Tax Treatment of Natural Gas
The Marcellus shale geological formation underlies almost two-thirds of Pennsylvania. It is believed to hold trillions of cubic feet of natural gas. Recent advances in drilling technology and rising natural gas prices have attracted new interest in this previously untapped formation. The Marcellus shale natural gas boom is creating unprecedented and extraordinary income for many rural landowners in Pennsylvania.
Dealing with this newfound wealth requires careful financial and tax planning. The tax law surrounding oil, gas, and mineral (OGM) leases and royalties is complex and ever-changing. The Internal Revenue Service (IRS) and the Pennsylvania Department of Revenue have specific tax rules for OGM revenue. By understanding these rules, you can avoid penalties and possibly save money by sidestepping unnecessary taxes.
This guide is written for the landowner leasing the OGM rights on the property (lessor), not the producer or lessee (usually a gas company). You as the landowner are potentially liable for income, property, and estate taxes from your land and the natural resources therein, primarily OGM, crops, livestock, and timber. Tax issues and responsibilities for producers or those with a “working interest” in the OGM are beyond the scope of this publication.
The “landowner” referred to in this publication is one who has fee interest in the mineral or subsurface rights to the property. In other words, he or she has a real property interest, also referred to as “mineral property” or “oil and gas property.” This distinction is important since the subsurface or mineral rights of some land in Pennsylvania are severed from surface rights. Owning the surface land does not automatically imply that you own the subsurface or mineral rights. Careful examination of the deed is important to verify ownership rights.
As a landowner you should be aware of the laws surrounding OGM production. Pennsylvania OGM exploration and production is closely supervised and regulated by various state agencies. There are a number of oil and gas regulations and laws such as the Oil and Gas Act, Coal and Gas Resource Coordination Act, and Oil and Gas Conservation Law. In addition, there are environmental laws that address OGM, including the Clean Streams Law, the Dam Safety and Encroachments Act, the Solid Waste Management Act, and the Water Resources Planning Act.
Before signing any documents, you should discuss the lease conditions with an attorney who is familiar with oil and gas law. Also examine the financial and tax options available to you as a result of having the additional income. Being aware of the potential tax liability and/or tax savings could significantly affect decisions about whether to lease and how to use the monies. For tax purposes it is also very important to keep good records of all activities associated with gas leasing.
This publication provides an overview of some key tax topics facing Pennsylvania landowners. The focus is on income taxes, with brief discussions of property taxes, estate taxes, and related issues. More detailed publications are referenced at the end of this fact sheet, but it would be best to consult a financial advisor or tax accountant who is familiar with the oil and gas industry.
Oil, gas, and mineral (OGM) revenue, whether from leases or royalties, is subject to federal income tax and Pennsylvania personal income tax. However, because OGM is a natural resource and is “used up” as it is produced and sold, it is subject to a depletion expense, which can be deducted from royalty income. The following sections discuss tax rules regarding income, depletion deductions, and other expenses that apply to landowners leasing or selling OGM.
Establishing a Cost Basis
Assets such as land, timber, or OGM are recognized as capital assets for tax purposes. The investment costs involved in acquiring the capital assets cannot be deducted in the year they occur but must be capitalized (included in a basis) until such time as the asset is disposed of, depleted, or sold. As the asset is “used up,” the basis is then depleted and a tax deduction is allowed.
A cost basis in real property is the purchase price of the land and its related capital assets such as timber, gas (mineral rights), equipment, and buildings. The basis also includes additional expenses such as lawyer fees, title search, and surveys associated with acquiring the land. When establishing basis, the landowner allocates the costs among the different capital assets.
If the rights are acquired through inheritance, the basis is “stepped up” to the fair market value at the time the decedent dies. A qualified appraisal is needed to establish cost basis upon inheritance or if the rights are transferred to another entity. If the land is gifted, the basis is “carried over” from the donor’s basis. When landowners sell land or timber, or lease their gas rights, they are entitled to a tax deduction as they deplete the basis from the revenue received. However, there is no cost basis in mineral rights unless:
- at establishment of the basis, there was an amount specified for mineral rights, or
- as part of an estate tax valuation, the minerals and surface were valued separately, or
- at date of acquisition there is substantial evidence of value attributable to the minerals when allocating basis.
