Disclosures About

Oil and Gas Producing Activities AICPA Oil and Gas Conference, Denver, CO

November 14, 2012

Joe Blice, CPA, Audit Partner, Dallas

Joe has 16 years of professional experience and serves as an Audit Partner in the Dallas office of Hein & Associates LLP. He provides a wide range of audit and accounting services for both public and privately held companies in the energy industry. Joe has significant experience with Securities and Exchange Commission disclosure and reporting requirements, and assists companies with mergers and acquisitions as well as initial and secondary securities offerings. Joe also specializes in share-based payment arrangements and foreign currency translation.

Joe serves as the Local Energy Niche Leader for the Dallas office and he is a member of the Council of Petroleum Accountants Societies (COPAS) where he has served in various capacities since 2003. He also serves on the conference committee of the North American Petroleum Accounting Conference (NAPAC), and is a frequent speaker at various energy related presentations.

Prior to joining Hein & Associates LLP in 2003, Joe served as the Controller of a publicly-traded oil and gas company where he assisted with a merger and a private placement for the organization. He began his career as a member of the audit staff of Ernst &Young LLP after graduating from the University of Oklahoma.

Learning Objectives

• SEC Disclosure Requirements

– Regulation S-K 1200

• US GAAP Disclosure Requirements

– FASB ASC Topic 932-235

– FASB ASC Topic 932-360

• SMOG Example

• Frequent SEC Comments interspersed

SEC Disclosure Requirements

SEC Disclosure Requirements

• What goes in the front part of a document?

– Registration statements – Item 11 of Form S-1

– Annual reports on Form 10-K or equivalent - Item 2 -

Properties

Applicability of S-K 1200

• Material oil and gas producing activities

– 10% of revenue

– 10% of operating income

– 10% of total assets

General Note (S-K 1201)

• 15% Threshold related to geographic area

– By country

– By groups of countries within an individual content

– By continent

– Catch-all – ―as appropriate for meaningful disclosure in the

circumstances‖

• Aggregation is allowed

• Applies to practically all disclosures

Disclosure of Reserves (S-K 1202)

• Tabular Disclosure of Reserves

– Proved developed

• PDP

• PDNP

– Proved undeveloped

– Probable (optional)

– Possible (optional)

Disclosure of Reserves (S-K 1202)

• Tabular Disclosure of Reserves (continued)

– Oil in barrels

– Natural gas liquids (if significant) in barrels

– Natural gas in cubic feet

– Synthetic oil

– Synthetic gas

– Any product intended to be upgraded into

synthetic oil or gas

• See Example 1

Disclosure of Reserves (S-K 1202)

• Aggregated Totals and Equivalent Units

– Not required

– State basis of conversion

• Dollar values in table

– Frequently disclosed

– PV10 is a non-GAAP measure

Disclosure of Reserves (S-K 1202)

• Technology Used to Establish Reserves

– Initial reporting

– Material additions

• See Example 2

Disclosure of Reserves (S-K 1202)

• Internal Controls used in the Reserves Estimation

Effort

– Qualifications of the company representative responsible

– Qualifications of the person primarily responsible for the

preparation of the report if third party is used

– These are areas of frequent SEC staff comment

• See Example 3

Disclosure of Reserves (S-K 1202)

• Third Party Reserves Reports

– Filed as an exhibit to the public document

– Letter at the front of the report

– Detail tables not required

Disclosure of Reserves (S-K 1202)

• Requirements of Third Party Reserves Reports

– The purpose for which the report was prepared and for whom it was prepared;

– The effective date of the report and the date on which the report was completed;

– The proportion of the registrant’s total reserves covered by the report and the geographic area in which the covered reserves are located;

– 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;

Disclosure of Reserves (S-K 1202)

• Requirements of Third Party Reserves Reports (continued)

– A discussion of primary economic assumptions;

– A discussion of the possible effects of regulation on the ability of the registrant to recover the estimated reserves;

– A discussion regarding the inherent uncertainties of reserves estimates;

– A statement that the third party has used all methods and procedures as it considered necessary under the circumstances to prepare the report;

– A brief summary of the third party’s conclusions with respect to the reserves estimates; and

– The signature of the third party.

