Daily Tax Report: State provides authoritative coverage of state and local tax developments across the 50 U.S. states and the District of Columbia, tracking legislative and regulatory updates,...
Annabelle Gibson is a State Tax Law Editor at Bloomberg BNA.
Increased examination into energy taxation has come to the forefront of political debate in recent years as the industry expands from its strong basis in traditional fossil fuels to include a variety of renewable energy resources.
Legislative and regulatory proposals from both sides of the aisle have been introduced in 2015 that address taxes on the energy industry, and proposals regarding federal income taxation, tax credits and severance taxes have all featured in the discussion over whether increasing or decreasing energy taxes will help or harm America’s economy. The dialogue runs the gamut between opponents of energy taxes, who want to encourage fossil fuel development, provide for U.S. energy independence and support the U.S. economy, to supporters of higher taxes on fossil fuels to discourage their use, decrease CO2 emissions and support development of renewable energy as the source of America’s energy future.
This report provides a preliminary overview of some developments that have occurred this year through July 2015, particularly focusing on Internal Revenue Service (IRS) proposed regulations for master limited partnership (MLP) income taxation, federal budget proposals recommending fossil fuel tax “preference” eliminations, and noteworthy severance tax developments occurring at the state level. The report also briefly remarks on the ongoing concern about the potential negative effect Organisation for Economic Co-operation and Development (OECD) activity regarding base erosion and profit shifting (BEPS) could have on energy companies around the globe.
A comprehensive report on energy tax issues, which will be released in September, will provide additional detail on the above topics and provide an analysis of developments affecting the renewable energy sector. It will also discuss the substantial motor fuel excise tax activity that has occurred this year, both at the federal and the state levels.
The IRS has taken an active part in the energy tax discussion this year. One of its most notable actions was the May release of proposed regulations regarding what activities publicly traded partnerships (PTPs), more commonly known as master limited partnerships (MLPs), can conduct to generate “qualifying income” in order to be eligible for pass-through tax treatment for federal tax purposes.
MLPs are limited partnerships with one or more general partners that manage partnership activities, along with any number of limited partners that invest in the MLP by purchasing “units” (shares) of the MLP that are publicly traded on stock exchanges.
Generally, MLPs are treated as corporations for federal tax purposes under I.R.C. §7704 because they are publicly traded entities. However, §7704(c) provides an exception to this rule when the MLP has “passive” income, meaning that 90 percent or more of the MLP’s gross income for the taxable year consists of “qualifying income.”
Section 7704(d) provides a list of what constitutes qualifying income. Of interest to energy companies is §7704(d)(1)(E), which outlines the basics of the “natural resource exception.” Section 7704(d)(1)(E) states that the following activities constitute qualifying income: “Income and gains from the exploration, development, mining or production, processing or refining, transportation or marketing of any mineral or natural resource.”
Since enacted in 1987, §7704(d)(1)(E) has provided fossil fuel energy companies with easy access to favorable pass-through tax treatment. The use of the MLP structure has surged as technological advances in the industry, such as hydraulic fracturing (fracking) technologies, have emerged. Data from the National Association of Publicly Traded Partnerships (NAPTP)1 shows that in 1990, only 37 percent of MLPs were operating in the energy and natural resources sector. By 2013, that number rose to over 80 percent. Today, there are approximately 130 MLPs operating in the energy sector.
Corresponding with technological advances in the industry, the IRS became the go-to source to clarify when particular activities generate “qualifying income” because §7704 does not enumerate how expansive and/or restrictive the natural resource exception is. Energy companies seeking the benefits of MLP pass-through tax treatment often request private letter rulings (PLRs) from the IRS to confirm approval of qualifying activities before going public.
The IRS typically would answer up to five PLRs in any given year prior to 2008. But the number of PLR requests has surged in recent years and the IRS received more than 30 requests just in 2013.
Sensing a need for further guidance on what activities generate qualifying income and to hinder the barrage of PLR requests, the IRS stopped issuing PLRs for a year beginning March 2014 while it developed regulations to clarify what activities constitute §7704(d)(1)(E) qualifying income.
The guidance came in the form of Prop. Regs. §1.7704-4, REG-132634-14, 80 Fed. Reg. 25970, issued May 6. The proposed regulations, as written, provide definitions for §7704(d)(1)(E) activities and provide examples of specific qualifying activities. In addition to information on the stated activities in §7704(d)(1)(E) (exploration, development, mining or production, processing or refining, transportation and marketing), the proposed regulations provide information regarding “intrinsic” activities associated with §7704(d)(1)(E) activities.