In other words, the cost depletion applies only to landowners who have established a basis in their OGM. This is unusual in Pennsylvania because most landowners did not consider OGM under their property prior to the recent interest in Marcellus shale and therefore did not allocate any OGM costs to their cost basis in the property. If they did establish a cost basis for OGM, it may have been many years ago when OGM prices were very low. This does not mean that you cannot make a depletion deduction from leasing OGM rights. Landowners without a cost basis have the option of a percentage depletion. These issues are discussed later in the section, “Royalty Payments.”
Sales and Lease Income
A landowner may sell or lease mineral rights and/or sell or lease easements for right-of-ways such as roads or pipelines. If you decide to sell the mineral rights or land for an easement (e.g., for a permanent pipeline), for tax purposes it is treated as a long-term capital gains sale (IRC 1231) as long as it has been owned for more than one year. More commonly, a landowner enters into a leased agreement with a third party for exclusive drilling rights or, for example, a six-month right of way for a road. Detailed lease provisions are discussed in other publications, but the owner may receive payments from:
- A lease “bonus” payable upon execution of the lease.
- Delay rental payments for each year in which drilling has not started.
- Advance royalty payments.
Lease bonus payments and advance royalty payments are really “rent” and generally are reported for tax purposes in the year they are received. To avoid penalties and interest, you must make quarterly estimated tax payments if you have taxable income over $8,000 annually.
Lease Bonus Payments
Cash payments, commonly known as cash bonuses, are received when the lease is executed; they are considered rent and are treated as ordinary income. Sometimes a lease states that payments are to be made annually over a period of years (i.e., installment payments). Again, these payments are taxed in the year received.
Some landowners negotiate for a guaranteed stream of annual payments for a period of years. This receipt of a guarantee of any type may limit your tax planning options. Specific issues include the following: (a) if production begins, the annual payments stop, even if installment payments are still due, and (b) the transferability of the right-to-receive-payments lease to another party is limited. Issues regarding installment payments for OGM, often used to reduce one-time tax burdens, should be discussed with an accountant or a financial advisor.
If you have a cost basis in the mineral rights, you will be able to deduct a certain amount as cost depletion. Bonus payments do not qualify for percentage depletion deductions. However, other related lease expenses such as attorney fees, land surveying, deed or title work, and property taxes are deductible in the year they occur.
Joe Smith leases natural gas on a 100-acre tract to Krakow, Inc., and receives $200,000 as a bonus payment. The lease provides for a primary term of five years and continues as long as gas is produced on the property. Krakow, Inc., assumes all development and operations costs and will pay Smith one-eighth of proceeds when production starts. Smith reports the $200,000 bonus payment as ordinary income, subject to cost depletion, on Schedule E (Form 1040) and on Form PA-40.
Delay Rental Payments
If drilling does not start within one year of the lease’s commencement, the lease can either expire or the lessee can provide a payment to retain the lease and allow additional time to drill and produce gas. This payment is known as the delay rental payment; it is also ordinary income and not subject to depletion deductions. These types of delay payments are not common and often are included as part of the up-front bonus payment. Termination of the lease may be indicated by the absence of the delay rental payment as part of the income reported in the current tax return though it was present in the prior return.
Using the lease from Example 1, annual delay rental payments of $6.00 per acre are payable to Smith. Krakow, Inc., did not develop the leased property within one year after the lease commenced. Krakow paid Smith $600 ($6 per acre for 100 acres) the next year to give Krakow additional time to develop the property. Smith reports the $600 as ordinary income on Schedule E (Form 1040) and on Form PA-40.
Advance Royalty Payments
In some rare cases, the lease may call for advance royalty payments (also treated as rental income), regardless of actual production. Again, these payments are treated as ordinary income. If there is production during that period, the landowner is entitled to claim a depletion. If you can claim cost depletion in that period, the advance royalty payment in excess of production is eligible only for cost depletion, not a percentage depletion. See the section “Depletion Rules” for more details.
If drilling results in a producing well, you will receive periodic payments for your share of the production in accordance with the terms of the lease. This is known as a royalty interest, which entitles you as landowner to a share of the OGM production, free of development and operating costs, over the productive life of the property. This royalty share is negotiable but under Pennsylvania law may not be less than one-eighth (12.5 percent) of the gross production.
