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B.C. Reg. 495/92
O.C. 1854/92
Deposited December 18, 1992
effective January 1, 1993

Petroleum and Natural Gas Act

Petroleum and Natural Gas Royalty and

Freehold Production Tax Regulation

Note: Check the Cumulative Regulation Bulletin 2014
for any non-consolidated amendments to this regulation that may be in effect.

[includes amendments up to B.C. Reg. 30/2014, March 14, 2014]

Point in Time

Contents
 1 Definitions and interpretation
 2 Powers of administrator and collector
 3 Royalty and tax share
 4 Royalty and tax payment
 5 Oil royalty and tax rates
 6 Natural gas and natural gas by-products royalty and tax rates
 7 Royalty and tax calculations
 7.1 Coalbed methane producer cost of service bank
 8 Reporting
 9 Examination of return and assessment of royalty or tax
 10 Producer liability
 11 Reconsideration by collector or administrator
 12 Appeals
 13 Interest and penalties
Schedule A

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 Oil and Gas 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 Oil and Gas 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 Oil and Gas 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 Oil and Gas 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 delivered under section 9 (1), (1.1) or (1.2);

"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 alteration application,

(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 Oil and Gas 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 Oil and Gas Activities Act or the former Act, as that term is defined in section 116 (1) of the Oil and Gas 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:

60 - 0.035 x (measured depth to completion point - 2300)

100

(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:

60 - 0.035 x (measured depth to completion point - 2 300)

100

(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;

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

(consideration – actual costs)

sales volume
where
"consideration" means the consideration received or receivable by the producer for the disposition of the natural gas liquids;
"actual costs" means the actual costs, approved by the collector, that are incurred by the producer for transporting and processing the natural gas liquids from the point of production to the point of sale;
"sales volume" means the volume of natural gas liquids involved in the disposition;

"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;

"pay", in respect of a pool, means the portion of the pool that is determined by the Oil and Gas Commission 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

  2.5 x (wellhead price - threshold price for heavy oil)
1 + 
  wellhead price

(b) for third tier oil, the lesser of

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

  3.5 x (wellhead price – threshold price for third tier oil)
1 + 
  wellhead price

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:

A x B x C
where
A  means the weighted average royalty or tax rate in relation to the well event and the producing month,
B  means the producer cost of service rate in relation to the coalbed methane project to which natural gas produced by the well event was delivered in the producing month, and
C  means the producer cost of service natural gas volume in relation to the well event in the producing month, and

(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:

A x B x C
where
A  means the weighted average royalty or tax rate in relation to the well event and the producing month,
B  means the producer cost of service rate in relation to the reporting facility to which natural gas produced by the well event was delivered in the producing month, and
C  means the producer cost of service natural gas volume in relation to the well event and the producing month, and

(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;

"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 Oil and Gas Commission 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) a battery as defined in the Drilling and Production Regulation, or

(b) if there is no battery to receive the effluent from a well event, the surface equipment associated with that well event that measures the volume of effluent produced;

"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 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 x RO x (1 – P),

B = the volume of new oil determined in accordance with the following formula: B = V x RN x 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 x RO x (1 – P),

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

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

H = the volume of heavy oil determined in accordance with the following formula: H = V x 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 sold in the producing month 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 Oil and Gas Commission 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:

(consideration – actual costs)

sales volume
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 sold in the producing month 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 Oil and Gas 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 and sold in that 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 and sold in that 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) and (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:

(TP/TPH) x 24
where
  TP  means the total production from the well event in the following applicable period:
    (i) if the well event is not a reactivated well event, the period of 12 consecutive calendar months that begins with the calendar month in which the well event first commences continuous production;
    (ii) if the well event is a reactivated well event, the period of 12 consecutive calendar months that begins with the calendar month in which the reactivated well event commenced or recommenced continuous production, and
TPH  means the total number of hours during which the well event produced natural gas in that 12 calendar month period,

(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

(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, and

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

(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, and

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

(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:

