Petroleum and Natural Gas Act

PETROLEUM AND NATURAL GAS ROYALTY AND
 FREEHOLD PRODUCTION TAX REGULATION

[includes amendments up to B.C. Reg. 191/2005, August 1, 2005]

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;

"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;

"alteration application" means an Application to Alter a Well, referred to in section 42 of the Drilling and Production Regulation, that has been approved as required by that regulation;

"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) approved as a scheme under section 100 (1) (a) or (b) of the Petroleum and Natural Gas Act, and

(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 well" means a completed well as defined in section 1 of B.C. Reg. 336/91, the Drilling and Production Regulation;

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

"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;

"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;

"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;

"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 pay the top of which has a true vertical depth deeper than 4 000 metres,

(c) has a rig release date after November 30, 2003 and before July 1, 2008, and

(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;

"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, and

(b) has a pay the top of which has a true vertical depth deeper than 2 300 metres;

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

(a) for a vertical well, the measured depth to top of pay, and

(b) for a horizontal well, the sum of

(i) the measured depth to top of pay, 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 top of pay;

"deep well event" means a well event referred to in subsection (5);

"discovery oil" means oil discovered in a new pool discovery well completed after June 30, 1974;

"discovery well" means a discovery well as defined in 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 Crown;

"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 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 all completions in a zone for a well with a primary product of natural gas;

"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 of the well;

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

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

(a) for a gas well event with a measured depth to top of pay between 2 300 metres and 2 875 metres, it means the amount determined by the following formula:

[30 - 0.035 x (measured depth to top of pay - 2300) / 100]

(b) for a gas well event with a measured depth to top of pay deeper than 2 875 metres, it means 0.10;

"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:

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;

"low productivity well" means a low productivity well within the meaning of subsection (2);

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

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

"marginal well depth" means,

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

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

"natural gas processing plant" means a plant for the extraction from natural gas of marketable gas and natural gas by-products but does not include production facilities as defined in the Drilling and Production Regulation;

"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;

"new oil" means

(a) oil, other than heavy oil or third tier oil, 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 other than incremental oil that qualifies as third tier oil under paragraph (b) of the definition of "third tier oil",

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

(d) oil 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 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;

"old oil" means oil 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 natural gas processing plant or a specified group of natural gas processing plants, for marketable gas that becomes available for disposition during that month from that plant or group of plants;

"price factor" means the following:

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

(b) for third tier oil, the lesser of

(i) the factor that is determined by the formula

, and

(ii) a factor of 2;

"producer" means

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

(i) the holder of the location, or

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

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

"producer cost of service allowance", in relation to a reporting entity and a producing month, means,

(a) in the case of well events that are 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 reporting entity and the producing month,
B	means the producer cost of service rate in relation to the reporting entity for the producing month, and
C	means the producer cost of service natural gas volume in relation to the reporting entity in the producing month, or

(b) in the case of well events that are not part of a coalbed methane project, the lesser of

(i) the amount determined using the formula in paragraph (a), and

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

"producer cost of service natural gas volume" means, in relation to a reporting entity in a producing month, the amount determined by the following formula:

field sale volume + delivered natural gas – returned gas volume

where

"field sale volume" means the reporting entity's share of natural gas that, before being processed at a natural gas processing plant, is sold in the field in that producing month;

"delivered natural gas" means the reporting entity's share of natural gas delivered, in that producing month, to the following:

(a) to a natural gas processing plant;

(b) directly to market;

"returned gas volume" means the reporting entity's share of marketable gas that has, in that producing month, been

(a) processed at a natural gas processing plant, and

(b) returned to the field for use in the production of petroleum and natural gas;

"producer cost of service rate", in relation to a producer's reporting entity, means a rate, expressed as an amount per 1 000 m³, established by the administrator under section 2 (8.1), to cover the producer's cost, in relation to the reporting entity, 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,

if the producer undertakes such operations with respect to that producer's own natural gas produced and sold or delivered to a storage facility;

"producer price" means a price of natural gas determined by the administrator each month for each producer at each natural gas processing plant 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;

"reactivated well event" means any well event that

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

(b) 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 alteration 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 entity" means a reporting entity within the meaning of subsection (3);

"reporting entity's share" means, in relation to a producer's reporting entity, the volume of oil, marketable gas or natural gas by-products that is

(a) produced from the reporting entity's wells, and

(b) attributable to the producer in accordance with the producer's interests in the reporting entity's wells;

"reporting entity's well" means, in relation to a producer's reporting entity, any well event or tract if the interest held by the producer in that well event or tract is designated as or is assigned to the reporting entity;

"reporting facility" means a facility as defined in B.C. Reg. 362/98, the Drilling and Production Regulation;

"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 gas the royalties from which are to be shared under the terms of the revenue sharing agreement applicable to that gas;

"revenue sharing oil" means oil 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 reporting entity's wells, the reporting entity'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 reporting entity, and