Usually, the life of the royalty payment is continuous; its life may be limited, however, by the terms of the lease agreement. It is important to clarify in the lease whether expenses are deducted from royalty payments before the royalty share is split. If the gas company deducts royalty expenses from the gross revenue before allocating royalty, the net royalty amount may be less than the 12.5 percent. Although many royalties are being negotiated at higher rates anyway, you should carefully consider these expenses and how they may affect net royalty payments.
Royalty payments are considered ordinary income to the landowner. They are subject to percentage depletion provided that percentage depletion is greater than cost depletion. This situation is usually the case because the property is acquired for the purpose of using surface rights, not mineral rights, and therefore the landowner will have no basis in the mineral rights. Royalty payments are not subject to self-employment tax and are reported on Schedule E (Form 1040).
Royalty payments are reduced by allowable depletion and other related expenses (if any) to arrive at ordinary income to the landowner. For example, if Pennsylvania had a severance tax it could also be subtracted from royalty payments, depending on how royalty owners are treated in severance tax legislation.
If a landowner has working (operating) interest in OGM operations as opposed to royalty interest, this working interest entitles its owner to share in the production; but the owner must bear a share of the development and operation costs. The seven-eighths working interest generally is conveyed to an operator (i.e., the gas company) in consideration of a cash bonus and development of the property. If the landowner has an operating interest in the production, he or she reports income on Schedule C and is subject to self-employment taxes. The operating interest owner is allowed to deduct a wider variety of expenses in addition to the depletion allowance.
The most common expenses that are directly associated with OGM production and that are allocable deductions for landowners are depletion expenses since landowners have only a royalty interest. However, landowners who have a working (or operating) interest in the production can also deduct expenses that include intangible drilling and development costs (IDCs), operating expenses, and production taxes, as well as depletion expenses.
Typical expenses for those with a working interest include:
- Geological and geophysical expenditures. These are costs related to obtaining and accumulating data that serve as the basis for the acquisition or retention of mineral-producing properties. These costs are generally capital expenses and are not deductible annually as normal operating expenses.
- Intangible drilling and development costs (IDCs). These include expenditures for wages, fuel, repairs, hauling, supplies, etc., that are incidental to and necessary for drilling and preparing wells for the production of oil and gas. These expenses can be deducted in the year they occur or are capitalized.
- Operating expenses for producing oil and gas leases. These include labor for operating the well, maintaining the equipment specified in the lease, repairs, supplies, utilities, automobile and truck expenses, taxes, insurance, and accounting costs. Operating expenses also include depreciation of the lease and well equipment.
Since OGM is being “used up” or depleted as it is extracted and pro- duced, the IRS allows the owner of an economic interest in an OGM- producing property a reasonable de- duction for depletion in calculating taxable income from the property. To have an economic interest and be eligible for the deduction, you must have a legal ownership inter- est in the property and must receive income from the OGM extraction. The depletion deduction is allowed only when the OGM is sold and income is reportable; it is not allowed for production alone. If you have more than one interest because you own separate tracts or parcels of land, the interests can be combined and treated as one property. Or you may elect to treat one or more of the interests as separate properties.
The IRS requires that a land- owner compare two methods when computing the depletion deduction for OGM property:
- Cost depletion—a unit of production method using the landowner’s basis in the mineral property.
- Percentage depletion—a specified percentage (15 percent for natural gas) of the landowner’s gross income from the property, limited to 100 percent of the landowner’s taxable income from the property and 65 percent of the landowner’s taxable income from all sources.
The method of computing the depletion deduction is not elective. You must use the larger of the two amounts. As mentioned before, in most cases a landowner leasing OGM does not have a cost basis so will automatically use the percentage depletion method.
Cost Depletion Method
Cost depletion allows you a tax deduction that is at least equal to the investment, as the depleting property is consumed. You must have basis available to take advantage of this cost depletion. As mentioned previously, it is highly unusual for a landowner to have cost depletion, but the issue is discussed here to provide contrast with the discussion of percentage depletion that follows. Cost depletion, if it is greater than the allowable percentage depletion, must be used in lieu of percentage depletion. A depletion unit must first be computed by dividing the landowner’s adjusted depletable basis by the number of remaining thousands of cubic feet (Mcf) of gas (“reserves”). The depletion unit is then multiplied by the number of units (Mcf) sold during the tax period to compute the cost depletion deduction (see Example 3). The “reserves” used in the cost depletion calculation for any tax period are the reserves at the end of that tax period plus the units produced during that tax period. It is obviously difficult to project future reserves, so the calculation must be ”reasonable.”