(TP/TPH) x 24
where
  TP  means the total production from the well event in the following applicable period:
    (A) if the well event is not a reactivated well event, the period of 12 consecutive calendar months that begins with the calendar month in which the well event first commences continuous production;
    (B) if the well event is a reactivated well event, the period of 12 consecutive calendar months that begins with the calendar month in which the reactivated well event commenced or recommenced continuous production, and
  TPH  means the total number of hours during which the well event produced natural gas in that 12 calendar month period;

(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:

(TP/TPH) x 24
where    
  TP  means the total production from the well event in the following applicable period:
    (A) if the well event is not a reactivated well event, the period of 12 consecutive calendar months that begins with the calendar month in which the well event first commences continuous production;
    (B) if the well event is a reactivated well event, the period of 12 consecutive calendar months that begins with the calendar month in which the reactivated well event commenced or recommenced continuous production, and
  TPH  means the total number of hours during which the well event produced natural gas in that 12 calendar month period,

(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, or

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

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

[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.]

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  (1) On or before the 25th day of each calendar month, a producer is to pay to the government royalty and tax based on an estimate of the value of

(a) oil produced from an oil well event by the producer in the producing month that is the calendar month before the calendar month of the royalty or tax payment,

(b) marketable gas produced from a well event and made available for sale by the producer in the producing month that is the second calendar month before the calendar month of the royalty or tax payment, and

(c) natural gas by-products produced from a well event and sold by the producer in the producing month that is the second calendar month before the calendar month of the royalty or tax payment.

(2) A producer to whom Crown invoices are delivered under section 9 (1) in respect of a producing month is, on or before the later of the 25th day of the calendar month in which the Crown invoices are delivered and 15 days after the date that the Crown invoices are delivered, to pay the total of those invoiced amounts less the amount paid under subsection (1) (a) of this section in respect of the producing month.

(2.1) A producer to whom Crown invoices are delivered under section 9 (1.1) in respect of a producing month is, on or before the later of the 25th day of the calendar month in which the Crown invoices are delivered and 15 days after the date that the Crown invoices are delivered, to pay the total of those invoiced amounts less the amount paid under subsection (1) (b) and (c) of this section in respect of the producing month.

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

(2.3) A producer to whom Crown invoices are delivered under section 9 (1.2) in respect of a producing month is, on or before the later of the 25th day of the calendar month in which the Crown invoices are delivered and 15 days after the date that the Crown invoices are delivered, to pay the total of those invoiced amounts less the amount paid under subsection (1), (2) and (2.1) of this section in respect of the producing month.

(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) (l).

(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 (9) and (10).

(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) If a producer advises the administrator that the producer intends to undertake a project to construct or upgrade pipelines, bridges, roads, rails or trails in support of resource exploration or development,

(a) the administrator may agree that the producer is entitled to deduct from the royalty or tax otherwise payable by the producer under this Act a portion of the costs attributable to that project,

(b) the administrator may, for the purposes of paragraph (a), enter into an agreement with the producer identifying the various steps that constitute the project and specifying what constitutes the completion of each step, what the estimated completion cost of each step is to be and what the estimated completion cost for the project is to be, and

(c) the project deduction amount available to a producer who has entered into an agreement under paragraph (b) for each of the specified steps of the project is 50% of the lesser of the estimated completion cost for that step and the amount actually spent by the producer to complete that step, if the administrator is satisfied that

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

(ii)   the producer intends to complete the project, and

(iii)   the completion cost for which the deduction amount is calculated has actually been paid by the producer.