Disclosure of Reserves (S-K 1202)

• Primary economic assumptions – frequent SEC

comment area

– State the specific price used and how derived

• See Example 4

Disclosure of Reserves (S-K 1202)

• Optional Sensitivity Analysis

– What-if summary of reserves

– State prices used

– State cost assumptions

– State why these are reasonable and useful to a reader

Proved Undeveloped Reserves (S-K 1203)

• Total quantities of PUD at year end

• Material changes during the year, including

conversion to PDP/PDNP

• Investments and progress made during the year in

converting PUD to PDP/PDNP

• Why material amounts remain booked for five years

or more after disclosure as PUD

Proved Undeveloped Reserves (S-K 1203)

• Frequent Areas of SEC Staff Comment

– Inadequate disclosure of reasons for material changes

– Inadequate disclosure of technologies used to book additional PUDs

– Inadequate disclosure of progress toward converting PUD to PDP/PDNP

– Mathematically impossible development rates

– Reserves remaining booked more than five years from initial record

– Reserves scheduled to be developed more than five years hence

• Be very specific in your discussion

Production, Prices and Costs (S-K 1204)

• Production by final product sold

• Average sales price

• Average production cost EXCLUDING severance

and ad valorem taxes

• See Example 5

Production, Prices and Costs (S-K 1204)

• Production Volumes

– Sales volumes only

– Compression and shrinkage excluded

• Net to the Entity’s interests

– Exclude royalties, except in certain circumstances, and with disclosure of reasons

• Stated in Normal Units

– Barrels for oil, condensate and natural gas liquids

– Cubic feet for natural gas

– Synthetics in the final unit as sold

• Equivalent Units

– Express in same basis as used in depletion calculation

– Disclose equivalency ratio

Drilling and Other Exploratory and Development

Activities (S-K 1205)

• Drilling & exploratory activities by geographic area for each of the last three fiscal years:

– Number of net productive and dry exploratory wells drilled

– Number of net productive and dry developmental wells drilled

• Difference between developmental versus exploratory

• Wells completed during the year irrespective of spud date

• See Example 6

Present Activities (S-K 1206)

• Wells in process

– Gross and net

– Undrilled locations – rules say not to disclose, but many do

• Improved recovery efforts

• Pressure maintenance operations

• Any other material activities

Delivery Commitments (S-K 1207)

• Wells in process

– Gross and net

– Undrilled locations – rules say not to disclose, but many do

• Improved recovery efforts

• Pressure maintenance operations

• Any other material activities

• See Example 7 for Present Activities and Delivery Commitments

Oil and Gas Properties, Wells, Operations and

Acreage (S-K 1208)

• Wells by geographic area, gross and net

• Example:

Oil Natural Gas Total

Gross Net Gross Net Gross Net

France 11 10.5 43 16.8 54 27.3

Asia 6 5.9 78 70.3 84 76.2

USA — — 132 39.0 132 39.0

Total 17 16.4 253 126.1 270 142.5

Oil and Gas Properties, Wells, Operations and

Acreage (S-K 1208)

• Gross and Net Undeveloped Acreage by geographic area

– Leases

– Concessions

• What does undeveloped mean?

– Acres on which wells have not been drilled

– Presence of reserves is irrelevant

• Example:

– Assume 1,000 acre plot with two wells, and 40 acre spacing

– Assuming full development, there would be 25 locations

– 920 undeveloped acres (25 total less two drilled times 40 acres)

Oil and Gas Properties, Wells, Operations and

Acreage (S-K 1208)

• Discuss minimum remaining terms

• Frequent area of SEC comment

• See Example 8

US GAAP Disclosure Requirements

US GAAP Disclosure Requirements

• Different requirements for public and private companies

• Some included in accounting policy footnote

• Remainder in Supplementary Information, which is NOT

required to be audited, and is not required for private

companies

• All disclosures generally required for each year in which a

balance sheet and an income statement or statement of

operations is required

• Same requirements for geographic areas as SEC rules

US GAAP Disclosure Requirements

• Applicable to public and private entities

• Disclose method of accounting

– Full Cost (Regulation S-X, Rule 4-10)

