Financial Incentive Programs

  • The State of Alaska in its role as a sovereign taxing authority through the Department of Revenue (DOR) and as a landowner, through the Department of Natural Resources (DNR) offer a number of incentives to encourage exploration and development of Alaska's oil and gas resources. The incentives provided via the State's production tax, administered by DOR, are outlined first, followed by the incentives related to the State's ownership of oil and gas lands and its royalty interest on the oil and gas produced from those lands, administered by DNR.

  • Related Information and Documents

    Geophysical and Seismic Data Available for Distribution

    Cook Inlet

    North Slope

    Geological and Well Data Available for Distribution

    To arrange for data distribution contact Kurt Johnson (kurt.johnson@alaska.gov) or Jean Riordan (jean.riordan@alaska.gov) at the Geologic Materials Center, at 907-696-0079.

  • Production Tax Incentives

    The production tax terms and incentives vary across Alaska's geographical regions where taxable oil and gas activity occurs. Broadly speaking, the tax differs between the North Slope (north of 68 degrees north latitude), the Cook Inlet, and all other regions of the state ("Middle Earth"). Some incentives offset the calculation of the tax itself, like the Gross Value Reduction (GVR) (see below) and tax ceilings. There are also non-transferable credits, like the small producer credit, or the per barrel credit, that can only be used to offset a taxpayer's tax liability in the production year. Finally, there are credits that are transferable in that they can be carried forward to offset future tax liability, sold to another taxpayer, or, to the extent State funding is appropriated, redeemed for cash from the State. The State can allow a credit redemption to be assigned to a creditor to allow financing of an oil and gas project. See AS 43.55.029. Below, a brief description of the tax for each of the State's three geographical areas is followed by a discussion of credits available.

    North Slope

    Under AS 43.55, the State assesses a production tax equal to 35% of a measure of net cash flow from oil and gas production on the slope. In determining net cash flow, the taxpayer starts with a destination value, nets back to the lease or property by deducting reasonable, actual transportation costs, and then, from this gross value, deducts field operating and capital expenditures ("lease expenditures"). In determining net cash flow, for GVR-eligible production on the North Slope, 20 percent of the gross revenue is excluded. The GVR, codified in AS 43.55.165(f), applies to revenue generated from production from either new units (post 2003), new participating areas (post 2011), or expansions of current participating areas (post 2013). The GVR percentage can be increased to 30% if the post 2003 unit is entirely comprised of leases with a royalty rate over 12.5%.

    There are some limitations or exceptions to this net tax. For gas sold for use in-state, the tax is simply 17.7 cents per thousand cubic feet (mcf). This special tax treatment for gas used in-state sunsets in 2022.

    For gas committed to a major gas sale from a lease modified under AS 38.05.180(hh), the tax in kind payment is 13 percent. Finally, the net tax cannot fall below a minimum tax of 4% of the gross value on the North Slope, excluding gas sold for use in-state.

    The State also provides for a non-transferable per-barrel credit. For each barrel of taxable oil that is GVR eligible (per AS 43.55.165(f)) there is a $5 credit. For oil production that is not GVR eligible, a sliding scale per oil barrel credit is available. The non-GVR, per barrel credit is $8 at less than $80) oil netback values, and ratchets down by a dollar for every $10 increase in netback value per barrel until the credit goes to zero. These per barrel oil credits are non-transferable and can only be used to reduce current year tax liability. For non-GVR eligible production the per-barrel credit cannot be used to reduce the tax below the minimum tax of 4%.

    In addition, producers who produce a small volume in Alaska receive a tax credit per AS 43.55.024(c), the Small Producer Credit. This credit amount is $12 million per calendar year for producers with production less than 50,000 barrels of oil equivalent (BOED). The credit amount declines on a straight line sliding scale to zero credit for production greater than 100,000 BOED. The Small Producer Credit continues for nine calendar years after first production or 2016, whichever is later. To receive the credit first production must occur before May 1 2016. This credit is also non-transferable and can only be used to reduce tax liability in the year the credit accrues.

    In addition to these non-transferable credits, there are credits that are transferable and, for small-volume producers, could be reimbursable by the State if the State appropriates funds to do so. For the North Slope, the main transferable credit available is the "net operating loss" or "Carried-forward annual loss" credit. (NOL credit).