(9.1) If a pipeline company advises the administrator that the pipeline company intends to undertake a project, in a contractual arrangement with one or more producers, to construct or upgrade pipelines in British Columbia in support of resource exploration or development in British Columbia,

(a) the administrator may agree that the producer or producers are entitled to deduct from the royalty or tax otherwise payable by the producer or producers under this Act a portion of the costs attributable to that project,

(b) the administrator may, for the purpose of paragraph (a), enter into an agreement with the parties to the contractual arrangement, identifying the various steps that constitute the project, and specifying what constitutes the completion of each step, what the estimated completion cost of each step is to be and what the estimated completion cost for the project is to be,

(c) the project deduction amount available, for each of the specified steps of the project, to all producers who have entered into an agreement for that project under paragraph (b), is 50% of the lesser of the estimated completion cost for that step and the amount actually spent by the parties to the contractual arrangement to complete that step, if the administrator is satisfied that

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

(ii)   the parties to the contractual arrangement intend to complete the project, and

(iii)   the completion cost for which the deduction amount is calculated has actually been paid by the parties to the contractual arrangement.

(9.2) For the purposes of subsection (9.1):

"pipeline" means a pipe or system or arrangement of pipes by which is conveyed petroleum or natural gas, or water used or obtained in drilling for or in the production of petroleum or natural gas, and property used for, with or incidental to their operation, but does not include a pipe or system or arrangement of pipes to distribute natural gas in a community to ultimate consumers;

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

(10) Despite subsections (9) and (9.1), the total amount of project deduction amounts that may be deducted from the amount of royalty or tax payable by a producer must not exceed 50% of the lesser of

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

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

[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.]

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.

Item 1
Column 1 Column 2
Old oil produced in a volume not exceeding 95 m3 during the month in respect of which royalty is calculated

(a) from an oil well event, or

(b) in accordance with the terms of a unitization agreement
(PRODUCTION)2x 100


(792 x PRODUCTION)
Item 2
Column 1 Column 2
Old oil produced in a volume exceeding 95 m3 during the month in respect of which royalty is calculated

(a) from an oil well event, or

(b) in accordance with the terms of a unitization agreement
(11.4 + 0.4 (PRODUCTION — 95)) x 100


PRODUCTION
Item 3
Column 1 Column 2
New oil produced in a volume not exceeding 159 m3 during the month in respect of which royalty is calculated

(a) from an oil well event, or

(b) in accordance with the terms of a unitization agreement
(PRODUCTION)2 x 100


(1058 x PRODUCTION)
Item 4
Column 1 Column 2
New oil produced in a volume exceeding 159 m3 during the month in respect of which royalty is calculated

(a) from an oil well event, or

(b) in accordance with the terms of a unitization agreement
(23.9 + 0.3 (PRODUCTION — 159))  x 100


PRODUCTION
Item 4.1
Column 1 Column 2
Third tier oil produced from an oil well event in a volume not exceeding 159 m3

during the month in respect of which royalty is calculated
PRICE FACTOR x PRODUCTION


26.45
Item 4.2
Column 1 Column 2
Third tier oil produced from an oil well event in a volume exceeding 159 m3

during the month in respect of which royalty is calculated
PRICE FACTOR x [956 + 12 (PRODUCTION — 159)]


PRODUCTION
Item 5
Column 1 Column 2
Freehold oil produced in a volume not exceeding 159 m3 during the month in respect of which royalty is calculated

(a) from an oil well event, or

(b) in accordance with the terms of a unitization agreement
0.06 x PRODUCTION
Item 6
Column 1 Column 2
Freehold oil produced in a volume exceeding 159 m3 during the month in respect of which royalty is calculated

(a) from an oil well event, or

(b) in accordance with the terms of a unitization agreement
1575 + 20 (PRODUCTION — 159)


PRODUCTION
Item 7
Column 1 Column 2
Heavy oil produced from an oil well event in a volume not exceeding 20 m3 during the month in respect of which royalty is calculated 0
Item 8
Column 1 Column 2
Heavy oil produced from an oil well event in a volume exceeding 20 m3

but not exceeding 200 m3 during the month in respect of which royalty is calculated
PRICE FACTOR x (PRODUCTION — 20)2


24 x PRODUCTION
Item 9
Column 1 Column 2
Heavy oil produced from an oil well event in a volume exceeding 200 m3

during the month in respect of which royalty is calculated
PRICE FACTOR x ((PRODUCTION — 200) x 11 + 1350)


PRODUCTION

(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.

