*Since 2002, the government has introduced royalty rates for marginal and ultra-marginal natural gas, royalty credits for deep gas exploration, summer drilling and infrastructure development.
For detailed information on how to calculate royalties, please refer to the Oil and Gas Royalty Handbook at http://www.sbr.gov.bc.ca/business/Natural_Resources/Oil_and_gas_royalties/handbook.htm. In addition, you can send your questions on royalty to: oilandgasroyaltyquestions@gov.bc.ca.
Base 15 Gas
Non-conservation gas produced from wells that were spudded before June 1, 1998.
Base 12 Gas
Non-conservation gas from wells spudded after May 31, 1998, unless they meet the criteria for Base 9. The land cannot be freehold land.
Base 9 Gas
Non-conservation gas from wells spudded after May 31, 1998 on lands for which the oil and gas rights were issued after May 31, 1998 and which are completed within 5 years of the date rights are issued. The land cannot be freehold land.
Producer Price
A price determined monthly for each producer at each processing plant. The producer price is based on an average of each producer’s sales, less than producer’s actual costs of gathering, processing and transporting the gas.
Posted Minimum Price
A price set each month by the Crown which is the lowest price acceptable for the determination of natural gas royalties.
Reference Price
The greater of the Producer Price or the Posted Minimum Price.
Select Price
A parameter used in the royalty rate formula. At a reference price lower than the select price the royalty rates are fixed, while at higher prices, the royalty rates rise as prices rise. The select price in 1998 was $50/103m3.
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The key feature of the natural gas royalty regime in British Columbia is that it is a price-sensitive regime. That is, when the Reference Price is below the Select Price, the royalty rate is fixed, while at prices above the Select Price, the rate increases as prices increase.
There are two broad classifications of natural gas used for royalty purposes: “conservation gas” and “non-conservation gas.” Conservation gas is roughly defined as gas that is produced in association with oil, and is conserved and marketed, rather than flared into the atmosphere. In order to compensate royalty payers for the forced conservation of this often high unit cost gas, a lower base royalty rate of 8% is applied.
Non-conservation gas is comprised of all gas not classified as conservation gas (including gas produced in association with oil which is part of a concurrent production scheme) and makes up the vast majority of natural gas production in British Columbia. Within the category of non-conservation gas, there are three royalty categories that are dependent on the date on which the title was acquired from the Crown and on the date on which the well was drilled.
The formula used to calculate the royalty rates for natural gas are as follows:
All Conservation Gas: R% = 400 + 15 (P-50) but not less than 8%
P
Non-Conservation Gas:
Base 15 Gas: R% = 750 + 25 (P-50) but not less than 15%
P
Base 12 Gas: R% = 12*SP + 40 (P-SP)
P
But not less than 12% and not greater than 27%.
Base 9 Gas: R% = 9*SP + 40 (P-SP)
P
But not less than 9% and not greater than 27%.
Where “R%” is the royalty rate, “P” is the Reference Price and “SP” is the Select Price.
These rates are depicted in the chart below.
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Natural gas prices for royalty purposes (Producer Prices) are determined by the Ministry of Energy and Mines by averaging the actual selling prices for gas sales with certain common characteristics for each company and deducting applicable costs. The result is a netback price, generally determined at the plant inlet, which is unique for each producer/plant/month combination. If this price falls below a minimum price known as the Posted Minimum Price (PMP), then the PMP becomes the price of the gas for royalty purposes (the Reference Price). There are currently 5 PMPs calculated each month. Production behind each processing plant is subject to one of these.
There are three marketable natural gas by-products associated with natural gas production: Liquefied Petroleum Gas (LPG), Condensate, and Sulphur. LPG and Condensate have a fixed royalty rate of 20% while sulphur is 16.667%. These rates are not price sensitive, nor does the PMP apply to their values.
The Crown’s volumetric share of each product is determined by multiplying the applicable royalty rate by the total volume of the product. The Crown share is then valued at the appropriate price (for gas this is the Reference Price) to determine the Gross Crown Royalty. This is typically a value determined at the inlet to a processing plant.
When natural gas is extracted from the ground it is rarely in a useable form: it typically contains impurities that must be removed. This removal process is known as processing the gas and is performed at one of several gas processing plants in the province. The gas must also be transported to these facilities through a network of pipelines that are typically owned by the producer. Since the Crown share of the gas is also gathered in these systems, allowances are made for the costs incurred by the producers for these facilities.
These allowances are known as Producer Cost of Service (PCOS) and Gas Cost Allowances (GCA). PCOS covers the cost of gathering, dehydration, and compression of the Crown share of gas, while GCA covers the cost of processing the Crown Share of gas into a marketable form. GCA is only deductible for those producers whose gas is processed at a plant owned by a producer (as opposed to a custom processing plant) since the prices determined by the ministry for all other gas is net of the tolls charged by third parties for this service. These allowances are deducted from the gross royalty to a maximum of 95 percent of the gross royalty.
This process results in a monthly remittance to the Crown by producers for the value of the raw gas at the well of the volumetric share that the Crown feels represents the economic rent of the resources.
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A low productivity well may have its royalty rate reduced by a low productivity well adjustment factor that is determined by the following formula:
((5000-S)/5000)^2
Where
S is equal to the average daily natural gas production volume for the low productivity well in the producing month.
