1 Copyrighted Materials All Rights Reserved Permission granted, Hein & Associates LLP, for not-for-sale/not-for-profit limited distribution. University of North Texas Institute of Petroleum Accounting OIL AND GAS PRODUCING ACTIVITY DISCLOSURES Joe Blice Hein & Associates LLP Dallas, Texas Introduction Companies with significant oil and gas producing activities face a number of challenging disclosure requirements. For public companies, subpart 1200 of Regulation S-K contains the nonfinancial disclosure requirements, and the FASB s Accounting Series Codification (ASC) Section 932 contains the financial disclosure requirements. Private companies are not subject to the rules of Regulation S-K, nor several sections of ASC 932. This article will describe the disclosure requirements of each, as well as some pitfalls to avoid and common issues raised by the SEC staff. Nonfinancial Disclosure Requirements (Regulation S-K, subpart ) Generally, disclosures required by this section are applicable to public companies in which oil and gas producing activities are material to the entity s operations or financial position. Oil and gas producing activities are material if revenues from those activities are at least 10% of the company s total revenue, operating income or loss, or assets related to oil and gas producing activities are at least 10% of total assets. These disclosures are to be presented by geographic area, and the regulations define those areas as either (a) by country; (b) by groups of countries within an individual continent; or (c) by continent. Any geographic area with more than 15% of the entity s proved reserves earns a spot for specific disclosure. Those areas with less than 15% of the entity s proved reserves may be presented on an aggregate basis. All of the disclosures required by S-K subpart 1200 should be made in the forepart of the registration statement or annual report. The key to the geographical consideration is the 15% threshold of total proved reserves. Take care to ensure that the discussion of properties throughout the document is consistent with the manner in which geographical separations of reserves and other data are disclosed. For instance, if reserves within the United States are discussed and data by field is provided, a comment from the SEC staff may be received that requests all oil and gas 21
2 22 Petroleum Accounting and Financial Management producing activity data be shown by field for those fields within the United States that contain at least 15% of the entity s total proved reserves, notwithstanding the fact that all of those fields are located within one country. Disclosure of Reserves SK-1202 requires reserves be disclosed in a tabular format, consistent with the following example: Natural Oil (MBbls) Gas Liquids (MBbls) Natural Gas (MMcf) Total (Barrel Equivalents) Proved (2) (2) (2) (3) Developed: France 9, ,000 9,833 Asia 10,000 20,000 13,333 USA 2,000 4,000 4,000 6,667 Total Proved Developed 21,000 4,500 26,000 29,833 Proved Undeveloped: France 27,000 4,000 3,500 31,583 Asia 10,000 30,000 15,000 USA 2,000 4,000 4,000 6,667 Total Proved Undeveloped 39,000 8,000 37,500 53,250 Total Proved 60,000 12,500 63,500 83,083 Probable (1) 120,000 25, , ,667 Possible (1) 25,000 8,000 4,000 33,667 (1) Probable and possible reserves are optional disclosures. If these reserves are included, S-K 1202(a)(2) requires a discussion of the uncertainty related to such estimates. (2) Disclose separately, if material: oil, natural gas, synthetic oil, synthetic gas, and any product intended to be upgraded into synthetic oil or gas. If natural gas liquids are immaterial, they should be combined with oil rather than gas.