Item 1
Column 1 Column 2
Discovery oil Exempt from payment for the first 36 producing months
Item 2
Column 1 Column 2
Oil produced from an oil well event that, in the opinion of the collector, was lost without fault on the part of the producer and for which the producer received no compensation Exempt from payment

(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 Oil and Gas 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.]

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

6  (1) Subject to subsections (1.1), (1.2), (1.4), (1.5) and (1.6), 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.

Item 1
Column 1 Column 2
Non-conservation gas that is

(a) produced from well events in a well having a spud date before June 1, 1998, or

(b) revenue sharing gas
750 + 25 (REFERENCE PRICE — 50)


REFERENCE PRICE
Item 1.1
Column 1 Column 2
Non-conservation gas, marginal gas and ultramarginal gas, other than revenue sharing gas, produced from well events

(a) for which the entire spacing area is

    (i) in a lease that was disposed of under section 71 of the Act after May 31, 1998, or

    (ii) in a lease that was issued from a permit or license that was disposed of under section 71 of the Act after May 31, 1998, and

(b) which have a completion date not more than 60 months after the disposition date of the lease in paragraph (a) (i) or the disposition date of the permit or license in paragraph (a) (ii), as the case may be
9 x SP + 40(RP — SP)


RP



where

RP = REFERENCE PRICE

SP = SELECT PRICE for

the calendar year in which

the month of production occurs
Item 1.2
Column 1 Column 2
Non-conservation gas, marginal gas and ultramarginal gas not described in Item 1 or 1.1 12 x SP + 40(RP — SP)


RP



where

RP = REFERENCE PRICE

SP = SELECT PRICE for

the calendar year in which

the month of production occurs
Item 2
Column 1 Column 2
Conservation gas 400 + 15 (REFERENCE PRICE — 50)


REFERENCE PRICE
Item 3
Column 1 Column 2
Freehold non-conservation gas 460 + 15 (REFERENCE PRICE — 50)


REFERENCE PRICE
Item 4
Column 1 Column 2
Freehold conservation gas 245 + 9 (REFERENCE PRICE — 50)


REFERENCE PRICE
Item 5
Column 1 Column 2
Natural gas liquids 20
Item 6
Column 1 Column 2
Freehold natural gas liquids 12.25
Item 7
Column 1 Column 2
Sulphur 16.667
Item 8
Column 1 Column 2
Freehold sulphur 10.25

(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 that is not a marginal well event or an ultramarginal well event and that is not part of a coalbed methane project, a reduction factor in accordance with the following formula:

  (5000 — S) 2
 
 
  5000  
where  
  S is equal to the lesser of the average daily natural gas production volume for the well event in the producing month and 5 000.

(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) 2
 
 
  17 000  
where
S is equal to the lesser of the average daily natural gas production volume for the well event in the producing month and 17 000;

(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) 2
 
 
  25 000  
where
S is equal to the lesser of the average daily natural gas production volume for the marginal well event in the producing month and 25 000;

(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) 1.5
 
 
  60 000  
where
S  is equal to the lesser of the average daily natural gas production volume for the ultramarginal well event in the producing month and 60 000.

(1.4) 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.

(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.

Item 1
Column 1 Column 2
Natural gas or natural gas by-products that, in the opinion of the collector, were lost without fault on the part of the producer and for which the producer received no compensation. Exempt from payment
Item 2
Column 1 Column 2
Natural gas or natural gas by-products used for oil and natural gas production, for drilling purposes or for injection into the formation from which they were produced. Exempt from payment
Item 3
Column 1 Column 2
Natural gas produced from a deep discovery well event that is in a well having a spud date after November 30, 2003. Exempt from payment for the first 36 producing months.

(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 rate and tax rate, or the exemption from royalty and tax payable, as specified in subsections (1) and (2) respectively, 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).]

