Definitions and interpretation

1   (1) In this regulation:

"Act" means the Petroleum and Natural Gas Act;

"administrator" means the person appointed as the royalty administrator under section 73 (3) of the Act;

"amendment application" means an application to amend a well permit under the Energy Resource Activities Act;

"average daily natural gas production volume" means, in relation to a well event in a producing month, the volume of natural gas produced in the producing month from the well event, expressed in m³, divided by the number of hours during which the well event produced natural gas in the producing month and multiplied by 24;

"BPO lease" means a right to produce petroleum or natural gas if

(a) the right arose as a result of a Crown Petroleum and Natural Gas Tenure Disposition Agreement dated May 19, 2004,

(b) in section 1.1 of that agreement, the provisions comprising the 50% Bonus Payment Option have been retained and the provisions comprising the No Bonus Payment Option have been deleted, and

(c) the right to produce petroleum or natural gas relates to lands that are or form part of the Coal Lands as that term is defined in that agreement;

"coalbed methane project" means a well event or group of well events that is

(a) designated as a special project under section 75 of the Energy Resource Activities Act;

(b) capable of producing natural gas from strata or a stratum containing mainly coal;

"collector" means the person appointed as the royalty collector under section 73 (3) of the Act;

"completed", in relation to a well, has the same meaning as in the Drilling and Production Regulation;

"completion date" means the date on which a well becomes a completed well;

"completion point" means, in respect of a gas well event that

(a) is in a vertical well and

(i) has not been completed as an open hole, the bottom of the deepest perforations in the gas well event, or

(ii) has been completed as an open hole, the bottom of the last section of casing in the gas well event, or

(b) is in a horizontal well, the point in the wellbore referred to in paragraph (a) of the definition of "horizontal well" at which the angle of the wellbore first exceeds 80 degrees from vertical;

"concurrent production" means gas produced from an oil well event where the oil well event is part of an approved concurrent production scheme under section 97 of the Act as it read immediately before the section was repealed or concurrent production is authorized under the Energy Resource Activities Act;

"conservation gas" means natural gas produced from an oil well event where the marketable gas is conserved but does not include gas produced from an oil well event granted concurrent production status under section 97 of the Act as it read immediately before the section was repealed or concurrent production is authorized under the Energy Resource Activities Act;

"contract carrier" means a person who is the owner or operator of a pipeline that transports oil or natural gas, or both, for more than one producer and whose tariff has been approved by a public regulatory body having jurisdiction over that person;

"Crown invoice" means an invoice issued under section 9;

"Crown land" has the same meaning as in the Land Act;

"deemed value" means, for a volume of oil or natural gas by-products, the monetary value based on the fixed unit selling price established by the collector under section 7 (2);

"deep discovery well event" means a gas well event that

(a) is in a discovery well,

(b) has a completion point that has a true vertical depth deeper than 4 000 metres,

(c) is in a well that has a spud date after November 30, 2003,

(d) is in a well that has a surface location at least 20 kilometres away from the surface location of any well in a recognized pool of the same formation, and

(e) is not part of a coalbed methane project;

"deep re-entry well event" means a gas well event that

(a) is in a well that has been altered in accordance with an amendment application approved by the regulator before September 1, 2022,

(b) has a completion point that has a true vertical depth deeper than 2 300 metres, and

(c) is not part of a coalbed methane project;

"deep well depth" means, for a well event,

(a) if in a vertical well, the measured depth to the completion point, and

(b) if in a horizontal well, the sum of

(i) the measured depth to the completion point, and

(ii) the product of the applicable horizontal length factor multiplied by the positive difference between the total measured depth and the measured depth to the completion point;

"deep well event" means a well event referred to in subsection (5), (5.1) or (5.2);

"development well" means a well or portion of a well that is classified as a development well under section 2 of the Drilling and Production Regulation;

"discovery oil" means oil produced from an oil well event that is completed in a new pool discovery well after June 30, 1974;

"discovery well" means a well designated as a discovery well under section 2 of the Drilling and Production Regulation;

"Drilling and Production Regulation" means the Drilling and Production Regulation under the Energy Resource Activities Act;

"dry gas source" means a reporting facility, other than a natural gas processing plant, that produces natural gas that is not processed at a natural gas processing plant before being sold as marketable gas;

"exploratory outpost well" means a well or portion of a well that is classified as an exploratory outpost under section 2 of the Drilling and Production Regulation;

"exploratory wildcat well" means a well or portion of a well that is classified as an exploratory wildcat well under section 2 of the Drilling and Production Regulation;

"freehold conservation gas" means conservation gas that is produced from freehold mineral lands;

"freehold marketable gas" means marketable gas produced from freehold mineral lands;

"freehold mineral lands" means lands where the petroleum and natural gas rights are not owned by the government;

"freehold natural gas by-products" means natural gas liquids, sulphur and substances other than marketable gas recovered from natural gas produced from freehold mineral lands;

"freehold natural gas liquids" means ethane, propane, butanes, or pentanes plus and any other condensates, or any other combination of them, recovered from natural gas produced from freehold mineral lands;

"freehold non-conservation gas" means non-conservation gas produced from freehold mineral lands;

"freehold oil" means oil, other than heavy oil, produced from an oil well event or allocated to a tract in a unitized operation if the oil well event or tract is located on freehold mineral lands;

"freehold production tax" means the freehold production tax under section 80 of the Act;

"freehold sulphur" means sulphur recovered from natural gas produced from freehold mineral lands;

"gas cost allowance" means an allowance to a producer to offset the cost of a natural gas processing plant or a natural gas sales line that is not within a net profit royalty project ring fence, is owned and operated by the producer and is used by the producer to process or deliver natural gas that

(a) the producer owns, produces and sells,

(b) is owned by another producer who pays the owner of the processing plant or natural gas sales line for its use, or

(c) is delivered to a storage facility;

"gas well event" means

(a) all completions in a zone that are not within a net profit royalty project, for a well that has a primary product of natural gas, or

(b) all completions in zones that are not within a net profit royalty project in a well that has a primary product of natural gas and from which commingled production is permitted under the Energy Resource Activities Act or the former Act, as that term is defined in section 116 (1) of the Energy Resource Activities Act;

"goods and service costs" means, in relation to a well, the costs incurred by the producer for goods and services directly related to the drilling or completion of the well;

"heavy oil" means oil, produced from an oil well event, with a density of at least 890 kilograms per cubic metre;

"horizontal length factor", in relation to a gas well event, has the following meaning:

(a) for a gas well event in a well that has a spud date of or before August 31, 2009 and a measured depth to the completion point of between 2 300 metres and 2 875 metres, the amount determined by the following formula:

(a.1) for a gas well event in a well that has a spud date after August 31, 2009 and a measured depth to the completion point equal to or less than 2 875 metres, the lesser of the following amounts:

(i) 1;

(ii) the amount determined by the following formula:

(b) for a gas well event with a measured depth to the completion point deeper than 2 875 metres, 0.40;

"horizontal well" means a well that meets the following criteria:

(a) a wellbore in the well is drilled at an angle of at least 80 degrees from vertical, and, for the purposes of this paragraph, the wellbore is deemed to be a line connecting the wellbore's initial point of penetration into a productive zone to the wellbore's end point in that productive zone;

(b) the length of the wellbore referred to in paragraph (a) is at least 100 metres, measured from the wellbore's initial point of penetration into the productive zone referred to in paragraph (a) to the wellbore's end point in that productive zone;

"incremental oil" means oil that the administrator considers would not have been recovered without a new pressure maintenance scheme, improved pressure maintenance scheme or other enhanced oil recovery scheme methods, but does not include heavy oil;

"initial production period" means,

(a) in relation to a gas well event, the period that

(i) begins on the first day of the first producing month, and

(ii) ends on the last day of the producing month in which the gas well event reaches 8 760 production hours, and

(b) in relation to an oil well event, the period that

(i) begins on the first day of the first producing month, and

(ii) ends on the last day of the producing month in which the oil well event reaches 4 380 production hours;

"liquids price" means, in relation to a disposition of natural gas liquids in a producing month, the amount determined by the following formula:

"m³" means, in relation to the volume of a substance, one cubic metre of the substance measured at 101.325 kPA and 15°C;

"marginal gas" means non-conservation gas produced by a marginal well event;

"marginal well depth" means,

(a) for a well event in a vertical well, the true vertical depth of the wellbore's intersection with the top of the pay of the well event, and

(b) for a well event in a horizontal well, the total measured depth of the well event;

"marginal well event" means a well event referred to in subsection (4);

"marketable gas" means natural gas that is available for sale for direct consumption as a domestic, commercial or industrial fuel, or as an industrial raw material, or is delivered to a storage facility, whether it occurs naturally or results from the processing of natural gas;

"measured depth to the completion point", in relation to a gas well event, means the measured depth along the wellbore from the intersection with the completion point of the well event to the kelly bushing used in drilling the well;

"measured depth to top of pay", in relation to a well event, means the measured depth along the wellbore from the intersection with the top of the pay of the well event to the kelly bushing used in drilling the well;

"monthly allowable production" means the product of the calculated daily gas and daily oil allowable rate and 31 days;

"natural gas by-products" means natural gas liquids, sulphur and substances other than marketable gas, which are recovered from raw natural gas that has been produced from a well event by processing or normal 2 phase field separation;

"natural gas liquids" means ethane, propane, butanes or pentanes plus and any other condensates, or any combination of them, recovered from natural gas that has been produced from a well event;

"natural gas processing plant" means a plant for the extraction from natural gas of marketable gas and natural gas by-products;

"NBPO lease" means a right to produce petroleum or natural gas if

(a) the right arose as a result of a Crown Petroleum and Natural Gas Tenure Disposition Agreement dated May 19, 2004,

(b) in section 1.1 of that agreement, the provisions comprising the No Bonus Payment Option have been retained and the provisions comprising the 50% Bonus Payment Option have been deleted, and

(c) the right to produce petroleum or natural gas relates to lands that are or form part of the Coal Lands as that term is defined in that agreement;

"net profit royalty project" has the meaning given to it in the Net Profit Royalty Regulation;

"net profit royalty well event" has the meaning given to it in the Net Profit Royalty Regulation;

"new oil" means

(a) oil, other than heavy oil or third tier oil, produced from an oil well event that

(i) draws from an oil pool having on October 31, 1975 no completed well, or

(ii) is outside the outline, shown in each plat in Schedule A, of the surface area of the oil pool named on the plat,

(b) incremental oil produced from an oil well event other than incremental oil that qualifies as third tier oil under paragraph (b) of the definition of "third tier oil",

(c) oil, produced from an oil well event, that received the new oil reference price under the National Energy Program, or

(d) oil produced from an oil well event that is completed within the outline referred to in paragraph (a) (ii) if the oil well event

(i) resumed production on or after January 1, 1981 and had not produced oil for a period of at least 36 months immediately preceding that date, and

(ii) was not an injection, pressure maintenance or observation well event during the period referred to in subparagraph (i), whether or not the period was more than 36 months;

"non-conservation gas" means natural gas produced from a well event other than conservation gas;

"oil" means petroleum as defined in the Act;

"oil well event" means all completions in a zone for a well with a primary product of oil other than completions in a zone that are within a net profit royalty project;

"old oil" means oil produced from an oil well event other than new oil, heavy oil or third tier oil;

"operator of a reporting facility" means the person who is identified as the operator of a reporting facility in information provided to the collector;

"pay", in respect of a pool, means the portion of the pool that is determined by the regulator to be the pay;

"PMP exempt well event" means a well event that is designated as a PMP exempt well event by order of the administrator under section 2 (7);