– Successful Efforts (ASC 932)

• Usually appears on face of balance sheet,

accompanied by detail discussion in the summary of

significant accounting policies

• Depletion policy is an area of SEC comment focus

• See Example 9

Accounting Policy Disclosure (all entities)

• Areas to watch for

– Depletion policy – mineral interests versus all others

– Capitalized interest

– Capitalizing exploratory well costs

– Impairment – details on process for estimating fair value

– Process for monitoring and disposing of unproved mineral

interests

Accounting Policy Disclosure (all entities)

• Full Cost Method Companies

– Generally same disclosures required

– Add disclosure of costs excluded from depletion

• Unproved properties

• Major development projects not yet in service

• Aging of costs for the most recent three years and in the aggregate

for costs incurred more than three years ago

Accounting Policy Disclosure (all entities)

• Suspended Well Costs

• Successful Efforts Only

• Amount of capitalized costs pending the determination of proved reserves

• Changes in those amounts

• Amounts capitalized for more than one year

– Aging of amounts and the number of projects

– Narrative discussion of progress toward evaluating reserves

• See Example 10

GAAP Disclosure for Public Companies

• Capitalized costs

• Costs incurred

• Results of operations

• Proved reserves, and changes thereto

• Standardized measure, and changes thereto

Capitalized Costs

• Aggregate capitalized costs

• Aggregate accumulated depletion, depreciation,

amortization and valuation allowances

– Disparity in impairment rules and oil and gas rules

• See Example 11

Costs Incurred

• Acquisition costs

– all costs incurred to purchase, lease or otherwise acquire a property, whether proved or unproved.

• 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.

• Development costs

– costs to drill and equip wells with proved reserves.

• See Example 12

Results of Operations

• Revenues

• Production costs

• Exploration expenses (generally N/A for Full Cost)

• DD&A (including accretion of ARO liabilities)

• Income tax expenses (statutory rate, reflect specific

credits)

• Results of operations

• Excludes corporate overhead and interest costs

Results of Operations

• May exclude separate table if:

– substantially all of the entity’s operations are oil and gas

production; and

– Geographic segment disclosures, if required are made

elsewhere.

Proved Reserves

• Net quantities at the beginning and end of each year

• Royalties included, if known. If not, state that fact and the production received for the year

• Volume roll forward for all periods for which an income statement is presented

• Such disclosures must be made

– In the aggregate and

– For the enterprises’ home country (if material) and

– For each foreign geographic area (countries can be grouped)

Proved Reserves

• 100% of net reserve quantities attributable to the

parent and 100% of net reserve quantities of

subsidiaries, whether or not wholly owned

• If a significant portion of quantities are attributable to

minority interests, that fact and the approximate

portion

• If proportionate consolidation, then only include the

Company’s share

• If equity method, disclose separately

Proved Reserves

• Oil and natural gas liquids to be stated in barrels

• Natural gas in cubic feet

• Explain important economic factors or uncertainties

affecting particular components (high lifting costs,

facilities in process, punitive marketing arrangements

Proved Reserves

• Changes in proved reserves for last three years

– Revisions of previous estimates – either upward or downward, can result from new information or changing economic factors.

– Improved recovery – if significant

– Purchases of minerals in place

– Extensions and discoveries – relates to extension of proved acreage from existing reservoirs through additional drilling and discovery of new fields

– Production

– Sales of minerals in place

• Narrative explanation for significant items noted above.

Proved Reserves

• Changes in proved reserves for last three years

– Obtain volume roll forward from independent or internal engineer.

– The volume roll forward will be the basis for certain changes in SMOG.

• Disclose total proved developed reserves at the end of each year for which an income statement is required

• See Example

Standardized Measure of Oil and Gas Quantities

(SMOG)

• History lesson

– SMOG disclosures evolved due to disparity in oil and gas

property accounting methods

– ARAB Oil Embargo

– Reserve Recognition Accounting

– S-X Rule 4-10

– FASB 69 (now ASC 932)

SMOG

• Key Inputs

– Beginning and ending reserve reports

– Volume rollforward

– Specific reserves runs for all volumetric changes if

available

– Income statement

– Previously estimated development costs incurred

– Income tax basis of oil and gas properties, tax rates, and

NOL/other credit carryovers

SMOG Example

• Refer to handout

• Example is based on an example in Chapter 29,

Standardized Measure of Oil and Gas Reserves,

Petroleum Accounting Principles, Procedures, &

Issues, 7th Edition, available from PDI.