If cost depletion is used for bonus payments that are not based on production, cost depletion can also be based on dollar amounts. The landowner’s adjusted depletable basis is divided by the total remaining gross income expected to be received from the beginning of the tax period until the resource is totally depleted. This results in a depletion unit expressed as dollars of cost per expected dollar receipts.
If there is no production and the lease expires, the depletion previously allowed against bonus income must be restored as taxable income in the year the lease terminates. However, restoration of depletion on the bonus is not required if the landowner who owned the property and took depletion on the bonus has completely divested all the property prior to the lease’s expiration. You must keep accounts for the depletion of each property and adjust these accounts each year for units sold and depletion claimed.
When Smith acquired the property, he knew it contained gas, so he allocated a portion of the cost basis to gas. He established a basis in the mineral rights of his one-eighth royalty interest at $20,000 for his 100 acres. During the first year of the lease, 436 million cubic feet (Mmcf) were sold from the one well that covered 400 acres and includes his 100 acres. The estimated remaining reserves in that well field at the end of the year were 3,357 Mmcf.
First, the depletion unit must be calculated. In the example below Smith’s depletion unit is $.05/Mcf.
Depletion unit = Adjusted basis ÷ Reserves
Depletion unit = $20,000 ÷ (436 + 3,357 Mmcf) = $0.0053/Mcf
Although Smith receives only a one-eighth share, his cost depletion calculation considers the entire quantity that was depleted. The resulting depletion unit is then multiplied by the amount sold in that year (436 Mmcf) to determine the allowable cost depletion.
Cost depletion = Depletion unit X Units sold
Cost depletion = $0.0053 X 436,000 Mcf = $2,299
Since this is less than his cost basis of $20,000, Smith is allowed to deduct $2,299 from his original basis of $20,000. His adjusted basis is $17,701, which will be allowable for a cost depletion next year.
Percentage Depletion Method
Percentage depletion is allowable even if a landowner has a zero basis for cost depletion. The percentage depletion is based on income and is limited to the smaller of the following:
- 100 percent of your taxable income from the property figured without the depletion deduction
- 65 percent of your taxable income from all sources, figured without the depletion allowance
For this reason, the definitions of gross income from the property and taxable income from the property are very important. Gross income from OGM property is the amount for which the landowner sells the OGM in the immediate vicinity of the well. The landowner’s gross income from the property does not include a lease bonus or advance royalty that was payable without regard to production. In addition, delay rental payments and most land damage payments (e.g., timber harvesting) are not considered gross income for tax purposes. Net taxable income from the property is gross income from the property reduced by expenses. For those with a “working interest” in the property, the types of expenses associated with OGM production are deductible from gross income to determine net taxable income.
To calculate how much can actually be deducted, take 15 percent of the gross income from the property, limited to net taxable income from the property (see Example 4). For those with cost depletion, the allowable percentage depletion for each property can then be compared with the cost depletion applicable to each property to determine the greater of cost depletion or percentage depletion. The larger of the two is the allowable deduction.
If cost depletion for a property is greater, there is no carryover of unused percentage depletion for that property. If percentage depletion is greater, and any is disallowed due to the 65 percent of taxable income limitation, the disallowed portion is carried forward and added to the depletion allowance for the following year, before income limitations (including the 65 percent of taxable income imitation) are applied for that year.
If you claim a percentage depletion deduction, you must attach a statement (a plain piece of paper) to the tax return providing all data necessary to determine gross income from the property and taxable income from the property. An attractive element of percentage depletion is that the cumulative depletion deductions may be greater than the capital amount that you spent to acquire the property (i.e., the cost basis). However, if there is cost basis it must be adjusted annually by the amount of percentage depletion used.
Smith has used up his cost depletion as per Example 3. In the second year of production, the well produced the same amount—436 Mmcf. At $5.00 per Mcf the total income from the well that year was $2,180,000, of which one-eighth royalty interest was $272,500. Smith received $68,125 for his one-quarter share (i.e., Smith owns 100 acres in a 400-acre production unit) of his royalty interest in the well field. He made no other income from the property that year. Because Smith is a royalty interest owner, he is eligible for the percentage depletion deduction.
