ENERGY RESOURCES CONSERVATION BOARD
Calgary Alberta
Informational Letter IL 82-4
TO: All Oil, Gas and Oilsands Operators
DRILLING SPACING UNITS AND
TARGET AREAS REQUIREMENTS CLARIFIED
In August of 1981 the Energy Resources Conservation Board (Board) issued Order No. SU 1088 outlining the new target area requirements for the "white" and "j'-ellow" areas of the Province of Alberta as shown in Figure 1 of the order. Clause 1 of SU 1088 identifies the wells to which the new target area requirements apply. There has been some confusion as to the interpretation of this clause and consequently the Board believes it appropriate to provide a clarification.
The order requires that oil wells to be drilled in areas which are not
(a) within declared oil pools defined by Board G orders as of 1 August 1981, or
(b) subject to any spacing orders other than SU 1088,
shall be located in the northeast corner of a spacing unit in accordance with the new target area requirements. It should be noted, however, that the Board G orders and spacing orders refer to specific pools. A well to be drilled within the surface area shown in such an order, but to obtain production from a potential producing zone not included in that order, is subject to the new northeast target area.
The Board recognizes that the SU 1088-induced shift in target area require- ments within the surface boundaries of pools or spacing-order areas could lead to more than one surface well within a given drilling spacing unit (DSU) . Particularly in areas drilled on 32-hectare (80-acre) and 16-hectare (40-acre) spacing, but also in some areas developed on quarter-section spacing, the addition of another drill site elsewhere than on one of the existing sites may not be considered appropriate. The Board believes that where such a situation appears to be occurring, communication with poten- tially affected surface owners and occupants should take place at an early stage of development. In such cases, if it is determined that the concerns of landowners would be better served by utilizing existing well sites, and where the utilization of an existing well pattern for new formations to be drilled would not create subsurface conservation or equity problems, the Board would expect oil-industry operators to file applications for an appropriate change from the target-area requirements of SU 1088.
Appendix 1 attached generally summarizes the target-area requirements for the Province.
APPENDIX 1 IL 82-4
SUMMARY OF WELL SPACING REGULATIONS AND ORDERS Area Concerned and
Regulation/Order Conditions
1 Green area
Part 4 - Oil and Gas
Conservation
Regulations
2 White and yellow a ^
areas
Order No, SU 1088
3 Southeastern Alberta Order No. SU 800
All Areas of the Province
Other Spacing Orders
Gas ~
Oil
Gas - l~section drilling spacing unit - central target.
Oil - l/4-<section drilling spacing unit - central
target,
i-section drilling spacing unit - central target with primary and secondary areas, i/4~section drilling spacing unit, northeast targets with primary and secondary areas (Lsds 6, 8, 14, and 16),
Exceptions :
o Any well drilled within the surface boundaries of a declared oil pool as defined and described by Board G orders as of 1 August 1981 and intended for production from that pool, will be subject to the target-area requirements shown for Item 1, However, it should be noted that any well drilled within the surface boundaries of a declared oil pool as defined above, but to obtain production from a diff- erent pool will be subject to SU 1088 spacing requirements .
o Any well drilled to a pool or formation subject to a spacing order (SU) and within the area specified by that spacing order will be subject to the drilling spacing unit (DSU) and target area requirements outlined in that order.
Gas -
central
northeast 8, 14,
1-section drilling spacing unit - target .
1/4-section drilling spacing unit legal subdivision targets (Lsds 6 and 16).
Oil - 1/4-section drilling spacing unit, northeast legal subdivision targets.
These SUs specify the drilling spacing unit and/or target area requirements for gas and/or oil and apply only to the formation(s) or pool(s) specified in the order.
a As described in Figure 1, Order No. SU 1088.
b Area lying south of township 31 and east of the 5th meridian.