"posted minimum price" means, for each calendar month, a price, set by the administrator in relation to a group of natural gas processing plants, dry gas sources and net profit royalty projects under the authority of section 2 (4), for marketable gas that becomes available for disposition during that month from that group of natural gas processing plants, dry gas sources and net profit royalty projects;

"price factor" means the following:

(a) for heavy oil, the factor that is determined by the formula

(b) for third tier oil, the lesser of

(i) the factor that is determined by the formula:

and

(ii) a factor of 2;

"producer" means

(a) a holder of a location who markets or otherwise disposes of oil, natural gas or both, that has been produced by

(i) the holder of the location, or

(ii) a person authorized to do so by the holder of the location, and

(b) a person authorized by a holder of a location to produce and market or otherwise dispose of, on the holder's behalf, oil, natural gas or both;

"producer cost of service allowance", in relation to a well event and a producing month, means,

(a) if the well event is part of a coalbed methane project, the amount determined in accordance with the following formula:

(b) if the well event is not part of a coalbed methane project, the lesser of

(i) the amount determined in accordance with the following formula:

(ii) 95% of the total gross natural gas royalty or tax determined for the well event for the producing month under section 7 (7) (a);

"producer cost of service natural gas volume" means, in relation to a well event in a producing month, the producer's share of the volume of natural gas produced from the well event in the producing month;

"producer cost of service rate", in relation to a producer, means a rate determined by the collector using the methodology established by the administrator under section 2 (8.1), expressed as an amount per 1 000 m³, which rate may be used in the calculation of a producer cost of service allowance to cover the producer's cost of

(a) main field gathering, dehydration and field compression of non-conservation gas,

(b) conserving conservation gas,

(c) processing natural gas for use as fuel in paragraphs (a) and (b), and

(d) handling water produced from well events in a coalbed methane project;

"producer price" means a price of natural gas determined by the administrator each month for each producer in accordance with the method established by order of the administrator under section 2 (5), as that price may be amended from time to time under section 11 (2);

"producing month", in relation to a well event, means a calendar month in which any quantity of oil, natural gas or water is produced from the well event;

"production hour", in relation to a well event, means an hour in which any quantity of oil or natural gas is produced from the well event;

"project ring fence" has the meaning given to it in the Net Profit Royalty Regulation;

"reactivated well event" means

(a) a marginal well event that

(i) was suspended or abandoned on or before June 30, 2003, and

(ii) after that date, commenced or recommenced producing, or

(b) an ultramarginal well event that

(i) was suspended or abandoned on or before December 31, 2005, and

(ii) after that date, commenced or recommenced producing;

"re-entry date", in relation to a well, means the date selected as the re-entry date for the well by the regulator in an approval given to an amendment application;

"reference price" means,

(a) for marketable gas other than gas produced from a PMP exempt well event, the greater of

(i) the producer price, and

(ii) the posted minimum price that is, for the calendar month in which the marketable gas becomes available for disposition, applicable to the natural gas processing plant at which the marketable gas was processed;

(b) for marketable gas produced from a PMP exempt well event, the producer price;

(c) for natural gas liquids,

(i) the liquids price, or

(ii) if the collector has, under section 7 (2), fixed a unit selling price for the royalty or tax share of the natural gas liquids disposed of in a producing month, the deemed value of the natural gas liquids disposed of in the producing month divided by their volume;

(d) for sulphur,

(i) the sulphur price, or

(ii) if the collector has, under section 7 (2), fixed a unit selling price for the royalty or tax share of the sulphur disposed of in a producing month, the deemed value of the sulphur disposed of in the producing month divided by its volume;

"reporting facility" means a building, structure, installation, equipment or appurtenance that is connected to or associated with the recovery, development, production, storage, handling, processing, treatment or disposal of oil, natural gas, natural gas by-products, water or other substances that are produced from or injected into a well and, for certainty, includes a battery, gathering system, natural gas processing plant, meter station, pipeline, injection facility, terminal and treating plant;

"revenue sharing agreement", when used in relation to gas, oil or royalties to which one of the following agreements applies, means that agreement:

(a) the agreement entitled "Petroleum and Natural Gas Revenue Sharing Agreement" between

(i) the Blueberry River Indian Band and the Members of the Blueberry River Indian Band represented by its duly elected Chief and Councillors,

(ii) the Doig River Indian Band and the Members of the Doig River Indian Band represented by its duly elected Chief and Councillors, and

(iii) Her Majesty the Queen in right of British Columbia represented by the Minister of Aboriginal Affairs and the Minister of Energy, Mines and Petroleum Resources, or

(b) the agreement as defined in the Fort Nelson Indian Reserve Minerals Revenue Sharing Act;

"revenue sharing gas" means natural gas produced from a well event the royalties from which are to be shared under the terms of the revenue sharing agreement applicable to that natural gas;

"revenue sharing oil" means oil produced from an oil well event the royalties from which are to be shared under the terms of the revenue sharing agreement applicable to that oil;

"royalty for an unaccounted quantity" means royalty payable to the government in respect of an unaccounted quantity of oil, marketable gas or natural gas by-products, the amount of which royalty is calculated under section 7.2;

"royalty share" means,

(a) in the case of oil produced from an oil well event,

(i) if the oil is the subject matter of a unitization agreement under which royalty is determined in relation to a tract according to production volumes allocated to that tract under the agreement, the volume of oil that is produced from the oil well event, during the producing month in respect of which royalty share is calculated, that is determined by adding A and B, where

A = the volume of old oil determined in accordance with the following formula: A = V × RO × (1 − P),

B = the volume of new oil determined in accordance with the following formula: B = V × RN × P,

V = the total volume of oil allocated to the tract for that producing month under the unitization agreement,

RO = the royalty percentage rate set out in item 1 or 2, as applicable, of section 5,

RN = the royalty percentage rate set out in item 3 or 4, as applicable, of section 5,

P = the ratio, as determined by the administrator under section 2, of new oil production from the unitized operation to the total volume of oil production from the unitized operation, or

(ii) if subparagraph (i) does not apply, the volume of oil that is produced from the oil well event, during the producing month in respect of which royalty share is calculated, that is determined by adding C, D, E and H, where

C = the volume of old oil determined in accordance with the following formula: C = V × RO × (1 − P),

D = the volume of new oil determined in accordance with the following formula: D = V × RN × P,

E = the volume of third tier oil determined in accordance with the following formula: E = V × RE,

H = the volume of heavy oil determined in accordance with the following formula: H = V × RH,

V = the total volume of oil produced from the oil well event during that producing month,

RO = the royalty percentage rate set out in item 1 or 2, as applicable, of section 5,

RN = the royalty percentage rate set out in item 3 or 4, as applicable, of section 5,

RE = the royalty percentage rate set out in item 4.1 or 4.2, as applicable, of section 5,

RH = the royalty or tax percentage rate set out in item 7, 8 or 9, as applicable, of section 5,

P = the ratio, as determined by the administrator under section 2, of new oil production from the oil well event to the total volume of oil production from the oil well event,

(b) in the case of a class of marketable gas produced in a producing month from a well event, the producer's share of that marketable gas multiplied by the royalty percentage rate under section 6 that is applicable to the class of marketable gas, the producing month and the well event, and

(c) in the case of a class of natural gas by-products produced in a producing month from a well event, the producer's share of those natural gas by-products multiplied by the royalty percentage rate under section 6 that is applicable to that class of natural gas by-products;

"sales value" means, in relation to a disposition of oil, the greater of

(a) zero, and

(b) the consideration, without deductions, that is received or receivable by a producer for the disposition, or if the collector has, under section 7 (2), fixed a unit selling price for the royalty or tax share of the oil disposed of in a producing month, the deemed value of the oil disposed of;

"select price" means, for a class of gas, the price for that class of gas established for each calendar year by order of the administrator;

"spud date", in relation to a well, means the date selected by the regulator as the date on which the ground was first penetrated for the purposes of drilling the well;

"storage facility" means any underground reservoir or surface facility that is capable of storing natural gas;

"sulphur" means market grade elemental sulphur which is obtained from processing natural gas that has been produced from a well event;

"sulphur price" means, in relation to a disposition of sulphur in a producing month, the amount determined by the following formula:

where

"consideration" means the consideration received or receivable by the producer for the disposition of the sulphur;

"actual costs" means the actual costs, approved by the collector, that are incurred by the producer for transporting and processing the sulphur from the point of production to the point of sale;

"sales volume" means the volume of sulphur involved in the disposition;

"tariff" means rates or charges that are approved by a public regulatory body having jurisdiction over a contract carrier;

"tax" means the freehold production tax under section 80 of the Act;

"tax share" means,

(a) in the case of a class of freehold oil, the volume of freehold oil of that class that is determined by multiplying the volume of oil produced from the oil well event by the tax rate under section 5 that is applicable to the class of freehold oil,

(b) in the case of a class of freehold marketable gas produced in a producing month from a well event, the producer's share of that freehold marketable gas multiplied by the tax percentage rate under section 6 that is applicable to the class of freehold marketable gas, the producing month and the well event, and

(c) in the case of a class of freehold natural gas by-products produced in a producing month from a well event, the producer's share of those freehold natural gas by-products multiplied by the tax percentage rate under section 6 that is applicable to that class of freehold natural gas by-products;

"third tier oil" means

(a) oil, other than revenue sharing oil and heavy oil, produced from oil well events that draw from an oil pool having, on June 1, 1998, no completed well, or

(b) oil produced from an oil well event that is incremental oil, other than revenue sharing oil, that is derived from a pressure maintenance scheme, or an enhanced oil recovery scheme, that was approved after December 31, 1999 under section 100 of the Act as it read immediately before its repeal or that is designated as a special project under section 75 of the Energy Resource Activities Act;

"threshold price" means, for a class of oil, the price that is established, by order of the administrator under section 2 (10), as the threshold price for that class of oil;

"total measured depth", in relation to a well event, means the sum of the lengths of all of the vertically oriented and horizontally oriented wellbores that constitute the well event;

"true vertical depth" means, for any point on the wellbore of a well, the distance between the wellbore point and the point, directly above the wellbore point, that is the same elevation as the kelly bushing used in drilling the well;

"ultramarginal gas" means non-conservation gas produced by an ultramarginal well event;

"ultramarginal well depth" means,

(a) for a well event in a vertical well, the true vertical depth of the wellbore's intersection with the top of the pay of the well event, and

(b) for a well event in a horizontal well,

(i) if the total measured depth less the measured depth to top of pay is less than 1 000 metres, the total measured depth, or

(ii) if the total measured depth less the measured depth to top of pay is equal to or greater than 1 000 metres, the amount determined by adding

(A) measured depth to top of pay plus 1 000, and

(B) one half of the amount determined by subtracting the sum of the measured depth to top of pay plus 1 000 from the total measured depth;

"ultramarginal well event" means a well event referred to in subsection (6);

"vertical well" means any well that is not a horizontal well;

"weighted average royalty or tax rate" means, in relation to a well event and producing month, the total gross natural gas royalty or tax determined for the producer's share of the natural gas produced from the well event for the producing month under section 7 (7) (a) divided by the sum of

(a) the producer's share of the marketable gas produced from the well event in the producing month and made available for sale in that month, multiplied by the reference price for the marketable gas,

(b) the producer's share of the natural gas liquids produced from the well event in the producing month multiplied by the reference price for the natural gas liquids, and

(c) the producer's share of the sulphur produced from the well event in the producing month multiplied by the reference price for the sulphur;

"well event" means a gas well event or an oil well event;

"well permit" has the same meaning as in the Drilling and Production Regulation;

"wellhead price" means, in relation to oil, the greater of

(a) the average net value of that oil determined in accordance with section 7 (3) (b), and

(b) the threshold price.

