Oil and gas process engineering handbook

SPAR consists of a single tall floating cylindrical hull, supporting a fixed deck. The cylinder does not, however, extend all the way to the seabed. Rather, it is tethered to the bottom by a series of cables and lines. The large cylinder serves to stabilize the platform in the water, and allows for movement to absorb the force of potential hurricanes. SPARs can be quite large and are used for water depths from up to 3, meters. SPAR is not an acronym, and is named for its resemblance to a ship's spar.

SPARs can support dry completion wells, but are more often used with subsea wells. Subsea production systems are wells located on the sea floor, as opposed to the surface. This allows one strategically placed production platform to service many wells over a. Subsea systems are typically used at depths of meters or more and do not have the ability to drill, only to extract and transport.

Drilling and completion is performed from a surface rig. The aim of the industry is to allow fully autonomous subsea production facilities, with multiple wellpads, processing, and direct tie-back to shore. Photo: Statoil.

We will go through each section in detail in the following chapters. The summary below is an introductory synopsis of each section. The wellhead sits on top of the actual oil or gas well leading down to the reservoir. A wellhead may also be an injection well, used to inject water or gas back into the reservoir to maintain pressure and levels to maximize production. This process includes strengthening the well hole with casing, evaluating the pressure and temperature of the formation, and installing the proper equipment to ensure an efficient flow of natural gas from the well.

The well flow is controlled with a choke. We differentiate between, dry completion which is either onshore or on the deck of an offshore structure and subsea completions below the surface. The wellhead structure, often called a Christmas tree, must allow for a number of operations relating to production and well workover.

Well workover refers to various technologies for maintaining the well and improving its production capacity. Onshore , the individual well streams are brought into the main production facilities over a network of gathering pipelines and manifold systems.

The purpose of these pipelines is to allow setup of production "well sets" so that for a given production level, the best reservoir utilization well flow composition gas, oil, water , etc. For gas gathering systems, it is common to meter the individual gathering lines into the manifold as shown in this picture. For multiphase flows combination of gas, oil and water , the high cost of multiphase flow meters often leads to the use of software flow rate estimators that use well test data to calculate actual flow.

Offshore , the dry completion wells on the main field center feed directly into production manifolds, while outlying wellhead towers and subsea installations feed via multiphase pipelines back to the production risers. Risers are a system that allows a pipeline to "rise" up to the topside structure. For floating structures, this involves a way to take up weight and movement. For heavy crude and in Arctic areas, diluents and heating may be needed to reduce viscosity and allow flow.

More often, the well produces a combination of gas, oil and water, with various contaminants that must be separated and processed. The production separators come in many forms and designs, with the classic variant being the gravity separator. In gravity separation, the well flow is fed into a horizontal vessel.

The retention period is typically five minutes, allowing gas to bubble out, water to settle at the bottom and oil to be taken out in the middle. The pressure is often reduced in several stages high pressure separator, low pressure separator, etc.

A sudden pressure reduction might allow flash vaporization leading to instability and safety hazards. Most plants do not allow local gas storage, but oil is often stored before loading on a vessel, such as a shuttle tanker taking oil to a larger tanker terminal, or direct to a crude carrier. Offshore production facilities without a direct pipeline connection generally rely on crude storage in the base or hull, allowing a shuttle tanker to offload about once a week.

A larger production complex generally has an associated tank farm terminal allowing the storage of different grades of crude to take up changes in demand, delays in transport,etc. Metering stations allow operators to monitor and manage the natural gas and oil exported from the production installation. These employ specialized meters to measure the natural gas or oil as it flows through the pipeline, without impeding its movement. This metered volume represents a transfer of ownership from a producer to a customer or another division within the company , and is called custody transfer metering.