CANADIAN OFFICIAL PUBLICATIONS COLLECTION
DE PUBLICATIONS OFFICIELLES
CANADJ"ENi\ES
NATIONAL LIBRARY/ B I HLIOTIIEQUE NATIONALE CANADA
FEB 2 - 1982
/ ENERC
ENERGY RESOURCES CONSERVATION BOARD
gary yAlberta
•y
TO:
All Oil and Gas Operators
INFORMATIONAL LETTER
ASSESSMENT OF NATURAL GAS RESERVES, 1982 THE FREEHOLD MINERAL TAXATION ACT THE OIL AND GAS CONSERVATION ACT
In order to determine the pool average well-head value of natural gas for the 1982 taxation year, the Assessor appointed under the Freehold Mneral Taxation Act and the Oil and Gas Conservation Act will require the information specified in this letter not later than March 31, 1982.
The procedure provides that the plant operator or, where the natural gas is not processed at a plant, the gas gathering system operator shall provide certain data to the Assessor as set out hereunder:
1. Where the raw gas produced requires further processing at a plant, the plant operator shall provide to the Assessor, for each pool serviced, a value for net revenue including
(a) a value for residue gas sold for each pool at the price in effect on December 31, 1981. (The value shall include all rebates, and adjustments added to the well-head price as a consequence of the sale of gas beyond the Canadian border.),
(b) values for plant products such as propane, butane, a mix of natural gas liquids, pentanes plus at the price in effect on December 31, 1981,
(c) values for sulphur calculated as follows :
(i) where a plant sold more than it produced in 1981, the price per tonne in effect on December 31, 1981.
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(ii) where a plant sold less than it produced in 1981, a price calculated by the following:
price/tonne = Annual volume sold x December 1981 price Annual production
(d) cost for gathering, compression prior to plant, and plant operating costs.
2. Where the produced raw gas does not require further processing at a plant, the gathering system operator shall provide to the Assessor, for each pool serviced, a value for net revenue including
(a) a value for gas sold at the price in effect on December 31, 1981. (This value shall include all rebates, and adjustments added to the well-head price as a consequence of the sale of gas beyond the Canadian border) .
(b) values for any products such as pentanes plus recovered from the system which add significantly to the total value of the gas where such products can be attributed to specific pools, and
(c) cost for gathering and compression.
3. Some of the raw gas received at a plant and part of the residue gas and/or products are sometimes injected either into the pool of origin or into some other pool. If the material for injection is sold, then it must be included in the calculation of gross revenue, and the following additional data should be provided
(a) volumes of raw gas, residue gas or products injected,
(b) fields and pools from which produced and into which injected, and
(c) value of raw gas, residue gas or products injected. If the gas and/or products injected are not sold to the injecting system owner operator, a value for such fluids isn't required. Notwithstanding this general rule it may be advantageous to claim injected fluids as a revenue on the gas assessment (i.e. on this report), and as a cost on the oil assessment (the latter is usually accomplished by appeal . )
Accordingly, for the 1982 taxation year each gas processing plant operator or gas gathering system operator is required to submit details of product values, cost of service and net revenue for the determination
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of well head values on a pool basis. The procedure to be used and an example submission and format are attached hereto. You are requested to adhere to this format as closely as possible. As indicated in the example, a breakdown between plant, field compression and gathering system costs is to be provided. The costs attributable to compressors located within plants would comprise part of the plant total. Each plant operator would, in addition to the required plant information, submit all of the field compressor and gathering system data pertaining to the plant operation even though these facilities may be operated by other owners. Please note also, that specific information is required for residue or raw gas injected.
In the case where gas gathering, field compression and sale occurs without subsequent processing, the operator of the gathering and compressor facilities shall submit the appropriate sales and cost data.
When a plant operator has no ownership interest in the pools which are serviced by the processing plant, and is purchasing raw gas at the well-head at a common price, the plant operator shall submit the data referred to in item 1, and shall, in addition supply the price which he was paying the well operators for the raw gas as at December 31, 1981.