Below is a chart that summarizes the major provisions of REG-132634-14:
|§7704(d)(1)(E) Activity*||Proposed Definition||Qualifying Activities|
|Exploration||An activity performed to ascertain the existence, location, extent or quality of a mineral or natural resource deposit before the beginning of the development stage.||• Drilling an exploratory or stratigraphic type test well|
|• Conducting drill stem and production flow tests|
|• Conducting geological or geophysical surveys|
|• Interpreting geological or geophysical survey data|
|• Testpitting, trenching, drilling, driving exploration tunnels or adits and other activities described in Rev. Rul. 70-287 if conducted prior to development (applies to mineral exploration only)|
|Development||An activity performed to make minerals or natural resources accessible.||• Drilling wells to access mineral or natural resource deposits|
|• Constructing and installing drilling and/or production platforms in marine locations or similar structures in non-marine terrain|
|• Completing wells so that wells can produce oil and natural gas and the production can be removed from the premises (this includes equipment installation)|
|• Performing development techniques such as hydraulic fracturing, stripping, benching and terracing, dredging, stoping and caving or room-and-pillar excavation|
|• Constructing and installing gathering systems and custody transfer stations|
|Mining or Production||An activity performed to extract minerals or natural resources from the ground.||• Operating equipment to extract resources from mines and wells|
|• Operating equipment to convert raw material or raw well effluent into substances that can be readily transported or stored|
|Processing and Refining||Generally, an activity to purify, separate or eliminate impurities. (An activity will not qualify as processing or refining if the activity causes a substantial physical or chemical change in the mineral or natural resource, or transforms the mineral or resource into a new or different mineral product or manufactured product.)||Natural Gas|
|• Removing oil or condensate, water or non-hydrocarbon gases|
|• Separating natural gas into its constituents that are normally recovered in a gaseous phase and those normally recovered in a liquid phase|
|• Converting methane in one integrated conversion into liquid fuels that are otherwise produced from petroleum|
|• Physically separate crude oil into its component parts|
|• Chemically convert the separated components if one or more of the products of the conversion are recombined with other crude oil components in a manner that is necessary to the cost-effective production of gasoline or other fuels|
|• Physically separating products created through crude oil processing or refining activities|
|Non-Qualifying Activities: Production of plastics and similar petroleum derivatives; products not obtained through petroleum processing including heat, steam or electricity produced in the refining process; products obtained from third parties or produced onsite for use in the refinery if the excess is sold; products that result from further chemical change of the product produced from the separation of crude oil if not combined with other products.|
|Ores and Minerals|
|• Activities that satisfy the definition of mining processes listed under 1.163-4(f)(1)(ii) or 1.613-4(g)(6)(iii), including processes for eliminating impurities or foreign matter from smelted or partially processed metallic and nonmetallic ores and minerals|
|Transportation||The movement of minerals or natural resources and products produced during mining/production and processing/refining, including moving products by pipeline, barge, rail or truck.||• Providing storage services|
|• Operating gathering systems and transferring stations|
|• Pipeline construction, to the extent that the pipe is run to connect a producer or refiner to a preexisting interstate or intrastate line owner by the MLP (interconnect agreements).|
|Non-Qualifying Activities: Moving products to a place that sells or dispenses to retail customers.|
|Marketing||An activity performed to facilitate the sale of minerals or natural resources and products produced during mining/production and processing/refining.||• Includes blending additives into fuel|
|Non-Qualifying Activities: Activities and assets involved primarily in retail sales (sales to gas stations, home heating oil delivery services and local gas delivery services).|
|Intrinsic Activities||Generally, an activity specialized to support another §7704(d)(1)(E) activity, is essential to the completion of that activity, and requires the provision of significant services to support the activity. (Will be determined on an activity-by-activity basis.)||Activities must satisfy all three of the following: specialized, essential, and significant services.|
|• The MLP provides personnel to perform or support an activity and those personnel have received unique training to perform those activities, and|
|• If the activity involves the sale, provision or use of property, either the property has limited utility outside of the §7704(d)(1)(E) activity and is not easily converted to another use, or, the property is used as an injectant to perform an activity that is also commonly used outside of 7704(d)(1)(E) activities and as part of the activity, the partnership also collects, cleans, recycles or otherwise disposes of the injectant in accordance with all applicable regulations.|
|• The activity is required to physically complete a §7704(d)(1)(E) activity, or|
|• is required to complete with federal, state or local law.|
|Non-Essential Activities: Legal, financial, consulting, accounting, insurance and other similar services.|
|• Services that must be conducted on an ongoing or frequent basis by the MLP's personnel at the §7704(d)(1)(E) activity site/sites, or offsite if the services are offered exclusively to those engaged in §7704(d)(1)(E) activities (determined based on all facts and circumstances, including recognized industry best practices).|
|• Services necessary to perform an activity that is essential to or supports a §7704(d)(1)(E) activity.|
|Non-Significant Services: Activities principally involving the design, construction, manufacturing, repair, maintenance, lease, rent or temporary provision of property.|
|*This chart omits material regarding the timber industry.|
When the proposed regulations are finalized, §1.7704-4 will apply to income earned by an MLP for the taxable year beginning on or after the final publication date.