    Under AS 43.55.023(b) a credit is available for an annual loss (a lease expenditure that is not offset by income). This NOL credit can be applied for in the year following the loss. For two years (2015 and 2016 credit year, 2014 and 2015 loss year) the NOL credit percentage is 45 percent. Thereafter it is 35 percent. This NOL credit can be used to offset tax liability in the credit year, carried forward to offset tax liability in a future year, sold to another taxpayer, or, if a small volume producer in Alaska (less than 50,000 BOED) and the State appropriates funding, sold back to the State.

    Another transferable credit is the Alternative Tax Credit for Oil and Gas Exploration under AS 43.55.025. This credit is for expenditures on remote exploration wells and for seismic performed outside of units. This exploration tax credit program expires on July 1, 2016.

    The Alternative Exploration Credit for exploration wells is 30 percent if the bottom-hole location of the exploratory well is at least 25 miles from the boundary of any unit, or if the bottom-hole location the exploration well is more than three miles away from a preexisting well. A preexisting well is a well that has been spud more than a year-and-a-half (540 days) before the spud date of the exploratory well. If a preapproved exploratory well satisfies both the 3-mile and the 25-mile criteria, it receives a 40 percent credit for exploratory expenses. The program also offers seismic exploration tax credits of 40 percent of eligible costs for those portions of activities outside of a unit. Notification and data submittal requirements are detailed below.

    Even if an explorer receives a credit under AS 43.55.025, the exploratory expenses that were the basis for this credit are still deductible as a lease expenditure when calculating production tax liability under AS 43.55.011(e), and can be the basis of a NOL credit under AS 43.55.023(b) if the explorer lacks production income against which to deduct the exploration expenses.

    To receive the Alternative Tax Credit for an exploration well, an explorer must receive a finding before drilling the well from the DNR that the well qualifies for the tax credit per AS 43.55.025(c). A similar finding is not required for seismic.

    Also, as specified in 43.55.025(f)(2). the explorer must agree to notify DNR within 30 days of project completion or filing of a claim for credit, whichever is the latest, of the date of project completion and submit a report describing the processing sequence and a list of data sets available. Well data requested by and submitted to DNR will be made publicly available after expiration of the well's 24-month confidentiality period, followed by 30 days public notice. Seismic or other geophysical data will be made publicly available after 10 years followed by 30 days public notice. Well data include all analyses conducted on physical material and well logs collected from the well, results and copies of data collected and data analyses for the well, including well logs; sample analyses; testing geophysical and velocity data including seismic profiles and check shot surveys; testing data and analyses; age data; geochemical analyses; and tangible material. Seismic or other geophysical data sets include the data for an entire survey, irrespective of whether the survey area covers non-state land in addition to state land or land in a unit in addition to land outside a unit. Geophysical data include navigation/location data, field data, final output volumes, a report addressing acquisition and processing with processing flow and list of final products, and in the case of seismic data, final gathers and final stacking and migration velocities.

    Please contact Heather Ann Heusser at (907) 269-0137 for further information about the data submittal requirements for the Alternative Tax Credit.

    Cook Inlet

    The production tax on gas production is limited to 17.7 cents per mcf, while there is no production tax payable on oil production. Coupled with the low tax exposure, there are a few transferable, refundable credits available. Capital expenditures generate a tax credit of 20 percent under AS 43.55.023(a), the Qualified Capital Expenditure Credit (QCE credit), or, if the expenditures are for intangible well costs, the well lease expenditure credit (WLE credit) of 40 percent under AS 43.55.023(m). A QCE and WLE cannot be taken for the same expenditure. In place of the WLE credit or the QCE credit, a producer could apply for the 25% qualified capital expenditure credit under AS 43.20.043 or for the Alternative Tax Credit for an exploratory well expenditure. For the Cook Inlet, the Alternative Tax Credit requirements differ from those on the North Slope. In the Cook Inlet, the producer must show that the well is an exploration well to receive a 30% credit, and the producer could end up receiving a 40 percent credit if the exploratory well was more than 10 miles away from a unit. To obtain the Alternative Tax Credit, an explorer must obtain the finding from DNR that the well expenditure qualifies under AS 43.55.025(c) before the well is drilled. For an exploratory well, the WLE credit, the QCE credit, and the Alternative Tax Credit all require that the explorer comply with the data submittal requirements of AS 43.55.025(f)(2). More than one of these credits cannot be taken for the same expenditure. However, in addition to the QCE or WLE/Alternative Tax Credit, a producer can either obtain a 25 percent credit under AS 43.55.023(b), the NOL credit, for the same capital expenditure. To obtain more information about the data submittal or pre-approval process, please contact Heather Ann Heusser at (907) 269-0137.