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 sold 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 sold 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 of 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 section 7 (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:

PVEP    

x (TGNGRT — PCSA)
TPV    
where
PVEP means the production volume exempt from payment under Item 3 of section 6 (2) for the well event and producing month;
TPV  means the total production volume attributable to the well event in the producing month;
TGNGRT means the total gross natural gas royalty or tax determined for the well event and the producing month under paragraph (a);
PCSA  means the applicable producer cost of service allowance, and

(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:

(CV + AD) x PI
where
CV means the cumulative value that is shown in the specified table opposite the table depth of whichever of those deep well events is the deepest (the "deepest well event");
AD means the incremental value that is shown in the specified table opposite the table depth of the deepest well event multiplied by the positive difference between the deep well depth of that well event and the table depth of that well event;
PI  means the producer's interest in the deepest well event;
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;
Table 1
West Special Sour   East Special Sour
Depth

(metres)
Cumulative

Value $000
Incremental

Value

$/Metre
  Depth

(metres)
Cumulative

Value $000
Incremental

Value

$/Metre
2 500 0 4 200   2 500 0 1 500
3 000 2 100 600   3 000 750 650
3 500 2 400 700   3 500 1 075 750
4 000 2 750 800   4 000 1 450 850
4 500 3 150 900   4 500 1 875 1 000
5 000 3 600 1 000   5 000 2 375 1 100
5 500 4 100     5 500 2 925  
West Sweet   East Sweet
Depth

(metres)
Cumulative

Value $000
Incremental

Value

$/Metre
  Depth

(metres)
Cumulative

Value $000
Incremental

Value

$/Metre
2 500 0 3 800   2 500 0 1 400
3 000 1 900 550   3 000 700 600
3 500 2 175 600   3 500 1 000 700
4 000 2 475 700   4 000 1 350 800
4 500 2 825 800   4 500 1 750 900
5 000 3 225 900   5 000 2 200 1 000
5 500 3 675     5 500 2 700  
Table 2
West Special Sour   East Special Sour
Depth

(metres)
Cumulative

Value $000
Incremental

Value

$/Metre
  Depth

(metres)
Cumulative

Value $000
Incremental

Value

$/Metre
2 500 0 4 830   2 500 0 1 725
3 000 2 415 690   3 000 863 748
3 500 2 760 805   3 500 1 236 863
4 000 3 163 920   4 000 1 668 978
4 500 3 623 1035   4 500 2 156 1150
5 000 4 140 1 150   5 000 2 731 1 265
5 500 4 715     5 500 3 364  
West Sweet   East Sweet
Depth

(metres)
Cumulative

Value $000
Incremental

Value

$/Metre
  Depth

(metres)
Cumulative

Value $000
Incremental

Value

$/Metre
2 500 0 4 370   2 500 0 1 610
3 000 2 185 633   3 000 805 690
3 500 2 501 690   3 500 1 150 805
4 000 2 846 805   4 000 1 553 920
4 500 3 249 920   4 500 2 013 1 035
5 000 3 709 1 035   5 000 2 530 1 150
5 500 4 226     5 500 3 105  
Table 3
Depth

(metres)
Cumulative Value

$000
Incremental

Value $/Metre
2 500 445 430
3 000 660 720
3 500 1 020 980
4 000 1 510 1 006
4 500 2 013 974
5 000 2 500 622
5 500 2 811

(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:

(CV + AD) x PI
where
CV means the cumulative value that, in the portion of the following table applicable to the well under subsection (7.1), is shown opposite the table distance of the deep re-entry well event;
AD means the incremental value that, in the portion of the following table applicable to the well under subsection (7.1), is shown opposite the table distance of the deep re-entry well event multiplied by the positive difference between the incremental drilled distance applicable to that deep re-entry well event and the table distance of that well event;
PI  means the producer's interest in the deep re-entry well event;
table distance means the incremental drilled distance applicable to the deep re-entry well event rounded down to the next lowest table distance value,
incremental drilled distance means the positive difference between
    (a) the total measured depth of all deep well events and all deep re-entry well events in the well after the well has been altered in accordance with the amendment application, and
    (b) the total measured depth of all deep well events and all deep re-entry well events in the well before that amendment;
West   East
Depth

(metres)
Cumulative

Value $000
Incremental

Value

$/Metre
  Depth

(metres)
Cumulative

Value $000
Incremental

Value

$/Metre
100 0 750   100 0 450
300 150 500   300 90 300
1 500 750     1 500 450  

(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, 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.]

