Posted on Jul 20, 2017

Oil and gas investments have unique aspects of finance and taxes that are not seen in any other industry. High oil inventories have driven commodity prices and oil investment prices down, and it may be time to consider adding oil investments to a portfolio. Different entity structures and the accounting methods used make it difficult for investors to get a side-by-side comparison of O&G developers. Investors need to understand the pros and cons of each investment type under consideration, including the impact of accounting methods used, the developer’s strategy with regard to reserves, and finally the potential tax benefits or impacts.

‘Rise early, work late, strike oil.”

This quote was attributed to J. Paul Getty, one of the first U.S. oil tycoons who was once listed as the world’s richest private citizen at $1.2 billion. That was in 1966.

Anyone with dreams of striking it rich through oil and gas investments needs to rise early and work late to choose the right investment option. Investor responsibilities and tax compliance are complex. If it seems like a good way to diversify an already well-rounded portfolio, however, the landscape for investment is certainly looking up.

Over the last decade the U.S. oil and gas industry has undergone somewhat of a renaissance due to technological improvements in hydraulic fracturing, horizontal drilling, drilling fluids, and other techniques, which has allowed U.S. producers to begin to economically unlock the shale oil reserves. The result has been increasing U.S. oil production for the first time since 1970 when U.S. oil production peaked at nearly 9.7 million barrels of oil per day. By 2008, U.S. oil production had fallen to approximately 5 million barrels of oil per day.  Currently, U.S. production is on pace to exceed 9.9 million barrels of oil per day by 2018, an increase of nearly 100% in 10 years.

With the resurgence of the U.S. oil and gas industry, investment opportunities abound. I am a tax compliance expert, so this information should not be interpreted as investment advice. This article will briefly touch on the various types of oil and gas investments available today and will discuss the unique accounting and tax attributes related to these types of investments.

Types of Oil & Gas Investment

The following is a brief summary of different types of oil and gas investments. The bullet points outline the pros and cons for investors.

Publicly traded stocks (such as the major integrated oil companies and large independent oil companies) and ETF’s:

  • Highly liquid since there is an active trading market
  • Income and expenses are not passed through to investors.
  • Company retains any beneficial tax attributes
  • Cash returned to investors via dividends or stock buy backs
  • Arguably, the primary goal is increasing value through increasing reserves and production

Master Limited Partnerships (also publicly traded)

  • Highly liquid since there is an active trading market
  • Income and expenses are passed through to investors, thus investors are taxed on the operating income of the company
  • Beneficial tax attributes such as depletion and drilling costs are minimized because of publicly traded partnership/passive activity tax rules
  • Cash flow is normally distributed to partners on a regular basis

Publicly traded royalty trusts

  • Highly liquid since there is an active trading market
  • No exploration risk
  • Net income passed through to investors
  • Minimal tax benefits available
  • Cash flow is normally distributed on a monthly basis

Drilling partnerships (may be issued through a private placement offering, but generally are not publicly traded)

  • Illiquid – no active trading market
  • High exploration risk
  • Income and expenses passed to investors
  • Beneficial tax attributes such as intangible drilling costs and depletion pass through to investors
  • Cash flow is normally distributed on a monthly basis

Direct investments in working interests

  • Illiquid – no active trading market
  • Exceptionally high exploration risk
  • All income paid directly to investor and expenses paid directly by investor
  • Beneficial tax attributes such as drilling costs and depletion
  • By definition working interests are non-passive (unless owned in an entity that limits liability)

Direct investments in royalties

  • Illiquid – no active trading market
  • No exploration risk
  • Income (net of severance tax and certain marketing/transportation cost) paid directly to investor
  • Investor is not responsible for exploration, development or production expenses
  • Beneficial tax attributes limited to depletion

Next, we’ll look at how accounting methods used for publicly traded oil stocks and Master Limited Partnerships (MLPs) can impact how the balance sheet, net income and cash flows are presented on financial statements. In other words, the accounting method can influence how well an investment vehicle appears to be performing.