It forms the basis for invoicing the sold product and also for production taxes and revenue sharing between partners. Accuracy requirements are often set by governmental authorities. Typically, a metering installation consists of a number of meter runs so that one meter will not have to handle the full capacity range, and associated prover loops so that the meter accuracy can be tested and calibrated at regular intervals. Utility systems are systems which do not handle the hydrocarbon process flow, but provide some service to the main process safety or residents.

Depending on the location of the installation, many such functions may be available from nearby infrastructure, such as electricity. Many remote installations are fully self-sustaining and must generate their own power, water, etc.

The midstream part of the value chain is often defined as gas plants, LNG production and regasification, and oil and gas pipeline transport systems. Major transportation pipelines usually impose restrictions on the makeup of natural gas that is allowed into the pipeline.

Before the natural gas can be transported it must be purified. Whatever the source of the natural gas, once separated from crude oil if present it commonly exists in mixtures with other hydrocarbons, principally ethane, propane, butane and pentanes. In addition, raw natural gas contains water vapor, hydrogen sulfide H2S , carbon dioxide, helium, nitrogen and other compounds. Gas from a pure natural gas wellhead might have sufficient pressure to feed directly into a pipeline transport system.

Gas from separators has generally lost so much pressure that it must be recompressed to be transported. Turbine-driven compressors gain their energy by using a small proportion of the natural gas that they compress.

The turbine itself serves to operate a centrifugal compressor, which contains a type of fan that compresses and pumps the natural gas through the pipeline. Some compressor stations are operated by using an electric motor to turn the centrifugal compressor.

This type of compression does not require the use of any natural gas from the pipe; however, it does require a reliable source of electricity nearby.

The compression includes a large section of associated equipment such as scrubbers to remove liquid droplets and heat exchangers, lube oil treatment, etc. Pipelines can measure anywhere from 6 to 48 inches cm in diameter. Furthermore, the method used, if other than the method recommended in the Code and Standard, must also be equipped with details for design, construction, inspection, examination, and testing in accordance with the conditions required in the Code and Standard.

I have been involved in a project where the contractor uses a lifting equipment that is not found in the Code. The client asks the contractor to do a very detailed engineering analysis to ensure that the equipment is safe to use and meet engineering load requirements.

Thus, it is actually easier and safer if we use existing codes and standards and are proven to be safe to use in many industries. But again, we must realize that the nature of the Code and Standard is a general guide for designers to do their work in designing equipment. Your email address will not be published. Skip to content Code, Standard, and handbook are terms that are very often heard in the environment of Engineers and professionals working in the oil and gas industry.

Code, standard, handbook in oil and gas industry The Code and Standards generally contain the minimum requirements that must be done to achieve a safe construction, with the aim of promoting the safety and interests of the general public. Leave a Reply Cancel reply Your email address will not be published. Whether interest must be capitalized will depend on the production period and estimated cost. Those items are discussed at length in Treas.

An extensive review of these regulations is beyond the scope of this IRM. On the contrary, since the class life for assets used in Pipeline Transportation Oil and gas companies in the upstream sector also produce offshore platforms.

Whether a "jacket type" platform is an "inherently permanent structure" and should be considered real property for purposes of IRC A f , was addressed in CCA July 1, , transmitting WTA-N While a floating deepwater platform is affixed to the seabed in a different manner than a jacket type platform, it has some of the same characteristics. The total UNICAP costs that have been added to depreciable property that was placed in service during the tax year is to be reported on Line 23 of Form , Depreciation and Amortization.

If the amount seems negligible a review of the taxpayer's methodology in arriving at the figure may be warranted. To determine if the taxpayer is including any UNICAP costs in the basis of its leases, examiners should focus on high cost leases such as offshore tracts that recently underwent their initial drilling phase. Assume that the appropriate "avoided debt" interest rate for a taxpayer is 5 percent. Companies in the natural gas marketing and transportation sectors may acquire gas for resale.