• This is ―A‖ way, not ―THE‖ way.

Components of SMOG

+ Future cash inflows (revenues from reserve report)

- Future production costs (LOE from and all operating costs from reserve report)

- Future development costs (separate if material or can be combined with production costs)

- Future income tax expenses (future pretax income reflecting depletion estimates and credits, times statutory rates)

- Discount, at 10%

= Standardized measure

See Example 14

Changes in SMOG

• Net change in sales and transfer prices and in

production (lifting) costs related to future production

• Changes in estimated future development costs

• Sales and transfers of oil and gas produced during

the period

• Net change due to extensions, discoveries, and

improved recovery

• Net change due to purchases and sales of minerals

in place

Changes in SMOG

• Net change due to revisions in quantity estimates

• Previously estimated development costs incurred

during the period

• Accretion of discount

• Other – unspecified

• Net change in income taxes

Net Change in Prices and Costs Related to

Future Production

• Computed by variance analysis:

– Calculate net revenue per equivalent unit at each year

end, adjusting current year end amounts for specific

additions, if known, and add-back current year sales

– Multiply the difference in the net cost per unit times

previous year’s equivalent quantities, adjusting current

year end amounts for specific additions, if known

– Multiply that product by the average discount factor

• Excludes future development costs

Previously Estimated Development Costs

Incurred

• Use actual costs incurred related to properties

included in the prior year report as proved developed

nonproducing or proved undeveloped.

Sales and Transfers of Oil and Gas Produced

During the Period

• Directly from the income statement

• Usually revenues less severance tax less LOE.

Volume-related Changes in SMOG

• Net change due to extensions, discoveries, and

improved recovery

• Net change due to purchases of minerals in place

• Net change due to sales of minerals in place

• Net change due to revisions in quantity estimates

Volume-related Changes in SMOG

• Two Methods:

– Obtain specific reserves run from internal or external

engineering to determine the undiscounted future net cash

flow attributable to each type of change; or

– Compute as a volume variance analysis.

• Multiply each volume change times the current period-end net

revenue per equivalent unit (careful to include or exclude future

development costs as appropriate)

• Multiply each of those products times the effective discount factor

Change in Income Taxes

• Two Methods:

– Change in undiscounted amounts times average discount

factor

– Change in discounted amounts

Other (Unspecified)

• Catch-all

• What it takes to balance

• Should be very small – my rule of thumb is 10% of

the prior year SMOG balance

Accretion of discount

• Shortcut method of last year’s SMOG times 10% is

inappropriate

• Two Methods:

– Multiply prior year’s net cash flows by the current period’s

effective discount rates

– Multiply prior year PV10 times 10%

Joe Blice

972-687-7818

jblice@heincpa.com

EXAMPLE 1 – EXCERPT FROM EXXON MOBIL CORP 2011 ANNUAL REPORT ITEM 2. PROPERTIES.

Information with regard to oil and gas producing activities follows:

1. Disclosure of Reserves

A. Summary of Oil and Gas Reserves at Year-End 2011

The table below summarizes the oil-equivalent proved reserves in each geographic area and by product type for consolidated subsidiaries and equity companies. The Corporation has reported proved reserves on the basis of the average of the first-day-of-the-month price for each month during the last 12-month period. Gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. No major discovery or other favorable or adverse event has occurred since December 31, 2011, that would cause a significant change in the estimated proved reserves as of that date.