A 10-year transition period is available for energy companies to realign their activities to generate qualifying income under the new regulations. During that period, an MLP may continue to treat income as qualifying income even if it would no longer qualify under the new regulations, as long as the MLP has a Private Letter Ruling (PLR) from the IRS saying that the activity generates qualifying income. If the activity was begun prior to publication of the proposed regulations and the activity could have been reasonably interpreted as generating qualifying income, even if a PLR had not been issued, that activity will also generate qualified income during the transition period. A third transition option allows an MLP to treat an activity that begins after issuance of the proposed regulations, but before issuance of the finalized regulations, as a qualifying activity if the activity could reasonably be interpreted as a qualifying activity under the proposed regulations.
Importantly, as written, the regulations do not grandfather activities approved as qualifying activities in PLRs. If the proposed regulations are finalized in their current form, MLPs engaged in activities that do not satisfy the requirements of §7704(d)(1)(E) will have to make changes during the transition period if they want to continue to qualify for pass-through tax treatment.
The IRS resumed issuing PLRs March 6 and will continue to do so during the comment period for the proposed regulations, which ended Aug. 4, as well as throughout any additional hearing and revisionary period before final regulations are published.2
The natural resource exception is just that--it only applies to natural resources such as oil, natural gas, fertilizer, timber, etc. Activities related to renewable energy resources such as wind and solar power do not qualify. Instead, renewable energy companies structured as MLPs are taxed as corporations unless they generate 90 percent or more of their income from one of the other options under §7704(d)(1).
But recent legislative proposals, including one introduced in 2015, seek to extend the benefits of §7704(d)(1)(E) to renewable energy companies as well.
Senators Christopher Coons (D-Del.) and Jerry Moran (R-Kan.) introduced S. 1656 and Representatives Ted Poe (R-Tex.) and Mike Thompson (D-Calif.) introduced H.R. 2883, June 24. These bills, which are identical and are titled the “Master Limited Partnerships Parity Act,” would “level the playing field” between traditional and new energy businesses, Coons said in a statement posted on his Congressional website.3
S. 1656 and H.R. 2883 would expand the exception for activities that generate qualifying income under §7704(d)(1)(E) to include:
• renewable energy generation,
• storage of electrical power,
• generation, storage or distribution of thermal energy,
• use of recoverable waste energy,
• storage of renewable fuels such as alcohol fuel, biodiesel or other alternative fuels,
• production, storage or transportation of renewable fuels or renewable chemicals,
• audit/installation of energy efficient buildings, and
• sequestration and carbon capture during electric power generation.
If these bills are enacted, renewable energy companies would have access to the pass-through tax treatment natural resource MLPs currently enjoy. The bills are currently under committee consideration. Previous versions of this legislation introduced in 2012 and 2013 never made it out of committee.
Aside from income tax concerns, specific excise taxes and tax credits have featured in budget negotiations between the Administration and Congress.
President Barack Obama’s proposed fiscal year (FY) 2016 budget, which he submitted to Congress in February, contains a number of provisions that would have negative tax implications for fossil fuel energy companies. Specifically, the budget proposes changes or repeal of fossil fuel tax “preferences.” One driver behind repeal of these “preferences” is the President’s support of “a clean energy economy, reducing . . . reliance on oil, and reducing greenhouse gas emissions.”4
The President’s budget includes changes or outright repeal of the following tax incentives available to fossil fuel energy companies, which results in an approximately $48.2 billion additional tax burden for fossil fuel companies for fiscal years 2016-2025.