Cushion gas is the portion of gas stored in an underground storage facility or reservoir that is required to maintain the level of pressure necessary for operation of the facility. However, IRC A applies to costs incurred by a taxpayer relating to natural gas acquired for resale to the extent such costs are properly allocable to emergency gas.

Emergency gas is natural gas stored in an underground storage facility or reservoir for use during periods of unusually heavy customer demand. Other gas in the storage facility that is available to meet customer demand often called "working gas" is subject to IRC A. Temporary regulations 1. The following discussion assumes that an examination of these types of costs is permitted by the aforementioned directive. Because of the length of the temporary regulations, an exhaustive review will not be provided here; however, three important areas impact the oil and gas industry: whether an amount is paid to acquire or produce a unit of real or personal property see 1.

Examiners will find that the regulations under IRC A are referenced throughout the new tangible regulations. For example, 1. However, the temporary regulation refers to IRC A for the treatment of employee compensation and overhead costs required to be capitalized to property produced by the taxpayer or to property acquired for resale. Example 4 of 1. Rather, they must capitalize the geological and geophysical costs separately and amortize them as required under IRC h.

Examiners who focus on refinery improvements and turnaround costs will want to closely review the guidelines for unit of property for "Plant Property" that are found in Treas. Examiners who focus on pipeline improvements and repairs will want to closely review the statements regarding unit of property for "Network Assets" found in Treas.

Agents are encouraged to contact industry subject matter experts for the latest developments in this technical area. These expenditures can also include the cost of acquiring well logs and core data, sometimes called "bottom-hole data" , which pertains to wells drilled by other companies. In recent years the capability of seismic technology has increased dramatically, especially in regards to offshore exploration, drilling and production activities.

Data processing and digital imaging have been greatly enhanced by the use of extemely powerful computers and advanced computer modeling techniques. The clarity of seismic surveys has been greatly increased with the advent of "3D" seismic surveys which are achieved by running tightly spaced seismic lines over the entire survey area. In some very large oil fields 3D surveys are conducted periodically known as "4D" surveys and evaluated to determine the extent which fluids have moved within the reservoir over time in response to the withdrawal of oil and gas and the injection of water.

During drilling operations, sensors that are located in the drill string can collect seismic data "ahead of the drill bit" which can be used to optimize drilling parameters such as mud weight, drill path and casing points. An example of a direct cost would be the licensing fee paid to a vendor for the right to use a seismic survey it conducted. Examples of indirect costs would be the salaries of employees who evaluate the survey and overhead of the department which performs the computer processing of the survey.

On occasion the evaluation and processing is done by vendors or consultants. Examiners should be aware that for financial accounting purposes such costs are routinely charged to expense. Such accounts should be analyzed for geological and geophysical expenditures. For most oil and gas companies, amounts paid or incurred after August 8, with respect to domestic properties are amortized over a month period under IRC section h.

The half-year convention specified in IRC h 2 results in the amortization deduction being spread over three tax years. For certain "major integrated oil companies" defined in IRC h 5 the amortization period is extended to five years for expenses incurred after May 17, and seven years for expenses incurred after December 19, Examiners should note that the definition in IRC h 5 is unique, and could encompass the foreign refining operations for related entities.

For example, a U. The assistance of an engineer will generally be needed in the examination of these expenditures. The definition of IDC in Treas. An IRS engineer may have to be consulted if that situation arises. Legal expenses should be examined for charges for examination of abstracts, filing fees, quiet-title suits, and other items which should be capitalized as lease costs. General office expense or sundry expense accounts will often reveal charges applicable to lease acquisition costs.

Expenditures for travel incurred in the acquisition of leases must be capitalized and allocated to the leases involved. Analyze travel and other expenditures to determine those relative to the individuals instrumental in acquiring leases. Then relate these expenditures to leases comparing the locations and times of travel with the dates the leases were acquired.