    Under AS 43.55.025(a)(5) and (l), passed by the Alaska Legislature in 2010, the state of Alaska offers tax credits for exploration expenses of 100, 90 and 80 percent respectively for drilling the first, second and third exploration wells by a jack-up drilling rig, prescribed as follows: 100 percent of the first well up to $25 million, 90 percent of the second well up to $22.5 million, and 80 percent of the third well up to $20 million. Only the first jack-up rig in Cook Inlet receives this credit. Qualifying expenses shall only be for the drilling of wells from a jack-up rig and that test pre-Tertiary strata. All three wells must be drilled by unaffiliated parties. If production results from the drilling of a well that receives this credit, the operator shall repay 50% of credit over ten years following production start-up. This credit shall be taken in lieu of other credits under AS 43.55.023 (QCE, WLE, NOL Credit) and AS 43.55.025 (Alternative Tax Credit). To date, no producer has applied for this credit.

    To obtain more information about transferable credits for the Cook Inlet, please contact Destin Greeley of the Tax Division, DOR, at (907) 269-6642.

    Middle Earth (non North Slope, non Cook Inlet areas of the State)

    The State assesses a production tax equal to 35% of a measure of net cash flow. However, under AS 43.55.011(p) the production tax on Middle Earth fields is limited to a maximum of 4 percent of the gross value for the first seven years of commercial production. Commercial production must begin before 2022 to be eligible for this limit to apply.

    In addition to the Small Producer Credit that is based on State-wide production, a Middle Earth producer receives a six million dollar a year non-transferrable credit for nine years after first production under AS 43.55.024(a).To receive the credit first production must occur before May 1 2016. The credit must be used in the year the credit accrues; any unused portion of the credit cannot be carried forward to a subsequent tax year.

    Producers in the Middle Earth also have the WLE and QCE transferable tax credits available, and can qualify for the Alternative Tax Credit under terms similar to those for North Slope producers.

    Under AS 43.55.025(m)-(o), a company can obtain a tax credit of 80 percent of drilling expenses (to a maximum per well of $25 million) or 75 percent of seismic exploration expenses (to a maximum of $7.5 million) if those expenses are incurred in one of six Alaskan frontier areas: Kotzebue, Fairbanks, Emmonak, Glenellen, Egegik, or Port Moller. The drilling credit only applies to the first four wells drilled (not more than two in any one area) or the first four seismic projects (not more than one in any area). Expenditures qualifying for these Frontier Area credits can not also qualify for the QCE, Well Lease Expenditure, or NOL credits. Expenditures must be made before July 1, 2016 in order to qualify for this credit.

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  • Other Tax Incentives

    Natural Gas Exploration Tax Credits Under AS 43.20.043

    This program is applicable only to operators and working interest owners engaged in exploration for and development of natural gas resources and reserves south of 68 degrees north latitude. The program allows for a 25 percent tax credit equivalent of qualified capital investments made after December 31, 2009, and 25 percent of the annual cost of activity in the state during each tax year. The total allowable yearly tax credit, which is applicable against corporate income tax only, may not exceed 75 percent of the taxpayer's total tax liability. Unused tax credit may be carried forward for up to five years. Credit is transferable only as part of a conveyance, assignment, or transfer of the taxpayer's business. Credit under this program may be used in conjunction with any other credit authorized by AS 43.20, but not for tax credit or royalty modification provided under any other title. This program expires January 1, 2016.