|Tax Provision||Estimated Receipts*|
|Oil & Gas|
|Repeal expensing of intangible drilling costs||$15,495|
|Repeal percentage depletion for oil and natural gas wells||$13,253|
|Repeal the domestic manufacturing tax deduction for oil and natural gas companies under I.R.C. §199||$11,904|
|Increase the geological and geophysical amortization period for independent producers to 7 years||$2,876|
|Repeal exception to passive loss limitations for working interests in oil and natural gas properties||$185|
|Repeal the deduction for tertiary injectants||$97|
|Repeal the credit for oil and gas produced from marginal wells||$0|
|Repeal the enhanced oil recovery credit||$0|
|Cut the percent of depletion for hard mineral fossil fuels||$2,450|
|Cut expensing of exploration and development costs||$694|
|Cut the domestic manufacturing deduction for hard mineral fossil fuels||$561|
|Repeal capital gains treatment for royalties||$547|
|Total (Oil & Gas and Coal combined)||$48,062|
|Source: U.S. Dept. of Treas., Fiscal Year 2016 Greenbook Tables.|
|*This is the total for fiscal years 2016 to 2025.|
The budget also includes a provision repealing the natural resources exception under §7704(d)(1)(E), thus making fossil fuel MLPs subject to taxation as a corporation instead of as a partnership. Repeal would become effective in 2021, and would cost energy companies approximately $1.7 billion from 2021-2025.5
Other tax code changes from the President’s budget with negative implications for energy companies include a repeal of the last-in, first-out (LIFO) method of accounting and modifications of the dual capacity rule. Repeal of the LIFO method would cost oil and gas companies approximately $26.6 billion over 10 years, according to an American Petroleum Institute (API) analysis of the budget.6 Modifying the dual capacity rule would cost approximately $10.3 billion overall.7
Current federal excise taxes that apply to fossil fuel energy companies include the following:
|Coal Severance Tax||• Coal from surface mines--$1.10 per ton, not to exceed 4.4 percent of the sales price per ton|
|• Coal from underground mines--$0.55 per ton, not to exceed 4.4 percent of the sales price per ton|
|Oil Spill Liability Fund Tax||• Until Dec. 31, 2016--$0.08 per barrel|
|• Beginning Jan. 1, 2017--$0.09 per barrel|
|Abandoned Coal Mine Reclamation Fee||Surface Mining Fee for Anthracite, Bituminous and Subbituminous, Including Reclaimed Coal|
|• $0.28 per ton when value of coal is $2.80 per ton or more|
|• 10 percent of the value if the value of coal is less than $2.80 per ton|
|Underground Mining Fee for Anthracite, Bituminous, and Subbituminous|
|• $0.12 per ton if the value of coal is $1.20 per ton or more|
|• 10 percent of the value if the value of coal is less than $1.20 per ton|
|Surface and Underground Mining Fee for Lignite|
|• $0.08 per ton if the value of coal is $4.00 per ton or more|
|• 2 percent of the value if the value of coal is less than $4.00 per ton|
|In Situ Coal Mining Fee for All Coal Types Other Than Lignite|
|• $0.12 per ton based on Btu's per ton in place equated to the gas produced at the site as certified through analysis by an independent laboratory|
|In Situ Coal Mining Fee for Lignite|
|• $0.08 per ton based on the Btu's per ton of coal in place equated to the gas produced at the site as certified through analysis by an independent laboratory|
|*This chart only includes excise taxes applicable to fossil fuel (oil, gas, coal) organizations.|
A rise in the Oil Spill Liability Trust Fund tax and a return of Superfund taxes would occur if the President’s budget proposal were enacted.
The Oil Spill Liability Trust Fund tax generates approximately half a billion dollars a year, estimated to total $11.7 billion for 2016-2025, according to a Joint Committee on Taxation (JCT) report (JCX-99-15).
The budget proposes a $0.01 increase for calendar year 2016, and another $0.01 increase beginning Jan. 1, 2017, which would bring the total tax to $0.10 per barrel beginning in 2017. While $0.01 seems like a tiny amount, this increase would generate an additional $1.7 billion in revenue from 2016-2025, as estimated by the JCT. The tax base would also be expanded to include other crude products produced from bituminous deposits, and would prohibit a tax drawback for exported products beginning in 2016.
The reinstatement of Superfund taxes has been a staple in President Obama’s budget proposals since 2010.
These taxes expired 20 years ago in 1995. The following excise taxes were imposed to support the Hazardous Substance Superfund Trust Fund, which funded environmental cleanup and remediation projects across the U.S., along with a corporate environmental income tax:
• excise tax on domestic crude oil and imported petroleum products--$0.097 per barrel;
• excise tax on listed hazardous chemicals--varied between $0.22 to $4.87 per ton;
• excise tax on imported substances that used the above hazardous chemicals in their manufacture or production--same rate as the hazardous chemicals; and
If reinstated, Superfund taxes would be set at the rates imposed when they ended in 1995. The reinstated taxes would also be extended to other crude products in addition to oil. They are estimated to generate $21.2 billion in revenue, $10.6 billion of which can be attributed to the oil and gas industry specifically, according to the American Petroleum Institute budget analysis. These taxes would be reinstated beginning in 2016.
Taxes on the extraction, production or other severance of oil, natural gas, coal and other minerals and natural resources, called severance taxes, are imposed in over 30 states.
(Click image to enlarge.)
In several of the most oil rich states, large fluctuations in oil production and oil prices pose issues when estimating tax revenue and satisfying budget needs, and severance taxes and tax credits have played a significant part of state budget discussions.
Disputes over raising or lowering severance tax rates and whether to encourage additional energy development have led to heated debates among legislators and industry stakeholders.
(Click image to enlarge.)
The effect of price volatility is perhaps most evident in Alaska, where a significant portion of the state’s general fund is funded by oil and gas tax revenues, as Alaska does not levy a personal income tax or state sales tax.