The original mineral owner lessor or a sublessor may contract for an advance royalty on transfer of the operating interest. Advance royalties result from lease provisions that require the operating interest owner to pay a specified royalty a fixed amount or an amount based on royalties due on a specified production level regardless of whether there is any oil or gas extracted within the period for which the royalty is due.

Advance royalties also allow the lessee to apply any amount paid on account of oil and gas not extracted against royalties due on production in subsequent periods. Generally, the payor of an advanced royalty can deduct the advanced royalty from gross income for the year in which the oil or gas on account of which it was paid is sold. However, advanced royalties that result from a minimum royalty provision may, at the option of the payor, be deducted in the year paid or accrued.

For leases entered prior to October 29, , this option to deduct in the year paid or accrued was available for all advance royalties. The option, however, is a one-time election for the taxpayer and, once chosen, cannot be changed. A minimum royalty provision requires that a substantially uniform amount of royalties be paid at least annually either over the life of the lease or for a period of at least 20 years in the absence of mineral production requiring payment of aggregate royalties in a greater amount.

The example in paragraph 1 above is not a minimum royalty. Depletion is generally allowable in the year the oil or gas is produced under IRC A. However, the Supreme Court decided in the consolidated cases of Fred L. Engle and Phillip D. Farmar dated January 10, , that percentage depletion is allowable on oil and gas lease bonuses and advance royalty income.

See Commissioner v. Engle, US The IRS stated in a news release dated May 18, , that the depletion deduction could be taken in the year payment is received or accrued by the payee. Refer to Announcement , IRB Examination of the lease record which would include the royalty agreement , the journal entries recording minimum royalty transactions, and the related ledger accounts are proper steps to verify these transactions.

If a lease expires, any capitalized cost of the lease becomes a loss, even though the taxpayer may subsequently obtain a new lease on the property. If, prior to the expiration of a lease, a new lease is obtained covering the property, it is known as a top lease. In this case, the cost of the prior lease should not be allowed as a loss; and any bonus and other costs incurred in obtaining the renewal lease should be capitalized. In such event, the costs of both the old and new leases are included in the capital account of the property.

During the examination, look for top leasing transactions. Taxpayers frequently write off the cost of the original lease. Leases are carried under an identification number. The renewal may be noted by an "R" immediately after the lease number.

Otherwise, compare the leases claimed as expirations with the new leases to see if the same property is involved. Another method is to ask the taxpayer if there are any top leases. Quite often when a top lease is taken, the new lease will have a completely different number than the old lease. To find leases which have been charged off even though top leased, it may be necessary to compare the locations of the abandonments with the company's current holdings on a company land map.

The land department will have one. If the new lease is obtained after the date of expiration of the old lease, the loss may be allowable. Of course, facts and circumstances are vital elements in each case. An investment in minerals may be acquired by cash purchase, exchange of other property, services rendered, gift, inheritance, or liquidating dividends. In any transaction where different properties or assets are acquired, there may be the problem of allocation of the basis to the various properties or assets.

In some contracts, the amount involving each separate property or asset may be stated. When stated at realistic values, this eliminates the problem of allocation. Some apparently simple transactions require complex allocations of purchase price to an extent that engineer assistance will be needed.

The geological and geophysical expenditures incurred in an area must be allocated to the leases acquired and retained therein. This can best be illustrated by the following example. The lease is for a term of 5 years and 6 months. Watch for this type of transaction. This abandonment will appear as a credit to the leasehold account and a debit in the Expired and Surrendered Leases Expense. The leasehold account may explain this credit as "released acreage" when actually the company never had a lease on the acreage, but only an option.

The lease record usually identifies a lease by its terms, bonus, acreage, and other provisions, thereby making it possible to identify each lease acquired. Remember that all of the geological and geophysical expenditures incurred in an area of interest are allocated to the acreage acquired and retained in the area. The acreage not retained is outside of the area considered to be favorable for development, regardless of the fact that an option was obtained as a protective measure during the study.

