day on which the VA4 form is prepared.

1.5 CONTACT PERSON - The name of the person the Department can contact concerning information on the form.

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

1.7 NO SALES - If there are no sales during the year, check this box and leave Part 2 blank.

PART 2: ARM’S-LENGTH SALES

NOTE: COMPLETION OF FIELDS 2.1, 2.3, 2.4 AND 2.5 IS OPTIONAL.

2.1 POINT OF SALE - The point of delivery for volumes sold (NORTH AMERICA and OFF-SHORE).�

2.2 TONNES - Total tonnes of Alberta gas plant-produced sulphur sold by the royalty client during the month, for each point of sale.

(The total tonnes of sulphur does not include other producer's share of sulphur if the royalty client also markets other producer's share of sulphur.)

2.3 GROSS MONTHLY SALES VALUE - Total gross monthly sales value received for sulphur sales (tonnes) identified in field 2.2.

2.4 TRANSPORTATION COSTS - Total transportation costs incurred to transport sulphur (tonnes) identified in field 2.2, from the producing plant gate to the point of sale.

2.5 STORAGE COSTS - Total storage, loading and handling costs incurred as a direct consequence of the transportation of sulphur identified in field 2.4.

2.6 NET MONTHLY SALES VALUE - The gross monthly sales value …minus… transportation costs …minus… storage costs.

PART 3: CERTIFICATION

3.1 AUTHORIZED SIGNATURE - The signature of the authorized signing officer of the royalty client who is responsible for the information submitted.

3.2 NAME OF CORPORATE SIGNING OFFICER - The full name of the authorized signing officer whose signature appears in field 3.1.

3.3 TITLE OF CORPORATE SIGNING OFFICER - The position title of the authorized signing officer whose signature appears in field 3.1.

3.4 DATE - The date on which the authorized signing officer signed the VA4 form.


Appendix P - Forms The forms contained within this Appendix are for the use of Royalty Clients to submit to the Department. These are base copies from which additional copies can be made and used. The forms are: FORM 595 Sulphur Emission Control Assistance Program (SECAP) Schedule 1 AC1 Allowable Costs Facility Cost Centre Setup/Change AC2-V1 Allowable Costs Capital Cost Allowance Production Years 1994, 1995 and 1996 AC2-V2 Allowable Costs Capital Cost Allowance Production Years 1997 and Onwards AC3 Capital Costs Allowance Reallocations AC4 Allowable Costs Operating Costs AC5-V1 Allowable Costs Custom Processing Fees Paid Production Years 1994, 1995 and 1996 AC5-V2 Allowable Costs Custom Processing Fees Paid Production Years 1997 and Onwards. AC10 Application For Plant Type Code and Transportation Region Code CPAF Custom Processing Adjustment Factor GR1 Application to Grandfather Co-Generation or Long-term Contracts GR2 Annual Statement of Grandfathered Contact Sales ICC1 Invoice Consolidation Concurrence NGL1 NGL Valuation and Transportation NGL2 Storage Costs (For Production Year 1994 Only) OAS Owner Activity Statement OC1 Facility Operator Change Form OFSG Otherwise Flared Solution Gas Royalty Waiver Program Application Form Gas Royalty Registry Update PW1 Monthly Statement of Proprietary Gas - Royalty Waived RMF1 Consolidated Single Well Group Setup/Change RMF2 Reassignment of Volumes Setup/Change RMF2T Reassignment of Volumes Termination RMF3 Single Well/Injection Scheme Setup/Change TC20 Application For Facility To Meter Station Connection VA1 Election for Gas Valuation VA2 Corporate Average Price Calculation Gas VA3 Annual Corporate Average Price Calculation - Sulphur VA4 Monthly Corporate Average Price Calculation - Sulphur Request for Refund Vendor Maintenance Request Form Monthly Capital Cost Allowance Estimate Adjustment Worksheet Monthly Custom Processing Fee Estimate Adjustment Worksheet YECO Year End Close-out Form

April 1, 2002 ALBERTA NATURAL GAS ROYALTY Appendix P-1

gas royalty calculation information bulletin - april 2002 · for determining multiple gas valuation...

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