3 Blice 23 (3) Aggregated total of all products is not a required disclosure. If this information is disclosed, the basis for converting into equivalent units should be the same basis used for computing depletion expense. For instance, one barrel of oil is equivalent to 6,000 cubic feet of natural gas. Registrants frequently disclose the dollar value of their reserves estimates within the table above; and those amounts are usually the present value of the related future net cash flows before the effects of income taxes, or PV-10. Be aware that this is a non-gaap financial measure that is required to be reconciled to the most closely related GAAP measure, which would be the Standardized Measure of Oil and Gas Quantities, or SMOG. This article includes a discussion of SMOG in a later section. The first time a company discloses reserves estimates, or anytime a company discloses material additions to its reserve estimates, S-K 1202 requires a general discussion of the technologies used to establish the appropriate level of certainty for reserves estimates for material properties. The particular properties do not need to be identified. Here is an example of such disclosure from a recently filed registration statement: Technology Used to Establish Reserves Under the SEC rules, proved reserves are those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations. The term "reasonable certainty" implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proven effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In order to establish reasonable certainty with respect to our estimated proved reserves, we used technologies that have been demonstrated to yield results with consistency and repeatability. The
4 24 Petroleum Accounting and Financial Management technologies and technical data used in the estimation of our proved reserves include, but are not limited to, electric logs, radioactivity logs, core analyses, geologic maps and available downhole and production data, seismic data and well test data. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production. Non-producing reserve estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. S-K 1202 requires a discussion of the internal controls used in the reserves estimation effort, including the qualifications of the person primarily responsible for the oversight of such process. If reserves are prepared or audited by an outside engineering firm, the qualification of the person primarily responsible for the preparation of the report must also be disclosed in addition to the qualifications of the person in the company primarily responsible for the oversight of those services. Avoid vague references to generally accepted engineering standards or similar language as this is a frequent subject of SEC comment. Here s an example of such disclosure from a recently filed registration statement: Internal Control Over Reserves Estimation Process We maintain an internal staff of petroleum engineers and geoscience professionals to ensure the integrity, accuracy and timeliness of the data used in our reserves estimation process. Our policies regarding internal controls over the recording of reserves estimates require reserve estimates to be in compliance with the SEC rules, regulations, definitions and guidance and prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our proved reserves are estimated at the property level and compiled by our engineering staff. Our engineering staff interacts with our internal staff of operations engineers and geoscience professionals and with accounting employees to obtain the necessary data for the reserves estimation process. Our internal professional staff works closely with our independent reserve engineers to ensure the integrity, accuracy and timeliness of data that is furnished to them for their independent reserve estimation process. All of our reserve information is provided to our independent reserve engineers. In addition, other pertinent data
5 Blice 25 is provided such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to our independent reserve engineers as part of their evaluation of our reserves. Our Senior Vice President and Chief Operating Officer is primarily responsible for overseeing the preparation of our reserves estimates and has over [years] years of industry experience. Our Senior Vice President and Chief Operating Officer received his B.S. degree in Petroleum Engineering from [university] and is a Licensed Professional Engineer in the State of [state]. Following the preparation of our reserves estimates, for the years ended December 31, 2009, 2010 and 2011, we engaged [independent reserve engineering firm], our independent reserve engineers, to prepare independent estimates of the extent and value of the proved reserves associated with our oil and gas properties. See Independent Reserve Engineers below for further information regarding [independent reserve engineering firm] s reports. Independent Reserve Engineers Our estimates of reserves and related future net revenues at December 31, 2009, 2010 and 2011 were based on reports prepared by [independent reserve engineering firm], our independent reserve engineers, in compliance with the SEC rules, regulations, definitions and guidance and in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Copies of these reports have been filed as exhibits to the registration statement of which this prospectus forms a part. [independent reserve engineering firm] was established in [year] and performs consulting petroleum engineering services, including the issuance of reserves reports and audits, acquisition and divestiture evaluations, simulation studies, exploration resources assessments, equity determinations, and management and advisory services. The technical person primarily responsible for preparing the estimates set forth in the reserves reports included as exhibits to the registration statement of which this prospectus forms a part is [engineer s name]. [Engineer s name] has been practicing consulting petroleum engineering at [independent reserve engineering firm] since [year]. [Engineer s name] is a Licensed Professional Engineer in the State of [state] (No. [license
6 26 Petroleum Accounting and Financial Management number]) and has over [years] years of experience in the estimation and evaluation of reserves. He graduated from [university] in [year] with a Bachelor of Science Degree in [field of study]. [Engineer s name] meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; and he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. If the entity engages an outside party to prepare the reserves estimates, the report of the specialist is required to be filed along with the document in which the estimates are disclosed as an exhibit. Typically, this is included as exhibit 99.X. The report filed would be the letter that customarily appears at the front of a bound reserves report addressed to the company and signed by the engineering firm. The numerous tables that generally follow the letter in the exhibit filed with the SEC do not have to be included. The following are the specific requirements of the report to be filed: (1) The purpose for which the report was prepared and for whom it was prepared; (2) The effective date of the report and the date on which the report was completed; (3) The proportion of the registrant s total reserves covered by the report and the geographic area in which the covered reserves are located; (4) The assumptions, data, methods, and procedures used, including the percentage of the registrant s total reserves reviewed in connection with the preparation of the report, and a statement that such assumptions, data, methods, and procedures are appropriate for the purpose served by the report; (5) A discussion of primary economic assumptions; (6) A discussion of the possible effects of regulation on the ability of the registrant to recover the estimated reserves; (7) A discussion regarding the inherent uncertainties of reserves estimates; (8) A statement that the third party has used all methods and procedures as it considered necessary under the circumstances to prepare the report; (9) A brief summary of the third party s conclusions with respect to the reserves estimates; and (10) The signature of the third party.
