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In rolling and ripple modes you can watch simultaneously the new IN and OUT point of both clips so you can decide where is the best point for the new cut. For more informations about Trimming tools on other video editing applications please watch this playlist on youtube. It is when you insert marked source material into the timeline without replacing material already in the sequence.

Existing material moves beyond the spliced material, lengthening the overall duration of the sequence or of a track. You remove selected material from a track in the timeline and automatically close the gap.

Stability and Control

When you extract material, you shorten the duration of the track or sequence. An overwrite edit replaces existing material and does not lengthen the overall duration of the sequence unless the material used to overwrite goes beyond the end of the sequence. Each software has different ways to perform these operations. The first difference is the way they set target tracks. In AVID, you have a panel on the timeline head with buttons which represent the source 1 video button and a number of audio buttons equal to the number of the audio channels you have to move near the target tracks.

On Premiere and FCP even if in the latest version Premiere works same as AVID you have source buttons too to align to target tracks but instead of to activate or deactivate tracks you have to lock or unlock them. The operation you perform act on all tracks except the ones you locked. I guess this can be the way Kdenlive could work because its development is already in this direction. At today you can select a target track and you can lock tracks. For eg: if you want to insert a small part of an interview in the middle of a scene edited by 1 video track, 2 video tracks with graphics and 4 audio tracks environmental sounds, sounds efx and music you have to open a gap on all tracks.

And so on. For eg: I want to substitute a video clip, an audio track and I want to delete audio efx or music which correspond to the previously edited scene. Or I want to remove, by leaving a gap in the timeline, all the materials which correspond to a previously edited scene and that they are on several different tracks. For selecting the time position where to perform the actions, we have two ways: the first is to use the IN and OUT point on the timeline so we can remove, or fill, or replace, or let a blank area where indicated.

The clip length is determined by the selected area of the clip in the source window. The Insert and Overwrite functions finally have a super easy 3 Point Edit approach. When you use the audio video separation now you can set both the target tracks for video and audio. If just the video or the audio target is selected you will put only the video or the audio on the timeline.

If a track is set as the target the Led indicator will turn green. If the track is locked the Led will turn Red.

If some of the mute options mute video or mute audio are turned on the Led will turn yellow. AUDIO WORKFLOW In professional workflows, audio is always produced inside the video editor application except only for high budget fiction products where you edit the live audio in the video editor and you use applications as ProTools for adding music and efx and creating the final 5. In tv stations when the editor ends the job he delivers the content with a peak between db and db then, during broadcasting, the audio track passes through a compressor before to be normalized.

For this reason, every professional video editing system has a strong and complete audio workflow integrated. Then by the fact that today even small company can provide DCP contents to movie theaters mostly are advertisements but not only , video editor apps integrate also 5. On the timeline, the editor sets the volume automations, places transitions and uses filters for some minor effects.

By the mixer, he sets the volume, the pan and the filters for each track and he premixes some tracks by using busses or submixes as they are called in Premiere.

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TIMELINE WORKFLOW — Automations: in my experience the best way to creates automations in video editor apps is to cut the audio track where you have to make an automation, then you put a crossfade audio transition which in all professional applications you can use on single track and lift up or down the gain of the clip you have to modify. This technique is the fastest way to create automations on the timeline. By using transitions you can move the automation point by using a standard rolling operation, you can refine the length of the automation by change the duration of the transition, you can change the start and the end point of the automaton by sliding the transition.

For changing the gain of the clip you have to modify we have different approaches: on AVID, you select the clip on the timeline and you modify the gain by the mixer the mixer acts on the clip when selected and on all the track when nothing is selected. On Premiere, you have the gain menu in the contextual right-click menu and in FCP you have the volume of the clip in the effects stack I think that the FCP approach is probably the best one.

Audio crossfades in AVID — Filters are not generally used on the timeline except for managing audio channels or to fix some main issue of a specific clip. You can use filters on the timeline also when you have to create some specific special effect eg: echo bounce, distortions, etc on short clips. Audio split in Premiere I also see that video tracks are numbered reversed as all other video editor applications.

The tracks are not linked to anything not to the video not each other. If they move out of sync you have the number of frames reported on the video track and on the audio track which is out of sync. On Premiere, you have to choose which kind of track you want to create on the timeline mono, stereo, 5.