Taxes related to oil and gas projects in Alaska funded approximately 88 percent of Alaska’s unrestricted general fund in 2014.9 “Oil booms and busts, therefore, have a big impact on Alaska’s budget,” said the Nelson A. Rockefeller Institute of Government in a recent report.10 Because of declining prices, the state has encountered budget deficits and has had to reconsider its oil and gas tax policies.
Alaska imposes an oil and gas production tax and two additional surcharges dedicated to conservation efforts, in addition to property and corporate income taxes.
In 2013, the state enacted the More Alaska Production Act (MAPA), S.B. 21, which became effective on Jan. 1 and replaced Alaska’s Clear and Equitable Share (ACES) program enacted in 2007. MAPA uses the same tax base as ACES, but the tax rate and types of tax credits available are different.
Under MAPA, the oil and gas production tax rate is set at 35 percent of the production value tax based on the net value of oil and gas, which is the value of oil or gas at the point of production, less qualified lease expenditures. The two conservation surcharges total $0.05 per barrel of oil produced.
Unrestricted petroleum revenue totaled $4.8 billion and restricted petroleum revenue totaled $934.4 million in fiscal year (FY) 2014. However, a significant drop to just $1.7 billion and $458.1 million for unrestricted and restricted revenue, respectively, is predicted for FY 2015. An additional dip to $1.6 billion in FY 2016 is estimated for unrestricted revenue; restricted revenues are estimated to rise slightly to $494.1 million. The Alaska Department of Revenue does predict an oil revenue comeback beginning in 2017, and estimates unrestricted petroleum revenues between $2.6 billion and $3.9 billion from 2017 to 2024; restricted petroleum revenue estimates range between $458.1 million and $673.1 million.11
Alaska offers numerous tax credits to oil and gas companies to encourage production activities, which became the focus of the state's budget discussion this year because of the large budget deficit caused by low oil revenues. The following credits are available, in addition to credits for corporate income tax reduction:
• Oil or gas producer education credit,
• Qualified capital expenditure credit,
• Carried-forward annual loss credit,
• Well Lease Expenditures credit,
• Transferable tax credit certificate,
• Transitional investment expenditure credit,
• New area development credit,
• Small producer credit,
• Per-taxable-barrel credit,
• Alternative tax credit for exploration,
• Cook Inlet jack-up rig credit,
• Frontier basin credits, and
• Cash purchases of tax credit certificates.
On June 29, Gov. Bill Walker (I) vetoed a portion of spending allocated to paying tax credits in FY 2016 that was included in the legislature’s budget submitted to the governor, in order to lower overall state spending. Instead of $700 million available for tax credits, only $500 million will be available. “The state is tightening our belt and it’s only right that we do the same with the payments to oil companies. I absolutely understand that the industry is the state’s life blood. Unfortunately, in these fiscally challenging times, everyone must be part of the solution,” Walker said in a press release upon the budget’s signing.12
According to Walker, the reduction will not affect any companies that are currently producing oil and gas in Alaska. The $500 million in credits is “sufficient to pay all of the tax credit applications currently in process.” The $200 million reduction relates to repurchasing tax credits from new exploration and production, not current activity. The veto only delays payment of those credits to future years, instead of eliminating them permanently.
The Louisiana State Legislature’s activity this year revolved around tax exemptions from the state’s severance tax.
Louisiana’s severance tax rates vary depending on the type of resource that is extracted. Tax rates are as follows:
Oil/Condensates/Similar Natural Resources (assessed on the value of oil per barrel):
• Full rate--12.5 percent per barrel
• Incapable oil rate--6.25 percent
• Stripper oil--3.125 percent (exempt if valued below $20 a barrel)
• Reclaimed oil--3.125 percent
• Produced water (full rate)--10 percent
• Produced water (incapable oil rate)--5 percent
• Produced water (stripper oil rate)--2.5 percent
• Full rate--$0.158 per mcf (thousand cubic feet)
• Incapable oil-well gas--$0.03 per mcf
• Incapable gas-well gas--$0.013 per mcf
• Produced water (full rate)--$0.126 per mcf
• Produced water - incapable oil-well gas--$0.024 per mcf
• Produced water - incapable gas-well gas--$0.0104 per mcf
Louisiana also imposes an oil spill contingency fee, levied at $0.005 per barrel.
H.B. 549, which became effective on July 1 and applies to oil and gas production after that date, removes the permanent suspension of severance tax on horizontally drilled wells, but imposes an exemption for 24 months after the well is completed or until the payout of the well cost is achieved, whichever is first.
Beginning July 1, the following exemptions apply:
• If the price of oil is at or below $70 per barrel--100 percent;
• If the price of oil is above $70 and at or below $80 per barrel--80 percent;
• If the price of oil is above $80 and at or below $90 per barrel--60 percent;
• If the price of oil is above $90 and at or below $100 per barrel--40 percent;
• If the price of oil is above $100 and at or below $110 per barrel--20 percent;
• If the price of oil exceeds $110 per barrel - no exemption.