(1.1) Despite subsection (1), for the purposes of applying this regulation to wells with a spud date after November 30, 2003 and before January 1, 2009, the following terms continue to have the meanings they had on December 31, 2008:

(a) deep discovery well event;

(b) deep re-entry well event;

(c) deep well depth;

(d) deep well event.

(2)-(3) Repealed. [B.C. Reg. 73/2006, s. 2 (a).]

(4) A well event is a marginal well event if

(a) the well event is a gas well event,

(b) the result of the following calculation is less than 23 m³ for every metre of marginal well depth:

(c) the 12 calendar month period referred to in paragraph (b) ends after June 30, 2004,

(d) the well event is in a well that has a spud date after May 31, 1998 and before September 1, 2022, and

(e) the well event is not an ultramarginal well event and is not part of a coalbed methane project.

(5) In the case of a well that has a spud date of or before August 31, 2009, a well event is a deep well event if

(a) the well event is a gas well event,

(b) the well event, if in a horizontal well, has a completion point that has a true vertical depth deeper than 2 300 metres,

(c) the well event, if in a vertical well, has a completion point that has a true vertical depth deeper than 2 500 metres,

(d) the well event is not a deep re-entry well event, and

(e) the well event is not part of a coalbed methane project.

(5.1) In the case of a well that has a spud date after August 31, 2009 and of or before March 31, 2014, a well event is a deep well event if

(a) the well event is a gas well event,

(b) the well event, if in a horizontal well, has a completion point that has a true vertical depth deeper than 1 900 metres,

(c) the well event, if in a vertical well, has a completion point that has a true vertical depth deeper than 2 500 metres,

(d) the well event is not a deep re-entry well event,

(e) the well event is not part of a coalbed methane project, and

(f) the well event is not an ultramarginal well event.

(5.2) In the case of a well that has a spud date after March 31, 2014, a well event is a deep well event in either of the following circumstances:

(a) if

(i) the well event is a gas well event,

(ii) the well event, if in a horizontal well, has a completion point that has a true vertical depth deeper than 1 900 metres,

(iii) the well event, if in a vertical well, has a completion point that has a true vertical depth deeper than 2 500 metres,

(iv) the well event is not a deep re-entry well event,

(v) the well event is not part of a coalbed methane project, and

(vi) the well event is in a well that has a spud date before September 1, 2022;

(b) if

(i) the well event is a gas well event,

(ii) the well event is in a horizontal well and has

(A) a completion point that has a true vertical depth equal to or less than 1 900 metres, and

(B) a deep well depth deeper than 2 500 metres,

(iii) the well event is not part of a coalbed methane project, and

(iv) the well event is in a well that has a spud date before September 1, 2022.

(6) A well event is an ultramarginal well event if

(a) the well event is a gas well event,

(b) in the case of a well that has a spud date of or before March 31, 2014, the well event is either

(i) in a vertical well and has a true vertical depth to the top of the pay of the well event of less than 2 500 metres, or

(ii) in a horizontal well and has a true vertical depth to the top of the pay of the well event of less than 2 300 metres,

(b.1) in the case of a well that has a spud date after March 31, 2014, the well event is in a vertical well and has

(i) a true vertical depth to the top of the pay of the well event of less than 2 500 metres, and

(ii) a completion point that has a true vertical depth equal to or less than 2 500 metres,

(c) one of the following applies to the well event:

(i) the well event is in an exploratory wildcat well and the result of the following calculation is less than 17 m³ for every metre of ultramarginal well depth:

(ii) the well event is in an exploratory outpost well or a development well and the result of the following calculation is less than 11 m³ for every metre of ultramarginal well depth:

(d) the 12 calendar month period referred to in paragraph (c) (i) and (ii) ends after January 31, 2007,

(e) the well event is either

(i) a reactivated well event with a re-entry date after December 31, 2005 in a well with a spud date after May 31, 1998 and before September 1, 2022, or

(ii) in a well that has a spud date after December 31, 2005 and before September 1, 2022, and

(f) the well event is not part of a coalbed methane project.

(7) Despite the definition of "producer cost of service allowance" in subsection (1),

(a) in the case of a gas well event in a well that has a spud date of or after September 1, 2022, the producer cost of service allowance for the gas well event is zero for the initial production period,

(b) in the case of a gas well event described in section 6 (1.9), following the initial production period, the producer cost of service allowance for the gas well event is zero for the subsequent period referred to in section 6 (1.8) (a), and

(c) in the case of an oil well event in a well that has a spud date of or after September 1, 2024, the producer cost of service allowance for the oil well event is zero for the initial production period.

[am. B.C. Regs. 256/93; 367/93, s. 1; 21/98, s. 1; 180/98, s. 1; 18/99, s. 1; 218/99, s. 1; 456/99, s. 1; 10/2000; 50/2001, s. 1; 29/2002, s. 1; 233/2003; 250/2003, s. 1; 302/2003, s. 1; 442/2003, s. 1; 178/2004, s. 1; 138/2005, s. 1; 191/2005, Sch. 1, s. 1; 73/2006, ss. 1 and 2; 329/2006, s. (a); 99/2008, s. 1; 17/2009, s. 1; 193/2009, s. 1; 269/2010, Sch., s. 14; 91/2012, s. (a); 30/2014, s. 1; 194/2018, Sch. 1, s. 1; 117/2022, ss. 1 and 2; 187/2023, Sch., ss. 12 and 14; 259/2024, ss. 1 and 2.]

Powers of administrator and collector

2   (1) All calculations required under this regulation shall be carried to the number of decimal places as designated by the collector.

(2) Repealed. [B.C. Reg. 21/98, s. 2.]

(3) The administrator may determine the ratio referred to in paragraph (a) (i) or (ii) of the definition of "royalty share" in section 1 by delivering written notice of the ratio to one of the producers of the oil to which the ratio applies.

(4) For the purpose of determining posted minimum prices, the administrator may, by order,

(a) designate one or more groups of natural gas processing plants, dry gas sources and net profit royalty projects, and

(b) include as members of any group designated under paragraph (a) any one or more of natural gas processing plants, dry gas sources and net profit royalty projects.

(5) For the purpose of determining the producer price in relation to natural gas, the administrator may, by order, establish the method by which producer prices are to be determined.

(6) The method established under subsection (5) may comprise or include calculations involving one or more components, which components may be identified or determined

(a) in accordance with a method set out in the order, or

(b) by the administrator, acting reasonably.

(7) The administrator may, by order, designate as a PMP exempt well event any well event that, before the coming into force of this subsection, produced natural gas that had an H₂S content of at least 10%.

(8) The collector may order that a producer receive a gas cost allowance or a producer cost of service allowance, or both.

(8.1) For the purpose of the order in subsection (8), the administrator may establish the methods by which rates used in the calculation of producer cost of service allowances or rates used in the calculation of gas cost allowances may be determined.

(8.2) If the administrator establishes one or more methods under subsection (8.1), the collector is to determine annual producer cost of service rates and gas cost allowance rates using the applicable methodology established by the administrator.

(9) By order, the administrator may, for each calendar year, establish a select price for each class of gas.

(10) The administrator may, by order, establish, for each class of oil, a threshold price for that class of oil.

(11) The collector may review the production history of any marginal well event or ultramarginal well event and the operator of the well event must, on request, provide to the collector all documents within the power or control of the operator that relate to the matters that are or might have been included or reflected in that production history.

(12) If the collector believes that the operator limited the production of a well event for the primary purpose of having the well event qualify as a marginal well event or an ultramarginal well event, the collector may disqualify that well event from qualifying for a royalty rate reduction under section 6 (1.3) (b) or (c).

(13) The collector may apply the well depth deduction amount determined for a producer in relation to a well under section 7 (7) (c) to the producer's interest in any one or more deep well events or deep re-entry well events in that well.

(14) The collector may apply the deep re-entry deduction amount determined for a producer in relation to a well under section 7 (7) (d) to the producer's interest in any one or more deep well events or deep re-entry well events in that well.

[am. B.C. Regs. 21/98, s. 2; 180/98, s. 2; 218/99, s. 2; 456/99, s. 2; 50/2001, s. 2; 250/2003, s. 2; 302/2003, ss. 2 and 3; 191/2005, Sch. 1, s. 2; 73/2006, s. 3; 99/2008, s. 2.]

Royalty and tax share

3   (1) The collector must designate the applicable class of oil, natural gas or natural gas by-products for the purposes of calculating a royalty share and tax share.

(2) The first sale of oil, natural gas or natural gas by-products shall include the royalty share and tax share, except where natural gas that has never been sold is delivered to a storage facility, in which case the delivered gas includes the royalty share and tax share.

(3) Notwithstanding subsection (2), where the administrator gives written notification to a producer

(a) of the government's intention to take the royalty share or the tax share, and

(b) of the government's requirement that the producer deliver the royalty share or the tax share to a person named in the notification

the producer shall deliver the royalty share or tax share in accordance with the notification and the delivery is in lieu of the payment referred to in section 4.

[am. B.C. Regs. 302/2003, s. 2; 73/2006, s. 4.]

Royalty and tax payment

4   (0.1) In this section:

"greenhouse gas" has the same meaning as in section 1 of the Greenhouse Gas Reduction Targets Act;

"pipeline company" means a person who owns, constructs or operates a pipeline.

(1) A person to whom Crown invoices are issued must, by the end of the calendar month in which the Crown invoices are issued, pay to the government the total of the invoiced amounts in one of the following manners:

(a) by an electronic method specified by the collector;

(b) by a money order or cheque mailed to the government at an address specified by the collector.

(2) A payment of an amount to the government under subsection (1) is deemed not to be paid to the government until,

(a) if the payment is made directly to the government by an electronic method, the day of receipt by the government,

(b) if the payment is made to a savings institution by an electronic method, the day recorded as the day of receipt by the savings institution, or

(c) if the payment is mailed to the government, the day of receipt by the government.

(2.1) Repealed. [B.C. Reg. 194/2018, Sch. 1, s. 2 (a).]

(2.2) Repealed. [B.C. Reg. 191/2005, Sch. 2, s. 1.]

(2.3) Repealed. [B.C. Reg. 194/2018, Sch. 1, s. 2 (a).]

(3) A producer may deduct an overpayment in accordance with section 9 (7).

(4) In addition to any deduction allowed under subsection (3), a producer may deduct a summer drilling deduction amount determined under subsection (5) in respect of a well if

(a) the producer has an interest in the well at the time the well is completed, and

(b) the well has a spud date after June 30, 2003 and before December 1, 2003, or, in any subsequent year up to 2012, after March 31 of that year and before December 1 of that year,

(c) the same drilling rig drills the well from the spud date of the well until the well reaches its final total measured depth, or if, in the opinion of the collector, the same drilling rig is incapable of drilling the well for the whole of that period due to damage, 2 or more drilling rigs drill the well from the spud date of the well until the well reaches its final total measured depth,

(c.1) the well does not have a completion in a zone that is within a net profit royalty project, and

(d) the producer files a report for the summer drilling credit in accordance with section 8 (1) (r).

(5) The summer drilling deduction amount is, for each well referred to in subsection (4), the producer's proportionate interest in the well multiplied by the lesser of the following:

(a) 10% of the goods and service costs attributable to the well;

(b) $100 000.

(6) In addition to any deductions allowed under subsections (3) and (4), a producer may deduct

(a) an infrastructure charge deduction amount if and to the extent that that deduction amount is available to the producer under subsections (7) and (8), and

(b) a project deduction amount if and to the extent that that deduction amount is available to the producer under subsections (10) and (13).