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:

A + B + C + D - E - F
where
A  means the balance, if any, in the coalbed methane producer cost of service bank for the coalbed methane project at the end of the immediately preceding producing month,
B means any amount added to the producer's coalbed methane producer cost of service bank for the coalbed methane project during the producing month under subsection (2),
C means the amount, if any, by which the aggregate of the producer's producer cost of service allowances for the producing month for all well events in the coalbed methane project exceeds the producer's total gross natural gas royalty or tax determined under section 7 (7) (a) for the producing month for those well events,
D means any amount added to the producer's coalbed methane producer cost of service bank for the coalbed methane project during the producing month under subsection (3) (b) of this section,
E means any amount deducted from the producer's coalbed methane producer cost of service bank for the coalbed methane project during the producing month under subsection (3) (a), and
F means the amount, if any, deducted from the producer's coalbed methane producer cost of service bank for that coalbed methane project under section 7 (5.1) during the producing month.

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

Reporting

8  (1) For the purposes of section 74 (1) of the Act, the following reports must be filed with the collector in the form and manner required by the director:

(a) every operator of a reporting facility must, on or before the 25th day of the calendar month following each producing month, file reports indicating the production and disposition in that producing month of oil, condensate, natural gas and water obtained at the reporting facility;

(b) every producer of oil must, on or before the last day of the calendar month following each producing month, file a report indicating, for each reporting facility or unitized operation at which the producer had oil sales 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, and

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

(c) every producer of natural gas must, on or before the last day of the second calendar month following each producing month, file a report indicating, for that producing month,

(i)   the producer's share of the volumes of marketable gas produced from each well event in which the producer has an interest,

(ii)   the producer's share of the sales volumes and values of natural gas by-products produced from each well event in which the producer has an interest, and

(iii)   the producer's share of the volume of natural gas produced from each well event in which the producer has an interest;

(d) every producer that, under section 4, makes a payment on account of oil, marketable gas or natural gas by-product royalties and taxes, must, on or before the last day of the calendar month in which the payment is made, file a report respecting that payment indicating the amounts paid

(i)   by producing month for petroleum, marketable gas and natural gas by-product royalty and taxes,

(ii)   by producing month for estimated marketable gas and natural gas by-product royalty and taxes, and

(iii)   for penalties and interest;

(e) every operator of a well event must, on or before the 20th day of the calendar month following the calendar month in which operations at the well event began or were suspended, file a report indicating the commencement or suspension of operations;

(f) every operator of a facility to which a well event is connected must, on or before the 20th day of the calendar month after the calendar month in which the well event is connected to the facility or in which a change in producers' interests in the well event is effective, file a report indicating the producers' interests or the change in producers' interests in the natural gas and oil produced from the well event;

(g) every 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 20th day of the second 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, file a report indicating the change in producers' interests in the tract;

(h) for the purpose of section 2 (8), every 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 15 of the calendar year following the calendar year in which the plant processed gas or the pipeline transported gas, file a report indicating the capital and operating costs of the plant or sales line;

(i) every person who processes natural gas produced in British Columbia must, on or before the 25th day of the calendar month following the calendar month in which the natural gas was processed, file for the month in which the natural gas was processed

(i)   a report indicating the volume of natural gas, expressed in 1 000 m3, delivered to a natural gas processing plant and the disposition of the marketable gas by producer and purchaser, and