7 Blice 27 The SEC has recently commented on several filings regarding the third party reserves report, stating that the discussion of the primary economic assumptions lacked the specific reference price for each product in the report. Specifically, the staff seems to expect that the report states the price used and how it was derived. Here s an example of the language from an exhibit furnished with a recently filed registration statement: Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month in the year ended December 31, [20XX]. For oil and NGL volumes, the average West Texas Intermediate posted price of $[XX.XX] per barrel is adjusted by lease for quality, transportation fees, and regional price differentials. For gas volumes, the average Henry Hub spot price of $[X.XXX] per MMBTU is adjusted by lease for energy content, transportation fees, and regional price differentials. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $[XX.XX] per barrel of oil, $[XX.XX] per barrel of NGL, and $[X.XXX] per MCF of gas. Companies reporting reserves under S-K 1200 rules may also present a reserves sensitivity analysis. This gives the registrant a chance to illustrate how their reserves estimates would be impacted by changes in price or cost. If the registrant chooses to present this information, it must be accompanied by a discussion of the prices and costs used and why those are reasonable. Proved Undeveloped Reserves Item 1203 of S-K requires disclosure of total proved reserves at year end. This should be accomplished by the example table in the previous section. In addition to the total quantity, the registrant must also describe (a) the material changes that occurred in the proved undeveloped (PUD) category during the year; (b) discussion of investments and progress made during the year to develop PUD reserves; and (c) the reasons why material amounts of PUD reserves remain undeveloped for five years or more after their initial disclosure as PUD. The narrative description is a frequent subject of SEC comment. Consider the following example: Company Y s disclosure of future development costs in the prior year amounted to $100,000,000, and in its narrative, Company Y states that it incurred $10,000,000 of development costs during the year to develop PUD reserves. At the current year end, Company Y reports future
8 28 Petroleum Accounting and Financial Management development costs of $105,000,000. The staff may challenge the rate at which Company Y is developing its PUD reserves by stating: Based on your progress during the year it will take over 10 years to fully develop your PUD reserves. Please confirm to us that you will develop your PUD reserves within five years and describe your plans to fund the development costs. Inadequate disclosure of the reasons for material changes in PUD reserves is also a frequent subject of comment. For material increases, include specifics as to why new PUD reserves qualify for booking and what technology supports the conclusion. Examples might include the results of successful drilling that allowed additional PUD locations to be recorded, or acquisitions of acreage on which sufficient analog information exists. For material decreases, state the reasons which might include revisions resulting from additional performance information on analogous wells, or simply due to price decreases. Production, Prices and Costs Item 1204 of S-K requires disclosure, by geographic area and for the last three fiscal years, of (a) production of oil, natural gas, natural gas liquids; and all other products; (b) the average sales price realized for each product; and (c) the average production cost per equivalent unit. Production volumes should be volumes sold rather than volumes produced. For example, if a company has natural gas production and burns a portion of production in compression, then only report those volumes sold rather than amounts produced. Additionally, volumes should be reported net to the entity s interest, and net of royalties and other volumes due to third parties. However, for production in countries outside of the United States, net production before royalties may be presented if more appropriate, as long as that fact is emphasized in the disclosure and in the tabular captions. Production volumes for each product should be stated in their normal units of measure such as barrels for oil and natural gas liquids, and cubic feet for natural gas. Totals should be converted to an equivalent unit using the same conversion method used in computing depletion expense. Average production costs per equivalent unit should exclude severance and ad valorem taxes. Organizing the statement of operations within the financial statements such that severance and ad valorem taxes are presented separately from lease operating expenses will facilitate this exercise.
9 Blice 29 Here is an example of the disclosure from a recently filed registration statement: Year Ended December 31: Production data: Natural gas (MMcf) 3, , , Oil (MBbls) Natural gas liquids (MBbls) Equivalents (MMcfe) 4, , , Average sales prices: Natural gas ($ per Mcf) $ 3.35 $ 3.54 $ 3.40 Oil ($ per Bbl) Natural gas liquids ($ per Bbl) Equivalents ($ per Mcf) Production costs ($ per Mcfe of production) Drilling and Other Exploratory and Development Activities Item 1205 of S-K calls for a disclosure by geographic area for each of the last three years of the number of net productive and dry exploratory and developmental wells drilled. Many companies include both gross and net wells in their tabular presentation, which can be useful information for a reader. The number of wells should be the number of wells completed during each year, irrespective of the spud date.