(7) Subsection (8) applies to a producer if

(a) the producer enters into an agreement with the minister or the BC Transportation Financing Authority under which the producer agrees, for the purpose of providing cost recovery for the use of bridges, roads, rails, trails, utilities or other structures or works, to pay specified charges for specified activities in a specified area,

(b) the producer is obliged to pay charges or tolls established for the purpose referred to in paragraph (a) under Part 3 of the Transportation Act, or

(c) the producer is obliged to pay tolls prescribed for the purpose referred to in paragraph (a) under the Ministry of Energy and Mines Act.

(8) The infrastructure charge deduction amount available to a producer referred to in subsection (7) is 50% of so many of the charges and tolls referred to in that subsection as the administrator is satisfied

(a) represent cost recovery for the use of bridges, roads, rails, trails, utilities or other structures or works, and

(b) have been paid by the producer.

(9) For the purposes of subsection (10), a producer may notify the administrator, in writing, that the producer intends to undertake a project to

(a) construct or upgrade pipelines, bridges, roads, rails or trails in British Columbia in support of petroleum or natural gas exploration or development in British Columbia, or

(b) do one or more of the following in respect of an oil and gas or storage activity in British Columbia:

(i) avoid, reduce or sequester greenhouse gas emissions;

(ii) avoid or reduce an adverse effect on water quality or quantity or the timing of water flow;

(iii) avoid or reduce an adverse effect on the environment.

(9.1)-(9.2) Repealed. [B.C. Reg. 192/2016, s. 1 (c).]

(10) If the administrator receives a notice under subsection (9), the administrator may enter into an agreement with the producer that

(a) entitles the producer to deduct, from the royalty or tax otherwise payable by the producer under the Act, a portion of the costs attributable to that project in the form of a project deduction amount determined in accordance with subsections (11) and (15),

(b) for the purposes of paragraph (a), identifies the steps that constitute the project and specifies

(i) what constitutes the completion of each step of the project,

(ii) the estimated completion cost of each step of the project, and

(iii) the estimated completion cost of the project, and

(c) for the purposes of paragraph (a), specifies the circumstances that must exist or the conditions that must be met before the project deduction amount, or a portion of a project deduction amount, may be deducted.

(11) Subject to subsection (15), the project deduction amount available, for each of the specified steps of a project, to a producer who has entered into an agreement for that project under subsection (10) is up to 50% of the lesser of the estimated completion cost of that step and the amount spent by the producer to complete that step, if the administrator is satisfied that

(a) the step has been completed in the manner and to the extent required by the agreement,

(b) the producer intends to complete the project,

(c) the completion cost for which the deduction amount is calculated has been paid by the producer, and

(d) the circumstances or conditions referred to in subsection (10) (c) exist or have been met.

(12) For the purposes of subsection (13), a pipeline company may notify the administrator, in writing, that the pipeline company intends to undertake a project, in a contractual arrangement with one or more producers, to

(a) construct or upgrade pipelines in British Columbia in support of petroleum or natural gas exploration or development in British Columbia, or

(b) do one or more of the following in respect of an oil and gas or storage activity in British Columbia:

(i) avoid, reduce or sequester greenhouse gas emissions;

(ii) avoid or reduce an adverse effect on water quality or quantity or the timing of water flow;

(iii) avoid or reduce an adverse effect on the environment.

(13) If the administrator receives a notice under subsection (12), the administrator may enter into an agreement with the parties to the contractual arrangement that

(a) entitles the producer or producers to deduct, from the royalty or tax otherwise payable by the producer or producers under the Act, a portion of the costs attributable to that project in the form of a project deduction amount determined in accordance with subsections (14) and (15),

(b) for the purposes of paragraph (a), identifies the steps that constitute the project and specifies

(i) what constitutes the completion of each step of the project,

(ii) the estimated completion cost of each step of the project, and

(iii) the estimated completion cost of the project, and

(c) for the purposes of paragraph (a), specifies the circumstances that must exist or the conditions that must be met before the project deduction amount, or a portion of a project deduction amount, may be deducted.

(14) Subject to subsection (15), the project deduction amount available, for each of the specified steps of the project, to producer or producers who have entered into an agreement for that project under subsection (13), is up to 50% of the lesser of the estimated completion cost of that step and the amount spent by the parties to the contractual arrangement to complete that step, if the administrator is satisfied that

(a) the step has been completed in the manner and to the extent required by the agreement,

(b) the parties to the contractual arrangement intend to complete the project,

(c) the completion cost for which the deduction amount is calculated has been paid by the parties to the contractual arrangement, and

(d) the circumstances or conditions referred to in subsection (13) (c) exist or have been met.

(15) The total amount of project deduction amounts that may be deducted from the amount of royalty or tax otherwise payable by a producer under the Act must not exceed 50% of the lesser of

(a) the estimated completion cost of the project, and

(b) the amount spent by the producer or the parties to the contractual arrangement, as the case may be, to complete the project.

(16) For the purposes of subsection (11) (d) or (14) (d), as applicable, the administrator may take any steps that are, in the opinion of the administrator, necessary to determine that the circumstances or conditions referred to in those subsections exist or have been met, as the case may be.

[am. B.C. Regs. 21/98, s. 3; 50/2001, s. 3; 250/2003, s. 3; 442/2003, s. 2; 546/2004, App., s. 24; 191/2005, Sch. 2, s. 1; 317/2005; 73/2006, s. 5; 35/2008; 99/2008, s. 3; 128/2013, s. 1; 192/2016, s. 1; 194/2018, Sch. 1, s. 2; 187/2023, Sch., s. 11.]

Oil royalty and tax rates

5   (1) In Column 2 of each item in subsection (1.1), "PRODUCTION" means, in relation to an oil well event during a month, the total volume of all oil of every class produced from the oil well event in the month.

(1.1) The royalty or tax percentage rate specified in Column 2 for an item applies to the class of oil specified in Column 1 for the item.

(1.2) In the case of an oil well event in a well that has a spud date of or after September 1, 2024, despite subsection (1.1), the royalty or tax percentage rate for oil produced from the oil well event, other than oil in a class of oil specified in Column 1 for item 7, is 5% for the initial production period.

(2) Upon application, the collector may approve an exemption from payment of royalty or tax to the extent specified in Column 2 for an item as it applies to the category of oil specified in Column 1 for the item.

(3) If oil was or is classified as new oil on or after January 1, 1978 and would be classified as old oil if part (c) of the definition of new oil in section 1 is not applicable to it, an exemption is granted from the obligation to pay royalty on that oil at a royalty rate in excess of the royalty rate applicable to new oil.

(4) The royalty or tax exemption periods approved under subsection (2) are subject to a maximum exempt production equal to the lesser of

(a) the monthly allowable production of oil multiplied by the number of royalty exempt producing months, and

(b) 11 450 cubic metres of oil.

(5) If a new pool discovery well is converted into an injection well as part of a pressure maintenance technique designated under section 75 of the Energy Resource Activities Act prior to the oil well producing its full royalty holiday entitlement under subsection (4), the collector, on application, may approve a transfer of the unused portion of the royalty holiday entitlement to another oil well producing from the same pool.

[am. B.C. Regs. 367/93, s. 2; 40/97; 180/98, s. 3; 218/99, ss. 3 and 4; 456/99, s. 3; 50/2001, s. 4; 302/2003, s. 2; 73/2006, s. 6; 99/2008, s. 4; 269/2010, Sch., s. 15; 187/2023, Sch., s. 12; 259/2024, s. 3.]

Natural gas and natural gas by-products royalty and tax rates

6   (1) Subject to subsections (1.1), (1.2), (1.21) and (1.3), the royalty or tax percentage rate specified in Column 2 for an item applies to the class of natural gas or natural gas by-products specified in Column 1 for the item but, despite the foregoing, the royalty or tax percentage rate must not be less than

(a) 15% for Item 1, 9% for Item 1.1, 12% for Item 1.2, 8% for Item 2, 9% for Item 3 and 5% for Item 4, and must not be more than 27% for Items 1.1 and 1.2, and

(b) for marketable gas produced under the authority of a NBPO lease, the greater of

(i) 6%, and

(ii) the rate calculated under paragraph (a) after the application of section 6 (1.3) of this regulation.

(1.1) The royalty percentage rate that is, under subsection (1), applicable to a class of marketable gas produced in a producing month from a well event may be reduced by a reduction factor determined under subsection (1.2) or (1.3) (a), (b) and (c), multiplied by the royalty percentage rate determined under Item 1, 1.1, 1.2 or 3 in subsection (1) for the class of marketable gas produced from the well event.

(1.2) There may be determined for a well event described in subsection (1.21) a reduction factor in accordance with the following formula:

(5000 − S) 5000

2

(1.21) For the purposes of subsection (1.2), a well event must be a well event that

(a) is in a well that has a spud date before September 1, 2022,

(b) is not a marginal well event or an ultramarginal well event, and

(c) is not part of a coalbed methane project.

(1.3) A reduction factor may be determined for a well event in relation to a producing month in accordance with the following applicable formula:

(a) if the well event is part of a coalbed methane project, the reduction factor may be determined in accordance with the following formula:

(17 000 − S) 17 000

2

(b) if the well event is a marginal well event, the reduction factor may be determined in accordance with the following formula:

(25 000 − S) 25 000

2

(c) if the well event is an ultramarginal well event, the reduction factor may be determined in accordance with the following formula:

(60 000 − S) 60 000

1.5

(1.4) Despite subsection (1), if natural gas that is of a class referred to in Column 1 of item 1.1, 1.2 or 3 in subsection (1) is produced from a gas well event described in subsection (1.5), the royalty or tax percentage rate specified in Column 2 of that item is 2% for the 12 calendar months beginning with the month in which the well event first commenced continuous production.

(1.5) In order to be eligible for the royalty or tax percentage rate referred to in subsection (1.4), a gas well event must be a gas well event that

(a) is in a well that has a spud date after August 31, 2009 and before July 1, 2010,

(b) first commences continuous production before December 31, 2010, and

(c) is not part of a coalbed methane project.

(1.6) Subsections (1.2) and (1.3) (b) and (c) do not apply with respect to a gas well event described in subsection (1.5) until the end of 12 calendar months after the month in which the well event first commenced continuous production.

(1.7) In the case of a gas well event in a well that has a spud date of or after September 1, 2022,

(a) despite subsection (1), the royalty or tax percentage rate for natural gas and natural gas by-products produced from the gas well event is 5% for the initial production period, and

(b) subject to subsection (1.8) (b), subsection (1.3) (a) does not apply in relation to the gas well event until the initial production period has ended.

(1.71) In the case of an oil well event in a well that has a spud date of or after September 1, 2024,

(a) despite subsection (1), the royalty or tax percentage rate for natural gas and natural gas by-products produced from the oil well event is 5% for the initial production period, and

(b) subsection (1.3) (a) does not apply in relation to the oil well event until the initial production period has ended.

(1.8) In the case of a gas well event described in subsection (1.9),

(a) following the initial production period and despite subsection (1), the royalty or tax percentage rate for natural gas and natural gas by-products produced from the gas well event is 5% for a subsequent period that

(i) begins on the first day of the producing month immediately following the initial production period, and

(ii) ends on the last day of the producing month in which the gas well event reaches 3 647 production hours, and

(b) subsection (1.3) (a) does not apply in relation to the gas well event until that subsequent period has ended.

(1.9) For the purposes of subsection (1.8), a gas well event must be a gas well event in relation to which all of the following apply:

(a) the gas well event is in a well that has a spud date of or after September 1, 2024;

(b) natural gas has been produced from the gas well event during the initial production period;

(c) the amount determined in relation to the gas well event by applying the following formula is less than 0.05618:

(2) Upon application, the collector may approve an exemption from payment of royalty or tax to the extent specified in Column 2 for an item as it applies to the category of natural gas or natural gas by-products specified in Column 1 for the item.