You can change the way the software interprets the audio format by a special menu. Once on the timeline, audio and video are linked but you can separate them by using the command in the contextual menu as it is for Kdenlive or by using the mouse while you keep pressed the alt key in this situation you can manage the audio as you want. Then, when you complete the operation the audio is still linked to the video in the new position but the video and the audio clip report, as it is in AVID, the number of frames they are out of sync.

On FCP, even if you can create a stereo pair track, you always use single channel tracks by default. The audio and the video are linked but you can use the linked selection button on the right upper corner of the timeline to turn linked selection on and off. When you move audio out of sync you see, as for the others systems, the number of the frames reported on the clips. For eg. Or if you want to insert only the audio part of the clip you just set the audio target track but not the video target track.

These are virtual channels. You can create one or more of these. You can decide, by selecting on the channel list of the track, to send the output signal of each audio track straight to the final master or to pass, before, trough a bus. The busses can premix all the input channels they receive, so you can put common filters on more track together and then send them to the master for the final mix.

For eg you can have some tracks with different filter treatments which pass in a bus for be treated with a common reverb and then which are mixed to a music track in the final master. Premiere Pro Audio Mixer. In my opinion, Cinelerra has a lot of problems in stability and usability. Ardour misses working panners and the ambisonic workaround is not a good workflow for usability and for the lack of features. Kdenlives already accepts all kind of multichannel tracks. I tried to put mono, stereo and 5. I think that this is pretty good and simple. By this function and 5. Right-click contextual menu for clip speed from a clip on the timeline in Premiere Pro You can change speed, reverse it and manage the audio for keeping it in sync.

The way you can reverse the clip on Kdenlive is pretty rigid. I found a workaround to slow down the reversed clip by opening the mlt script into a text editor and by changing the framerate value: higher is the number slower is the play speed. NOTE: this feature was just implemented. Now the speed effect which is in the effects library is able also to reverse the clip at all speed and to keep the audio at the new speed in both directions in sync. After the recent fix, It is finally possible to also change the speed to an audio-only clip. These blending features are very well implemented and useful but in the standard professional video editor apps where this excellent approach on layer blending we can find in Kdenlive is missing transitions are a different thing.

They are crossfades, wipes, 3D effects as page curl, cubes, etc. At today on all the main video editor apps, you can apply the transition effect on a single track this is made mostly for using the keyboard and you have a panel for fine tune the parameters. Transitions in AVID. If you had the aircraft in trimmed, level flight and let go of the ailerons, they would induce an oscillating roll on their own. The airplane had negative lateral stability. A final case of static stability places our marble on a perfectly flat, frictionless surface in a vacuum.

Ridiculous, I know, but that's how engineering professors think. If you push the marble in any direction, it will move and continue to move. While static stability concerns the initial tendencies of an object, dynamic stability concerns the resulting motion over a span of time. If the initial tendencies tend to decrease, the object is said to have positive dynamic stability. If they increase, it is negative dynamic stability.

If they stay the same, of course, that is neutral dynamic stability. If the dynamic motion is in agreement with the static tendency, you have a non-oscillatory stability. If the motion oscillates but gets smaller over time, you have positive static and dynamic stability. If the motion oscillates but gets greater with time, although you had positive static stability this was only the initial tendency. You will have a negative dynamic stability. If the motion oscillates without end at the same magnitude, your initial static stability as been countered with negative dynamic stability. You have dynamic stability if the amplitude of any oscillations dampen out with time.

These are further classified as "stick fixed" or "stick free. Most aircraft with hydraulically actuated controls are stick fixed and should exhibit greater stability. A stick free airplane is one that will allow control movement in response to air loads, gusts, or other stimuli. The motion is so slow that the effects of inertia forces and damping forces are very low. The whole phugoid can be thought of as a slow interchange between kinetic and potential energy. The short periods correspond closely with the normal pilot response time, and there is the possibility than any attempt to dampen out these oscillations may actually reinforce them and produce instability.