(c) in the case of a class of natural gas by-products produced in a producing month from a reporting entity's wells, the reporting entity'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;

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

where

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

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

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

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

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

"tax share" means,

(a) in the case of a class of freehold oil, the volume of freehold oil of that class that is determined by multiplying the production volume 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 reporting entity's wells, the reporting entity'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 reporting entity, and

(c) in the case of a class of freehold natural gas by-products produced in a producing month from a reporting entity's wells, the reporting entity'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) 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;

"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;

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

"weighted average royalty or tax rate" means, in relation to a reporting entity and producing month, the total gross natural gas royalty or tax determined for the reporting entity for the producing month under section 7 (7) (a) divided by the sum of

(a) the reporting entity's share of marketable gas multiplied by the reference price for the marketable gas,

(b) the reporting entity's share of natural gas liquids multiplied by the reference price for the natural gas liquids, and

(c) the reporting entity's share of sulphur multiplied by the reference price for the sulphur;

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

"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.

(2) A well event is, in a producing month, a low productivity well if,

(a) in the case of a well event that is part of a coalbed methane project, the well event produces, in the producing month, an average daily natural gas production volume of less than 17 000 m³, or

(b) in the case of any other well event, the well event produces, in the producing month, an average daily natural gas production volume of less than 5 000 m³.

(3) A producer that has an interest in one or more well events or tracts may designate one of those interests as a reporting entity or may group 2 or more of those interests into a grouping, and each such designation or grouping, if approved by the collector, constitutes a reporting entity.

(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		x 24
	TPH
MWD

where

TP		means the total production from the well event in the period of 12 consecutive calendar months that begins with the calendar month in which marketable gas is first produced from the well event or is first produced from the reactivated well event since its reactivation,
TPH		means the total number of hours during which the well event produced natural gas in that 12 calendar month period, and
MWD		means the marginal well depth of the well event,

(c) the 12 calendar month period referred to in paragraph (b) ends after June 30, 2004 and before July 1, 2009, and

(d) the well event is in a well that has a spud date after May 31, 1998.

(5) 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 pay the top of which has a true vertical depth deeper than 2 300 metres,

(c) the well event, if in a vertical well, has a pay the top of which has a true vertical depth deeper than 2 500 metres, and

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

[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.]

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, and

(b) include as members of any group of natural gas processing plants designated under paragraph (a) any one or more natural gas processing plants.

(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.

[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.]

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 Crown’s intention to take the royalty share or the tax share, and

(b) of the Crown’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. Reg. 302/2003, s. 2.]

Royalty and tax payment

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

(a) oil produced 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 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 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.]

(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) if

(a) the producer has one or more interests in a well, and

(b) the well has a spud date after June 30, 2003 and before December 1, 2003, after March 31, 2004 and before December 1, 2004 or after March 31, 2005 and before December 1, 2005.

(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 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.

(10) Despite subsection (9), 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 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.]

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

Item 2

Item 3

Item 4

Item 4.1

Item 4.2

Item 5

Item 6

Item 7

Item 8

Item 9

(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

Item 2

(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 meters of oil.

(5) If a new pool discovery well is converted into an injection well as part of a pressure maintenance scheme 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.]

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

6 (1) Subject to subsections (1.1) and (1.2), 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

Item 1.1

Item 1.2

Item 2

Item 3

Item 4

Item 5

Item 6

Item 7

Item 8

(1.1) The royalty percentage rate that is, under subsection (1), applicable to a class of marketable gas produced in a producing month from those of a reporting entity's wells that are, in that producing month, low productivity wells or marginal well events may be reduced by the sum of the low productivity reduction factors determined in relation to those low productivity wells under subsection (1.2), (1.3) or (1.4) 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 those low productivity wells.

(1.2) There may be determined, for each of a reporting entity's wells that is, in a producing month, a low productivity well that is not, in that producing month, a marginal well event and that is not part of a coalbed methane project, a low productivity reduction factor in accordance with the following formula:

		(5000 – S)		2
P x
		5000

where

P	is equal to the volume of natural gas produced in the producing month from the low productivity well divided by the sum of the volumes of natural gas produced in the producing month from all of the reporting entity’s wells that are low productivity wells and that produce the same class of marketable gas;
S	is equal to the average daily natural gas production volume for the low productivity well in the producing month.

(1.3) There may be determined, for each of a reporting entity's wells that is, in a producing month, a low productivity well and that is part of a coalbed methane project, a low productivity reduction factor in accordance with the following formula:

P x ((17 000 - S) / 17 000)²

where
P	is equal to the volume of natural gas produced in the producing month from the low productivity well divided by the sum of the volumes of natural gas produced in the producing month from all of the reporting entity’s wells that (a) are part of the coalbed methane project, (b) are low productivity wells, and (c) produce the same class of marketable gas;
S	is equal to the average daily natural gas production volume for the low productivity well in the producing month.

