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 The U. The requirement to capitalize foreign IDC does not apply to dry holes or nonproductive wells. Can a taxpayer file an amended return and deduct the unamortized IDC in the year paid or incurred for wells that prove to be nonproductive after the close of the taxable year?
The Service's view is that an amended return may be filed for that year deducting the unamortized IDC for the wells that prove to be unproductive after the close of the taxable year. If the taxpayer previously deducted the unamortized IDC in the year the nonproductive well was plugged and abandoned, an amended return must be filed taking into income the amount that was deducted.
Examiners should be aware that there are some important differences in the tax treatment of Intangible Drilling Costs IDC and "nonproductive well costs". While the treatment of IDC under the IRC is generally favorable for taxpayers, the treatment of nonproductive well costs is even more favorable.
Nonproductive well costs are the IDC incurred in the drilling of a nonproductive well. The term nonproductive well does not include an injection well other than an injection well drilled as part of a project that does not result in production in commercial quantities ".
The production of oil and gas in "commercial quantities" is not defined by the code, regulations or revenue rulings. A brief mention in the Committee Report on P. As explained in Rev. Similarly, a well should not be treated as nonproductive if it is still producing oil and gas, or is capable of being restored to economic production, even if it has not yet generated enough income to offset drilling and equipment costs.
For purposes of this section of the IRM the term "successful well" will be used to describe a well that is not a nonproductive well. Differences in tax treatment of IDC on successful wells and nonproductive wells costs include:. Taxpayers normally elect to currently deduct IDC incurred in the U. For those that elect to capitalize such IDC, Treas. In contrast, nonproductive well costs incurred by U.
IRC b requires integrated oil companies to capitalize 30 percent of the IDC incurred in drilling successful wells in the U. In contrast, percent of nonproductive well costs incurred by integrated oil companies are currently deductible.
However, the costs of drilling a nonproductive well are not included in the AMT preference item. However, Treas. Reg 1. Without conclusive evidence that a well is nonproductive as of the date of filing its original tax return, a taxpayer should assume that IDC incurred during the year was related to a successful well.
If the well is later determined to be nonproductive the taxpayer may file an amended return to treat the IDC as nonproductive for that taxable year rather than the year in which the well was determined to be nonproductive. Both IDC on successful wells and nonproductive well costs are normally reported as an Other Deduction on Line 26 of a corporate income tax return.
Examiners may find that they are combined and reported only as "Drilling Costs". Examiners should request separate lists of the two types of costs by well preferably in electronic format so they can be analyzed. Examiners should also look for unusually large figures and also for figures that suggest an estimated amount was deducted e. The tax treatment of drilling costs is dependent to a large degree upon operational decisions made at the conclusion of the drilling phase.
When the drilling of a well reaches total depth the operator must decide how to proceed. Information will first be gathered from well "logging" tools sensors to help determine certain characteristics of the geologic layers and any fluids contained within. Other tools that can obtain small cores and fluid samples from prospective reservoirs may also be lowered into the well and then retrieved.
On rare occasions the operator will attempt to produce the well to verify that a commercial rate of oil and gas can be achieved. Based on the results, the operator will place the well into one of the following conditions:.
Cement will be placed within the well in a number of intervals and a metal plate welded to the top near the ground level. Temporarily Abandoned. The drilling rig may install the final string of casing in the well before leaving the drill site. Future operations, such as installing the tubing and perforating the well, may be performed by a less expensive "completion rig". The operator will file a Temporarily Abandoned or Idle Well report with the appropriate regulatory agency. The final string of casing and the well tubing is installed.
The well is perforated and the christmas tree is installed. A retrievable plug or check-valve may be set in the tubing just below the christmas tree for safety purposes, but the well is otherwise ready to produce. Shut-in status may occur when there is not yet a pipeline or tank battery for the well to flow into. The operator will file a Shut-in or Idle Well report with the appropriate regulatory agency.
The well is completed and production to the pipeline or tank battery has been established. The operator will file a Completed Well report with the appropriate regulatory agency. Since there are numerous regulatory agencies, the title of the well status reports and the information that must accompany them when submitted varies. Tax Considerations - When a well has been drilled and then placed into either temporarily abandoned or shut-in status, the drilling costs should generally be treated as IDC.
Examiners often find that wells that are temporarily abandoned are improperly treated as nonproductive wells or improperly written off as abandonment losses. When a well is plugged and abandoned immediately after drilling, the well is clearly nonproductive, and drilling costs can be treated as such. The assistance of an IRS engineer may be necessary.
The option with respect to IDC does not apply to expenditures by which the taxpayer acquires tangible property ordinarily considered as having a salvage value. If the taxpayer fails to deduct costs qualifying as intangible drilling costs as expenses on the taxpayer's return for the first taxable year in which the taxpayer pays or incurs such costs, the taxpayer is deemed to have elected to recover such costs through depletion to the extent that they are not represented by physical property, and through depreciation to the extent that they are represented by physical property.
Normally, taxpayers will elect to deduct IDC currently. The timing of a tax deduction for many taxpayers is an important factor in the planning of a good tax program. The deductions for IDC could be a major item in this tax planning. Like other deductible expenses, the deductions for IDC depend on the taxpayer making the election to deduct the expenses, method of accounting, drilling contract provisions, and many other factors. For taxpayers using the cash basis method of accounting, IDC is deductible in the year paid, under certain conditions, although the work is performed in the following year.
Refer to Pauley v. Taxpayer A owns percent of the working interest in an oil and gas lease and enters into a drilling agreement with Taxpayer B for the drilling of a well on Taxpayer A's property.