This lead to pilot induced oscillations PIO , which can destroy an aircraft in a matter of a few seconds. Should such an oscillation develop, usually as a result of sharp gusts, the best procedure is to release the controls and allow the natural damping of the aircraft to take over. A positive control force will also eliminate the PIO. The impulse to steady the aircraft should be avoided in all cases. On the other hand, if the airplane reacts to the sideslip by turning away from the new relative wind, thus increasing the sideslip angle, the airplane has negative directional stability.

If no reaction results from sideslip, the airplane is said to have neutral directional stability. For an example of how this can go wrong, see KCA A dutch roll is a combination of yawing and rolling motions where the rolling motion continuously reverses itself with less noticeable yaw moments unless the rolling is significant. It is better called "oscillatory stability. One factor makes the aircraft maneuverable, the other makes it stable. The unstable case, however, needs to be qualified in this way: if the divergence is very slow then it can be tolerated.

To the pilot there is no significant difference between a dutch roll which is only very, very slowly divergent over one which is truly neutral. For most pilots, manually damping a dutch roll is either a theoretical exercise or a simulator demonstration. For many of us, however, it was a daily survival drill. Let us assume that your aeroplane develops a diverging dutch roll. The first thing to do is nothing — repeat nothing.

Too many pilots have grabbed the aeroplane in a rush, done the wrong thing and made matters a lot worse. Don't worry about a few seconds delay because it won't get much worse in this time. Just watch the rolling motion and get the pattern fixed in your mind. Then, when you are good and ready, give one firm but gentle correction on the aileron control against the upcoming wing. Don't hold it on too long — just in and out — or you will spoil the effect. You have then, in one smooth controlled action, killed the biggest part of the roll. Also added new Exhibit 4. See Exhibit 4.

Deleted expired tax provisions previously numbered as Exhibits 4. Several new tax incentives are described in IRM 4. Updated IRM 4. Added IRM 4. Outer Continental Shelf. Kathy J. This handbook introduces examiners to and assists them in the examination of income tax returns of taxpayers in the oil and gas industry. Diligent use of these guidelines will shorten the time needed to acquire the examination skills essential to this specialty.

Nothing contained herein should discourage examiners from improving upon these techniques or from exercising their own initiative and ingenuity. Authoritative industry references are available in Exhibit 4. The list is also useful for the study of oil and gas taxation. While the list is not exhaustive, it will provide an excellent introduction.

Refer to Exhibit 4. These guidelines are a compilation of the examination techniques used by some of our most experienced revenue agents. They are intended to illustrate the variety of problems encountered in examining Federal income tax returns involving oil and gas transactions. The oil and gas examination guidelines in this handbook identify potential issues and problem areas that an agent will likely encounter in the examination of an oil company or individual operator.

While no guideline, examination plan, or textbook can cover all possible issues or examination techniques in an industry as complex and diverse as the petroleum industry, the handbook will be a useful tool for the examiner. However, individual initiative, planning, and research will be needed to cope with the rapid changes taking place within the petroleum industry.

This industry, which involves the exploitation of natural resources, is subject to a large number of substantive tax law provisions. It becomes impractical, if not impossible, to clearly delineate examination techniques from the application of law. In many sections of this IRM, examination techniques are interspersed with discussion of the legal aspects of the particular transactions involved. References to the tax law will be general and brief in nature and should not be relied upon for complete understanding of the law. Rather, it is recommended that the agent augment these guidelines with research and study.

Included in Exhibit 4. Many examination features in the oil and gas industry are common to commercial enterprises but the handbook will highlight those areas peculiar to the industry. Note that the examination techniques in this issuance are suggestive but not mandatory procedures for field personnel.

These guidelines do not alter existing technical or procedural examination instructions contained in the IRM. In the event of any inconsistencies between these guidelines and the basic text of the IRM, then the latter will prevail. Procedural statements in this issuance are for emphasis and clarity and are not to be taken as authority for administrative action.

In summary, a good knowledge of oil and gas tax law can only be acquired through study and several years of examination experience in the industry. The examination techniques and procedures presented here are not intended to serve as a textbook in oil and gas tax law. The material presented here should be studied, considered, and applied where appropriate to ensure an efficient and effective examination. It is unlikely that an examiner would ever apply all of the techniques mentioned here in any one examination.