An operator will sometimes purchase a block of leases from a broker in a lump sum purchase at the broker's purchase price plus a commission. Frequently, the broker's purchase price will be capitalized by the purchaser operator but the commission charged to expense.

The entire cost to the operator should be capitalized and allocated to the lease acreage acquired in the purchase.

You can identify this type of transaction by examining the commission expenses account and the purchase agreement. These two sources of identification are usually sufficient. Look into the subsequent year to ascertain whether some undue tax advantage may have resulted from the allocation of the purchase price. An allocation of a disproportionate share of the purchase price may have been made to acreage considered undesirable and that would be released early, thus the retained acreage would have low leasehold costs.

When a producing property is purchased, the price paid must be allocated between leasehold and equipment. The cost basis is allocated between leasehold and equipment in proportion to their fair market value FMV. Refer to Rev. Upon finding that a taxpayer has acquired a group of properties for a lump sum, the agent should obtain from the taxpayer:.

The purchase of a group of producing properties, or a group of both producing and nonproducing properties, presents a complicated valuation problem.

The best approach is to first allocate the total purchase price among the various properties. Although leasehold and equipment could be treated separately, at this point it is best to make allocations to each property. This helps keep values in perspective. Leasehold and equipment together where applicable are treated as a property unit. The reason for this is that most engineering appraisals, upon which purchases are based, value leasehold and equipment together.

The valuation engineer projects future income and expenses of each property separately on an annual basis. Each future year's income is then discounted at the "going rate" to determine the present worth of all expected future net income to the property.

The projections include expected future capital investments as an expense and income from salvage of equipment as income. This type analysis necessarily includes income from sale of production and use of equipment in the same projection. The projections made in this manner give a realistic value to the "package" of leasehold and equipment. Quite often the value of equipment depends on the value of the oil and gas which it will produce.

Seldom will equipment salvage value be anywhere close to its replacement cost, but its utility value if substantial amounts of oil and gas can be expected to be produced by it can easily equal its replacement cost.

If no oil or gas will be produced by the equipment, its only value is its salvage value. This is usually much less than replacement cost. After the allocations have been made to each property, the property allocations will be divided between leasehold and equipment based on relative fair market values.

In this allocation, normally equipment should not be valued at more than its replacement cost less depreciation or less than its net salvage value. Usually the value of the leasehold will have a bearing on the equipment value. The most appropriate time for the IRS to make corrections to a taxpayer's allocations of a lump sum purchase price is in the year of purchase.

The agent should be alert for acquisitions of groups of assets which may require allocations of purchase price. Quite often any type of incorrect allocation can ultimately allow the taxpayer to claim an incorrect tax advantage.

This is true regardless of whether the amount allocated to a particular property or asset is too high or too low. The situations to watch for are whether allocations were made which would result in the cost being written off too rapidly through too great an allocation to nonproducing properties which were abandoned, and too great an amount of cost recovered through depreciation by reason of an excessive allocation of cost to depreciable property. A distortion could result in excessive abandonment losses, excessive depreciation, or percentage depletion where cost depletion should apply.

Allocation of purchase price may be a potential Whipsaw aka Correlative Adjustments issue. When a material amount is involved, every reasonable effort should be made to secure the return of both sides to the transaction to secure consistency of treatment. The buyer and seller will seldom value the property in a like manner. The agent should be aware that Treas. In all cases in which an agent has a substantial problem with respect to allocation among properties and between leasehold and equipment, the agent should request engineering assistance.

Nonproducing oil and gas leases, as well as producing properties, are acquired by oil operators through arrangements that are unique to the petroleum industry. These acquisition arrangements differ vastly from the normal purchase of properties.

For purposes of this handbook, these unusual acquisition arrangements are referred to as complex acquisitions. Included in this category are acquisitions of property by drilling for an interest, performance of services for an interest, the use of production payments, "farm-ins," and the acquisition of government leases.