Continue Reading: A Look at Accounting Methods of Developers

Scott Allen, CPA, joined Cornwell Jackson as a Tax Partner in 2016, bringing his expertise in the Construction and Oil and Gas industries and 25 years of experience in the accounting field. As the Partner in Charge of the Tax practice at Cornwell Jackson, Scott provides proactive tax planning and tax compliance to all Cornwell Jackson tax clients.

Contact him at Scott.Allen@cornwelljackson.com or 972-202-8032.

Posted on Jun 27, 2017

 

When considering publicly traded O&G stocks or Master Limited Partnerships (MLPs), investors should spend some time with the audited financial statements.  Companies that are involved in exploration and development may either account for their oil and gas activities under the successful efforts method or the full cost method. This choice has a material impact on the balance sheet, net income, and how cash flows are presented on the financial statements.

With the Successful Efforts accounting method, the oil company:

  • Capitalizes costs only when the costs are associated with successfully finding or developing oil and gas reserves
  • Expenses dry holes and any other costs associated with failed efforts at finding or developing oil and gas reserves
  • Expenses production costs
  • Recovers any capitalized costs through depletion

With the Full Cost accounting method, the oil company:

  • Acknowledges that unsuccessful efforts are a necessary and unavoidable part of the business of exploration
  • Capitalizes all costs related to acquiring, exploring, and developing reserves
  • Expenses all production costs
  • Recovers capitalized costs through depletion
  • Performs the annual ceiling test: the capitalized amount carried on the balance sheet cannot exceed the present value of future cash flows (revenue net of future development and production costs) discounted at 10%. To the extent capitalized costs exceed the full cost ceiling, an expense is incurred to write off the excess.

Generally, in times of rising or high O&G commodity prices, the full cost accounting method will report higher net income because costs incurred in unsuccessful projects are capitalized. Consequently, the assets reported on the balance sheet will be higher assets. In times of falling or lower O&G commodity prices, however, the full cost method will report a lower net income and can have significant write downs because of the ceiling test. There are good arguments on both sides for choosing either the Successful Efforts method or the Full Cost accounting method. The key takeaway here is that during times of falling or lower commodity prices, companies that use the successful efforts accounting method may look artificially more successful than companies using the full cost accounting method. Be aware that you may not be comparing apples to apples when looking at the financial statements of companies that use different accounting methods.

Read the Footnote With Regard to Reserves

Another important disclosure, included with the annual financial statements, is the footnote discussing mineral reserves. This unaudited footnote is included with financial statements filed with the SEC, and it is generally the last footnote to the financial statements. It should outline (at least at a high level) how successful the developer has been at building reserves.

By carefully reading the footnote discussing the reserves and the management discussion and analysis section of the annual report, investors can learn where the drilling is happening, the biggest blocks of drillable acres, plans to complete or explore those areas and trends with regard to adding reserves. Understanding the plans of a developer to continue future exploration — such as where and to what extent — can support decisions on investment.

Continue Reading: Tax Benefits for Investing in Oil & Gas

Scott Allen, CPA, joined Cornwell Jackson as a Tax Partner in 2016, bringing his expertise in the Construction and Oil and Gas industries and 25 years of experience in the accounting field. As the Partner in Charge of the Tax practice at Cornwell Jackson, Scott provides proactive tax planning and tax compliance to all Cornwell Jackson tax clients.

Contact him at Scott.Allen@cornwelljackson.com or 972-202-8032.

Posted on Jun 15, 2017

 

O&G exploration is still highly speculative, even with the advanced technologies available today. The unique tax benefits to this industry — designed as incentives for O&G development — can include a large direct deduction of all costs associated with development in the year they occurred. No other industry allows that timing of cost recovery. MLPs, for example, can deduct 70-80 percent of their costs to develop a drilling site, regardless of how successful it is. If it ends up being a dry hole, they can deduct 100 percent of the costs, but of course they’ve lost a lot of money on the investment.