(3) Repealed. [B.C. Reg. 442/2003, s. 3 (f).]

(4) The volume of natural gas that may be exempt from payment under Item 3 must not exceed 283 000 000 m³.

(5) The royalty and tax exemption for any natural gas by-products produced from a gas well event terminates at the same time as the exemption of natural gas.

(6) The royalty or tax percentage rate specified in subsection (1), (1.4), (1.7), (1.71) or (1.8), as the case may be, and the exemption from royalty and tax payable specified in subsection (2), apply to the persons or class of persons who are producers of British Columbia natural gas and whose gas or a portion of whose gas is processed outside of British Columbia.

[am. B.C. Regs. 180/98, s. 4; 18/99, s. 2; 50/2001, s. 5; 29/2002, s. 2; 112/2002; 250/2003, s. 4; 302/2003, s. 2; 442/2003, s. 3; 178/2004, s. 2; 138/2005, s. 2; 73/2006, s. 7; 329/2006, s. (b); 99/2008, s. 5; 193/2009, s. 2; 91/2012, s. (b); 117/2022, s. 3; 259/2024, s. 4.]

Royalty and tax calculations

7   (0.1) In this section:

"minimum royalty amount" means the sum of the following:

(a) the specified percentage of the volume of marketable gas made available for sale in the producing month from a well event multiplied by the reference price for that marketable gas;

(b) the specified percentage of the volume of natural gas liquids produced from a well event in the producing month multiplied by the reference price for those natural gas liquids;

(c) the specified percentage of the volume of sulphur produced from a well event in the producing month multiplied by the reference price for that sulphur;

"specified percentage" means

(a) 6%, in the case of a deep well event under section 1 (5.2) (b), and

(b) 3%, in any other case.

(0.2) Subsection (5) (c) (iii) and (iv) and (d) (iii) and (iv) applies only to producing months after March 2013.

(1) The royalty and tax share shall be sold under section 3 (2) at the following price:

(a) for oil, the actual unit selling price;

(b) for natural gas, the reference price of that natural gas;

(c) for natural gas by-products, the actual unit selling price.

(2) If

(a) there is no actual unit selling price for the oil or natural gas by-products referred to in subsection (1) (a) or (c), or

(b) the actual unit selling price is, in the opinion of the collector, less than the fair market value,

the collector shall fix a unit selling price for the royalty or tax share at a level not exceeding the highest unit selling price received by any producer during the month in which the sale takes place, and the royalty or tax share is deemed to have been sold at the unit selling price fixed by the collector.

(3) Subject to subsection (3.1), for the purposes of determining the amount of royalty and tax payable by a producer to the government for oil, the collector shall

(a) deduct from the sales value the costs incurred by the producer for

(i) transporting oil by truck or through a producer-owned sales line, and

(ii) tariffs charged by a contract carrier for transporting oil,

except where the transportation or tariff charge was a factor used in establishing the sales value of the oil,

(b) calculate the average net value by dividing the amount determined in paragraph (a) by the volume of oil sold,

(c) calculate the gross oil royalty or tax payable by multiplying the average net value by the royalty or tax share, and

(d) calculate the net oil royalty or tax payable by deducting from the gross oil royalty or tax payable the value of the royalty or tax share exempt from payment.

(3.1) The amount of royalty and tax payable to the government for oil produced under the authority of a BPO lease is the net oil royalty or tax calculated in respect of that oil under subsection (3) multiplied by 75%.

(4) The collector may disallow a claim for costs under subsection (3) (a) where the claim cannot be substantiated.

(5) Subject to subsection (5.1), the amount of royalty or tax payable to the government for natural gas in relation to a well event and producing month is the total gross natural gas royalty or tax determined under subsection (7) (a), or, for natural gas produced under the authority of a BPO lease, 75% of the total gross natural gas royalty or tax determined under subsection (7) (a), minus

(a) the producer cost of service allowance, or, for natural gas produced under the authority of a BPO lease, 75% of the producer cost of service allowance,

(b) the royalty or tax exempt value determined under subsection (7) (b),

(c) subject to subsections (8) and (10), if the royalty or tax is payable in relation to a deep well event that is located in a well that has a spud date after November 30, 2003, and if the difference obtained by reducing the amount of the well depth deduction amount determined under subsection (7) (c) by the total of all previous deductions made under this paragraph is positive, the lesser of

(i) the portion of the well depth deduction amount determined under subsection (7) (c) that, when added to the amounts referred to in paragraphs (a) and (b) of this subsection, reduces to zero the total gross natural gas royalty or tax determined under subsection (7) (a),

(ii) the difference obtained by reducing the amount of the well depth deduction amount determined under subsection (7) (c) by the total of all previous deductions made under subsection (5) (c),

(iii) the positive difference obtained by reducing the amount of the well depth deduction amount determined under subparagraph (i) of this paragraph by the minimum royalty amount, and

(iv) zero, if the difference obtained by reducing the amount of the well depth deduction amount determined under subparagraph (i) of this paragraph by the minimum royalty amount is equal to or less than zero, and

(d) subject to subsections (9) and (10), if the royalty or tax payable in relation to a deep re-entry well event that is located in a well that has a re-entry date after November 30, 2003, and if the difference obtained by reducing the amount of the well depth deduction amount determined under subsection (7) (c) by the total of all previous deductions made under subsection (5) (c) is positive, the lesser of

(i) that portion of the deep re-entry incremental deduction amount determined under subsection (7) (d) that, when added to the amounts referred to in paragraphs (a) to (c) of this subsection, reduces to zero the total gross natural gas royalty or tax determined under subsection (7) (a),

(ii) the difference obtained by reducing the amount of the deep re-entry incremental deduction amount determined under subsection (7) (d) by the total of all previous deductions made under subsection (5) (d),

(iii) the positive difference obtained by reducing the amount of the deep re-entry incremental deduction amount determined under subparagraph (i) of this paragraph by the minimum royalty amount, and

(iv) zero, if the difference obtained by reducing the amount of the deep re-entry incremental deduction amount determined under subparagraph (i) of this paragraph by the minimum royalty amount is equal to or less than zero.

(5.1) For well events in a coalbed methane project, the amount of royalty or tax payable to the government for natural gas in relation to a producing month is the sum of the amounts determined for that producing month under subsection (5) for each well event in the coalbed methane project less the lesser of

(a) the balance in the producer's coalbed methane producer cost of service bank referred to in section 7.1 for the coalbed methane project at the end of the immediately preceding producing month, and

(b) the portion of that balance that is necessary to reduce to zero the royalty or tax payable to the government under this subsection for all well events in the coalbed methane project.

(6) Repealed. [B.C. Reg. 21/98, s. 4.]

(7) For the purpose of subsection (5),

(a) the total gross natural gas royalty or tax payable in relation to a well event and producing month means the sum of

(i) the royalty share or tax share, as the case may be, of marketable gas made available for sale in the producing month from the well event multiplied by the reference price for that marketable gas,

(ii) the royalty share or tax share, as the case may be, of natural gas liquids sold from the well event in the producing month multiplied by the reference price for the natural gas liquids, and

(iii) the royalty share or tax share, as the case may be, of sulphur sold from the well event in the producing month multiplied by the reference price for the sulphur,

(b) the royalty or tax exempt value in relation to a well event and producing month means the amount determined by the following formula:

(c) the well depth deduction amount means, for a producer with interests in one or both of deep well events, and deep re-entry well events, in a single well, the amount determined by the following formula:

specified table means,

(i) in the case of a deep well event under section 1 (5), the portion of Table 1 applicable to the well under subsection (7.1),

(ii) in the case of a deep well event under section 1 (5.1) or (5.2) (a), the portion of Table 2 applicable to the well under subsection (7.1), and

(iii) in the case of a deep well event under section 1 (5.2) (b), Table 3;

table depth means the deep well depth of the deepest well event rounded down to the nearest 500 metres;

(d) the deep re-entry deduction amount means, for a producer with an interest in a deep re-entry well event, the amount determined by the following formula:

(7.1) For the purposes of determining which portion of the table in subsection (7) applies to a well event,

(a) the portions of the table applicable to East apply to a well event if the well event has a spud date after November 30, 2003 and before January 1, 2009 and the well event is located in any of the following areas, which areas, in the case of areas referred to in subparagraphs (i) to (xvi), are described in accordance with the petroleum and natural gas grid established under the Petroleum and Natural Gas Grid Regulation, B.C. Reg. 321/93, and, in the case of the areas referred to in subparagraphs (xvii) to (xxi), are described in accordance with the Dominion Land Survey System:

(i) that portion of Group 095-A-01 to Group 095-A-04 (inclusive) that is located within British Columbia;

(ii) that portion of Group 095-B-01 to Group 095-B-04 (inclusive) that is located within British Columbia;

(iii) Group 094-O-01 to Group 094-O-16 (inclusive);

(iv) Group 094-P-01 to Group 094-P-16 (inclusive);

(v) Group 094-I-01 to Group 094-I-16 (inclusive);

(vi) Group 094-J-01 to Group 094-J-16 (inclusive);

(vii) Group 094-G-01 to Group 094-G-16 (inclusive);

(viii) Group 094-H-01 to Group 094-H-16 (inclusive);

(ix) that portion of Group 094-A-01 to Group 094-A-16 (inclusive) that is located outside the Peace River Block;

(x) that portion of Group 093-P-09 that is located outside the Peace River Block;

(xi) that portion of Group 093-P-10 that is located outside the Peace River Block;

(xii) Groups 093-P-01, 093-P-02, 093-P-07 and 093-P-08;

(xiii) Group 093-I-16;

(xiv) Blocks A and G to K of Group 093-I-15;

(xv) Blocks A, B and F to K of Group 093-I-09;

(xvi) Block I of Group 093-I-08;

(xvii) the portion of the Peace River Block within Township 076 east of Range 20 W6M that is within British Columbia;

(xviii) the portion of the Peace River Block within Township 077 east of Range 20 W6M that is within British Columbia;

(xix) the portion of the Peace River Block within Township 078 east of Range 20 W6M that is within British Columbia;

(xx) the portion of the Peace River Block within Township 079 east of Range 20 W6M that is within British Columbia;

(xxi) the portion of the Peace River Block within Township 080 to Township 088 and Range 13 to Range 26 W6M that is within British Columbia,

(a.1) the portions of the table in subsection (7) applicable to East apply to a well event if the well event has a spud date after December 31, 2008 and is located in any of the following areas, which areas, in the case of areas referred to in subparagraphs (i) to (xxxvi), are described in accordance with the petroleum and natural gas grid established under the Petroleum and Natural Gas Grid Regulation, B.C. Reg. 536/2004, and, in the case of the areas referred to in subparagraphs (xxxvii) to (lxxiii), are described in accordance with the Dominion Land Survey System:

(i) that portion of Group 095-A-01 to Group 095-A-04 (inclusive) that is located within British Columbia;

(ii) that portion of Group 095-B-01 to Group 095-B-04 (inclusive) that is located within British Columbia;

(iii) that portion of Group 095-C-01 that is located within British Columbia;

(iv) Group 094-P-01 to Group 094-P-16 (inclusive);

(v) Group 094-O-01 to Group 094-O-3 (inclusive);

(vi) Blocks A to C, Units 1-7 and 11-100 of Block D, and Blocks E to L of Group 094-O-04;

(vii) Group 094-O-05 to Group 094-O-16 (inclusive);

