Senate Bill 21, which was recently signed into law, significantly alters Alaska's Oil and Gas Production Tax regime. Although discussions regarding this law have largely been focused on North Slope activity, other areas of the state are also affected.
To understand the relevance of the amendments, it is useful to have a basic understanding of the major components of the production tax regime. The tax is levied on the net profits of oil and gas production from leases or properties in the state, except for the federal and state royalty share and oil and gas used in drilling or production operations. At a high level, the calculation starts with destination value, generally the higher of the sales price or a calculated prevailing value of the oil. The costs of pipeline and marine transportation are subtracted from the destination value to obtain the gross value at the point of production (GVPP). Upstream operating and capital costs (termed lease expenditures) are subtracted from the gross value at the point of production to reach net profit per Btu equivalent barrel of oil and gas, known as production tax value. The calculation can be shown as follows:
Production Tax Liability = [(GVPP – Lease Expenditures) * Tax Rate] – Credits
Before January 1, 2014, the tax that is levied on net profit per Btu equivalent barrel of oil and gas is the sum of (1) a base tax rate of 25% and (2) a progressive surcharge that is calculated on a monthly basis and starts at 0.4% for every $1 by which net profit per barrel exceeds $30, up to $92.50. For net profits over $92.50, the progressive surcharge equals the sum of 25% (0.4% times $62.50) plus 0.1% per every additional $1 of profit per barrel, up to a maximum progressive surcharge of 50%. Thus, the maximum total nominal tax rate is 75%.
The production tax regime includes a minimum tax for oil and gas produced on the North Slope, and producers are subject to the higher of the rates discussed above or the minimum tax. The minimum tax is 4% of the GVPP when the average calendar year ANS West Coast sales price per barrel is more than $25. The tax is 3% of the GVPP when prices are $20-25/bbl, 2% when prices are $17.50-20/bbl, 1% when prices are $15-17.50/bbl and zero when prices are $15/bbl or less. Note that with one exception, discussed below, production tax credits may be applied to reduce the minimum tax.
The production tax regime has several tax credits that were designed to encourage oil and gas exploration and investment. Of particular relevance to the new law are the 20% credit for qualified capital expenditures and a credit for 25% of carried-forward annual losses, defined as upstream capital and operating expenditures that the explorer or producer was unable to deduct against revenues in the previous calendar year. Companies can transfer the credits, or, if a company produces an average of not more than 50,000 barrels per day and has no tax liability, it can apply to the State of Alaska for a cash purchase of 100% of the value of the credit.
Commencing January 1, 2014, the tax rate will be 35% with no progressive surcharge. The minimum tax on North Slope production remains the same. Favorable production tax ceiling rates for Cook Inlet production and gas produced and used in Alaska are unchanged and sunset in 2022. Likewise, the tax rate of 4% of GVPP is still in place for production outside of the North Slope and Cook Inlet for seven years following commencement of commercial production, although the sunset date was extended to include commercial production that begins before 2027, rather than before 2022.
The 20% credit for qualified capital expenditures incurred for North Slope operations will only be available for expenditures incurred before January 1, 2014. The 25% carried-forward annual loss credit will be increased to 45% for expenditures incurred for North Slope operations after January 1, 2014 and before January 1, 2016. For expenditures incurred after January 1, 2016 for North Slope operations, the carried-forward annual loss credit will be for 35% of the loss. The new law does not change these credits for expenditures incurred for activity in other areas of the state.
Also commencing January 1, 2014, the GVPP will be reduced by 20% for certain North Slope oil or gas production. To qualify for the 20% reduction (known as a "gross revenue exclusion"), one or more of the following criteria must be met:
the oil or gas is produced from a lease or property that does not include a lease that was in a unit on January 1, 2003;
the oil or gas is produced from a participating area established after December 31, 2011 that is within a unit formed before January 1, 2003; or
the oil or gas is produced from acreage that was added to a participating area on or after January 1, 2014, if the producer demonstrates to the Department of Revenue that the volume produced is from acreage added to an existing participating area.
In addition to the reduction discussed in the preceding paragraph, commencing January 1, 2014 the GVPP for oil or gas produced from a lease or property that does not include a lease that was in a unit on January 1, 2003, is reduced by 10% if the production is from a unit composed entirely of leases with a royalty rate of more than 12.5%. This reduction is not available if the royalty obligation for any lease in the unit has been reduced to 12.5% or less through a grant of royalty modification by the Department of Natural Resources, nor does it apply to gas produced before 2022 that is used in the state.
A producer may also apply a $5/bbl tax credit against the producer's tax liability for oil produced after December 31, 2013 that meets one or more of the criteria discussed in the preceding two paragraphs. For North Slope oil production that does not meet any of the criteria discussed in the preceding two paragraphs, a producer may apply a credit against the producer's tax liability for oil produced after December 31, 2013, although this credit may not be applied to reduce the North Slope minimum tax. The amount of the credit depends on the average GVPP each month. The maximum credit is $8/bbl of taxable oil if the average GVPP for the month is less than $80/bbl. If the average GVPP for the month is greater than $80/bbl, but less than $90/bbl, the credit is $7/bbl. The amount of credit per barrel continues to be reduced by $1 for each $10 incremental increase in the average GVPP, and is zero if the average GVPP for the month is $150/bbl or higher.
It is worth noting that apart from the changes discussed above, the oil and gas production tax regime is largely unchanged. Accordingly, companies that drill exploration wells and conduct seismic exploration and that qualify for the alternative credit for exploration may receive 30% or 40% credits for exploration wells and 40% credits for seismic exploration. The same expenditures may qualify for the carried-forward annual loss credit. Thus, explorers may qualify for up to 85% in credits for expenditures incurred for North Slope exploration in 2014 and 2015 (the carried-forward annual loss credit includes an overhead allowance, so actual cost recovery is 87%). Likewise, companies engaged in drilling and seismic exploration in areas other than the North Slope can obtain 40% credits for certain "well lease expenditures" in addition to the carried-forward annual loss credit for the same expenditures, yielding a cost recovery of 65% (actually 66% due to the overhead allowance). There are also incentives for drilling exploration wells and conducting seismic exploration outside of the North Slope and Cook Inlet, including credits for the lesser of $25 million or 80% of expenditures for wells and the lesser of $7.5 million or 75% of the costs of seismic exploration. Companies can transfer the credits, or, if a company produces an average of not more than 50,000 barrels per day and has no tax liability, it can apply to the State of Alaska for a cash purchase of 100% of the value of the credit.
The new law, which can be found here, also includes a state corporate income tax credit for qualified oil and gas service industry expenditures incurred in the state. The credit may not exceed the lesser of 10% of qualified expenditures or $10 million.