Examiners should consider taking the Micromash course "Oil and Gas Taxation" prior to beginning an examination of an oil and gas company. The oil and gas industry is one of the largest and most important segments of the U. Due to the size and complexity of the industry, some basic examination guidelines are needed to assist examiners. The exploration, development, and production of crude oil and natural gas require enormous amounts of capital.

To obtain the funds needed, companies sometimes join together and pool their resources to explore for oil. Large integrated oil companies, as well as small companies and individuals, participate in the exploration, development, and production phases of the oil and gas industry. Many times partnerships are formed to enable outside investors to invest in drilling ventures.

The investors may have little knowledge of the oil and gas industry. They are willing to invest funds in risky drilling ventures because the tax benefits are favorable, and large economic benefits are possible. Institutional investors that hope to achieve moderate returns without undue risk are known to invest sizeable amounts in the industry by purchasing royalty interests in producing oil and gas properties. The transportation, refining, and marketing of petroleum and natural gas by-products, which also require extremely large capital investments, used to be dominated by large vertically integrated oil companies.

However, due to a variety of business, economic and regulatory reasons, the number of companies that own all segments of the industry has been greatly reduced. The industry is as active and dynamic as ever, and the large capital requirements still exist, but the complexion has changed markedly. For example, it is fairly common for publicly traded partnerships to own significant portions of midstream and transportation assets.

The importance of the petroleum industry to the economy of the United States has led Congress to pass specialized tax laws that are unique to the oil and gas industry. Petroleum industry accounting records have been adapted to the specialized nature of the industry. As a result, an efficient and effective examination of a return with oil and gas investments, transactions, or operations will require specialized knowledge of the industry, accounting, and tax law. Oil and gas drillers and service companies make up another large part of the industry.

The drilling companies are hired on a contract or fee basis for the drilling rig, labor force, and various other expenses related to the drilling of the well. The fee is often charged on a per-day basis and referred to as a "day rate". Service companies are hired by oil and gas exploration companies to provide the technology, tools, and expertise throughout the drilling, evaluation, completion, and production phases of the well.

Many drillers and service companies are foreign controlled corporations or domestic corporations owning foreign subsidiaries, so referrals to international examiners are often necessary. Some common areas that examiners should be aware of when working these types of companies are:. At a high level the oil and gas industry is often viewed as having only two primary segments — "Upstream" and "Downstream". The upstream segment explores for and produces oil and gas that is used by the downstream segment. The downstream segment transports, processes, and refines oil and gas into desirable products and by-products, and then markets them to industrial, wholesale and retail customers.

However, it is more appropriate to describe the general activities of these business segments as follows:. Upstream : companies in this segment explore for crude oil and natural gas; develop oil and gas fields; and produce oil and gas via wells. The gathering of those raw products by the producer in the general vicinity of its wells is sometimes considered one of its upstream activities. Downstream : companies in this segment perform the functions that are not normally considered part of upstream activities.

These functions include gathering, processing, transportation, refining, marketing, distribution and retailing. There are some accepted sectors of the downstream segment which are described below, although some functions are performed by more than one. The physical and chemical differences between crude oil and natural gas dictate that the conversion of those raw products into finished ones is typically performed in a different manner i.

Midstream and Transportation : companies in this sector perform functions such as gathering crude oil and natural gas from well and field sites; treating natural gas to remove contaminants and to recover natural gas liquids NGLs ; and operating natural gas plants to separate natural gas into "pipeline quality gas" essentially methane and other gas and liquid components. These companies also operate "fractionation plants" where large quantities of NGLs are separated into components such as ethane, propane, butane, and iso-butane. Important transportation functions include moving crude oil from gathering sites to oil refineries.

Pipelines are normally used; however railcars are occasionally used to move significant quantities of crude oil while a pipeline is under construction. A very extensive network of intrastate and interstate natural gas pipelines transports gas to local utility companies and industrial customers. Companies in this sector also transport refined liquid products from refineries and NGLs and pipeline quality gas from gas plants. Transportation of large quantities is normally done via pipelines, although railcars and river-going barges are used to move some liquid products.

Very large ships known as oil tankers and liquefied natural gas LNG carriers transport oil and gas between countries and continents. Refining : oil refineries convert crude oil into a wide variety of finished products, such as transportation and heating fuels, lubricants, waxes, asphalts, and petroleum coke. Oil refineries also commonly provide large quantities of hydrocarbon gases and liquids to chemical plants a. Oil refineries that process large quantities of "heavy" crude oil may also produce large quantities of elemental sulfur "powder" or "bricks" which can be transported as solids via rail or barge.