10 30 Petroleum Accounting and Financial Management Here is an example of the disclosure from a recently filed registration statement: Year Ended December 31: Gross Net Gross Net Gross Net Development Wells Productive Dry Exploratory Wells Productive Dry Total Wells Productive Dry Present Activities Item 1206 of S-K calls for a disclosure by geographic area of the entity s present activities such as the number of wells in process, improved recovery efforts, pressure maintenance operations, and any other material activities. This discussion should be as of a date very close to the filing of the document that includes the disclosure. Wells in process should be expressed in gross and net numbers. Caution the rules say not to disclose undrilled locations, although many companies do. Including this disclosure may draw a comment from the SEC, so including language as to why the information about planned drilling activities is material to a reader is suggested. Delivery Commitments Item 1207 of S-K calls for a disclosure by geographic area of any commitments to provide a fixed quantity of oil or natural gas. If applicable, include any material information about how those commitments will be met. Specifically, the rule requires disclosure of (a) the principal source of the oil or natural gas to be delivered and the quantities expected from each source and for all sources combined; (b) the total quantities of oil and gas that are subject to delivery commitments; and (c) how the entity has ensured that there will be reserves or supplies sufficient to meet delivery commitments for the succeeding three years.
11 Blice 31 This rule requires a discussion of any uncertainties related to those reserves or supplies available to satisfy existing delivery commitments. Examples of such uncertainties might include supplies subject to curtailments or interruption, any factors beyond the registrant s control that may affect the ability to meet the obligations, and the potential impact on earnings in the event that the registrant is unable to fulfill its obligations. If the entity has been unable to fulfill any delivery commitments within the last three years, include a discussion of the related circumstances and the impact on the company s operations. Note that when disclosing reserves and supplies available to fulfill delivery commitments, only include proved developed reserves and quantities available under long-term contracts. Oil and Gas Properties, Wells, Operations, and Acreage Item 1208 of S-K calls for a disclosure of information about the quantity of wells and acreage by geographic area as of a reasonably current date or as of the end of the fiscal year. Disclose the total gross and net wells separately for oil wells and for gas wells. Here is an example of the disclosure of productive wells: Oil Natural Gas Total Gross Net Gross Net Gross Net France Asia USA Total Disclose gross and net undeveloped acreage held under leases and concessions; and discuss concentrations and the minimum remaining terms of leases and concessions. Undeveloped acreage includes those acres on which wells have not been drilled, irrespective of whether there are proved reserves. For example, consider a group of leases covering a 1,000 acre plot with two producing wells on 40 acre spacing, in which a company holds a 100% working interest. Assuming full development, the plot would accommodate 25 wells. There are two proved developed wells on the acreage, and for the sake of this example there are four proved undeveloped locations. The net undeveloped acreage in this area would be 920 acres (25 total wells less 2 developed wells times 40 acres per well). Following is an example of the disclosure of undeveloped acreage. (Note that the disclosure of undeveloped acreage as well as the minimum remaining terms of that acreage has been accomplished in one table.)
12 32 Petroleum Accounting and Financial Management Acres Expiring During the Year Ended December 31: Gross Net Gross Net Gross Net Gross Net France (1) 5,000 3,000 7,000 7,000 1,000 1,000 Asia (2) 8,000 5,000 14,000 10,000 USA (3) 12,000 6,000 14,000 8,000 7,000 4,000 1, Total 17,000 9,000 21,000 15,000 16,000 10,000 15,000 10,600 (1) The company s acreage in France is held under several exploration concessions with five-year renewal clauses. Upon expiration of the initial term, application for renewal is required. Although there can be no assurance that the company s renewal applications will be approved, historically, all such renewals have been approved and it is anticipated that the respective governing bodies will continue to do so. (2) The company s acreage in Asia is generally held under exploration licenses expiring during 2014 and The company anticipates completion of the drilling program on the related acres prior to the expiration of the licenses and exchange of those exploration licenses for production concessions. (3) In 2014, the company has options to extend approximately 15,000 gross (7,500 net) acres for an additional three years by making extension payments.