The other unique tax benefit for O&G investment derives from the statutory concept of depletion. Every time you take oil or gas reserves out of the ground, you deplete the value of the asset.

When it comes to tax benefits for oil and gas investing, benefits vary by investment type. The most significant benefits apply mainly to direct working interest investments and to certain drilling partnerships. Direct investments in royalty interests receive a more limited benefit, as do Master Limited Partnerships (MLPs). Investors in O&G publicly traded stocks don’t receive a tax benefit directly, but may receive income taxed at long term capital gain rates via dividends or stock buy backs.

The following are the primary tax benefits that apply to direct working interest investments and partnerships (to a degree). CPAs like myself who are knowledgeable about tax compliance and reporting of O&G investment income can determine if your particular investments are eligible for these deductions.

Intangible drilling and completion costs (“IDC”)

IDCs include all the expenses incurred by the operator of the well related to the drilling and preparing the well for production. Such expenses may include the cost of the drilling contractor, wages paid to employees to oversee the project, survey work, site preparation, fuel, etc. IDC also includes the cost of casing and tubing in addition to certain other tangible items, so the term “intangible” can be a bit misleading. The costs of pumping equipment, flow lines, storage tanks, separators, salt water disposal equipment, and other production facilities or equipment is not classified as IDC and is required to be capitalized and depreciated.

With the exception of integrated oil companies and drilling projects situated outside of the United States, IDC can be fully deducted in the year in which they occurred. You must make the election to deduct IDC on the first return in which IDC is incurred by either deducting or affirmatively electing.

  • For cash basis taxpayers, if the contract with the operator requires the costs to be prepaid, IDC is fully deductible when paid, even if the actual costs are incurred by the operator in the following year.
  • Taxpayers can elect to capitalize and amortize over 60 months straight line (if IDC incurred on non-domestic oil and gas properties, it must be capitalized and amortized over 10 years – not eligible to be expensed).

In assessing the potential tax benefits available from a potential oil and gas investment, the investor should consider their alternative minimum tax (“AMT”) position. IDC is partially deductible for AMT purposes. Excess IDC (difference between IDC deducted and the amount that would have been amortized during the tax year had the election to capitalize and amortize been made) is added to AMT income and multiplied by 40 percent. All excess IDC above the product is considered preference IDC and is not deductible for AMT. For example:

  • Assume AMT income before any IDC preference add back is $500,000 and Excess IDC is $400,000; AMTI including Excess IDC = $900,000 x 40% = $360,000 amount deductible from AMT
  • $40,000 is the preference IDC add back, thus, taxable AMT is $540,000

The IDC deduction applies to working interests, either owned through drilling partnerships or direct working interests. It also applies to MLPs, but passive activity and publicly traded partnership tax rules limit its utility.

Depletion

Investors compute cost depletion and statutory depletion (also known as percentage depletion), then deduct the larger of the two amounts. Depletion is calculated on a property-by-property basis.

  • Cost depletion is computed by the units of production method (total volume produced during the year / total expected remaining volumes to be ultimately produced at the beginning of the tax year multiplied by leasehold cost.
    • No income limitations apply
    • Once all leasehold costs are fully recovered through depletion, cost depletion is zero
  • Percentage depletion is calculated by multiplying gross sales for the property for the year by 15%
    • Allowable depletion is limited to taxable income for the property, thus, percentage depletion can reduce taxable income on a property to zero, but may not create a tax loss for the property.
    • Overall income limit – 65% of taxable income; any allowable percentage depletion above the overall limit is carried over to future years
    • Not limited to leasehold cost – thus may continue to deduct percentage depletion after all leasehold costs are fully recovered

This is the 100,000-foot view of O&G investing for the potential investor looking to diversify a portfolio while prices are low. To explore if these opportunities may be right for you, consult with your investment advisor. Cornwell Jackson can assist potential investors with analyzing the potential tax impacts of oil and gas investments and with the complexity of tax filing each year. Contact us with any questions.