Marketing and Retail : companies in this sector distribute products like gasoline, diesel, heating oil, and aviation fuel to wholesalers, retailers and end users. While a large percentage of gasoline stations are branded with the name of a well known oil company or refiner, only a minor percentage are actually owned by those corporations.

The great majority are franchises. Over the past few decades the traditional gasoline "service station" has largely been replaced by combination gasoline station and convenience store "C-stores". Natural gas is distributed to residential consumers and to many industrial companies by local gas utility companies. Service Industry : companies in this segment are primarily known for supporting the upstream segment -- by owning and operating equipment such as drilling rigs; supplying goods such as well casing pipe ; and performing services such as fracturing wells and conducting seismic surveys.

Some companies manufacture their own equipment. The scope of these companies range from privately owned firms that operate in a limited region to multinational corporations with activities, employees, and customers around the world. In the course of an examination, the examination will probably require assistance from a specialist. When a specialist is needed, the examiner should involve the specialist early in the examination process. The specialist will greatly assist the examiner in identifying, planning and developing the issues.

Referrals to specialists are made on the Specialist Referral System. Refer to IRM 4. Engineer Referrals : Referrals should be made during the early stages of each examination when significant and complex engineering issues are noted on the return. The CAS should be involved in the review of records for record retention evaluations and to assist the agent as appropriate throughout the examination. The CAS is also trained in the use of statistical sampling techniques. In those instances where the volume of records is such that a percent examination is not feasible, statistical sampling should be considered.

International Examiners : Referrals to International Examiners IE are made on the Specialist Referral System during the early stages of each examination initiated when it is ascertained that the taxpayer is engaged in business outside the United States either directly or through related, controlled, or controlling affiliates. See IRM 4. Since IRC allocations may be possible in these cases, it is important that the referral reflect all such subsidiaries controlled by the corporation being referred.

Financial Products Specialists : Referrals should be made during the early stages of each examination when significant and complex financial product issues are noted on the return. These may include futures, options, government securities, and other financial products. Excise and Employment Tax Specialists : During the examination when the agent discovers claims for excise and employment tax payments, the assistance of a specialist should be requested through the team manager.

The agent's manager must contact the Office of Indian Tribal Governments to coordinate any first contact with an entity owned by an Indian tribal government or situated on Indian land. Examiners are encouraged to become familiar with the numerous petroleum industry trade publications. Frequently, these publications will contain industry statistics that are very useful in the examination of oil and gas issues.

For instance, the selling prices of domestic and foreign crude oils are sometimes shown in periodicals. A comparison of these industry average prices with the purchase price paid to a Controlled Foreign Corporation CFC will sometimes point out "pricing" problems between related entities. Another use of industry statistics is a comparison of drilling costs with the costs reported on the tax return being examined.

While average drilling cost statistics are not reliable for purposes of making adjustments, comparisons will often point out problems that might not be easily identified under normal examination techniques. An apparent excessive drilling cost may be easily explained as being due to accidents, such as losing the drill string.

On the other hand, the excessive cost may be the result of excessive charges or due to the inclusion of lease costs in the intangible drilling costs IDC use billed to joint owners. The wide use of industry statistics can materially reduce examination time. Furthermore, their use as a testing tool will frequently identify problem areas that would not be found using normal examination techniques.

IRS engineers will usually have access to current petroleum industry statistics. Oil and gas exploration and production is closely supervised and regulated by the various state agencies. Virtually every state has different requirements, and the agencies within each state that administer the laws are varied. In Texas the Railroad Commission administers the laws relating to oil and gas exploration and production.

One of the resources available to examiners with respect to a description of the various actions taken on oil and gas properties are the various state permits required to be obtained before any type of drilling, exploration, deepening, plugging and abandoning, or other activity can be done.

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The applications for the various permits and reports of work performed filed with the state agencies provide a wealth of helpful information, such as dates of notices of intention to drill a well, type of well, legal description of property, estimated total depth, and other details. Production severance tax rates imposed on oil and gas production by the various states have not been shown on the attached schedule because of the many differences in the rates and manner in which applied. This knowledge is, however, important to the examiner because, in many instances, investors will report the net amount of the proceeds received from the sale of oil and gas as gross income subject to depletion.