Crude Oil

Natural Gas Liquids Bitumen

Synthetic Oil

Natural Gas

Oil-EquivalentBasis

(million bbls) (million bbls) (million bbls) (million bbls) (billion cubic ft) (million bbls)

Proved Reserves Developed

Consolidated Subsidiaries United States 1,211 241 – – 15,450 4,027 Canada/South America(1) 92 17 519 653 658 1,391 Europe 258 44 – – 3,041 809 Africa 858 192 – – 853 1,192 Asia 994 166 – – 5,762 2,120 Australia/Oceania 71 55 – – 1,070 304

Total Consolidated 3,484 715 519 653 26,834 9,843

Equity Companies United States 266 4 – – 83 284 Europe 28 – – – 7,588 1,293 Asia 1,023 434 – – 19,305 4,674

Total Equity Company 1,317 438 – – 26,976 6,251

Total Developed 4,801 1,153 519 653 53,810 16,094

Undeveloped Consolidated Subsidiaries

United States 449 118 – – 10,804 2,368 Canada/South America(1) 26 – 2,587 – 177 2,643 Europe 59 15 – – 545 164 Africa 605 20 – – 129 647 Asia 727 – – – 709 845 Australia/Oceania 99 37 – – 6,177 1,166

Total Consolidated 1,965 190 2,587 – 18,541 7,833

Equity Companies United States 82 1 – – 29 88 Europe 1 – – – 2,581 431 Asia 232 44 – – 1,261 486

Total Equity Company 315 45 – – 3,871 1,005

Total Undeveloped 2,280 235 2,587 – 22,412 8,838

Total Proved Reserves 7,081 1,388 3,106 653 76,222 24,932

(1) South America includes proved developed reserves of 0.6 million barrels of crude oil and natural gas liquids and 72 billion cubic feet of natural gas and proved undeveloped reserves of 0.6 million barrels of crude oil and natural gas liquids and 65 billion cubic feet of natural gas.

In the preceding reserves information, consolidated subsidiary and equity company reserves are reported separately. However, the Corporation operates its business with the same view of equity company reserves as it has for reserves from consolidated subsidiaries.

The Corporation’s overall volume capacity outlook, based on projects coming on stream as anticipated, is for production capacity to grow over the period 2012-2016. However, actual volumes will vary from year to year due to the timing of individual project start-ups, operational outages, reservoir performance, regulatory changes, asset sales, weather events, price effects on production sharing contracts and other factors as described in Item 1A—Risk Factors of this report. The estimation of proved reserves, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments and detailed analysis of well information such as flow rates and reservoir pressure declines. Furthermore, the Corporation only records proved reserves for projects which have received significant funding commitments by management made toward the development of the reserves. Although the Corporation is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approvals and significant changes in projections of long-term oil and gas price levels.

EXAMPLE 2 – EXCERPT FROM 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 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.

EXAMPLE 3 – EXCERPT FROM 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 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 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.

EXAMPLE 4 – EXCERPT FROM REPORT FILED WITH RECENT 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.

EXAMPLE 5 – TABULAR DISCLOSURE OF PRODUCTION, PRICES AND COSTS

Year Ended December 31: 2009 2010 2011 Production data:

Natural gas (MMcf) 3,601.30 6,627.00 8,038.70 Oil (MBbls) 43.50 48.20 250.70 Natural gas liquids (MBbls) 25.90 24.10 18.50 Equivalents (MMcfe) 4,017.70 7,060.80 9,653.90

Average sales prices:

Natural gas ($ per Mcf) $ 3.35 $ 3.54 $ 3.40 Oil ($ per Bbl) 58.37 77.24 94.30 Natural gas liquids ($ per Bbl) 32.20 40.00 48.27 Equivalents ($ per Mcfe) 3.85 3.99 5.37

Production costs ($ per Mcfe of production) 1.42 1.23 1.12

EXAMPLE 6 – TABULAR DISCLOSURE OF DRILLING AND OTHER EXPLORATORY AND DEVELOPMENT ACTIVITIES

Year Ended December 31: 2009 2010 2011 Gross Net Gross Net Gross Net Development Wells