Past experience has indicated that incomplete data or no data is received for some pools in which processing of the gas is not required, but gas gathering systems are necessary. It is in the owner's interest that cost of service be supplied in these cases.
In processing submissions received. Board staff will be referring to the Board publication "Alberta Gas Plant Statistics Monthly Supplement" (ERCB - 13B) which summarizes Gas Plant processing statistics as reported to the Board via the reports "Gas Processing Plant Statement" (form S-20) and "Monthly Gas Processing Plant Products Statement" (form S-21).
The Assessor is aware that some of the information used in the compilation of these data may be of a confidential nature. Except for the net price used in the assessment calculation, the information supplied as required above will not be disclosed. Please note however, that the data submitted must include accurate information on both gross revenue and cost of service.
Any inquires regarding these matters should be directed to Mr. Dale Youngstrom, telephone 261-8374, or Mr. Graham Jenkinson or Mss Debbie Ross, telephone 261-3490.
DATED at Calgary, Alberta on 26 January 1982
ENERGY RESOURCES CONSERVATION BOARD
M. R. Blackadar
Assessor
Digitized by the Internet Archive in 2015
https://archive.org/details/energyresources198245
PROCEDURE FOR ESTABLISHING WELL HEAD GAS PRICES
To assure conformity in reporting and calculation of the well head price for each pool, we are requesting that the following information and basis be used. Where there is no processing plant, read "gas gathering system" in place of "plant".
1. The name of each field and pool
Note 1: fields and pools into which wells are placed for this
purpose should be those designated for reporting purposes by the Energy Resources Conservation Board, as they existed as at December 31 of the base year (year just ended) for those wells. The assessor uses Board field and pool designations in determining the total production applicable to each pool. To calculate an accurate pool price it is essential that the net revenue supplied by the operator and the production supplied by the Board relate to identical groups of wells.
Note 2: undefined wells as designated by the Board, should be
considered separately and identified by the well location, rather than the pool code. If the gas produced from a number of undefined wells has approximately the same product composition, they may all be reported in one column under the heading "undefined" provided that the wells together with their individual gathered gas volumes are separately listed elsewhere in the report.
Note 3: when a well changes its pool designation during the year,
its annual production should be assigned to the pool that it was part of on December 31. For example, a well which was designated as undefined until September was reclassified by the Board as a Viking well on September 15. The report should show all of the year's production from this well under the heading Viking Pool and the appropriate field.
2. The plant processing the gas, and the plant code assigned by the Board.
3. The plant operator.
4.
Raw gas volume received at the plant and final products after processing for each pool in 1981 in SI Units.
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(a) Raw gas received at the plant in 103 m3 at 101.325 kPa.
*(b) Raw gas injected after receipt at plant - 103 m3 at 101.325 kPa. Please identify field and pool into which injected.
*(c) Residue or marketable gas injected after receipt at plant - 103 ni3 at 101.325 kPa. Please identify field and pool into which injected.
(d) Sales gas, other than injected - 103 m3 at 101.325 kPa.
*(e) Propane injected - m3. Please identify field and pool into which injected.
(f) Sales of propane, other than injected - m3.
*(g) Butanes injected - m3. Please identify field and pool into which injected.
(h) Sales of butanes, other than injected - m3.
*(i) Pentanes plus injected - m3. Please identify field and pool into which injected.
(j) Sales of pentanes plus, other than injected - m3. Do not report field condensate reported on Board S-1 forms.
*(k) N.G.L. other than above, injected - m3. Please identify field and pool into which injected.
(1) Sales of N.G.L., other than injected - m3.
(m) Recovered sulphur - tonnes.
*Gas and other fluids may be sold for injection purposes or may be considered sold if the recipient wishes to claim a value of injected fluids on the oil assessment, or may be considered to have no immediate value. Please specify classification into which the injected gas or products fall.