Frequently promoters, accountants, lawyers, geologists, operators, and others receive an interest in an oil and gas drilling venture in return for services rendered. These services may have been rendered in acquiring drilling prospects, evaluating leases, packaging the drilling program, or, in general, administrative services such as formation of partnerships, filing with Securities and Exchange Commission SEC , and other functions.

It is a common practice for the promoter or sponsor of a drilling package to acquire part or all of the interest in the drilling venture in return for services. GCM , —1 CB , provided that the receipt of an interest in a drilling venture in return for capital and services furnished by a driller and equipment supplier was not taxable on receipt. This ruling provided for the "pool of capital" doctrine that is widely quoted in oil and gas tax law. The same reasoning has been extended to geologists, petroleum engineers, lease brokers, accountants, and lawyers who receive an interest in an oil or gas drilling venture in return for services rendered.

This doctrine resulted from the court decision in Palmer vs. Bender , U. The "pool of capital doctrine" is widely accepted by accountants and lawyers and is still quoted to justify the tax-free receipt of property for services.

Subsequent changes in the tax laws, and subsequent court cases, have significantly limited the use of GCM IRC 61 and 83, Treas. It provides rules for the time and manner that property will be valued for this purpose. Case law that supports the taxation of property received for services rendered is James A.

Lewis Engineering Inc. Commissioner , F. Commissioner , 56 T. Frazell , F. Refer to IRC a. Agents who are examining oil and gas partnerships and drilling ventures should carefully analyze the partnership agreement, joint venture agreement, and prospectus to determine if the promoter or sponsor of the venture is receiving a property interest in the form of an interest in a joint venture or partnership in return for services rendered.

This is a very complex area of tax law; therefore, it is essential that the facts are carefully analyzed and documented. The issue should not be proposed without extensive research. In most cases, an examiner should discuss the issue with the group manager before attempting to fully develop the issue due to the time usually required by this issue.

An additional problem that will be encountered is that the status of GCM is unclear at this time. It has not been revoked although it seems to have been partially superseded by the Code, case law, and the Tax Reform Act. Technical advice is recommended when this issue is considered and the adjustment is substantial. Some guidance with respect to this problem has been issued in Rev.

In certain circumstances the Service will not treat the receipt of such an interest as a taxable event for the partner or partnership. See also Campbell v. While the pool of capital doctrine is still viable in specific factual circumstances, it does not equate to a special exemption from IRC 83 for the oil and gas industry.

Generally, for the pool of capital doctrine to apply, all of the following must occur:. The contributor of services must receive a share of production, and the share of production is marked by an assignment of an economic interest in return for the contribution of services. The contribution must perform a function necessary to bring the property into production or augment the pool of capital already invested in the oil and gas in place.

Drilling contractors will sometimes drill a well on an oil and gas lease in return for an interest in the lease. The drilling contractor will incur percent of the drilling cost in return for a 75 percent interest in the 3, acre lease. Since the driller is entitled to only 75 percent of the working interest oil, 25 percent of drilling costs and equipment costs as leasehold cost must be capitalized. The promoter cannot deduct any cost of drilling or deduct any depreciation because no expenses were incurred.

Oil operators sometimes agree to drill a well on another owner's property in return for percent of the working interest in the drilling site. For additional background on this subject, refer to the discussions of "farm-in" and "carried interest" found in IRM 4. Generally, the ruling states that the driller will be entitled to deduct percent of the intangible drilling and development costs IDC if the arrangement is a true carried interest.

The driller will, however, receive income to the extent of the value of the property outside of the drill site. Examiners should carefully inspect the legal instruments and lease assignments where "carried interests" are present to determine if acreage outside of the drilling site is conveyed as consideration of drilling. The "carried party," in situations described above, also incurs a taxable event. The transferrer will have a gain or loss on the transfer of property other than the drilling site.