Productive 1 0.7 9 2.1 14 2.4 Dry — — — — — —

Exploratory Wells Productive 2 1.2 23 5.0 33 8.3 Dry 1 0.7 — — 1 0.1

Total Wells Productive 3 1.9 32 7.1 47 10.8 Dry 1 0.7 — — 1 0.1

EXAMPLE 7 – DISCLOSURE OF PRESENT ACTIVITIES FROM EXXON MOBIL CORP. ANNUAL REPORT

5. Present Activities

A. Wells Drilling

Year-end 2011 Year-end 2010

Gross Net Gross Net

Wells Drilling

Consolidated Subsidiaries United States 1,276 527 1,088 491 Canada/South America 83 69 92 30 Europe 26 8 27 8 Africa 34 11 54 19 Asia 102 63 98 66 Australia/Oceania 9 2 1 –

Total Consolidated Subsidiaries 1,530 680 1,360 614

Equity Companies United States 2 1 1 1 Europe 13 4 34 10 Asia 32 2 7 1

Total Equity Companies 47 7 42 12 Total gross and net wells drilling 1,577 687 1,402 626

B. Review of Principal Ongoing Activities

UNITED STATES

ExxonMobil’s year-end 2011 acreage holdings totaled 15.6 million net acres, of which 1.9 million net acres were offshore. ExxonMobil was active in areas onshore and offshore in the lower 48 states and in Alaska.

During 2011, 1,318.0 net exploration and development wells were completed in the inland lower 48 states, including development activities in the Barnett Shale of North Texas, the Freestone Trend of East Texas, the Haynesville Shale of Texas and Louisiana, the Fayetteville Shale of Arkansas, the Woodford Shale of Oklahoma, the Bakken oil play in North Dakota and Montana, the Marcellus Shale of Pennsylvania and West Virginia, the Eagle Ford Shale of South Texas, the Piceance Basin of Colorado, the San Joaquin Basin of California and the Permian Basin of West Texas.

ExxonMobil’s net acreage in the Gulf of Mexico at year-end 2011 was 1.8 million acres. A total of 1.3 net exploration and development wells were completed during the year after the offshore drilling moratorium was lifted. The deepwater Hadrian South project and the non-operated Lucius project were both funded in 2011, and project activities are under way. Project work continued on the non-operated St. Malo project. Offshore California 1.0 net development well was completed.

Participation in Alaska production and development continued and a total of 13.6 net development wells were completed.

CANADA / SOUTH AMERICA

Canada

Oil and Gas Operations

ExxonMobil’s year-end 2011 acreage holdings totaled 5.2 million net acres, of which 1.5 million net acres were offshore. A total of 124.2 net exploration and development wells were completed during the year. The Horn River Pilot project was funded in 2011. Project activities continued on the Hibernia Southern Extension project.

In Situ Bitumen Operations

ExxonMobil’s year-end 2011 in situ bitumen acreage holdings totaled 0.5 million net onshore acres. A total of 34.0 net development wells were completed during the year.

Argentina

ExxonMobil’s net acreage totaled 1.0 million onshore acres at year-end 2011, and there were 1.3 net development wells completed during the year.

Venezuela

ExxonMobil’s acreage holdings and assets were expropriated in 2007. Refer to the relevant portion of “Note 15: Litigation and Other Contingencies” of the Financial Section of this report for additional information.

EUROPE

Germany

A total of 4.8 million net onshore acres and 0.1 million net offshore acres were held by ExxonMobil at year-end 2011, with 7.3 net exploration and development wells completed during the year.

Netherlands

ExxonMobil’s net interest in licenses totaled approximately 1.6 million acres at year-end 2011, of which 1.2 million acres are onshore. A total of 11.1 net exploration and development wells were completed during the year. The non-operated project to redevelop the Schoonebeek oil field started up in 2011.

Norway

ExxonMobil’s net interest in licenses at year-end 2011 totaled approximately 1.0 million acres, all offshore. ExxonMobil participated in 2.4 net exploration and development well completions in 2011. The non-operated Aasgard Subsea Compression project was funded in 2011.

United Kingdom

ExxonMobil’s net interest in licenses at year-end 2011 totaled approximately 0.3 million acres, all offshore. The divestment of Mobil North Sea Limited (MNSL) was completed in 2011. A total of 0.8 net development wells were completed during the year.