Gross income, for depletion purposes, means gross revenue before payments of severance taxes. The tax rates, and how they are applied, may be obtained from the taxpayer or from the state agency that administers the tax. This section provides guidelines for determining the cost of oil producing and non-oil producing property. Second, economic transactions involving oil and gas interests and the tax consequences as they relate to examination techniques are described in detail.

For purposes of this section, the terms "mineral property" or "oil and gas property" refer to a real property interest. A major factor in the examination of oil and gas records is the verification of the cost of a property. The cost basis of the real property interest is recovered through depletion. This cost also provides the basis for the computation of gain or loss on the sale of all or part of such property.

If the property is producing, the cost or basis of the associated equipment is recovered through depreciation. If the property is nonproducing, the cost may be recoverable upon expiration of the contract or by virtue of its worthlessness demonstrated by unsuccessful development. The examination of an oil and gas producer operator is made difficult by the use of non-uniform accounting procedures. Not only is each taxpayer different but the methods used to record transactions vary.

This is because oil and gas producing companies, depending upon their size, keep the type of records they deem sufficient for their needs. In planning the examination, note whether the return indicates new acquisitions or producing leases. Experience shows that new nonproducing properties are acquired each year, and numerous complications may arise in connection with such acquisitions. A wide variety of problems is created through the various contractual agreements made to acquire and explore oil properties. For this reason, the new properties and the way they are acquired should be closely examined.

The type of ownership interest determines the extent to which the investor and operator will share in the income from oil and gas production. The various kinds of property interests or rights constitute the ownership of the oil and gas extracted. IRC defines a property as each separate interest owned in each mineral deposit in each separate tract or parcel of land. An understanding of the tax consequences of oil and gas transactions requires a clear concept of mineral interests and their interrelationships:.

Landowner Interests are those in which the landowner owns the land in fee, including the minerals on and beneath the surface. The landowner may sell or otherwise dispose of subsurface or mineral rights without relinquishing surface rights. Ownership of the mineral rights, which includes the total of all rights to the oil and gas in place, is of primary concern.

These rights, separately or jointly held, may include executory rights -- i. Non-landowner Interests are those mineral rights held by someone other than the landowner. In this case, the party can sell or otherwise dispose of ownership interest in the minerals. When such dispositions are made, other interests and new owners come into the picture, each having a piece of the mineral deposit. These interests entitle the owners to share in the total production from the property.

A landowner generally owns what is known as a "fee interest," which consists of the ownership of both surface and mineral rights. The landowner can sell or lease all or any part of the land or minerals. A lease agreement usually provides for a cash consideration, or bonus, and a royalty to be paid to the landowner. The lease usually contains a provision for the lessee to pay a delay rental for each year development is not started or forfeit the lease. Cash bonuses received upon the execution of an oil and gas lease are regarded, for income tax purposes, as advance royalties. The Supreme Court in Anderson v.

Helvering , US , ; 24 AFTR ; USTC stated "cash bonus payments, when included in a royalty lease, are regarded as advance royalties, and are given the same tax consequences. In any subsequent year during the term of the lease, the receipt of the delay rental will be ordinary income to the landowner on which no depletion is allowable. The delay rental is not an advance payment for oil but is in the nature of rent paid for the privilege of deferring development.

See Treas. If drilling results in a producing well, the landowner will receive periodic payments for its share of the production in accordance with the terms of the lease. These payments, called royalties, are ordinary income to the landowner. This income is subject to percentage depletion to the extent provided in IRC A and the regulations provided thereunder, provided that percentage depletion is greater than cost depletion.

This will usually be the case when the fee interest in the entire property is acquired for the purpose of using the surface rights and, as a result, the landowner will have no basis in the mineral rights. If there is no production and the lease expires, the depletion previously allowed against bonus income must be restored to income in the year the lease terminates.