• If the price of natural gas is at or below $4.50 per million BTU--100 percent;
• If the price of natural gas is above $4.50 per million BTU and at or below $5.50 per million BTU--80 percent;
• If the price of natural gas is above $5.50 per million BTU and at or below $6 per million BTU--60 percent;
• If the price of natural gas is above $6 per million BTU and at or below $6.50 per million BTU--40 percent;
• If the price of natural gas is above $6.50 per million BTU and at or below $7 per million BTU--20 percent;
• If the price of natural gas exceeds $7 per million BTU--no exemption.
This year, the North Dakota Legislative Assembly made changes to its “triggers,” tax incentives that are part of the state's severance tax regime.
Currently, North Dakota levies an oil production tax and an oil extraction tax. The rates are as follows:
• Gross Production Tax:
• Oil - 5 percent of the gross value of the well
• Natural Gas - $0.1106 per mcf
• Oil Extraction Tax:
• 6.5 percent of the gross value at the well of the oil extracted (for existing wells)
• 4 percent of the gross value at the well of the oil extracted (applies in certain situations)
The production tax generated $1.1 billion in net collections for fiscal year (FY) 2013, $1.5 billion in FY 2014, and is estimated to generate $1.5 billion in collections in FY 2015.14 The extraction tax generated $1.3 billion and $1.8 billion in 2013 and 2014, respectively, and is estimated to produce approximately $2 billion in 2015.15
North Dakota’s extraction tax also includes “triggers,” which are incentives that lower the tax rate when oil prices drop below a certain point. These “triggers” are designed to spur oil and gas drilling in times when low prices would otherwise hinder development. North Dakota’s “small trigger” was in effect from February through June 2015, reducing the extraction tax to 2 percent for the first 75,000 barrels or first $4.5 million of gross value of oil produced. The large “trigger,” which would have lowered the rate even farther, did not go into effect.
The extraction tax will see some changes starting next year. In April, the legislature passed H.B. 1476, which reduces the oil extraction tax to 5 percent of the gross value at the well of the oil extracted beginning Jan. 1, 2016. The bill also changes the “triggers.” Instead of a “small trigger” and a “large trigger” that lower the tax rate, a “high-price trigger” will raise the extraction tax rate to 6 percent for a 3-month period when oil prices exceed a certain price, set at $90 for 2016.
The gross production tax will not change, so the overall North Dakota tax on oil beginning in 2016, combining the production and extraction taxes, will be 10 percent, down from the current rate of 11.5 percent.
Some state legislatures are running into roadblocks when it comes to severance taxes.
Currently, a battle is raging between Pennsylvania’s administration and state legislature over whether to enact a severance tax on natural gas production in the state.
Natural gas extraction has boomed in Pennsylvania since 2008, corresponding with the advancement in hydraulic fracturing (fracking) technology. Much of Pennsylvania overlays the natural gas-rich Marcellus shale region, and the state has become the second largest natural gas producer in the U.S., behind Texas.
(Click image to enlarge.)
To capitalize on the revenue opportunity for the state, lawmakers enacted an unconventional gas well fee, called an impact fee, in 2012 that authorizes counties and municipalities to levy a fee on natural gas producers for all unconventional gas well spuds. The fee varies depending on the average annual price of natural gas and get lower as well spuds age.
The impact fee has generated between $203 million and $226 million dollars each year for the three years it has been in effect.16 But the fee is not a traditional severance tax, levied on the actual extraction or production of natural resources.
Some lawmakers within Pennsylvania, including Gov. Tom Wolf (D), would like to impose a severance tax on natural gas activity to generate revenue to fund education programs and lower property taxes. In his budget proposal submitted to the Pennsylvania General Assembly March 3, Wolf included a provision that would have imposed a 5 percent severance tax based on the value of natural gas, along with an additional $0.047 per mcf surcharge. The proposal also set a floor price for natural gas of $2.97 mcf. The severance tax would have been imposed in lieu of the impact fee.
When set at those rates, the tax and surcharge were estimated to generate approximately $1 billion in revenue each year, with a portion of that money going to local jurisdictions in the same manner as the impact fee. Some estimates predicted the tax and surcharge to generate between $1.1 billion and $1.9 billion a year through 2020.17
But Gov. Wolf’s proposal met a harsh backlash from oil and gas producers, industry advocacy groups and state legislators, and has led to a budget stalemate that has lasted over a month.