Download the Whitepaper: Oil & Gas 101: Investing Basics

Scott Allen, CPA, joined Cornwell Jackson as a Tax Partner in 2016, bringing his expertise in the Construction and Oil and Gas industries and 25 years of experience in the accounting field. As the Partner in Charge of the Tax practice at Cornwell Jackson, Scott provides proactive tax planning and tax compliance to all Cornwell Jackson tax clients.

Contact him at Scott.Allen@cornwelljackson.com or 972-202-8032.

Posted on Mar 10, 2017

The working interest owner of a portfolio of proved up leases has fully recovered its cost of the leasehold through depletion and would like to sell its holdings at a gain. The leases have increased in value because they have proven that there is oil and gas in economically viable quantities but all well locations have not been drilled.

There are two components to the gain. The first is actual appreciation of the property, relating to the increase in value from proving up the non-drilled (i.e. undeveloped) portion of the leases. The second is a result of recovering the costs the working interest owner has in the property via depletion. With proper planning, the owner will experience two different tax rates. Any gain received on the appreciation in value related to the undeveloped leasehold will be taxed at capital gains rates. However, the gain attributable to the producing leasehold as a result of recovering costs through depletion will be taxed as ordinary income.

To maximize the capital gains treatment, the selling party will try to allocate as much value as possible to the nonproducing leases in the purchase agreement and as little as possible to the proved up leases. The buyer may be more interested in allocating value to the physical equipment on the producing leases in order to accelerate cost recovery through depreciation and depletion. It can be a tricky negotiation process, but can be sweetened for the seller by one more possible option.

Mineral interests are considered real property and qualify for like-kind exchange treatment (1031s). If the nonproducing piece of the transaction is significant, the seller can shelter gains through a like-kind exchange of real property (e.g. hotels, more raw land, apartment buildings, etc.). The exchange may increase the value of the gain in the long run, depending on the property exchanged. The seller must disclose to the potential buyer that a 1031 exchange is involved and must draft the contract properly to shelter the nonproducing portion of the property. To the extent the seller receives cash as part of the deal or has too large a percentage of value allocated to producing property, the transaction may have limited tax deferral options as a 1031 exchange.

Conclusion: For the seller of proven leases with significant undeveloped acreage, there are significant tax planning opportunities depending on how the contract is written.  Proper planning may result in shifting of gain from ordinary rates to long term capital gains rates. The seller may also choose to pursue a like-kind exchange of the mineral rights for another qualifying real estate investment. This option can shelter the gains while adding a tangible asset to the seller’s portfolio.

To view other scenarios and learn more about this topic, visit: Oil & Gas Update: Tax Implications of Buying and Selling Mineral Rights

The oil and gas industry has experienced booms and busts of varying lengths since the dawn of mineral exploration. The current climate for O&G suggests continued consolidation, however forecasts by industry experts anticipate the boom may be back by 2018. For any owners or buyers of mineral interests, the market may be ripe for making deals now — with a careful eye toward the tax implications of buying and selling mineral rights. No two deals are alike, and it’s important to learn the potential tax impact and the types of taxes you may be paying.

Download Now: Oil & Gas Update: Tax Implications of Buying and Selling Mineral Rights

 

Scott Allen, CPA, joined Cornwell Jackson as a Tax Partner in 2016, bringing his expertise in the Construction and Oil and Gas industries and 25 years of experience in the accounting field. As the Partner in Charge of the Tax practice at Cornwell Jackson, Scott provides proactive tax planning and tax compliance to all Cornwell Jackson tax clients. Contact him at Scott.Allen@cornwelljackson.com or 972-202-8032.