13 Blice 33 Financial Disclosure Requirements (FASB ASC ) The financial statement disclosures required of entities with significant oil and gas producing activities are different for public and private companies. A portion of the disclosure is typically located in the company s accounting policy footnote, and the remainder can be included in one or more separate footnotes. Certain disclosures required of a public company are considered supplemental information and are customarily unaudited. Generally, all disclosures are required for each period for which a balance sheet and income statement are presented. Financial Statement Disclosure Requirements All Entities Disclose whether the company follows the full cost or successful efforts method of accounting for costs incurred in oil and gas producing activities. This is typically included both on the face of the balance sheet as well as in the accounting policy footnote. The policy disclosure should include a description of what costs are capitalized versus those that are expensed. Be sure to include the policy for capitalized interest, the policy for capitalizing exploratory well costs, the method by which depletion is computed, as well as how impairment is estimated. The company should also disclose how it monitors the costs of unproved properties and how they are either reclassified to proved properties or disposed of through impairment. Of course these considerations are significantly different for full cost and successful efforts. The following is an example disclosure of the policies regarding oil and gas producing activities: Proved Oil and Natural Gas Properties We follow the successful efforts method of accounting for our oil and natural gas producing activities. Under this method, we capitalize all property acquisition costs and cost of development wells as incurred. We capitalize costs to drill and equip exploratory wells pending our determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense. There were no exploratory wells capitalized pending determinations of whether the wells found proved reserves at December 31, 2010 or Geological and geophysical costs, including seismic studies and costs of carrying and retaining unproved properties, are charged to exploration expense as incurred. Expenditures for maintenance, repairs and minor renewals necessary to maintain properties in
14 34 Petroleum Accounting and Financial Management operating condition are charged to workover expense as incurred. Major betterments, replacements and renewals are capitalized to the appropriate property and equipment accounts. We capitalize interest on expenditures for significant exploration and development projects that last more than one year while activities are in progress to bring the assets to their intended use. Through December 31, 2010 and 2011, we had not capitalized any interest costs because the drilling of our exploration and development wells generally lasts less than one year, and capitalized interest on those projects would be inconsequential. Capitalized costs of proved properties are amortized using the unit-of-production basis based on production and estimates of proved reserves quantities. Capitalized costs of proved mineral interests are depleted over total estimated proved reserves, and capitalized costs of wells and related equipment and facilities are depleted over estimated proved developed reserves. On the sale or retirement of a complete unit of a proved property or field, the cost and related accumulated depletion, depreciation and amortization are eliminated from the property accounts, and the resulting gain or loss is recognized in income. On the retirement or sale of a partial unit of proved property, the cost is charged to accumulated depletion, depreciation and amortization unless doing so significantly affects the unit-of-production amortization rate for an entire field, in which case the resulting gain or loss is recognized in income. Unproved Oil and Natural Gas Properties Unproved oil and natural gas properties consist of costs incurred to acquire unproved leases. Unproved lease acquisition costs are capitalized until the leases expire or when we specifically identify leases that will revert to the lessor, at which time we expense the associated unproved lease acquisition costs to impairment. Lease acquisition costs related to successful drilling are reclassified to proved properties. On the sale of an entire interest in an unproved property for cash or cash equivalents, gain or loss is recognized to the extent of the difference between the proceeds received and the net carrying value of the property. Proceeds from sales of partial interests in unproved
15 Blice 35 properties are accounted for as a recovery of costs unless the proceeds exceed the entire cost of the property. Impairment of Oil and Natural Gas Properties We review our proved oil and natural gas properties for impairment whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. We estimate the undiscounted future net cash flows of our oil and natural gas properties and compare such undiscounted future cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, we will adjust the carrying amount of the oil and natural gas properties to fair value. We assess our unproved oil and natural gas properties periodically for impairment on a property-by-property basis based on remaining lease terms, drilling results or future plans to develop acreage and record impairment expense for any decline in value. Oil and Natural Gas Sales Payable Oil and natural gas sales payable represents amounts collected from purchasers for oil and natural gas sales which are either revenues due to other revenue interest owners or severance taxes due to the respective state or local tax authorities. Generally, we are required to remit amounts due under these liabilities within 30 to 60 days of the end of the month in which the related production occurred. Advances from Joint Interest Owners Advances from joint interest owners represent amounts collected from other parties holding working interests in properties operated by us in advance of drilling or workover operations on oil and natural gas wells. As amounts are expended on behalf of the other parties, the advances are applied to joint interest billings. Asset Retirement Obligations Asset retirement obligations (ARO) consist of future plugging and abandonment expenses on oil and natural gas properties. We record the fair value of our ARO in the period in which wells are completed and first placed in service and a corresponding increase in
16 36 Petroleum Accounting and Financial Management the carrying amount of oil and natural gas properties. The liability is accreted to its present value each period and the capitalized cost is depreciated using the unit-of-production method. The accretion costs are recorded as a component of depletion, depreciation and amortization on our consolidated statements of operations. We also adjust the liability for changes resulting from revisions to the timing or the amount of the original estimate. If the liability is settled for an amount other than the recorded amount, a gain or loss is recognized in lease operating expense. Lease Operating Expense Production costs, including pumpers' salaries, saltwater disposal, repairs and maintenance and other operating expenses are expensed as incurred and included in lease operating expense on our consolidated statements of operations. All entities are required to provide disclosure about continued capitalization of exploratory well costs for each period in which an income statement or statement of operations is presented. The following items are required under this disclosure: (1) The amount of capitalized exploratory well costs pending the determination of proved reserves, with changes in those amounts for each year in which an income statement appears. Changes in those costs are categorized as either additions to capitalized costs, costs reclassified to wells and equipment resulting from the determination of proved reserves, and costs charged to expense. Amounts capitalized and subsequently expensed or reclassified to wells and equipment during the same annual period need not be included in the disclosure of changes. (2) The amount of capitalized exploratory well costs that have been capitalized for over one year, with an aging of those amounts and the number of projects. (3) For exploratory costs capitalized more than one year, a narrative description of the company s efforts toward evaluating the reserves and the matters required to complete the determination of whether the activity resulted in proved reserves.