The consideration deemed received is the "fair market value" of the property transferred excluding the drilling site. A net profits interest is considered to be an overriding royalty payable out of the working interest income. SeeIRC and Rev. A conveyance of a drilling site in return for a net profits interest is similar to a situation in which an operator conveys a working interest in a lease and retains an overriding royalty interest.

The results would essentially be the same on nonproducing properties. The operator who drills the well would be entitled to deduct percent of the IDC, and the transferrer would be considered to have merely retained an overriding royalty interest. If producing properties are conveyed in exchange for a retained net profits interest, the transferrer would generally be subject to the recapture provisions of the tax laws in regard to investment tax credits and depreciation, if a gain results.

A production payment is a share of the minerals produced from a lease, free of the cost of production, that inter alia terminates when a specified sum of money has been realized. Production payments may be reserved by a lessor or carved out by the owner of the working interest. Refer to Treas. Prior to the Tax Reform Act of , oil and gas production payments were treated as economic interests in oil and gas.

In acquisitions of oil and gas leases, production payments were frequently retained by the seller as a financing tool. The purchaser of a lease was not required to report the income accruing to the production payment retained by the previous lease owner. Thus, it can be seen that oil and gas property could be acquired and paid for out of production that was not taxable to the purchaser.

A common practice in the acquisition of oil and gas properties prior to passage of the Tax Reform Act was to use a production payment in so-called "ABC" transactions. Therefore, the acquisition of a property burdened by a production payment is usually similar to the purchase of a property encumbered by a mortgage.

Agents should realize, however, that carved-out production payments pledged for development are excepted from treatment as loans by IRC The United States Department of the Interior announces blocks of acreage available for lease by competitive bid under the Outer Continental Shelf Lands Act of a specific date. Generally, two contiguous leases acquired on the same day, whether by single or separate documents from the same assignor, would be treated as one property.

Refer to IRC j and Treas. However, government leases are an exception to the rule above; refer to Rev. The government leases are not considered to be acquired simultaneously, even though executed on the same date, because the granting of any one lease by competitive bidding is independent of the granting on other leases. Offshore government oil and gas leases may be defined as blocks containing 5, acres identified by numbers and includes the seabed and subsoil of the submarine areas adjacent to the territorial waters of the United States over which the United States has exclusive rights, in accordance with international law, with respect to the exploration and exploitation of natural resources.

In many of the Western states of the U. Except for lands located within a known geologic structure of a producing oil or gas field, BLM is required by law to lease these minerals on a noncompetitive basis to the first qualified applicant.

Although some of the minerals are not particularly valuable for oil and gas exploration, some of the minerals are quite attractive. In an area where there is little or no current oil and gas exploration activity, a person may acquire leases merely by application and paying the filing fees and first year's rental. The BLM leases the Government tracts which are on proven structures and are, therefore, not wildcat to the highest responsible bidder on a competitive bidding basis. For some years, the competition has been extremely keen for wildcat leases in the attractive areas of New Mexico, Wyoming, and Colorado.

Many persons have wanted to be the first qualified applicant when specific tracts become open for leasing. The reason for this is that the leases had a ready market at values many times the amount that BLM will accept for them. The situation described in paragraph 7 prompted the BLM to devise the following plan for determining who was the first qualified applicant for any tract.

The BLM announces the tracts by size, legal description, and date they are to be available for leasing. Interested persons are allowed to file an application to lease any or all tracts, but each separately described lease requires a separately filed lease application. The "winner" is then awarded the lease and must then pay the first year's rental to the BLM. Because of the resemblance to lotteries, it is believed by some people that the successful bidder is actually being awarded a prize and has income to the extent of the difference between the value of the lease and the filing fee.

Prior to , it had been the Service's position that any cash payment paid by the lessee to the lessor upon granting of an oil and gas lease was a capital investment in the property and not deductible as a business expense.