5. Gross value of products from pool - 1981. All values must be based on the price received for the product as at December 31, 1981, except sulphur which should be calculated on the basis shown on page 1 of the covering letter. For sales gas, this price is made up of
(i) the price received for the gas and
(ii) the price adjustment as determined by the Minister for
December 1981 pursuant to The Natural Gas Pricing Agreement Act.
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Note: In all instances the operator will use the best figures
available to him for product prices on the assumption that this will be representative of the pool.
(a) Value of residue gas as at December 31, 1981. (Please list separately, "price received" and "price adjustment" as shown in the attached example).
(i) residue gas sold to the market
-0 .c.i.j.hvvr (1)
**(ii) residue gas injected. **(iii) total of (i) and (ii).
(b) Value of propane as at December 31, 1981 (Please show unit o price) .
(i) propane sold to the market **(ii) propane injected, (iii) total of (i) and (ii).
(c) Value of butanes as at December 31, 1981. (Please show unit price. )
(i) butanes sold to the market **(ii) butanes injected, (iii) total of (i) and (ii).
(d) Value of pentanes plus as at December 31, 1981. (Please show unit price.)
(i) pentanes plus sold to the market ' **(ii) pentanes plus injected, (iii) total of (i) and (ii)
** Value must be assigned in certain cases. See footnote under number 4 on previous page and Section 3 of covering letter.
(e) Value of other N.G.L. as at December 31, 1981. (Please show unit price).
(i) N.G.L. sold to the market
**(ii) N.G.L. injected.
(iii) total of (i) and (ii)
(f) Value of sulphur produced. See covering letter.
The sum of the above income streams is the gross value of the plant's share of the pool as at December 31, 1981.
1981 cost of service of gathering, compressing and processing. Generally speaking, the cost of service principles, utilized by producers, in their submissions to the Department of Energy and Natural Resources (Department), for calculating deductions for gathering and processing gas for royalty purposes shall be used. Section 3 of the booklet issued by the Department entitled "Guidelines for the Calculation of Crown Royalty on Natural Gas and Associated By-products" may provide useful assistance to those who are not familiar with the procedure. As 1981 is the base year for a present value calculation, the cost of service should not take into consideration previous over or under deductions. For the purpose of this assessment, the cost of service of facilities required for cycling and load levelling are permitted deductions. As a well operating cost allowance will be used by the assessor, in addition to a cost of service deduction, consideration must be made in allocating only a proper share of field costs to gathering and field compression.
For purposes of prorating capital costs and operating expenses of a pool's share of facilities utilized, the same procedures as approved by the working interest owners and/or the Department should be used.
The "cost of service" permitted which has evolved using the general principles of the Jumping Pound Decision consists of:
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(a) Direct operating cost of the pool's share of a facility. This may include operator's overhead consistent with that negotiated by participants in a joint venture and/or recognized by the Department.
(b) Rate of return on remaining invested capital - use 15% of the mid-term rate base of the pool's share of the facility. The mid-term rate base consists of
(i) average depreciated capital cost
(ii) working capital allowance (1/6 of direct operating cost)
(iii) land at cost
, (c) Depreciation of the pool's share of the facility. A
straight line depreciation is requested, in whatever percentage is appropriate for the facility. Four to five per cent appears to be the most popular range.
The sum of the individual costs of service for plant, gathering systems and compression is the 1981 cost of service for the pool.
7. The 1981 net revenue generation of the pool is the difference between the gross value (item 5) and the cost of service (item 6).
It is understood that this net revenue value relates only to the part of the pool production processed at a particular plant. Where two or more plants are involved in one pool, the assessor will sum the data submitted by each plant operator. The same is true of net revenues determined by gas gathering system operators, where more than one system is operated in a pool.
In addition, for those pools for which production of field condensate was reported, the gross revenue shall be adjusted by the assessor to take the value of condensate sales into consideration.
Note: Although this procedure relates to the information to be provided by the plant operators, it should be understood that where no processing plant is used, the gas gathering system operators or distributors should supply the necessary data.