  • Gas Storage Incentives

    Under AS 43.20.046, passed by the Alaska Legislature in 2010, natural gas storage tax credits are established for any natural gas storage facility commencing operations between December 31, 2010 and January 1, 2016. The credit equals $1.50 per thousand cubic feet of "working gas" storage capacity, up to lesser of $15 million or 25% of the costs incurred to establish gas storage facility. This credit may be used to offset up to 100% of corporate income tax liability, and any excess credit is available for state purchase. This credit expressly does not apply to gas storage related to gas sales pipeline on the North Slope. To receive the credit under this statute, the facility shall operate as a public utility regulated by the Regulatory Commission of Alaska (RCA) with open access for third parties. The storage capacity shall be determined by the Alaska Oil and Gas Conservation Commission (AOGCC). In 2012 the Alaska Legislature provided for a similar credit for a liquefied natural gas storage facility, limited to $15 million or 50 percent of the costs of that facility.

    Additionally, under AS 38.05.180(u), passed by the Alaska Legislature in 2010, natural gas storage that qualifies for a credit under AS 43.20.046 is exempt from rents, fees and royalties for ten years following startup of commercial operation. Non-native natural gas injected and stored in the storage reservoir is presumed to be first-out. All credits and the exemption from rents, fees, and royalty payments shall be passed through to rate payers.

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  • Royalty Incentives

    The State also offers incentives as a landowner with a royalty owner to encourage oil and gas exploration and development.

    Royalty Modification under AS 38.05.180(j)

    DNR will work with lessees to modify royalty provisions if necessary to make a defined project economic. For a new field or pool, a lessee must show that the field or pool is sufficiently delineated (AS 38.05.180(j)(1)(A)(i)) so the extent of the field development can be ascertained and its economics evaluated. The lessees must then show that the development of the delineated field or pool would not be economically feasible under the current royalty terms. (AS 38.05.180(j)(1)(A)(iii). For a new project related to an existing field or pool, the lessee must show that the defined development is necessary to prolong the life of the field or pool (AS 38.05.180(j)(1)(B), and that the project would not be economically feasible under current royalty terms.

    To make its necessary showing, the lessee must provide financial and technical data to the DNR. To date, DNR has granted royalty modification for Oooguruk field's Nuiqsut and Kuparuk development (2005) under AS 38.05.180(j)(1)(A), for the Oooguruk field's Nuna development in 2014 under AS 38.05.180(j)(1)(B), and for the Nikaitchuq field in 2008 under AS 38.05.180(j)(1)(A).

    Contact Greg Bidwell at (907) 269-3565 for information about the royalty modification requirements.

    Cook Inlet Discovery Royalty

    A lessee that drills a well that discovers a previously undiscovered pool of oil or gas in the Cook Inlet pays a 5% royalty on production from that pool attributable to an eligible lease for the 10 years following discovery. AS 38.05.180(f), 11 AAC 83.1000. The lessee must provide DNR with a sworn statement of discovery within 30 days of the discovery and, within one year of the completion of the discovery well, provide DNR with an application providing evidence that a well in the newly discovered pool is capable of producing in paying quantities. 11 AAC 83.1020. The lessee must perform flow tests and provide DNR with supporting data to establish the existence of a previously undiscovered pool and the newly discovered pool is capable of producing in paying quantities. See, for example, DNR's decision granting discovery royalty here. Contact Kyle Smith at (907) 269-8807 for further information.

    Exploration Incentives Under AS 38.05.180(i)

    The commissioner of the DNR may establish an exploration incentive credit (EIC) system. Credits may be made available for both drilling and geophysical survey costs. This EIC must be designated by the DNR commissioner as a lease sale term for state-owned lands only and is not allowed for exploration costs on unleased, Federal-, or private-owned lands. For drilling, credits may provide up to 50 percent of costs incurred, depending on well depth and location. Since the state began offering EICs under this program, 22 exploratory wells qualifying for credit have been drilled on state leases. There have been no applications for geophysical EICs. The last claim for this credit was made for a well drilled in 1994.

  • Nonconventional Natural Gas Rent and Royalty Incentive

    Under AS 38.05.180(n)(2), if the lessee under a gas only lease demonstrates that the potential resources underlying the lease are reasonably estimated to be nonconventional gas, the annual rental payment on the lease will be reduced to $1 per acre and the royalty may be reduced to 6.25 percent.

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