However, restoration is not required if there is no production, the lease has expired, and the taxpayer who took depletion on the lease bonus has completely divested the property prior to the expiration of the lease without production. Termination of the lease may be indicated by the absence of the delay rental in the income of the current return and its presence in the prior return. If, prior to expiration, the lease was extended and a bonus was paid for such extension, percentage depletion would be allowable on the bonus only if reportable prior to August 16, After that date, taxpayers may still compute cost depletion on these payments.

Restoration to income of bonus depletion would not be required with respect to the original lease or the extension unless the lease terminated without production and depletion had been deducted. At such time, the allowed depletion on the original lease and renewal top lease should be included in income. The landowner can sell all or any part of the mineral rights. If a fee interest in the minerals is sold, the sale is governed by the provisions of IRC If the sale of the property otherwise qualifies as provided in IRC , a long-term capital gain is realized on the sale of minerals.

There is no cost basis unless one of the following conditions exists:. Seller's basis was the result of an estate tax valuation in which minerals and surface were valued separately. Seller's cost basis can be properly allocated between surface and minerals because of substantial evidence of value attributable to the minerals at date of acquisition.

The basis is applicable in the event of a sale or for computing cost depletion. Generally, the basis of minerals should not be allowed as an abandonment loss where the owner also owns the land. The agent should inspect the prior-year return. The prior-year return may disclose a delay rental which does not appear in the current return.

This indicates for the current year either unreported income from delay rental or a lapsed lease which may require restoration of bonus depletion by the lessor.

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Experience indicates that bonus income and royalty income are usually reported, but bonus depletion is rarely restored to income. The position of a fee royalty owner is the same, irrespective of surface rights ownership. The owner may lease interest, receive a bonus or delay rentals, receive income from production, and may sell all or any portion of royalty interest. Rights or interest in production may be created by the owner of the minerals and consist of two major categories:.

Royalty Interest entitles its owner to share in the production from the mineral deposit, free of development and operating costs, and extends undiminished over the productive life of the property. Working Interest also entitles its owner to share in the production, but this owner must bear its share of the development and operation costs. Royalty and working interest owners may, subject to certain restrictions, sell or otherwise dispose of all or part of their respective interests in the total production.

When this happens, there are additional subdivisions of the total production known as overriding royalties, oil and gas production payments, net profits interest, carried interest, and other income items. Exhibit 4. Beginning with the landowner, this is carried through a few of the various interests which may be carved out of the original ownership of the minerals in place. The fee royalty generally will represent a negotiated amount between the landowner's retained interest for the oil or gas in place and the lessee oil company.

Usually the life of the fee royalty is perpetual. However, its life may be limited by the terms of the instrument under which it was created.

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In some areas, the life of a fee royalty may be governed by state law. There are two types of royalty interest which may be acquired from the landowner. In one, the landowner conveys by royalty deed the title in fee simple to all or a portion of the landowner's royalty interest in the property. The deed may describe the interest sold as a fraction of the "landowner's royalty" or a number of "royalty acres. This transaction may take place before or after leasing.

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The interest thus assigned is a fee royalty. In the other type, the landowner, after leasing, may sell portions of royalty interest in the lease. This is not a fee interest, but a share of the production of oil or gas under this lease, and expires with the termination of the lease. In this respect, it is similar to an overriding royalty. Usually this is after a lease has been granted for the development of the property and there appears to be a prospect of future production. The purchase is usually made by an investor or royalty dealer. The principal issues encountered here are the treatment of acquisition costs and deductions for worthlessness losses claimed as a result of unsuccessful exploration.

The small investor may maintain ledger control accounts of producing royalties and nonproducing royalties. These are supported by separate accounting for each property interest particularly producing properties and usually showing the property interest owned. The landowner usually has the recorded instruments of conveyance for inspection if they are needed. The larger investor may maintain control accounts of Producing Royalties and Nonproducing Royalties, and a subsidiary record known as a Royalty and Fee Land Record for each royalty interest owned.

Such record shows the property, location, description, interest owned, from whom acquired, date acquired, cost, lease information, and record of rentals received. When verifying cost for an investor who has claimed an abandonment loss, the agent should verify that the cost has been removed from the subsidiary record as well as the control account. The cost may have been written off for tax purposes without appropriate charges on the books. When a royalty becomes a producing property, the investment account is transferred from the Non-producing Royalties account to the Producing Royalties account.