Posted on Mar 4, 2017

A mineral rights lessee decides that the timing is right to flip his lease portfolio of undeveloped leases to a large oil and gas company, which in turn will develop the land for production. He isn’t in the business of E&P, but wants to retain an overriding royalty interest in the future oil or minerals produced. He negotiates a deal with the E&P company which will receive a 100% working interest (but receives only 80% of the revenue). In exchange, the mineral rights lessee will receive cash and carves out a 5% overriding royalty interest for himself (the remaining 15% of revenue will cover royalties owned by the original lessor).

In this scenario, the lessee/flipper carves out an ongoing interest in the property. Because the carved out interest has differing characteristics than the transferred interest, this transaction does not qualify for sale treatment. He does not get to deduct the cost of acquiring the mineral rights against the cash he receives from the E&P company. The cash payment is taxed as ordinary income and any royalties he receives in the future will be taxed as ordinary income. Essentially the transaction is treated as a sublease and taxed the same way as the original leasing transaction.

If, however, the lessee/flipper doesn’t retain any economic interest in the property, the transaction will essentially be treated as a property sale and he can offset proceeds by deducting his cost in acquiring the mineral rights. The net gain will be taxed as a capital gain.

Finally, assume the lessee/flipper decides to retain a fractional working interest rather than an override. He sells a 95% working interest to the E&P company and retains a 5% working interest. On the face of it, this transaction looks nearly identical to the transaction described above. However, since the retained interest has the same characteristics as the sold interest, the transaction qualifies as a sale. The proceeds the lessee/flipper receives will be offset by the proportionate share of the cost of acquiring the lease and the resulting gain will be taxed as a capital gain.

As you can see, there is a higher tax cost to retaining a piece of the action through a carve out — the royalties — because the lessee/flipper is gambling that the royalties from production will far outweigh his costs for retaining that 5%.

As for the E&P company, the cost of acquiring the leases are capitalized and will be recovered through depletion once the property begins production.

Conclusion: Retaining an overriding royalty interest after selling a working interest is a gamble that production will more than compensate for foregoing sale treatment.

To view other scenarios and learn more about this topic, visit: Oil & Gas Update: Tax Implications of Buying and Selling Mineral Rights

The oil and gas industry has experienced booms and busts of varying lengths since the dawn of mineral exploration. The current climate for O&G suggests continued consolidation, however forecasts by industry experts anticipate the boom may be back by 2018. For any owners or buyers of mineral interests, the market may be ripe for making deals now — with a careful eye toward the tax implications of buying and selling mineral rights. No two deals are alike, and it’s important to learn the potential tax impact and the types of taxes you may be paying.

Download Now: Oil & Gas Update: Tax Implications of Buying and Selling Mineral Rights

Scott Allen, CPA, joined Cornwell Jackson as a Tax Partner in 2016, bringing his expertise in the Construction and Oil and Gas industries and 25 years of experience in the accounting field. As the Partner in Charge of the Tax practice at Cornwell Jackson, Scott provides proactive tax planning and tax compliance to all Cornwell Jackson tax clients. Contact him at Scott.Allen@cornwelljackson.com or 972-202-8032.

Posted on Mar 1, 2017

A land (surface) owner is approached by an oil company to gain right of way to a development site. The company owns the mineral rights and proposes to build a pipeline. The company will pay for the use of the access land, but will not purchase it.

Oddly, the tax law provides that cash received by the land owner for a right of way is not a sale, and therefore it isn’t a capital gain. Nor is it treated as ordinary taxable income. Instead, it is essentially treated as a return of capital; the cost basis in the land is reduced and the right of way payment, which can be substantial, is tax-free.

It is important for the land owner to understand his or her position in this transaction because rarely does one receive money tax-free. The size of the payment may also change the land owner’s personal balance sheet and require careful decisions for financial or estate planning.

Conclusion: Surface owners may receive a sizable payment, tax-free, depending on the value a working interest owner places on access to the development site. The land owner’s tax basis will also decrease.