(viii) Units 11-100 of Block A, Units 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block B, Units 71-77, 81-87, 91-97 of Block E, Units 71-100 of Block F, Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-100 of Block G, Blocks H to K (inclusive), Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block L of Group 094-N-01;

(ix) Units 71-77, 81-87, 91-97 of Block G, Units 71-100 of Block H, Block I, Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block J, of Group 094-N-07;

(x) Blocks A to C (inclusive), Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block D, Units 1-7, 11-17, V 21-27, 31-37, 41-47, 51-57, 61-67, 71-100 of Block E, Blocks F to L (inclusive) of Group 094-N-08;

(xi) Blocks A-D, Units 1-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block E, Blocks F-K (inclusive), Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block L of Group 094-N-09;

(xii) Block A, Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block B, Units 1-7, 11-17, 21-27 of Block G, Units 1-30 of Block H of Group 094-N-10;

(xiii) Block A, Units 1-73, 81-83, 91-93 of Block B, Units 1-70 of Block C, Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67 of Block D, Units 1-3, 11-13, 21-23, 31-33, 41-43, 51-53, 61-63, 71-73, 81-83, 91-93 of Block G, Block H and I, Units 1-3, 11-13, 21-23, 31-33, 41-43, 51-53, 61-63, 71-73, 81-83, 91-93 of Block J of Group 094-N-16;

(xiv) Group 094-J-01 to Group 094-J-03 (inclusive);

(xv) Blocks A to C (inclusive), Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block D, Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block E, Blocks F to K (inclusive), Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block L of Group 094-J-04;

(xvi) Blocks A to C (inclusive), Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block D, Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block E, Blocks F to K (inclusive), Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block L of Group 094-J-05;

(xvii) Group 094-J-06 to 094-J-11 (inclusive);

(xviii) Blocks A to C (inclusive), Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block D, Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block E, Blocks F to K (inclusive), Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block L of Group 094-J-12;

(xix) Blocks A to C (inclusive), Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block D, Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block E, Blocks F to K (inclusive), Units 1-7, 11-17, 21-27, 31-37, 41-47, 51-57, 61-67, 71-77, 81-87, 91-97 of Block L of Group 094-J-13;

(xx) Group 094-J-14 to Group 094-J-16 (inclusive);

(xxi) Group 094-I-01 to Group 094-I-16 (inclusive);

(xxii) Group 094-H-01 to Group 094-H-16 (inclusive);

(xxiii) Block A, Units 1-3, 11-13, 21-23, 31-37, 41-47, 51-57, 61-67, 71-100 of Block B, Units 71, 81, 91 of Block C, Unit 91 of Block E, Units 1, 11-15, 21-25, 31-35, 41-45, 51-59, 61-69, 71-79, 81-89, 91-100 of Block F, Blocks G to K (inclusive), Units 1, 11, 21, 31-33, 41-43, 51-55, 61-65, 71-75, 81-85, 91-97 of Block L of Group 094-G-01;

(xxiv) Units 31, 41, 51-53, 61-63, 71-73, 81-83, 91-95 of Block A, Units 51, 61, 71-73, 81-83, 91-95 of Block G, Units 1-5, 11-17, 21-27, 31-39, 41-49, 51-100 of Block H, Block I, Units 1-5, 11-15, 21-25, 31-37, 41-47, 51-59, 61-69, 71-79, 81-89, 91-100 of Block J, Unit 91 of Block K of Group 094-G-07;

(xxv) Block A to Block C (inclusive), Units 1-7, 11-19, 21-29, 31-100 of Block D, Blocks E to L of Group 094-G-08;

(xxvi) Group 094-G-09;

(xxvii) Block A and B, Units 1, 11-13, 21-23, 31-33, 41-43, 51-55, 61-65, 71-77, 81-87, 91-100 of Block C, Unit 91 of Block D, Units 1, 11-13, 21-23, 31-37, 41-47, 51-100 of Block E, Blocks F to L (inclusive) of Group 094-G-10;

(xxviii) Units 51, 61, 71-75, 81-85, 91-99 of Block H, Units 1-9, 11-100 of Block I, Units 11-13, 21-23, 31-37, 41-47, 51-100 of Block J, Units 51, 61, 71-73, 81-83, 91-97 of Block K of Group 094-G-11;

(xxix) Units 71-73, 81-83, 91-97 of Block A, Units 71, 81, 91-95 of Block F, Units 31-35, 41-45, 51-59, 61-69, 71-100 of Block G, Units 1-7, 11-19, 21-29, 31-100 of Block H, Blocks I and J, Units 1-5, 11-19, 21-29, 31-100 of Block K, Units 31-33, 41-43, 51-57, 61-67, 71-77, 81-87, 91-97 of Block L of Group 094-G-13;

(xxx) Blocks A and B, Units 1-7, 11-100 of Block C, Units 11, 21, 31-33, 41-43, 51-59, 61-69, 71-100 of Block D, Blocks E to L (inclusive) of Group 094-G-14;

(xxxi) Group 094-G-15 and Group 094-G-16;

(xxxii) Unit 91 of Block H, Units 1, 11-13, 21-23, 31-37, 41-47, 51-57, 61-67, 71-79, 81-89, 91-100 of Block I, Units 91-93 of Block J of Group 094-B-16;

(xxxiii) that portion of Group 094-A-09 to Group 094-A-11 that is located outside the Peace River Block;

(xxxiv) that portion of Block I, Units 1, 11-15, 21-25, 31-35, 41-45, 51-57, 61-67, 71-100 of Block J, Units 71, 81, 91 of Block K of Group 094-A-12 that is located outside the Peace River Block;

(xxxv) Blocks A and B, Units 1, 11-13, 21-23, 31-35, 41-45, 51-55, 61-65, 71-77, 81-87, 91-99 of Block C, Units 11-13, 21-23, 31-35, 41-45, 51-57, 61-67, 71-79, 81-89, 91-100 of Block E, Units 1-9, 11-100 of Block F, Blocks G to L (inclusive) of Group 094-A-13;

(xxxvi) Group 094-A-14 to Group 094-A-16 (inclusive);

(xxxvii) that portion of the Peace River Block within Sections 1-3, 10-15, 22-29, 32-36 of Township 88 Range 23 W6M;

(xxxviii) that portion of the Peace River Block with Township 88 east of Range 23 W6M within British Columbia;

(xxxix) Sections 1-3, 10-15, 22-27, 34-36 of Township 87 Range 23 W6M;

(xl) Township 87 east of Range 23 W6M within British Columbia;

(xli) Sections 1-5, 8-16, 21-28, 33-36 of Township 86 Range 23 W6M;

(xlii) Township 86 east of Range 23 W6M within British Columbia;

(xliii) Sections 1, 2, 12, 13, 24 of Township 85 Range 24 W6M;

(xliv) Township 85 east of Range 24 W6M within British Columbia;

(xlv) Sections 1-5, 8-16, 22-27, 35, 36 of Township 84 Range 24 W6M;

(xlvi) Township 84 east of Range 24 W6M within British Columbia;

(xlvii) Sections 1, 12, 13, 24 of Township 83 Range 25 W6M;

(xlviii) Township 83 east of Range 25 W6M within British Columbia;

(xlix) Sections 1, 2, 10-15, 22-27, 34-36 of Township 82 Range 25 W6M;

(l) Township 82 east of Range 25 W6M within British Columbia;

(li) Sections 12, 13, 24-26, 35, 36 of Township 81 Range 25 W6M;

(lii) Township 81 east of Range 25 W6M within British Columbia;

(liii) Sections 1-3, 9-16, 20-29, 31-36 of Township 80 Range 24 W6M;

(liv) Township 80 east of Range 24 W6M within British Columbia;

(lv) Sections 12, 13, 23-26, 34-36 of Township 79 Range 24 W6M;

(lvi) Township 79 east of Range 24 W6M within British Columbia;

(lvii) Section 36 of Township 78 Range 24 W6M;

(lviii) Sections 1-4, 9-17, 19-36 of Township 78 Range 23 W6M;

(lix) Township 78 east of Range 23 W6M within British Columbia;

(lx) Sections 1, 12-14, 23-27, 34-36 of Township 77 Range 23 W6M;

(lxi) Township 77 east of Range 23 W6M within British Columbia;

(lxii) that portion of the Peace River Block within Section 36 of Township 76 Range 23 W6M;

(lxiii) that portion of the Peace River Block within Township 76 east of Range 23 W6M within British Columbia;

(lxiv) Group 093-P-01;

(lxv) Units 1-5, 11-15, 21-25, 31-37, 41-47, 51-100 of Block A, Units 51, 61, 71-73, 81-83, 91-97 of Block B, Units 71, 81, 91-93 of Block E, Units 11, 21, 31-33, 41-43, 51-57, 61-67, 71-100 of Block F, Units 1-7, 11-100 of Block G, Blocks H to K (inclusive), Units 1-3, 11-15, 21-25, 31-37, 41-47, 51-100 of Block L of Group 093-P-02;

(lxvi) Units 51, 61, 71-73, 81-83, 91-95 of Block I of Group 093-P-03;

(lxvii) Units 1-5, 11-19, 21-29, 31-100 of Block A, Units 31, 41, 51-53, 61-63, 71-75, 81-85, 91-97 of Block B, Units 71, 81, 91 of Block F, Units 1-7, 11-17, 21-27, 31-39, 41-49, 51-59, 61-69, 71-100 of Block G, Blocks H to J (inclusive), Units 1, 11-13, 21-23, 31-35, 41-45, 51-55, 61-65, 71-75, 81-85, 91-97 of Block K of Group 093-P-06;

(lxviii) Group 093-P-07 and Group 093-P-08;

(lxix) That portion of Group 093-P-09 and Group 093-P-10 that is located outside of the Peace River Block;

(lxx) That portion of Blocks A, B, Units 1-7, 11-19, 21-29, 31-39, 41-49, 51-59, 61-69, 71-100 of Block C, Units 71, 81, 91-93 of Block D, Units 1-3, 11-13, 21-23, 31-33, 41-43, 51-55 of Block E, Blocks F to H (inclusive) of Group 093-P-11 that is located outside of the Peace River Block;

(lxxi) Units 51, 61, 71-73, 81-83, 91-97 of Block H, Units 1-7, 11-17, 21-27, 31-100 of Block I, Units 31, 41, 51-53, 61-63, 71-77, 81-87, 91-100 of Block J, Unit 91 of Block K of Group 093-I-09;

(lxxii) Units 51, 61, 71, 81, 91 of Block H, Units 1, 11-13, 21-23, 31-33, 41-43, 51-53, 61-63, 71-73, 81-83, 91-95 of Block I of Group 093-I-15;

(lxxiii) Blocks A, B, Units 1, 11-17, 21-27, 31-100 of Block C, Units 31, 41, 51-55, 61-65, 71-77, 81-87, 91-97 of Block D, Units 1-7, 11-19, 21-29, 31-39, 41-49, 51-100 of Block E, and Blocks F to L (inclusive) of Group 093-I-16,

(b) the portions of the table applicable to West apply to a well event located in British Columbia to which paragraph (a) does not apply,

(c) the portions of the table applicable to Special Sour apply to a well event if

(i) the maximum potential H₂S release rate from the well in which the well event is located is 0.01 m³/s or greater and less than 0.1 m³/s and that well is located within 500 metres of the corporate boundaries of an urban centre,

(ii) the maximum potential H₂S release rate from the well in which the well event is located is 0.1 m³/s or greater and less than 0.3 m³/s and that well is located within 1.5 kilometres of the corporate boundaries of an urban centre,

(iii) the maximum potential H₂S release rate from the well in which the well event is located is 0.3 m³/s or greater and less than 2.0 m³/s and that well is located within 5 kilometres of the corporate boundaries of and urban centre, or

(iv) the maximum potential H₂S release rate from the well in which the well event is located is 2.0 m³/s or greater, and

(d) the portions of the table applicable to Sweet apply to a well event located in any well in British Columbia to which paragraph (c) does not apply.