Plant No. X
DATA SHEET - EXAMPLE FIELD COMPLEX WELL HEAD VALUE
1982 ASSESSMENT THE OIL AND GAS CONSERVATION ACT THE FREEHOLD MINERAL TAXATION ACT
1. POOLS
(both field and pool required - actual names and code nos.)
2. PLANT
3. PLANT OPERATOR
4. VOLUMES* & PRODUCTS
Example A Pool
Example B Pool
Example Plant Example Company
Example C Pool
Example D Pool
5.
a) Raw gas - plant inlet 197 415 103 m3
b) Raw gas injected 103 m3
c) Residue gas injected 103 m3
d) Sales gas 103 m3
e) Propane injected, m3
f) Sales of propane, m3 453
g) Sales of butanes, m3 1 870
h) Sales of pentanes plus, m3 n 998
i) Recovered sulphur, tonnes 3 292
GROSS VALUE PRODUCTS FROM POOLSc
a) Gas Income $/103 ni3
(Unit Price) - 51.47
Price adjustment - 26.62
$78:w
107 118
28 174a
338 482
165 409
56 348b(to 'E' Pool)
118 555 65 843
190b(to 'E' Pool) 392 1 137 7 353 1 829
Sold to market Injected
9 257 960 4 400 215 13 658 175
5 141 680
5 141 680
277 204 318a 1 362 5 465 39 327 13 456
21 646 860
21 646 860
124 577
357
1 255 8 295 4 085
9 726 656
9 726 656
Gas volumes measured at 101.325 kPa and 15°C injected to pool of origin and not sold injected to pool *E' and payment received
The prices quoted in this example, are for illustrative purposes only. December 31, 1981 prices must be used in submissions. See Page 1 of covering letter.
Example Example Example Example
A Pool B Pool C Pool D Pool
b) Propane Income $
(Unit Price - $64.78/m3)
Sold to Market 29 345 25 394 88 230 23 126
Injected 12 308
41 653 25 394 88 230 23 126
c) Butanes Income $
(Unit Price - $104.27/m3)
Sold to market 194 985 118 555 569 836 130 859
d) Pentanes Plus Income $ (Unit Price - $87.68/m3)
Sold to Market 1 051 985 644 711 3 448 191 727 306
e) Sulphur Income $
(Unit Price-$85.00/tonne) 279 820 155 465 1 143 760 347 225
GROSS VALUE 15 226 618 6 085 805 26 896 877 10 955 172
COST OF SERVICE - All figures in Thousands of Dollars
a) Cumulative Capital & Mid-term Rate Base
i) Plant Capital 11 106
Mid-term Rate Base 9 781
ii) Compression Capital 196 Mid-term Rate Base 181
iii) Gathering System Capital 265 230 1 164 248
Mid-term Rate Base 222 205 1 036 231
b) Cost of Service
i) Cost of Service
Plant - Operating 1 501
Depreciation (4% S.L.*) 444 Return on Rate Base (15%) 1 467
3 412
Plant Split** 929 350 1 472 661
Straight line depreciation must be used. Percentage used must not vary from year to year.
Residue Gas was used in the example as the basis for the plant split for purposes of simplicity. Actual split of plant costs should be made on the basis of the plant operator's knowledge of the costs involved for each pool. This split would normally have the approval of the working interest owners or the Department.
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Example Example Example Example
A Pool B Pool C Pool D Pool
ii) Compression
Operating Costs 2
Depreciation (4% S.L.*) 8
Return on Rate Base (15%) 27
37
iii) Gathering System
Operating Costs 18 51 50 20
Depreciation (4% S.L.*) 11 9 47 10
Return on Rate Base (15%) 33 31 155.
62 91 252 65
iv) Total Cost of Service 991 441 1,724 763
1981 NET REVENUE 14 236 5 645 25 173 10 192 5-6
Straight line