This was true even if the payment was termed a rental and was the same amount for each successive year of the lease. After the issuance of this revenue ruling with one exception , all "rentals" paid on Government leases have been treated as business expense, currently deductible. In the same year, the taxpayer assigned rights under the application to a third party for cash and a further agreement that, if the lease was issued, the third party would pay an additional sum and allow the taxpayer to retain an overriding royalty.

Fees paid by successful applicants for participation in bidding for noncompetitive Government leases are capital investments. See IRC and Rev. Certain departmental overhead costs should be allocated to the cost of acquiring oil and gas leasehold properties.

This includes both developed and undeveloped properties. For a discussion of the various items that should be considered for capitalization in property acquisitions, refer to IRM 4. The use of the terms "farm-in" and "farm-out" are found in connection with the transfer of property in a "sharing arrangement.

The transferrer will usually retain some type of interest in the property, normally an overriding royalty interest. A farm-out by Taxpayer A , the transferrer, is a farm-in to Taxpayer B , the transferee. The acquisition or disposition of the interest in property by a farm-in or farm-out will not normally result in a taxable event, except for that property which is outside the "drill site" as described in Rev.

The arrangements and details regarding the transfer of any property should be reviewed in detail to ascertain the taxability of the transaction. In the case of oil and gas wells, a taxpayer has an option to treat intangible drilling and development costs as either capital expenditures, under IRC a , or as expenses as provided in IRC c and Treas.

In the event that the taxpayer has elected to capitalize such costs, they become part of the depletable investment recoverable through the depletion deduction Treas. Refer to United States v. Dakota-Montana Oil Co. If a taxpayer has elected to capitalize IDC, Treas.

Intangible drilling and development costs IDC is a phrase peculiar to the law of oil and gas taxation. It describes all expenditures made for wages, fuel, repairs, hauling, supplies, and other items incident to and necessary for the drilling of wells and the preparation of wells for the production of oil and gas.

IRC c provides that intangible drilling and development costs incurred in the development of oil and gas properties may, at the option of the taxpayer, be chargeable to capital or to expense. However, to qualify, the taxpayer must be one who holds a working or operating interest see Treas.

For a definition of "economic interest," see Treas. For a definition of "operating interest," see Treas. For a definition of "complete payout period," see Rev. IRC c provides that Intangible Drilling and Development Costs IDC incurred by an operator in the development of oil and gas properties may, at the taxpayer's option, be chargeable to capital or expense. For this purpose, "operator" is defined as one who holds a working or operating interest in any tract or parcel of land either as a fee owner or under a lease or any other form of contract granting working or operating rights.

The option granted by Treas. If the taxpayer fails to deduct such costs as expenses on such return, the taxpayer shall be deemed to have elected to recover such costs through depletion to the extent they are not represented by physical property. The election, once made, is irrevocable. For each tax year such taxpayers may elect to capitalize any portion of the IDC and amortize the cost on a straight line basis over 60 months. The amount that a taxpayer elects to amortize for a particular taxable year is generally irrevocable.

Examiners should review Treas. In the case of a corporation which is an integrated oil company, IRC b provides that the amount allowable as a deduction under IRC c is reduced by 30 percent. This provision applies to IDC paid or incurred after The amount not allowable 30 percent as a current expense is allowable as a deduction pro-rated over a month period beginning with the month in which the costs are paid or incurred, and is not to be taken into account for purposes of determining depletion under IRC IRC Refer to IRC b 2 For purposes of IRC b an "integrated oil company," with respect to any taxable year, means any holder of an economic interest with respect to crude oil who is not an independent producer.

An independent producer is a person who is allowed to compute percentage depletion under the provisions of IRC A c.

It must be capitalized to the depletable basis of the property or amortized on a straight line basis over 10 years. The capitalized IDC which is attributable to installation of casing, derricks, and other physical property must be recovered through depreciation. There is a special exception for lDC incurred or paid for certain North Sea operations. The interest must have been acquired prior to