At this point, the property should be shown in the return as income producing property subject to depletion. The royalty dealer usually watches oil company leasing operations very closely. When an area of interest is identified, the dealer begins purchasing the fee royalties in the area. The dealer usually has certain investors with whom it regularly deals, and to whom a portion of the royalty interest is acquired, retaining a small fraction as its own investment.

The dealer usually sells a portion of the royalty obtained for a greater sum than the entire cost of the interest obtained. A fraction of the cost corresponding to the fractional interest is retained. The investor or dealer should capitalize, as part of the cost of royalties, commissions, title examination and recording fees, travel expense, or other expenses incurred in connection with the acquisition of the royalty interest. If a single sum was capitalized as cost of the royalty, this may indicate that some of the above acquisition costs were charged to expense.

This would require an analysis of certain expense accounts. Amounts paid or incurred for geological and geophysical before enactment of the Energy Tax Incentives Act of should be capitalized pursuant to Rev. However, amounts paid or incurred for geological and geophysical activity after enactment of the Energy Bill should be amortized over two years under IRC h. After May 17, , the geological and geophysical amortization amount for certain integrated oil companies was extended to five years.

Acquisition costs must also be allocated to the cost basis of the specific royalties acquired. Where multiple royalties are acquired, it may be difficult to determine the accuracy of the taxpayer's allocation of travel, geological, geophysical expenses, and general office expenses. The interests of an investor or operator in mineral deposits as well as the rights to share in the production from such deposits are governed by the terms of a leasing contract or supporting agreement. Through these contracts there may be numerous assignments, conveyances, and dispositions of interest or rights.

By analyzing the various leasing contracts and the resulting tax consequences, the examiner can pick up leads to potential tax adjustments. A substantial amount of examination time can be spent on such analyses and is often a productive and important examination step. The oil and gas lease has progressed from a simple instrument to a complex document. Most leases contain eight principal elements:. Date — Determines the precedence of documents. Habendum clause — Fixes the duration of the lease interest. If production is not attained in the time specified, often called the primary term, the lease expires by its own terms.

Granting clause — Specifies what the lessor has granted and the consideration paid. Royalty clause — Sets out the principal inducement, aside from the cash consideration, for the property owner to sign the agreement. Drilling and delay rental clauses — One of the primary considerations in an oil and gas lease is the early development of the property. Drilling and delay rental clauses specify the manner in which early drilling can be deferred. This may be done for a specified period by the payment to lessors of delay rentals.

However, drilling cannot be deferred past the primary term of the lease without voiding the lease. Description of the property — An accurate description of the property is necessary. A system of land measurements known as the "Rectangular System" is used today in most oil-producing states.

Areas of some oil-producing states, however, are not laid out in this system but are surveyed in parcels, sometimes in irregular geometric patterns. Special considerations — Additional clauses may be inserted in a lease agreement to more fully describe the rights and duties of the parties; such as, drilling restriction near buildings, right to unitize or pool lands, or right to use surface facilities. While most leasing contracts may contain these basic elements, variations in their wording and meaning abound. These contracts vary to such an extent that it would be impractical to talk in terms of a "typical contract.

A lease is a contract between a landowner or mineral owner lessor and a second party lessee. The lessor grants to the lessee the exclusive right to drill for and produce oil, gas, or other minerals on the property described in the lease. A lease usually provides for:. Cash lease bonus payable to the lessor upon the execution of the lease and approval of the title. Delay rental for each expiring year during which the lessee has not commenced drilling operations.

Continuation of the contract between the lessor and lessee as long as oil or gas is produced from the property. The lessor's share of the production is known as the royalty interest or landowner's royalty. This is the working interest and is burdened with the costs of development and operation. The amount of production designated as the landowner's royalty has become fixed by custom. In addition, such landowner may be able to obtain a larger lease bonus in a lump sum or installments.

In lieu of a bonus, the lessor and lessee may prefer a minimum guaranteed royalty arrangement. This might be the most advantageous position for both parties. The lessee does not undertake a specific obligation to develop the property or to pay delay rentals, but does agree that the lease will expire if the property is not developed or rentals are not paid.

Ordinarily, the lessee can abandon the property without penalty. It is customary, however, for the lessee to formally terminate the lease if the lessee desires to surrender the property without development.