17 Blice 37 Following is an example disclosure that satisfied these requirements (narrative omitted): The following table summarizes the costs incurred to drill and equip exploratory wells pending the determination of whether proved reserves have been found as of December 31: Project A $ 6,000 $ 10,000 $ Project B 600 3,000 5,000 Total $ 6,600 $ 13,000 $ 5,000 The following table provides an aging of costs incurred to drill and equip exploratory wells (based on the date of the projects inception) pending the determination of whether proved reserves have been found as of December 31: Capitalized exploratory well costs that have been capitalized for: One year or less $ 5,400 $ 6,400 $ 1,600 One to three years 1,200 6,600 3,400 Total $ 6,600 $ 13,000 $ 5,000 Number of projects Financial Statement Disclosure Requirements Publicly Traded Companies Publicly traded companies are required to make all the disclosures discussed in the preceeding plus additional disclosures about capitalized costs, costs incurred, results of operations, proved reserves, and the standardized measure of oil and gas quantities. The disclosures should be made for all consolidated entities as a whole, with separate disclosure for the information pertaining to equity method investees, net to the reporting entity s interest. If the company has non-controlling interests in subsidiaries with oil and gas producing activities, the disclosures should state that fact and the approximate amounts attributable to non-controlling interests if material. Also, the disclosures should be presented by geographic area and in the aggregate. Refer
18 38 Petroleum Accounting and Financial Management to the discussion of nonfinancial disclosure requirements for more detail on geographic areas. Capitalized Costs: Disclose the aggregate capitalized costs for oil and gas producing assets and the aggregate balance of accumulated depletion, depreciation, amortization and valuation allowances at the end of each year for which a balance sheet is presented. The following is an example of a tabular presentation of these items, which can be included on the face of the balance sheet or in the notes to the financial statements: Our oil and natural gas properties consisted of the following as of December 31: Mineral interests in properties: Unproved properties $ 32,500 $ 65,000 Proved properties 25,000 30,000 Wells and related equipment and facilities 325, ,000 Support equipment and facilities 5,000 8,000 Uncompleted wells and related equipment 13,000 5,000 Total capitalized costs 400, ,000 Accumulated depletion, depreciation and amortization (170,000) (215,000) Net capitalized costs $ 230,500 $ 343,000
19 Blice 39 Costs Incurred for Property Acquisition, Exploration, and Development Activities: Disclose costs incurred for each year for which an income statement is presented, irrespective of whether the costs are capitalized or charged to expense. The categories to be presented are as follows: (1) Acquisition costs all costs incurred to purchase, lease or otherwise acquire a property, whether proved or unproved. (2) Exploration costs may be incurred before or after acquiring a property. Includes all geological and geophysical costs, the costs of carrying and retaining undeveloped properties such as delay rentals, taxes, legal costs for title defense and the maintenance of land records. (3) Development costs costs to drill and equip wells with proved reserves. The following is an example of a tabular presentation of these items: Our costs incurred in oil and natural gas activities consisted of the following for the year ended December 31: Property acquisition costs: Unproved properties $ 19,000 $ 1,000 $ 65,000 Proved properties 64,000 2,000 Exploration costs 24, ,000 85,000 Support equipment and facilities 8,000 5,000 8,000 Development costs 6,000 13,000 22,000 Total costs incurred $ 121,000 $ 122,000 $ 182,000
20 40 Petroleum Accounting and Financial Management Results of Operations for Oil and Gas Producing Activities Disclose the net results of oil and gas producing activities for each year for which an income statement is presented: revenues less production costs, exploration expenses, depletion, depreciation and amortization expense, impairments and income taxes. If oil and gas producing activities are substantially all of the entity s business and there are no reportable segments, then this disclosure can be omitted. If the entity has reportable segments, those disclosures can satisfy this requirement. Note that these disclosures, if required, do not include general and administrative expenses. Income taxes are to be computed using the statutory rates applicable to the company s oil and gas operations and reflect deductions and tax credits reflected in the entity s income tax for the period. Proved Oil and Gas Reserve Quantities: Disclose the company s net quantities of proved reserves in the aggregate and by product at the beginning and end of each year, along with the changes in those quantities. Disclose at each year end, the quantities of total proved developed reserves; changes in those quantities are not required. Consistent with the comments on nonfinancial