To view other scenarios and learn more about this topic, visit: Oil & Gas Update: Tax Implications of Buying and Selling Mineral Rights

The oil and gas industry has experienced booms and busts of varying lengths since the dawn of mineral exploration. The current climate for O&G suggests continued consolidation, however forecasts by industry experts anticipate the boom may be back by 2018. For any owners or buyers of mineral interests, the market may be ripe for making deals now — with a careful eye toward the tax implications of buying and selling mineral rights. No two deals are alike, and it’s important to learn the potential tax impact and the types of taxes you may be paying.

Download Now: Oil & Gas Update: Tax Implications of Buying and Selling Mineral Rights

Scott Allen, CPA, joined Cornwell Jackson as a Tax Partner in 2016, bringing his expertise in the Construction and Oil and Gas industries and 25 years of experience in the accounting field. As the Partner in Charge of the Tax practice at Cornwell Jackson, Scott provides proactive tax planning and tax compliance to all Cornwell Jackson tax clients. Contact him at Scott.Allen@cornwelljackson.com or 972-202-8032.

Posted on Feb 27, 2017

An owner of undeveloped or partially developed land (who also owns the mineral rights to the property) is considering whether to lease mineral rights on the undeveloped property or to sell the rights. An E&P company or other lessee wants the right to explore, drill and/or develop any minerals discovered.

If the owner leases the rights, the owner will reserve a royalty interest. For example, the owner may retain one-eighth of the interest of the minerals produced in the form of a royalty (some royalties have been as high as 25 percent in recent years for valuable holdings). The lessee will usually agree to sweeten the deal with a cash payment, commonly referred to as a lease bonus.

The owner retains the title to the minerals. The lease bonus is taxed as ordinary income as are the royalty payments once production begins. Even though the transaction is called a lease, and the lessee has a cash outlay for the lease bonus, the lease bonus is non-deductible. The lessee recovers the lease bonus cost through depletion once the property begins production.

If the minerals are not developed during the term of the lease, the lease will expire and the owner contractually regains all mineral rights and has the right to negotiate a lease with another party. However, the lessee may request to extend the lease. The payment to extend the lease, commonly referred to as a delay rental is also taxed as ordinary income by the owner. The lessee must add the delay rental cost to the cost of the lease bonus, and recovers those costs through depletion once production begins.

In the event, the lease expires, the lessee is able to deduct any unrecovered lease bonus and delay rental costs in the year of expiration.

In the rare event that the owner decides to sell the mineral rights (e.g. original owner dies and new owner prefers immediate payment), the income on the sale is treated as capital gains.

Conclusion: Even though capital gains tax rates are generally lower than ordinary income tax rates, generally the mineral interest owner will choose to lease rather than sell because the upside of the royalty far outweighs the favorable tax treatment of capital gains.

To view other scenarios and learn more about this topic, visit: Oil & Gas Update: Tax Implications of Buying and Selling Mineral Rights

The oil and gas industry has experienced booms and busts of varying lengths since the dawn of mineral exploration. The current climate for O&G suggests continued consolidation, however forecasts by industry experts anticipate the boom may be back by 2018. For any owners or buyers of mineral interests, the market may be ripe for making deals now — with a careful eye toward the tax implications of buying and selling mineral rights. No two deals are alike, and it’s important to learn the potential tax impact and the types of taxes you may be paying.

Download Now: Oil & Gas Update: Tax Implications of Buying and Selling Mineral Rights

Scott Allen, CPA, joined Cornwell Jackson as a Tax Partner in 2016, bringing his expertise in the Construction and Oil and Gas industries and 25 years of experience in the accounting field. As the Partner in Charge of the Tax practice at Cornwell Jackson, Scott provides proactive tax planning and tax compliance to all Cornwell Jackson tax clients. Contact him at Scott.Allen@cornwelljackson.com or 972-202-8032.

 

Posted on Feb 27, 2017

The oil and gas industry has experienced booms and busts of varying lengths since the dawn of mineral exploration. The current climate for O&G suggests continued consolidation, however forecasts by industry experts anticipate the boom may be back by 2018. For any owners or buyers of mineral interests, the market may be ripe for making deals now — with a careful eye toward the tax implications of buying and selling mineral rights. No two deals are alike, and it’s important to learn the potential tax impact and the types of taxes you may be paying.