The 5 percent tax and $0.047 surcharge would have made Pennsylvania one of the highest severance tax states in the U.S., when it is currently one of the lowest, according to the Pennsylvania IFO.18 Effectively, the tax rate would start at 17.3 percent in 2016 and eventually level out to 7.5 percent by 2020. The impact fee effective tax rate is only about 0.8 percent.19 The American Petroleum Institute (API) estimated that the governor’s plan would have reduced the state’s gross product by $20 billion through 2025.20
State legislators rejected the governor’s severance tax plan, Amendment 808 to H.B. 283, in a 193-0 vote in the House on June 1.
Legislators put together their own budget plan, H.B. 1192, which did not include a severance tax or changes to the impact fee, and submitted it to the governor for signature on June 30, but Wolf vetoed the entire budget bill.
The severance tax debacle has led to a budget impasse between the governor and the general assembly, and the Pennsylvania government has been operating for over a month without a budget.
Ohio Gov. John Kasich (R) took a different approach when confronted with opposition to his proposal for increasing the state’s existing severance tax.
In Ohio, severance taxes are imposed on natural resources based on their weight or volume when extracted. The rates are:
• Oil--$0.10 cents per barrel
• Natural Gas--$0.025 per mcf
• Coal--$0.10 cents per ton (an additional $0.012 per ton levy applies to surface mining operations)
• Salt--$0.04 cents per ton
• Limestone, sand, gravel, and dolomite--$0.02 cents per ton
• Clay, sandstone, conglomerate, shale, gypsum, and quartzite--$0.01 cent per ton
Gov. Kasich has been advocating for a severance tax increase since 2012, suggesting tax rates ranging between 1.5 percent and 4 percent.
This year, in his budget proposal submitted to the Ohio General Assembly in February, Kasich proposed changing the tax rate to 6.5 percent of the market value of oil or gas, along with a 4.5 percent tax for natural gas liquids. The severance tax would have generated $76.5 million in FY 2016 and $183.4 million in FY 2017.22 The revenue from the higher severance tax would have compensated for lost revenue stemming from a lower state income tax rate.
Ohio legislators were opposed to the tax increase, but were able to reach a compromise with the governor in mid-June. Instead of an increase, a task force was authorized that will study the effects an increase would have on the Ohio economy. The Ohio 2020 Tax Policy Study Commission must submit its recommendations to the legislature by Oct. 1 and legislators must then take those recommendations and pursue legislation.
North Carolina successfully enacted a new severance tax in 2014, which became effective July 1, 2015.
Gov. Pat McCrory (R) signed the Energy Modernization Act (EMA), S. 786, last year, which lifted the state’s drilling moratorium and imposes severance taxes on extracted energy minerals. The new taxes are assessed at the time of sale.
Oil and condensates are subject to a tax of 2 percent of the gross price paid; natural gas is subject to a tax of 0.9 percent of its market value. On-site use of minerals will qualify for a tax exemption. The tax rate on oil and condensates will rise to 3.5 percent in 2019 and to 5 percent in 2021. The natural gas rate will rise in 2019, 2021 and 2023, and will vary based on the market value of the gas when sold.
Energy companies also have to take note of activities regarding the Organization for Economic Cooperation and Development’s (OECD) upcoming completion of the Base Erosion and Profit Shifting (BEPS) project that has been ongoing for the past couple of years. Companies may have to reevaluate their existing tax structures as a result of BEPS recommendations.
According to a May news release from the 2015 Taxand Global Conference, BEPS presents an “upcoming hurdle” to companies that operate in multiple jurisdictions because “profits could be hit harder and deeper through taxation.”23 “Companies will have to spend more time and capital on internal and external compliance, particularly given the likely impact of the BEPS transfer pricing requirements on the Oil and Gas sector,” the release said.
The Coalition for Tax Competition has said the BEPS project “will result in onerous new reporting requirements and higher taxes on American businesses, and will cause “economic pain” because tax collection is being prioritized over other political and economic interests.24
Some congressional leaders have also been raising concerns about what BEPS will mean for the U.S. economy. In a July 16 speech on the Senate floor, Sen. Orrin Hatch (R-Utah) said that BEPS has become a “mechanism for rewriting global tax strategies--potentially including those commonly used by U.S. companies--behind closed doors without the input or consent of Congress itself.” The “U.S. tax base should not be up for grabs in an international free-for-all and I expect officials at the U.S. Department of Treasury to remember that,” he said.
The OECD is scheduled to complete work on BEPS in September and submit deliverables to the G20 finance ministers meeting in October. The G20 is an international forum for governments from 20 major world economies, including the U.S.
The discussion concerning the use of energy taxes to direct America’s energy future will continue during the remaining course of 2015. The comments in response to the proposed master limited partnership qualifying income regulations will be reviewed and analyzed over the coming months, and federal budget proposals regarding tax preferences will be bandied back and forth among federal lawmakers during the budget process. States will continue reviewing their existing tax regimes to determine whether energy tax increases or changes are necessary to support their revenue needs. And the BEPS project will be completed and recommendations submitted to participating countries.