disclosure requirements elsewhere in this article, products include oil, natural gas liquids, natural gas, synthetic oil, synthetic gas, and any other product that is intended to be upgraded into synthetic oil or gas. Changes in those quantities fall into six categories: (1) Revisions of previous quantity estimates these are any changes in reserves resulting from new information about proved reserves that existed in the prior year, including performance revisions obtained from drilling and production history or changes in economic factors (price and/or costs). (2) Improved recovery this would result from application of new techniques that allow the entity to record additional reserves. If not significant, improved recovery can be included in revisions of previous quantity estimates. (3) Purchases of minerals in place result from the acquisition of proved properties. (4) Extensions and discoveries result from either extensions of proved acreage through additional drilling or discoveries of new reservoirs. (5) Production same as sales volumes as discussed in the nonfinancial disclosure requirements section.
21 Blice 41 (6) Sales of minerals in place very simply the sale of properties with proved reserves during the period. For each material change in quantities, provide a narrative explanation describing the reasons for such change. This has historically been an area of frequent SEC comment. Here is an example disclosure from a recently filed registration statement: Oil (MBbls) Natural Gas Liquids (MBbls) Natural Gas (MMcf) Total (BOE) Total Proved Reserves: Balances January 1, ,121 1,972 1,244 58,417 Extensions, discoveries and other additions 3, ,478 Purchases of minerals in place 105, ,407 Production (6,111) (43) (26) (6,525) Revisions to previous estimates (3,748) (739) (612) (11,854) Balances December 31, ,525 1, ,923 Extensions, discoveries and other additions 91, ,575 Sales of minerals in place (3,641) (3,641) Production (8,852) (48) (24) (9,284)
22 42 Petroleum Accounting and Financial Management Revisions to previous estimates 11,548 (112) 3 10,894 Balances December 31, ,497 2, ,467 Extensions, discoveries and other additions 61,826 3,959 1,035 91,790 Sales of minerals in place (24,530) (24,530) Acquisitions ,111 Production (8,896) (251) (18) (10,510) Revisions to previous estimates (15,951) 46 (585) (19,185) Balances December 31, ,283 6,066 1, ,143 Proved Developed Reserves: December 31, , ,968 December 31, , ,690 December 31, ,695 1, ,249 The following is a discussion of the material changes in proved reserve quantities for the years ended December 31, 2009, 2010 and 2011: Year Ended December 31, 2009 The negative revision of our proved reserves for this period related to decreases in oil and natural gas prices from those used to calculate the prior year's proved reserves was 5,006 MMcfe, while 6,848 MMcfe related to well performance. Our additions resulting from extensions consisted of 1,697 MMcfe related to the drilling of new wells and 2,781 MMcfe related to new proved undeveloped locations. The increase in natural gas proved reserves from
23 Blice 43 acquisitions was primarily related to our acquisition of [field name] properties, while the increase in acquisitions of oil and natural gas liquids proved reserves related to the acquisition of additional interests in some of our [field name] properties. The oil and natural gas prices used in calculating our reserves at December 31, 2009, were the unweighted averages of the historical first-day-of-the-month prices for the prior 12 months of $57.65 per Bbl of oil and $3.87 per MMBtu of natural gas. Year Ended December 31, 2010 The positive revision of natural gas reserve quantities was primarily due to improved well performance in our [field name] wells, while the negative revisions of our oil and natural gas liquids reserve volumes was due to performance in certain of our [field name] properties. Our additions related to extensions consisted of 29,942 MMcfe related to the drilling of new wells and 67,633 MMcfe related to new proved undeveloped locations. Additionally, divestitures during the period related to the sale of natural gas properties in the [field name]. The oil and natural gas prices used in calculating our reserves at December 31, 2010, were the unweighted averages of the historical first-day-of-the-month prices for the prior 12 months of $75.96 per Bbl of oil and $4.38 per MMBtu of natural gas. Year Ended December 31, 2011 The negative revision in natural gas primarily related to well performance in the [field name], while the negative revision of oil and natural gas liquids resulted from well performance in [field name] properties. Our additions related to extensions consisted of 7,104 MMcfe related to the drilling of new wells and 84,686 MMcfe related to new proved undeveloped locations. Additionally, divestitures during the period related to the sale of natural gas properties in the [field name]. The oil and natural gas prices used in calculating our reserves at December 31, 2011, were the unweighted averages of the historical first-day-of-the-month prices for the prior 12 months of $92.71 per Bbl of oil and $4.12 per MMBtu of natural gas.