Smith first determines 65 percent of his adjusted taxable income, that is, Adjustable Gross Income (AGI) from all sources including the royalty. In this ex- ample, Smith’s AGI is $110,000.
Deductible limit = AGI X 65%
Deductible limit = $110,000 X 65% = $71,500
Next, Smith determines his allowable percentage deduction, which is limited to 15 percent of gross royalty income from the property.
Allowable percentage deduction = Gross income from property X 15% = $68,125 X 15% = $10,219
Since $10,219 is less than $71,500, Smith can deduct the entire $10,219 on his tax return.
Damage to surface areas such as crops or timber may occur during the development and production of the OGM. Payments for damage are ordinary income. If the damage is related to land or timber property, they are subject to a reduction in the land or timber basis. Landowners should attempt to salvage timber and maximize revenues from these nondrilling activities. There are numerous ways to ensure that the timber cut is marketed either by the drilling company or by landowners themselves. Timber revenues are eligible for capital gains treatment if certain requirements such as holding period and type of sale are met.
If as landowner you receive substantial income, you may consider creating a separate business entity to deal with immediate and future revenue streams and to address tax, liability, and succession planning concerns. On a spectrum, types of business entities range from sole proprietorship to “C” corporations. Generally, C corporations pay the highest tax rates, but they are better protected from liability and survivability (not having to dissolve the business) than sole proprietorships. In between these two extremes are numerous entities such as S corporations, limited liability corporations (LLCs), limited liability partnerships (LLPs), or master limited liability partnerships (MLLPs).
A discussion about business entity pros and cons is beyond the scope of this publication. Business entity considerations should be discussed with a financial advisor and an attorney. Generally, however, startup small businesses usually prefer the S corporations or LLCs, which provide the tax benefits of personal income tax rates but have liability and succession protection.
For example, in Pennsylvania royalties or lease bonuses from the natural gas industry are subject to 3.07 percent personal income tax. Corporations are subject to a net income tax of 9.99 percent. However, if such businesses are organized as LLCs, LLPs, or MLLPs, they pay the same rate as individual personal income tax, 3.07 percent.
Some of the larger Pennsylvania landowners such as hunt or country clubs have nonprofit tax exemption under Sec. 501(c)(7), since their main purposes are to provide social and recreational activities. IRS revenue rulings 58-589 and 66-149 address the role of social clubs revenue from OGM. In general, the law requires that the clubs’ income be derived exclusively from members, and if not they are subject to unrelated business taxable income (UBTI) tax. Lease and royalty income would classify as UBTI.
If the gross receipts for these “other than exempt sources of income” exceed 35 percent, the nonprofit status is terminated and a new entity would be subject to taxes on those receipts. A social club is allowed a one-time exemption for revenue, but if the club is going to receive annual payments it will lose nonprofit status. Also, none of the monies can be used for personal benefit. In other words, if any of the club’s net earnings benefit private shareholders through, for example, cash distributions, then the tax-exempt status is lost. Loss of nonprofit status normally results in C corporation status, which can mean double taxation. To avoid this outcome, many clubs are appraising mineral rights and setting up a separate entity to sell those rights to that entity at fair market value. Clubs should consider restructuring, preferably before the lease is signed.
Estate and Inheritance Taxes
Conservative estimates suggest that at prices of $5.00 per Mcf a gas well field of about 400 acres has the potential to earn more than $5 million over the life of the well (conservatively estimated at 20 years). One-eighth of that amount is a tidy sum for a landowner. There are many issues about valuing mineral rights, again beyond the scope of this publication. These issues should be discussed with financial advisers and certified appraisers knowledgeable about OGM.
Many landowners can be liable for federal estate taxes. The problem is the uncertainty of estate and gift tax rates and exemptions. Under current law, the federal estate tax is repealed for deaths occurring in 2010. In 2010, however, the current step up in basis (having your estate assets valued at current fair market value) will be replaced with a carryover basis (the lesser of the fair market value of the decedent’s property transferred through the estate or the decedent’s basis in the transferred property).
In other words, inheriting land in 2010 is estate tax free but potentially subject to capital gains tax. For deaths occurring after December 31, 2010, taxation of federal estates reverts to the provisions put in place in 2001: the maximum federal estate and gift tax rate will be 55 percent, with a maximum exemption of $1,000,000. This uncertainty requires careful planning, especially for landowners with over $1 million in projected income. In addition to potential federal estate taxes, Pennsylvania still requires state inheritance taxes starting at 0 percent for spouses and increasing to 15 percent for others.