Nevertheless, energy tax policies extend beyond the fossil fuel sector and the items discussed in this introductory report. There has been an increased congressional focus on tax credits available for renewable energy activities to incentivize development, and waning federal and state fuel tax revenues have spurred talks about possible changes to existing fuel tax policies. The comprehensive report coming out later this year will provide additional details on this subject matter.
Bloomberg BNA and Mayer Brown’s Energy Tax Conference: Maximizing Value will be held in Houston on September 21 and 22, featuring a panel session dealing specifically with IRS’ recent proposed regulations impacting MLPs, recent consolidation of existing MLPs, the rise of alternative MLP like structures and other trends. Additionally, a live webinar on July 23 will focus on the IRS’ recent proposed regulations impacting MLPs.
1 NAPTP is changing its name to the Master Limited Partnership Association, effective Sept. 1, 2015.
3 Press Release, Coons, Moran, Poe, Thompson bill will level the playing field for renewable energy (June 24, 2015), available athttp://www.coons.senate.gov/newsroom/releases/release/mlp-act.
4 U.S. Dept. of Treas., General Explanations of the Administration’s Fiscal Year 2016 Revenue Proposals (February 2015), available athttp://www.treasury.gov/resource-center/tax-policy/Documents/General-Explanations-FY2016.pdf [hereinafter Treasury General Explanations].
6 American Petroleum Institute, Industry Tax Increases in the Administration’s FY2016 Budget (February 2015), available athttp://www.api.org/~/media/files/policy/taxes/2015/api-analysis-of-fy-2016-budget.pdf.
7 Treasury General Explanations.
8 Alternative minimum taxable income is determined without regard to net operating losses or the environmental income tax deductions.
9 Alaska Oil and Gas Association, Did You Know?, http://www.aoga.org/facts-and-figures/did-you-know (last visited Aug. 7, 2015).
10 Nelson A. Rockefeller Institute of Government, Blinken Report: The Economy Recovers While State Finances Lag, 15 (June 23, 2015), available athttp://www.rockinst.org/pdf/government_finance/2015-06-23-Blinken_Report_Two.pdf.
11 Alaska Dept. of Rev., Revenue Sources Book: 2015 Spring, Tables 2-2, 2-3 and A-3b (April 2015), available athttp://www.tax.alaska.gov/programs/documentviewer/viewer.aspx?1143r.
12 Press Release, Alaska Office of the Governor, Governor Walker Signs Budget Bills into Law (July 1, 2015), available athttp://www.omb.alaska.gov/ombfiles/16_budget/PDFs/PR_15-90_Governor_Walker_Signs_Budget_Bills_into_Law_07012015.pdf.
13 Some rates are adjusted annually beginning on July 1. The rates listed here are in effect from July 1, 2015 to June 30, 2016.
16 Pennsylvania Public Utility Comn., Act 13 Disbursements and Impact Fees, available athttps://www.act13-reporting.puc.pa.gov/Modules/PublicReporting/Overview.aspx.
17 Pennsylvania Independent Fiscal Office (IFO), Testimony of Matthew Knittel, Director, before the Senate Environmental Resources and Energy Committee and the Senate Finance Committee, Table 2 (June 1, 2015), available athttp://www.ifo.state.pa.us/download.cfm?file=/resources/PDF/Testimony-2015-06-01-SEN-ERE-FIN.pdf.
18 Id. at Table 1.
20 Press Release, American Petroleum Institute, Study: New severance tax would stifle job growth and economic benefits of Pennsylvania’s energy development (May 7, 2015), available athttp://www.api.org/news-and-media/news/newsitems/2015/may-2015/study-new-severance-tax-would-stifle-job-growth-and-economic-benefits-of-pa-energy.
21 Ohio Dept. of Taxn., Ohio’s Taxes 2013: A Brief Summary of Major State & Local Taxes in Ohio, 67, available athttp://www.tax.ohio.gov/Portals/0/communications/publications/brief_summaries/2013_Brief_Summary/2013_Brief_Summary_Ohio_Taxes.pdf.
22 Ohio Office of Budget and Management, Executive Budget Recommendations for FYs 2016 and 2017, Table B-2 (Feb. 2, 2015), available athttp://obm.ohio.gov/Budget/operating/doc/fy-16-17/State_of_Ohio_Budget_Recommendations_FY-16-17.pdf.
23 Press Release, Jimmie van der Zwann, The Oil and Gas Sector--A Taxing Business (May 29, 2015), available athttp://www.taxand.com/taxands-take/media/oil-and-gas-sector-taxing-business.
24 Letter from Center for Freedom & Prosperity, et al. to U.S. Congress (July 14, 2015), available athttp://www.freedomandprosperity.org/files/OECD/ctc-BEPS-2015-07-14.pdf.
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