24 44 Petroleum Accounting and Financial Management Standardized Measure of Discounted Future Cash Flows (SMOG) Disclose SMOG at each year end and changes in SMOG for each year for which an income statement is required. SMOG is generally the present value of future net cash flows from the company s reserves report less the present value of future income taxes. The following are the components of SMOG: Future cash inflows (revenues from the reserves report) Less future production costs (lease operating expense and all operating costs from the reserves report) Less future development costs (from reserves report, if immaterial, can be combined with future production costs) Less future income tax expenses (estimated using net cash flows less the tax basis of oil and gas properties, less any tax credits or net operating loss carryforwards available to offset future taxable income, multiplied by the statutory rates attributable to the company s operations) Less discount at 10% Equals standardized measure Following is an example disclosure of SMOG: Future cash flows $ 550,000 $1,100,000 $1,500,000 Future production costs (180,000) (305,000) (370,000) Future development costs (175,000) (320,000) (465,000) Future income tax expense (45,000) (135,000) (200,000) Future net cash flows 150, , ,000 10% annual discount for estimated timing of cash flows (125,000) (140,000) (165,000) Standardized measure of discounted future net cash flows $ 25,000 $ 200,000 $ 300,000
25 Blice 45 The following are the categories of changes in SMOG: Net change in sales and transfer prices and in production (lifting) costs related to future production Represents the change in average net cash flow per unit before development costs or income taxes multiplied by prior year reserves adjusted for current year production and any sales of minerals in place. Changes in estimated future development costs Computed as a variance analysis based on the net difference in future development costs year over year after taking into account the effects of development costs incurred during the period, and additions of development costs resulting from extensions and discoveries, property sales, and other specifically identified items. Sales and transfers of oil and gas produced during the period Derived from the face of the statement of operation, revenues less lease operating expenses and severance and ad valorem taxes. Net change due to extensions, discoveries, and improved recovery Net cash flow added as the result of these additions, best supported by obtaining a specific reserves run from internal or external engineering to determine the undiscounted future net cash flows attributable to this type of change. Net change due to purchases and sales of minerals in place Net cash flow added or removed as the result of these additions, best supported by obtaining a specific reserves run from internal or external engineering to determine the undiscounted future net cash flows attributable to this type of change. Net change due to revisions in quantity estimates Can be computed as a variance analysis by multiplying the volume change by the current period net revenue per equivalent unit, taking care to include or exclude related future development costs as appropriate. Previously estimated development costs incurred during the period Use actual costs incurred related to properties included in the prior year report as proved developed nonproducing or proved undeveloped. Accretion of discount two methods are acceptable. Compute the discount on the cash flows from last year s reserve report using the current year s discount factors, or simply multiply the prior year s discounted future net cash flows by 10%. Other unspecified and unexplained changes. Generally, this amount is what is needed to balance the calculation and should be relatively small.
26 46 Petroleum Accounting and Financial Management Net change in income taxes Compute as the change in undiscounted amounts multiplied by the current period s average discount factor or the change in the discounted tax amounts. The following is an example disclosure of the changes in SMOG: Balance, beginning of period $ 56,000 $ 25,000 $200,000 Net change in sales and transfer prices and in production (lifting) costs related to future production (25,000) 200,000 25,000 Changes in estimated future development costs 4,000 (125,000) (145,000) Sales and transfers of all oil and gas produced during the period (13,000) (24,000) (45,000) Net change due to extensions, discoveries and improved recovery 2, , ,000 Net change due to purchase of minerals in place 35,000 40,000 Net change due to divestitures (3,000) (9,000) Net change due to revisions in quantity estimates (12,000) 4,000 (10,000) Previously estimated development costs incurred during the period 3,000 20,000 25,000 Accretion of discount 6,000 6,000 13,000 Changes in timing and other (10,000) 7,000 1,000 Net changes in income taxes (21,000) (100,000) (45,000) Standardized measure of discounted future net cash flows $ 25,000 $200,000 $300,000