AFRICA

Angola

ExxonMobil’s year-end 2011 acreage holdings totaled 0.6 million net offshore acres, and 5.2 net exploration and development wells were completed during the year. On Block 15, development drilling continued at Kizomba A and Kizomba C. The Angola Gas Gathering project was completed in 2011, and project work continued on Kizomba Satellites Phase 1. On the non-operated Block 17, the Pazflor project started up in 2011 and work continued on the Cravo-Lirio-Orquidea-Violeta project. Development drilling continued at Dalia, Girassol and Rosa. On the non-operated Block 31, project work continued on the Plutao-Saturno-Venus-Marte project.

Chad

ExxonMobil’s net year-end 2011 acreage holdings consisted of 46 thousand onshore acres, with 28.0 net development wells completed during the year. The undeveloped concessions of M’Biku, Belanga and Mangara were relinquished in 2011.

Equatorial Guinea

ExxonMobil’s acreage totaled 0.1 million net offshore acres at year-end 2011, with 3.8 net development wells completed during the year.

Nigeria

ExxonMobil’s net acreage totaled 1.0 million offshore acres at year-end 2011, with 7.3 net exploration and development wells completed during the year. Work continued on the deepwater Usan project, and the first phase of the Satellite Field Development project is under way.

ASIA

Azerbaijan

At year-end 2011, ExxonMobil’s net acreage totaled 9 thousand offshore acres. A total of 0.5 net development wells were completed during the year. Work continued on the Chirag Oil project.

Indonesia

At year-end 2011, ExxonMobil had 5.2 million net acres, 3.4 million net acres offshore and 1.8 million net acres onshore. A total of 3.4 net exploration wells were completed during the year. The full field development at Banyu Urip was funded in 2011 and project activities are under way.

Iraq

At year-end 2011, ExxonMobil’s onshore acreage was 0.9 million net acres. A total of 20.8 net development wells were completed at the West Qurna Phase I oil field during the year. In 2010, a contract was signed with South Oil Company of the Iraqi Ministry of Oil to redevelop and expand the West Qurna Phase I oil field. The term of the contract is 20 years with the right to extend for five years. In 2010 initial field rehabilitation activities commenced. Field rehabilitation activities across the life of this project will include drilling of new wells, working over of existing wells, optimization and debottlenecking of existing facilities, and the establishment of field offices and camps. During 2011, production sharing contracts were negotiated with the regional government of Kurdistan.

Kazakhstan

ExxonMobil’s net acreage totaled 0.1 million acres onshore and 0.2 million acres offshore at year-end 2011. Working with our partners, construction of the initial phase of the Kashagan field continued during 2011.

Malaysia

ExxonMobil has interests in production sharing contracts covering 0.5 million net acres offshore at year-end 2011. During the year, a total of 8.5 net development wells were completed. The Tapis and Telok projects were funded in 2011 and project activities are under way.

Qatar

Through our joint ventures with Qatar Petroleum, ExxonMobil’s net acreage totaled 65 thousand acres offshore at year-end 2011. During the year, a total of 0.4 net development wells were completed. ExxonMobil participated in 61.8 million tonnes per year gross liquefied natural gas capacity at year end. The development agreements associated with the Barzan project were signed in 2011.

Republic of Yemen

ExxonMobil’s net acreage in the Republic of Yemen production sharing areas totaled 10 thousand acres onshore at year-end 2011.

Russia

ExxonMobil’s net acreage holdings at year-end 2011 were 85 thousand acres, all offshore. A total of 0.6 net development wells were completed. The Sakhalin-1 Chayvo Expansion and Arkutun-Dagi projects continued development activities in 2011. ExxonMobil and Rosneft signed a Strategic Cooperation Agreement in 2011 to jointly participate in exploration and development activities in Russia, the United States and other parts of the world.

Thailand

ExxonMobil’s net onshore acreage in Thailand concessions totaled 21 thousand acres at year-end 2011.

United Arab Emirates

ExxonMobil’s net acreage in the Abu Dhabi offshore Upper Zakum oil concession was 81 thousand acres at year-end 2011, with 0.6 net exploration wells completed during the year.

ExxonMobil’s net acreage in the Abu Dhabi onshore oil concession was 0.5 million acres at year-end 2011, of which 0.4 million acres are onshore. During the year, a total of 3.7 net development wells were completed.