Regardless of tax issues, you should consider estate planning to ensure the continuation of any family enterprise. Landowners attempting to transfer family lands to the next generation often face complicating issues that jeopardize a successful transfer and the sustainability of their land holdings. These issues can include unexpected accrued values, especially with newfound Marcellus shale gas income.
Failure to begin planning for succession of family lands early in the ownership often leads to fewer options available to families later, and the situation is often complicated by unexpected illness, death, or divorce in the family. Lack of communication and involvement in the management of family lands and their eventual transfer often leads to parcelization or sale of family lands as the most convenient choice in resolving distribution of assets and service on debt. These decisions can ultimately have detrimental effects on the future sustainability and economic viability of Pennsylvania’s rural landscape.
Pennsylvania, unlike other states, does not subject OGM (subsurface property) to property taxes. Surface property is taxed, but Pennsylvania provides a preferential property tax known as Clean and Green to farm and forest landowners. Depending on the land use, the property is assessed at a current use value instead of fair market value. If the land use changes, the Clean and Green–enrolled property owner may be liable for rollback taxes and interest.
Gas leases do have impacts on farming and forestland, and the Pennsylvania legislature is considering legislation to amend Clean and Green. The most likely scenario is a loss of preferential assessment and rollback imposed only on the affected areas, that is, the areas where land use changes, not the entire property. These areas include the well site, areas that support access roads, pipelines, above-ground structures, and land used to store equipment, machinery, and vehicles. The bills also contain language to prohibit assessment of rollback taxes unless and until the owner is paid a royalty on gas or oil generated from the well.
Owing to the uncertainty of the current property tax assessment of affected natural gas areas, counties are enacting different rules. Some are doing nothing, some are rolling back the entire property, and others are rolling back only the affected land. Until the legislature acts, these inconsistent rules across counties will continue. One way for a landowner to deal with the current uncertainty is to have a clause in the lease contract that makes the drilling company (lessee) pay any increased property tax attributable to their actions.
A severance or yield tax is an extraction tax on the production of the resource. Only a few states do not have some type of severance or yield tax in addition to or in lieu of a tax on sales or gross income. In 2009, the Pennsylvania legislature declined to enact a severance tax on OGM production. This issue is expected to be actively debated in 2010. The current proposal calls for a 5 percent tax on the gross value of natural gas at the wellhead, plus 4.7 cents per 1,000 cubic feet of natural gas extracted and ready to be moved to the customer. It is not clear whether the tax will be assessed against the landowner or the company. It is likely that if the gas company pays the tax, that will ultimately reduce the net royalty payment to landowners.
Taxes are an integral part of managing any business venture, and involvement in natural gas development is no exception. Many landowners whose property overlies the Marcellus shale may become wealthy overnight as a result of leasing their mineral rights for the natural gas. Solid financial and tax planning is important to make sure these monies are put to their best use and not squandered through poor planning or unnecessary tax payments. For example, by taking advantage of the percentage depletion allowance, you can save thousands of dollars annually from income taxes.
In addition, it is critical to keep good records, not only for minimizing tax consequences but also to safeguard against audits. These would include records of all activities, revenues, and expenses associated with the OGM. Finally, you should view this publication as a primer. To make the most of OGM opportunities, seek additional and detailed advice from professionals.
For Further Information
- Penn State Extension Natural Gas website
- Stafford, Jim. Look Before You Lease. Available from NARO (the National Association of Royalty Owners)
Forest Finance and Tax Information
General Federal Income Tax Information
- Oil and Gas Industry Handbook section of the Internal Revenue Manual (Section 4.41.1)
- Hennessee, Patrick. 2008. Oil and Gas: Federal Income Taxation. CCH Publishers.
Depletion and Expenses
- IRS Publication 535: Business Expenses or PDF Version
- Pennsylvania Code on Income Tax
- Pennsylvania Personal Income Tax Guide 23–1, revised March 2007. Chapter 23: Natural Resources.
Clean and Green
Other Financial Considerations
Prepared by Michael Jacobson, associate professor of forest resources
TitleTax Treatment of Natural Gas
SeriesMarcellus Education Fact Sheet
This publication is available in alternative media on request.