Hold ‘em or fold ‘em? It’s not a poker game. It’s the oil and gas industry.

The U.S. oil and gas industry overall may still be in a consolidation phase, but reports from industry watchers like Deloitte noted in fall 2016 that activity may pick up briskly as early as 2018. In Texas, however, the environment looks different, with more hiring and production activity in early 2017 than was seen over the last two years.

Anticipating the shift, corporate E&P activity to build up reserves has been happening in West Texas since 2015 with multi-million dollar deals in the Permian Basin and elsewhere. According to Reuters, more than $28 billion in land acquisitions were transacted in West Texas last year, more than triple those in 2015. The players include Exxon and newer E&P players like Parsley Energy.

We are familiar with the variety of scenarios in oil and gas transactions. Each deal is unique, but there are a few common scenarios worth reviewing that demonstrate how the tax law treats transactions differently. Whether you are selling, leasing or buying, now is a good time to consider your options and prepare to act at just the right time.

Following are common scenarios that can occur in oil and gas transactions and their various tax treatments.  Before we introduce these scenarios, it is important to understand the types of ownership interests commonly seen in the oil and gas industry and the differences between them.

  • Royalty interests and over-riding royalties both collect a specified percentage of the gross revenue from the sale of oil and gas produced. Both typically are subject to severance tax that the State levies on oil and gas production. Both may also be subject to the costs of delivering the product to market (i.e. pipeline services fees), but royalty interests are normally not charged with the cost of developing the property nor are they normally charged with the cost of production and maintaining the well.
  • Net profits interests are a hybrid royalty that typically does not receive payment until the working interest owners have realized a pre-determined profit.
  • Working interests collect a specified percentage of revenue and pay their proportionate share of severance tax and the costs of delivering the product to market. However they are responsible for 100% costs of operating the well, producing the oil and gas, drilling and developing the well and maintaining the property. Clearly, the working interest owner takes virtually all of the risk in a very risky business. The tax law does provide the working interest owner with some unusual tax benefits, but those are beyond the scope of this article.

Oil and Gas Transaction Scenarios

The following scenarios are not based on any actual past or present oil and gas transaction, and the information provided does not constitute tax advice. These examples were created to more easily demonstrate the complexity and nuance of taxable or nontaxable mineral interests. Before entering into any contract, consult with your CPA or attorney. Click on any of the scenarios below to learn more about the scenario specific tax implications of buying and selling mineral rights.

SCENARIO #1 – Leasing vs. Selling Mineral Rights

SCENARIO #2 – Land Owner vs. Mineral Rights Owner

SCENARIO #3 – Lessee vs. Developer

SCENARIO #4 – Sale of Proved Up vs. Undeveloped Interests

 

Buyer and Seller Beware

Before leasing, buying or selling mineral rights or access, players must consider the current market. Market fluctuations impact the value of the property and also the options for structuring a successful transaction. The next few years may prove very fruitful for oil and gas in Texas or show mixed results because of global market pricing pressure, the political environment or other factors.

Cornwell Jackson’s Tax team can provide guidance on the structure of land and mineral rights transactions in line with market cycles and your goals. Our team can discuss the merits of certain deals and tax treatments both short-term and long-term. Contact us with your questions.

Download Now: Oil & Gas Update: Tax Implications of Buying and Selling Mineral Rights

Scott Allen, CPA, joined Cornwell Jackson as a Tax Partner in 2016, bringing his expertise in the Construction and Oil and Gas industries and 25 years of experience in the accounting field. As the Partner in Charge of the Tax practice at Cornwell Jackson, Scott provides proactive tax planning and tax compliance to all Cornwell Jackson tax clients. Contact him at Scott.Allen@cornwelljackson.com or 972-202-8032.