(8) If a deep well event is also a deep discovery well event, the maximum amount that may, in the aggregate, be deducted under subsection (5) (c) in relation to the well event is the positive difference, if any, obtained by subtracting the total of the royalty or tax exempt values determined in relation to the well event under subsection (7) (b) from the well depth deduction amount determined under subsection (7) (c).

(9) If a deep re-entry well event is also a deep discovery well event, the maximum amount that may, in the aggregate, be deducted under subsection (5) (d) in relation to the well event is the positive difference, if any, obtained by subtracting the total of the royalty or tax exempt values determined in relation to the well event under subsection (7) (b) from the deep re-entry incremental deduction amount determined under subsection (7) (d).

(10) For a well event described in section 6 (1.5) that is also a deep well event, the deduction under subsection (5) (c) of this section in relation to the well event for the 12 calendar months beginning with the month in which the well event first commenced continuous production is deemed to be the same as the deduction that would have been made had section 6 (1.4) not been enacted.

[am. B.C. Regs. 503/94; 65/95; 21/98, s. 4; 50/2001, s. 6; 29/2002, s. 3; 250/2003, s. 5; 302/2003, s. 2; 442/2003, s. 4; 178/2004, s. 3; 138/2005, s. 3; 191/2005, Sch. 2, s. 2; 73/2006, ss. 8 and 9; 17/2009, s. 2; 116/2009; 193/2009, s. 3; 269/2010, Sch. s. 16; 91/2012, s. (c); 128/2013, s. 2; 30/2014, s. 2; 194/2018, Sch. 1, s. 3.]

Coalbed methane producer cost of service bank

7.1   (1) Each producer having an interest in one or more well events that form part of a coalbed methane project has, for that coalbed methane project, a coalbed methane producer cost of service bank.

(2) There is to be added to a producer's coalbed methane producer cost of service bank for a coalbed methane project, on the completion of each completed well event that is part of the coalbed methane project, the amount determined by multiplying the producer's interest in that well event by the following:

(a) if the well event is on Crown land and production is under the authority of a BPO lease, $37 500;

(b) if the well event is on Crown land and production is under the authority of a NBPO lease, $30 000;

(c) for any other well event on Crown land, $50 000;

(d) for any well event on freehold mineral land, $30 000.

(3) A disposition by a producer to another person (the "acquirer") of all or part of the producer's interest in well events that form all or part of a coalbed methane project effects

(a) a deduction, from the balance of the producer's coalbed methane producer cost of service bank for that coalbed methane project, of that portion of the balance that is proportionate to the proportion of the producer's interest in the coalbed methane project that is being disposed of, and

(b) an addition, to the balance in the acquirer's coalbed methane producer cost of service bank for that coalbed methane project, of the amount of the deduction referred to in paragraph (a).

(4) The balance in a producer's coalbed methane producer cost of service bank for a coalbed methane project at the end of a producing month is equal to the amount determined by the following formula:

[en. B.C. Reg. 29/2002, s. 4; am. B.C. Regs. 442/2003, s. 5; 138/2005, s. 4; 73/2006, s. 10.]

Royalty for unaccounted quantities

7.2   (1) If the operator of a reporting facility does not account for a quantity of oil in information that the operator is required to provide under section 8 (1) (a) and if, under section 73.1 (1) of the Act, the collector treats the unaccounted quantity as having been sold, the collector may, in accordance with subsection (3) of this section, calculate the amount of royalty payable to the government by the operator in respect of that quantity.

(2) If the operator of a reporting facility does not account for a quantity of marketable gas or natural gas by-products in information that the operator is required to provide under any of section 8 (1) (b) to (e), indicating how the volumes of marketable gas and natural gas by-products are allocated, and if, under section 73.1 (1) of the Act, the collector treats the unaccounted quantity as having been sold, the collector may, in accordance with subsection (5) or (7) of this section, calculate the amount of royalty payable to the government by the operator in respect of that quantity.

(3) The total amount of royalty payable for an unaccounted quantity of oil is the quantity of oil referred to in subsection (1) multiplied by the unit selling price of oil fixed under subsection (4) multiplied by the royalty percentage rate for oil of 40%.

(4) The collector must fix a unit selling price of oil at a level not exceeding the highest unit selling price received by any producer during the month in which the unaccounted quantity of oil is treated as having been sold.

(5) The total amount of royalty payable for an unaccounted quantity of marketable gas is the quantity of marketable gas referred to in subsection (2) multiplied by the price of marketable gas fixed under subsection (6) multiplied by the royalty percentage rate for marketable gas of 27%.

(6) The collector must fix a price of marketable gas at a level not exceeding the highest reference price for marketable gas determined for any producer during the month in which the unaccounted quantity of marketable gas is treated as having been sold.

(7) The total amount of royalty payable for an unaccounted quantity of natural gas by-products is the quantity of natural gas by-products referred to in subsection (2) multiplied by the unit selling price of natural gas by-products fixed under subsection (8) multiplied by the following applicable royalty percentage rate:

(a) 20% for natural gas liquids;

(b) 16.667% for sulphur.

(8) The collector must fix a unit selling price for natural gas by-products at a level not exceeding the highest unit selling price received by any producer during the month in which the unaccounted quantity of natural gas by-products is treated as having been sold.

[en. B.C. Reg. 194/2018, Sch. 1, s. 4.]

Reporting

8   (1) The following persons must provide the following information to the collector in the form and manner required by the collector:

(a) the operator of a reporting facility must, on or before the 21st day of the calendar month after each producing month, provide information indicating the production, receipt, disposition, use and storage in that producing month of oil, natural gas, natural gas by-products and water obtained at the reporting facility, and any other information specified by the collector;

(b) the operator of a reporting facility must, on or before the 25th day of the calendar month after each producing month, provide information indicating, for the volumes of marketable gas that the reporting facility delivers during that producing month to be sold or stored and in respect of which royalty or tax has not previously been paid, how those volumes are allocated

(i) to a producer's share of a well event or unitized operation, or

(ii) if the operator is unable to allocate to a producer's share of a well event or unitized operation, to the reporting facility from which the volumes were received;

(c) the operator of a reporting facility to which volumes of marketable gas are allocated under paragraph (b) (ii) must, on or before the 25th day of the calendar month after each producing month, provide information indicating how those volumes are allocated under paragraph (b) (i) or (ii);

(d) the operator of a reporting facility must, on or before the 25th day of the calendar month after each producing month, provide information indicating, for the volumes of natural gas by-products that the reporting facility produces during that producing month, how those volumes are allocated

(i) to a producer's share of a well event or unitized operation, or

(ii) if the operator is unable to allocate to a producer's share of a well event or unitized operation, to the reporting facility from which the volumes were received;

(e) the operator of a reporting facility to which volumes of natural gas by-products are allocated under paragraph (d) (ii) must, on or before the 25th day of the calendar month after each producing month, provide information indicating how those volumes are allocated under paragraph (d) (i) or (ii);

(f) the operator of a reporting facility that delivers natural gas to a natural gas processing plant and the operator of a dry gas source must, on or before the 25th day of the calendar month after each producing month, provide information indicating, for the volumes of natural gas that the reporting facility delivers or that the dry gas source disposes of during that producing month, how those volumes are allocated

(i) to a producer's share of a well event or unitized operation, or

(ii) if the operator is unable to allocate to a producer's share of a well event or unitized operation, to the reporting facility from which the volumes were received;

(g) the operator of a reporting facility to which volumes of natural gas are allocated under paragraph (f) (ii) must, on or before the 25th day of the calendar month after each producing month, provide information indicating how those volumes are allocated under paragraph (f) (i) or (ii);

(h) the operator of a reporting facility must, on or before the 25th day of the calendar month after each producing month, provide information indicating, for the volumes of marketable gas that are returned to the reporting facility from a natural gas processing plant or meter station during that producing month, how those volumes are allocated

(i) to a producer's share of a well event or unitized operation, or

(ii) if the operator is unable to allocate to a producer's share of a well event or unitized operation, to the reporting facility from which the volumes were originally received;

(i) the operator of a reporting facility to which volumes of marketable gas are allocated under paragraph (h) (ii) must, on or before the 25th day of the calendar month after each producing month, provide information indicating how those volumes are allocated under paragraph (h) (i) or (ii);

(j) the operator of a reporting facility that delivers oil or condensate for sale must, on or before the 21st day of the calendar month after each producing month, provide information indicating, for that producing month, the producer, the purchaser and the shipper of the oil or condensate and any other information specified by the collector about the delivery and sale;

(k) a person who purchases, at a reporting facility, oil or condensate produced in British Columbia must, on or before the 10th day of the second calendar month after the calendar month in which the purchase occurred, provide information identifying the seller and indicating the volume, price, value, density and sulphur content of the oil or condensate and any other information specified by the collector about the oil or condensate;

(l) a producer of oil must, on or before the 10th day of the second calendar month after each producing month, provide information indicating, for each reporting facility or unitized operation at which the producer had sales of oil in that producing month,

(i) the volume of oil sold by the producer at that reporting facility or unitized operation in that producing month,

(ii) the sales value of oil sold by the producer at that reporting facility or unitized operation in that producing month,

(iii) the transportation and tariff costs that under section 7 (3) (a) may be deducted for that producing month, and

(iv) any other information specified by the collector;

(m) a producer of natural gas by-products must, on or before the 10th day of the second calendar month after each producing month, provide information indicating, for that producing month, the sales volumes and values of natural gas by-products produced from each well event in which the producer has an interest and any other information specified by the collector;

(n) the operator of a well event must, on or before the 15th day of the calendar month after the calendar month in which operations at the well event began or were suspended, provide information indicating the commencement or suspension of operations and any other information specified by the collector;

(o) the operator of a well event must, on or before the 15th day of the calendar month after the calendar month in which the well event is connected to a reporting facility or in which a change in producers' interests in the well event is effective, provide information indicating the producers' interests or the change in producers' interests in the natural gas and oil produced from the well event and any other information specified by the collector;

(p) the operator of a unitized operation for which there is a unitization agreement, under which royalty is determined in relation to a tract according to production volumes allocated to that tract under the agreement, must, on or before the 15th day of the calendar month after the calendar month in which there is a change in producers' interests in the natural gas or oil allocated to a tract, provide information indicating the change in producers' interests in the tract and any other information specified by the collector;

(q) for the purpose of section 2 (8), the operator of a producer-owned plant or a producer-owned sales line that is not located within a project ring fence must, on or before March 10 of the year after the calendar year in which the plant processed gas or the pipeline transported gas, provide information indicating the capital and operating costs of the plant or sales line and any other information specified by the collector;

(r) a producer who has drilled a well that qualifies for a summer drilling credit under section 4 (4) must, on or before June 30 of the year after the calendar year in which the well was drilled, provide information indicating

(i) the amount of goods and service costs incurred to drill the well, and

(ii) each producer's proportionate interest in the well.

(2) Subject to subsection (2.1), a person may amend information provided by that person under subsection (1) by providing the amended information to the collector.

(2.01) Subject to subsection (2.1), if a person who provides information under subsection (1) (a), (n), (o) or (p) becomes aware that the information is no longer accurate or complete, the person must provide to the collector amended information that is accurate and complete as follows:

(a) in the case of information provided under subsection (1) (a), on or before the next 21st day of a calendar month;

(b) in the case of information provided under subsection (1) (n), (o) or (p), on or before the next 15th day of a calendar month.