(ii)   a report indicating the production volume of natural gas by-products processed at the natural gas processing plant and the volume of natural gas by-products disposed of by producer, destination and purchaser;

(j) every person who operates a pipeline that receives oil or condensate produced in British Columbia must, on or before the 25th day of the calendar month following the calendar month in which the oil or condensate was received, file a report that, for the month in which the oil or condensate was received, indicates

(i)   the volume received at each sales meter, and

(ii)   the volume received from each facility from which the oil or condensate was delivered;

(k) every person who operates a treating plant to recover clean oil or condensate must, on or before the 25th day of the calendar month following the calendar month in which oil, condensate or water is received, file a report that, for the month in which the oil, condensate and water is received, indicates the volumes of oil, condensate or water delivered to the treating plant and the reporting facility from which the product was delivered;

(l) every 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 calendar year following the calendar year in which the well was drilled, file a report 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 a report filed under subsection (1) by filing an amended report with the collector.

(2.1) A person must not file an amended report under subsection (2) more than 72 months after the month in relation to which the amended report is being filed.

(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 60 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) No later than the 10th working day of the second month following the month in which a producer produces marketable gas, the producer must, by submission to the administrator of copies of all invoices for the following, report to the administrator on 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.]

Examination of return and assessment of royalty or tax

9  (1) After receiving reports filed by a producer of oil under section 8 (1) (b) for a producing month, the collector is, on or about the 10th day of the second calendar month following the producing month, to deliver a Crown invoice to the producer showing for the producing month the amount of royalties and taxes that is payable to the government in respect of the oil to which those reports apply.

(1.1) After receiving reports filed by a producer of natural gas under section 8 (1) (c) for a producing month, the collector is, on or about the 10th day of the third calendar month following the producing month, to deliver a Crown invoice to the producer showing for the producing month the amount of royalties and taxes that is payable to the government in respect of the marketable gas and natural gas by-products to which those reports apply.

(1.2) After a producer files an amended report under section 8 (2) to amend a report filed under section 8 (1) (b) or 8 (1) (c), the collector is to deliver an amended Crown invoice to the producer, on or before the 10th day of the second calendar month following the calendar month in which the amended report was filed, showing for the producing month the amount of royalties and taxes that is payable to the government in respect of the marketable gas and natural gas by-products to which the amended report applies.

(2) If the collector, on examining a report filed under section 8 (1) or an amended report filed under section 8 (2), disagrees with the information or calculations in it, the collector may

(a) request the person who filed the report or amended report to submit, within 60 days after the date of the request, a report based on the information the collector believes is correct, or

(b) assess or reassess royalty or tax payable to the government based on the information 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 72 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 and interest payable and the due date for payment of that amount.

(5) On assessing or reassessing the royalty or tax payable by a producer who has not filed a report or has filed a report containing information with which the collector disagrees, the collector shall mail a notice of assessment to the producer.

(6) The producer assessed shall pay to the collector the amount of royalty or tax owing as set out in the notice of assessment within 60 days after the date shown on the notice of assessment.

(7) In the case of an overpayment, 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.

(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.]

Producer liability

10  (1) A producer'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.

Reconsideration by collector or administrator

11  (1) The collector may reconsider or vary an invoice or assessment of royalties, taxes or penalties made under section 9 on the request of a producer who objects in writing to the amount assessed.

(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.]

Appeals

12  (1) A producer may appeal a decision of the collector under section 3 (1) or 11 (1) or a decision of the administrator under section 11 (2) to the Minister of Finance by mailing by registered mail, within 60 days after the decision of the collector or administrator, a notice of appeal addressed to the Minister of Finance.

(2) The notice must state the name and address of the producer, the date of the collector's or administrator's decision, the class designated under section 3 (1) and the amount of royalty, tax, interest or penalty assessed under section 9, if any, and must set out the reasons for the appeal and the facts on which it is based.

(3) On receipt of the notice of appeal and all relevant information from the office of the collector or administrator, the Minister of Finance, with or without a hearing, must confirm, vary or reverse the decision of the collector or administrator.