(1.4) There may be determined, for each of a reporting entity’s wells that is, in a producing month, a marginal well event and that is not part of a coalbed methane project, a low productivity reduction factor in accordance with the following formula:

		(25000 – S)		2
P x
		25000

 where

P	is equal to the volume of natural gas produced in the producing month from the marginal well event divided by the sum of the volumes of natural gas produced in the producing month from all of the reporting entity's wells that are marginal well events, and
S	is equal to the average daily natural gas production volume for the marginal well event in the producing month.

(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

Item 2

Item 3

(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 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.]

Royalty and tax calculations

7 (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), and

(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 Crown 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 Crown 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 Crown for natural gas in relation to a reporting entity 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 subsection (8), if the royalty or tax is payable in relation to deep well events that are located in a well that has a spud date after November 30, 2003 and before July 1, 2008, the lesser of

(i) that 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 the total gross natural gas royalty or tax determined under subsection (7) (a) to zero, and

(ii) the positive 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 subparagraph (i) of this paragraph, and

(d) subject to subsection (9), if the reporting entity consists of nothing more than interests in one or both of deep well events and deep re-entry well events in a single well and if the re-entry date is after November 30, 2003 and before July 1, 2008 , 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 the total gross natural gas royalty or tax determined under subsection (7) (a) to zero, and

(ii) the positive 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 subparagraph (i) of this paragraph.

(5.1) For a reporting entity, in relation to a coalbed methane project, the amount of royalty or tax payable to the Crown for natural gas in relation to a producing month is the amount determined for that producing month under subsection (5) 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 the royalty or tax payable to the Crown under this subsection to nil.

(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 reporting entity 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 reporting entity 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 reporting entity 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 reporting entity in the producing month multiplied by the reference price for the sulphur,

(b) the royalty or tax exempt value in relation to a reporting entity 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 reporting entity and producing month;
TPV	means the total production volume attributable to the reporting entity's wells in the producing month;
TGNGRT	means the total gross natural gas royalty or tax determined for the reporting entity 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 each reporting entity that consists of nothing more than 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 PS

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 depth of whichever of those deep well events is the deepest (the "deepest 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 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;
PS	means the reporting entity’s proportionate interest in the deepest well event;

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

and

(d) the deep re-entry deduction amount means, for each reporting entity that includes an interest in a deep re-entry well event, the amount determined by the following formula:

(CV + AD) x PS

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;
PS	means the reporting entity’s proportionate 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 alteration application, and

(b) the total measured depth of all deep well events and all deep re-entry well events in the well before that alteration.

(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 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,

(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 an 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).

[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.]

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 and that has a completion date prior to July 1, 2008, 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 every producer cost of service allowance for the producing month for all reporting entities in relation to the coalbed methane project exceeds the aggregate of every total gross natural gas royalty or tax determined under section 7 (7) (a) for the producing month for those reporting entities,
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.]

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 is, on or before the last day of the calendar month following each producing month, to 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, the following for each of the producer’s reporting entities:

(i) the volumes of marketable gas made available for sale;

(ii) the volumes and values of natural gas by-products sold;

(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 reporting entity and 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, file a report indicating the producers’ interest in the well event;

(g) every producer who has acquired an interest in a well event or tract must, on or before the 20th day of the second calendar month after the calendar month in which the closing date of the sales agreement occurs, file a report indicating the producer’s interest in the well event or tract;

(h) for the purpose of section 2 (8), every operator of a producer-owned plant or a producer-owned sales line 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 production 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) A producer may amend a report filed under subsection (1) (a) by filing an amendment with the collector only if the amended month is not more than 72 months before the filing of the amendment.

(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 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 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.]

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 Crown 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 Crown in respect of the marketable gas and natural gas by-products to which those reports apply.

(2) If the collector, on examining a report or amended report, disagrees with the information or calculations in it, the collector may

(a) request the producer 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 Crown 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 date of the receipt of the report on which the assessment or reassessment is based.

(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 producer 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.]

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 Provincial Revenue 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 Provincial Revenue.

(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 Provincial Revenue, with or without a hearing, must confirm, vary or reverse the decision of the collector or administrator.

(4) The Minister of Provincial Revenue 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.]

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 365.25
A x 1 x

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);

(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);

(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 producer fails to file a report referred to in section 8 (1) (a), (b), (c), (d), (e), (f), (g) or (h) or (5) or 9 (2) (a) within the required time, the producer may be assessed a penalty of $20 for each day that the failure to file continues, up to a maximum amount payable under this subsection of $6 000 for each report.

(5) If a producer fails to file a report referred to in section 8 (1) (i), (j) or (k) within the required time, the producer may be assessed a penalty of $100 for each calendar month or part of a calendar month that the failure continues, up to a maximum amount payable under this subsection of $6 000.

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

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)]

Copyright © 2005: Queen's Printer, Victoria, British Columbia, Canada