Taxpayer A is on the cash basis of accounting and paid Taxpayer B as provided in the agreement on December 29, The Government's position regarding the deduction of prepaid IDC by a cash basis taxpayer is set out in Rev. Commissioner , 79 TC 7 Ordinarily, the prepaid expense is deductible if:. The drilling contract requires a prepayment of the agreed amount. The prepayment must not be a mere deposit. In the above example, Taxpayer A is entitled to deduct the prepaid amount in since Taxpayer A has met all the conditions set forth in the revenue rulings.
The examining agent should be aware that, generally, when there are several working interest owners of the property, the operator of the property is the person that makes the contacts with the drilling company and enters into the drilling contract for the drilling of the well.
The drilling contractor will require the prepayment of the agreed amounts from the operator. It is, therefore, unlikely that a drilling contract would require a prepayment from any interest owners other than the operator. The prepayment to the operator by a nonoperator working interest owner does not satisfy the requirements for a deductible prepayment unless the operator was required to make a prepayment in accordance with the rules set out above.
The method of accounting used by the operator generally controls the deductibility of any amount to the working interest owners. The drilling contract and prepayment agreement should always be examined to learn the facts regarding every material prepayment requirement. The above discussion and revenue rulings apply only to the cash basis taxpayer. The deduction to the accrual basis taxpayer is controlled by the general rules regarding the accrual of any type of expense including the economic performance requirements of IRC IRC h.
The method of accounting used by the individual taxpayer, as well as by the operators of working interests, is very important in determining the year of deduction of intangible drilling and development expenses. Because the cash basis method of accounting gives the taxpayer more control over the timing of a deduction, most taxpayers use this method of accounting.
Cash Method — The cash method of accounting in the oil and gas business is no different than in any other business. The expenses are deductible when incurred and paid, and the income is taxable when received. The general rules of IRM 4. Accrual Method — The accrual method of accounting in the oil and gas business is similar to any other business. The expenses are deductible when all events have occurred to fix the liability and income is taxable when received or earned.
If the taxpayer owns drilling equipment and drills its own wells, the IDC is deductible when incurred. If the taxpayer has contracted for the drilling of the wells, the provisions of the drilling contract will fix the liability for the accrual of the expense deduction. Special attention should be given to the contract provisions in order to determine the proper accruals of any year end. Completed Contract Method — The use of the completed contract method of accounting for the deduction of IDC can not be used by the accrual basis taxpayer to postpone the deduction until a succeeding year.
The cost must be deducted in the year paid or incurred, depending on the taxpayer's general method of accounting. The Environmental Protection and Management Guideline guides industry through the requirements and processes associated with the Commission's legislative authorities.
The Fugitive Emissions Management Guideline guides industry through the regulatory requirements and guidance for fugitive emissions management in B. Chapter 4 provides information on regulatory requirements in the construction phase of the oil and gas regulatory life cycle.
Chapter 5 provides information on operational regulatory requirements for geophysical activities. The Road Notice of Intent to Deactivate Form is required by the Commission when a permit holder plans to deactive an oil and gas road.
The Road Notification Form allows permit holders to notify the Commission of temporary road closures or restrictions and must be submitted within 30 days of stoppage of use. The permit holder must also provide notification of resumption of use upon restarting use of the road, using the Road Notification Form. Chapter 7 provides information on operational regulatory requirements for well activities, including considerations for well data and well data submission.
The Summary Information: Discovery Wells provides information required to designate a well as a discovery well. A discovery well is a well that has encountered a previously undiscovered pool. The Summary Information: Special Data Wells provides information required to designate a well as a special data well. A special data well recognizes operators for obtaining specified, high value well data by providing extended confidentiality.
This document outlines the water source approval process and the requirements for hydrogeological assessment and data collection, monitoring, and data reporting. Chapter 8 provides information on operational regulatory requirements and guidance for well drilling activities.
The Flaring and Venting Reduction Guideline guides industry through the best practices for flaring, incinerating and venting gas at a facility. The Oil and Gas Handbook Drilling Waste Management Chapter provides industry with the requirements for storage and disposal of drilling wastes. Chapter 9 provides information on operational regulatory requirements and guidance for well completion, maintenance and abandonment activities.
Hydraulic Fracture Data - CSV Requirements Guide is intended to guide users through the processes for submitting hydraulic fracturing data electronically. The Hydraulic Fracturing Electronic Submission - Frac Submission Template provides users with the exact format required for creating a.
The Hydraulic Fracturing Electronic Submission - Perf Submission Template provides users with the exact format required for creating a. The Management of Saline Fluids for Hydraulic Fracturing Guideline is intended to provide guidance for permit holders planning to construct saline fluid storage facilities. Chapter 10 provides an overview of operational regulatory requirements for production and injection disposal activities.
Chapter 11 provides information on operational regulatory requirements for pipeline activities. The Commission has provided separate documentation to the identified permit holders for their self-assessment as part of the phase 1 of the compliance process.
The guideline, previously known as the Measurement Guideline for Upstream Oil and Gas Operations, has been updated with information including the addition of Chapter 6: Determination of Production at Gas Wells; updates to requirements and references; introduction of a decision tree analysis for well testing, and updates to measurement requirements for consistency with other provincial regulators.
Customers wishing to make payments, conduct research, or submit paperwork in person will need to do so before PM on Friday. This forms manual refers to the forms required by The Texas Railroad Commission RRC relating to the drilling, production and transportation of oil and gas.
The forms and procedures pertaining to oil and gas regulatory filings are for informational and instructional purposes only and are not intended to represent a comprehensive study of oil and gas forms and filing procedures.
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