(4) The Minister of Finance must convey the decision to the collector who must mail to the person who made the appeal notification of that minister's decision and must include, if applicable, notice of assessment reflecting that minister's decision.

[en. B.C. Reg. 302/2003, s.6 ; am. B.C. Reg. 4/2010, s. 2.]

Interest and penalties

13  (1) The annual rate of interest during a quarterly period for penalties, royalties 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 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) If, under subsection (2), interest is to be calculated on an amount, that interest must be calculated in accordance with the following formula:

  D
A x 1 x
 
  365.25  
where
A  means the amount on which interest is to be calculated;
I means the applicable interest rate under subsection (1) or (1.1);
D  means the number of days from and excluding the 25th day of the calendar month at the end of which A is owing to and including the 25th day of the following calendar month.

(2) Interest on overpayments and on unpaid royalties and taxes is to be calculated as follows:

(a) if, at the end of a calendar month, an amount is owing by a producer for one or both of royalty and taxes, interest is to be calculated on that unpaid amount in accordance with subsection (1.2);

(b) if the amount of an estimate payment made on or before the end of a calendar month under section 4 (1) is less than 90 percent of the royalty and tax that is invoiced to the producer for that calendar month under section 9 (1) or (1.1), interest on the difference between the payment and the invoice amount is to be calculated in accordance with subsection (1.2) of this section;

(c) if interest is payable under paragraph (a) or (b) on an amount (the "initial producer amount") and the whole or any part of the initial producer amount remains unpaid at the end of any calendar month following the calendar month in respect of which interest first became payable on the initial producer amount, interest is to be calculated on the unpaid portion of the initial producer amount in accordance with subsection (1.2);

(d) if royalties or taxes are overpaid by a producer in a calendar month and the overpayment is not reimbursed or credited on or before the end of that calendar month, interest on that overpayment is to be calculated in accordance with subsection (1.2);

(e) if the amount of an estimate payment made on or before the end of a calendar month under section 4 (1) is greater than 110 percent of the royalty and tax that is invoiced to the producer for that calendar month under section 9 (1) or (1.1), interest on the difference between the payment and the invoice amount is to be calculated in accordance with subsection (1.2) of this section;

(f) if interest is payable under paragraph (d) or (e) on an amount (the "initial amount") and the whole or any part of the initial amount is not paid or credited on or before the end of any calendar month following the calendar month in respect of which interest first became payable on the initial amount, interest is to be calculated on the unpaid portion of the initial amount in accordance with subsection (1.2).

(3) No charge shall be made if an interest charge is less than $5.

(4) If a person fails to file, within the required time, a report required under section 8 (1) (f) in relation to an interest in oil produced from a well event or a report required under section 8 (1) (a), (b), (c), (d), (e), (g) or (h) or (5) or 9 (2) (a), the person may be assessed a penalty of $20 for each day that the failure to file continues, or for any lesser number of days that the collector considers appropriate, up to a maximum amount payable under this subsection of $6 000 for each report.

(5) If a person fails to file, within the required time, a report required under section 8 (1) (f) in relation to an interest in natural gas produced from a well event or a report required under section 8 (1) (i), (j) or (k), the person may be assessed a penalty of $100 for each calendar month or part of a calendar month that the failure continues, or for any lesser number of months that the collector considers appropriate, up to a maximum amount payable under this subsection of $6 000 for each report.

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

Schedule A

Plats dated December 31, 1976, describing areas in the Peace River District.

NOTE: The plats in Schedule A are exempt from publication and may be inspected at the offices

of the Director of Mineral, Oil and Gas Revenue Branch, Ministry of Provincial Revenue, Victoria, B.C.

Note: this regulation replaces B.C. Reg. 222/88.

[Provisions of the Petroleum and Natural Gas Act, R.S.B.C. 1996, c. 361, relevant to the enactment of this regulation: section 73 (2)]