(2.1) A person must not provide amended information under subsection (2) or (2.01)

(a) more than 72 months after the month in relation to which the amended information is being provided,

(b) in respect of an amount assessed or reassessed under section 9 (2) and invoiced under section 9 (5), or

(c) in respect of an amount about which the collector has made a decision under section 11 (1), the administrator has made a decision under section 11 (2) or the Minister of Finance has made a decision under section 12 (4).

(3) Repealed. [B.C. Reg. 50/2001, s. 7.]

(4) A person who produces, processes, transports, acquires from a producer or offers to acquire from a producer oil, natural gas or natural gas by-products shall, not later than 30 days after a written request from the administrator or the collector, provide, in the form and manner and for the times requested, the information requested respecting the production, processing, transportation, acquisition or sale of the oil, natural gas or natural gas by-products.

(5) On or before the 9th day of the second calendar month after the month in which a producer produces marketable gas, the producer must, in the form and manner required by the administrator, provide to the administrator copies of all invoices for the following:

(a) sales of the marketable gas;

(b) purchases and sales of gathering, processing and transportation services made in the producing month.

[am. B.C. Regs. 21/98, s. 5; 50/2001, s. 7; 250/2003, s. 6; 302/2003, ss. 2, 4 and 5; 442/2003, s. 6; 191/2005 Sch. 2, s. 3; 73/2006, s. 11; 99/2008, ss. 6, 7 and 8; 269/2010, Sch., s. 17; 194/2018, Sch. 1, s. 5.]

Examination of return and assessment of royalty or tax

9   (1) After receiving information provided in respect of a producer under section 8 (1) for a producing month, the collector must, on or about the 23rd day of the second calendar month after the producing month,

(a) issue a Crown invoice to the producer showing, for the producing month, the amount of royalty and tax that is payable to the government in respect of the oil, marketable gas or natural gas by-products to which the information applies, and

(b) if royalty for an unaccounted quantity is payable as a result of the information provided by the operator of a reporting facility, issue a Crown invoice to the operator showing the amount of that royalty.

(1.1) Repealed. [B.C. Reg. 194/2018, Sch. 1, s. 6 (a).]

(1.2) After receiving amended information provided in respect of a producer under section 8 (2) or (2.01), the collector must

(a) issue an amended Crown invoice to the producer showing, for the producing month, the amount of royalty, tax, interest and penalty that is payable to the government in respect of the oil, marketable gas or natural gas by-products to which the amended information applies, and

(b) if royalty for an unaccounted quantity and interest are payable as a result of the information provided by the operator of a reporting facility, issue a Crown invoice to the operator showing the amount of that royalty and interest.

(2) If the collector, on examining information or amended information provided under section 8, disagrees with it or calculations in it, the collector may do either or both of the following:

(a) request the person who provided the information or amended information to provide, on or before a date specified by the collector or, if no date is specified, within 30 days after the date of the request, information that the collector believes is correct;

(b) assess or reassess royalty, tax, interest and penalty payable to the government based on the information that the collector believes is correct.

(3) The collector may make the assessment or reassessment referred to in subsection (2)

(a) at any time, if the producer has made a misrepresentation or committed fraud in making the return or supplying information under this regulation, or

(b) in any other case, not more than 84 months after the last day of the producing month to which the assessment or reassessment relates.

(4) The notice of assessment must contain the determination made by the collector of the amount of royalty, tax, interest and penalty payable and the due date for payment of that amount.

(5) On assessing or reassessing the royalty, tax, interest or penalty payable by a producer who has not provided information or has provided information or calculations with which the collector disagrees, the collector must issue to the producer a Crown invoice containing a notice of assessment.

(5.1) On assessing or reassessing the royalty for an unaccounted quantity, interest or penalty payable by the operator of a reporting facility who has not provided information or has provided information or calculations with which the collector disagrees, the collector must issue to the operator a Crown invoice containing a notice of assessment.

(6) Evidence that a Crown invoice has been issued under this section is proof, in the absence of evidence to the contrary, that the amount assessed is due and owing, and the onus of proving otherwise is on the person liable to pay the amount assessed.

(7) In the case of an overpayment by a producer, the producer may deduct from royalty or tax payments due after the date of the notice of assessment the amount of the overpayment indicated in the notice of assessment.

(7.1) In the case of an overpayment by the operator of a reporting facility, the operator may deduct from the royalty for an unaccounted quantity due after the date of the notice of assessment the amount of the overpayment indicated in the notice of assessment.

(8) The collector may assess a person for interest and penalties referred to in section 13.

[am. B.C. Regs. 50/2001, s. 8; 302/2003, s. 2; 191/2005, Sch. 2, s.  4; 73/2006, ss. 9 and 12; 99/2008, s. 9; 194/2018, Sch. 1, s. 6.]

Producer liability

10   (1) A person's liability for royalty, tax, interest or penalty due under the Act and this regulation is not affected by reason only of a prior incorrect assessment or the absence of an assessment.

(2) Royalty, tax, interest and penalties are payable whether or not an objection to the assessment is made under section 11 or 12.

(3) Subject to being amended, changed or varied on appeal or by reassessment, a Crown invoice issued or a penalty imposed under this regulation is valid and binding despite any error, defect or omission in the Crown invoice or penalty or in procedure.

[am. B.C. Reg. 194/2018, Sch. 1, s. 7.]

Reconsideration by collector or administrator

11   (1) The collector may reconsider or vary a Crown invoice for royalty, tax or penalty on the request of a producer or the operator of a reporting facility who objects in writing to the invoiced amount.

(2) The administrator may reconsider or vary a producer price

(a) on the request of a producer who objects in writing to the producer price as determined, or

(b) if the administrator determines that the information on which the producer price was calculated was incorrect or incomplete.

[am. B.C. Regs. 21/98, s. 6; 50/2001, s. 9; 302/2003, s. 2; 194/2018, Sch. 1, s. 8.]

Appeals

12   (1) An appeal to the Minister of Finance lies from a decision of the collector under section 3 (1) or 11 (1) or a decision of the administrator under section 11 (2).

(2) Written notice of the appeal must be given to the Minister of Finance within 90 days after the date of the decision.

(3) The appellant must set out in the notice of appeal a statement of all material facts and the reasons in support of the appeal.

(4) On receiving the notice of appeal, the Minister of Finance must

(a) consider the matter,

(b) affirm, amend or reverse the decision of the collector or the administrator, and

(c) promptly notify the appellant in writing of the result of the appeal.

(5) The Minister of Finance may

(a) delegate, in writing, the exercise of any power or performance of any duty conferred or imposed on the Minister of Finance under this section to an employee of the ministry of the Minister of Finance, and

(b) provide, in making a delegation, directions that are binding on the delegate respecting the exercise of the power or the performance of the duty.

(6) A delegation under subsection (5) may be made by name or by designation of the office.

[en. B.C. Reg. 194/2018, Sch. 1, s. 9; am. B.C. Regs. 239/2020, Sch. 4; 211/2022, Sch. 4, s. 1.]

Notice of appeal

12.1   (1) The date on which a notice of appeal is given to the Minister of Finance under section 12 (2) is the date it is received by the Minister of Finance.

(2) A notice of appeal is conclusively deemed to have been given to the Minister of Finance if it is received at a location and by a method specified by the Minister of Finance.

[en. B.C. Reg. 211/2022, Sch. 4, s. 2.]

Interest and penalties

13   (1) The annual rate of interest during a quarterly period for penalties, royalties, taxes and unpaid interest is 3.0% above the prime lending rate of the principal banker to the Province on the 15th day of the month immediately preceding a quarterly period commencing on January 1, April 1, July 1 and October 1 of each calendar year.

(1.1) The annual rate of interest during a quarterly period for overpayments is 2.0% below the prime lending rate of the principal banker to the Province on the 15th day of the month immediately preceding a quarterly period commencing on January 1, April 1, July 1 and October 1 of each calendar year.

(1.2) Repealed. [B.C. Reg. 194/2018, Sch. 1, s. 13 (c).]

(2) Interest payable must be

(a) compounded monthly, and

(b) calculated on the number of days since the last compounding of interest or, if no compounding has yet occurred, from the date that interest is payable.

(3) At the end of a calendar month, interest must be calculated in accordance with subsection (2) on an amount owing

(a) by a producer for royalty, tax, unpaid interest or penalty, or

(b) by the operator of a reporting facility for royalty for an unaccounted quantity, unpaid interest or penalty.

(4) If full payment of an account is not made by the due date shown on a Crown invoice, but is made within 30 days after a subsequent written request for payment is issued, the payment of the amount set out in the written request, without the interest accrued since the date of the written request, must be accepted in settlement of the account.

(5) If a producer overpays royalties or taxes, interest on the overpayment

(a) must be calculated in accordance with subsection (2) from the 61st day after the day the overpayment is received, and

(b) stops accruing

(i) on the day that payment of the amount owed is mailed to the producer or, if delivered to the producer without mailing, the day of delivery, or

(ii) on the day that the amount owed is applied to royalties, taxes, unpaid interest or penalties owing by the producer.

(6) If the operator of a reporting facility overpays a royalty for an unaccounted quantity and the overpayment is subsequently reversed,

(a) no interest is payable on the reversed amount before the day of the reversal, and

(b) interest on the reversed amount

(i) must be calculated in accordance with subsection (2) from the 61st day after the day the amount is reversed, and

(ii) stops accruing

(A) on the day that payment of the amount owed is mailed to the operator or, if delivered to the operator without mailing, the day of delivery, or

(B) on the day that the amount owed is applied to royalties, unpaid interest or penalties owing by the operator.

(7) This section does not operate to require the payment of an amount of interest less than $5.

(8) The collector may assess at any time interest, calculated in accordance with this section, on an amount owing for royalty or tax until the day that a Crown invoice is issued in relation to the amount owing.

(9) The collector may assess at any time interest, calculated in accordance with this section, on an amount owing for royalty, tax, unpaid interest or penalty from the day that a Crown invoice for the amount owing is due or the day that a notice of assessment is issued in relation to the amount owing.

(10) If a person does not, within the required time and in the required form and manner, provide information required under section 8 (1), (2.01), (4) or (5) or 9 (2) (a), the person may be assessed a penalty of $500 for each month or part of a month that the failure to provide the information continues, or for any lesser number of months that the collector considers appropriate.

(11) If a person provides information under section 8 (1), (2.01), (4) or (5) or 9 (2) (a) that contains any of the following data discrepancies and the discrepancies are not corrected by the date the person is required to provide the information, the person may be assessed a penalty of $100 in respect of each discrepancy for each month or part of a month that the failure to correct the discrepancy continues, or for any lesser number of months that the collector considers appropriate:

(a) an imbalance error;

(b) incomplete or invalid information;

(c) a metering difference error.

[am. B.C. Regs. 21/98, s. 7; 50/2001, s. 10; 191/2005, Sch. 2, s. 5; 73/2006, s. 13; 194/2018, Sch. 1, s. 10.]

Transition — interest and penalties

14   (1) Section 13 (1) to (5) applies to interest calculated for the first time on or after November 1, 2018 in respect of an amount, whether or not the amount was payable before that day.

(2) Section 13 (4) and (5), as it read immediately before November 1, 2018, applies to failures to file that began before that day and continue on or after that day.

[en. B.C. Reg. 194/2018, Sch. 1, s. 11.]

Transition — notice of appeal

15   This regulation, as it read on October 31, 2022, continues to apply in relation to a notice of appeal under section 12 from a decision of the collector or a decision of the administrator if the decision is dated on or before October 31, 2022.

[en. B.C. Reg. 211/2022, Sch. 4, s. 2.]