AUSTRALIA / OCEANIA

Australia

ExxonMobil’s year-end 2011 acreage holdings totaled 1.7 million net acres offshore. During 2011, a total of 1.3 net exploration wells were completed. Offshore installation continued for the Kipper Tuna Turrum project.

Project construction activity for the co-venturer operated Gorgon liquefied natural gas (LNG) project progressed in 2011. The project consists of a subsea infrastructure for offshore production and transportation of the gas, and a 15 million tonnes per year LNG facility and a 280 million cubic feet per day domestic gas plant located on Barrow Island, Western Australia.

Papua New Guinea

A total of 0.5 million net onshore acres were held by ExxonMobil at year-end 2011, with 0.1 net development well completed during the year. Work continued on the Papua New Guinea (PNG) LNG project. The project consists of conditioning facilities in the southern PNG Highlands, a 6.6 million tonnes per year LNG facility near Port Moresby and approximately 430 miles of onshore and offshore pipelines.

WORLDWIDE EXPLORATION

At year-end 2011, exploration activities were under way in several areas in which ExxonMobil has no established production operations and thus are not included above. A total of 36.5 million net acres were held at year-end 2011, and 6.5 net exploration wells were completed during the year in these countries.

6. Delivery Commitments

ExxonMobil sells crude oil and natural gas from its producing operations under a variety of contractual obligations, some of which may specify the delivery of a fixed and determinable quantity for periods longer than one year. ExxonMobil also enters into natural gas sales contracts where the source of the natural gas used to fulfill the contract can be a combination of our own production and the spot market. Worldwide, we are contractually committed to deliver approximately 3,000 billion cubic feet of natural gas for the period from 2012 through 2014. We expect to fulfill the majority of these delivery commitments with production from our proved developed reserves. Any remaining commitments will be fulfilled with production from our proved undeveloped reserves and spot market purchases as necessary.

EXAMPLE 8 – HYPOTHETICAL DISCLOSURE OF UNDEVELOPED ACREAGE

Acres Expiring During the Year Ended December 31: 2012 2013 2014 2015 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 1,000 600 Total 17,000 9,000 21,000 15,000 16,000 10,000 15,000 10,600

(1) Our acreage in France is held under several exploration concessions with 5-year renewal clauses. Upon

expiration of the initial term, we are required to apply for renewal. Although there can be no assurance that our renewal applications will be approved, we have historically had all such renewals approved and anticipate that the respective governing bodies will continue to do so.

(2) Our acreage in Asia is generally held under exploration licenses expiring during 2014 and 2015. We anticipate completing our drilling program on the related acres prior to the expiration of the licenses and exchanging those exploration licenses for production concessions.

(3) In 2014, we have options to extend approximately 15,000 gross (7,500 net) acres related to our USA properties for an additional three years by making extension payments.

EXAMPLE 9 – HYPOTHETICAL ACCOUNTING POLICY DISCLOSURE

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 2011.

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 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 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 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.

EXAMPLE 10 – HYPOTHETICAL DISCLOSURE OF CAPITALIZED EXPLORATORY WELL COSTS (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:

2009 2010 2011 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:

2009 2010 2011 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 2 2 1

EXAMPLE 11 – HYPOTHETICAL DISCLOSURE OF CAPITALIZED COSTS

Our oil and natural gas properties consisted of the following as of December 31:

2010 2011 Mineral interests in properties:

Unproved properties $ 32,500 $ 65,000 Proved properties 25,000 30,000

Wells and related equipment and facilities 325,000 450,000 Support equipment and facilities 5,000 8,000 Uncompleted wells and related equipment 13,000 5,000

Total capitalized costs 400,500 558,000 Accumulated depletion, depreciation and amortization (170,000) (215,000)

Net capitalized costs $ 230,500 $ 343,000

EXAMPLE 12 – HYPOTHETICAL DISCLOSURE OF COSTS INCURRED

Our costs incurred in oil and natural gas producing activities consisted of the following for the years ended December 31 (in thousands):

2009 2010 2011 Property acquisition costs:

Unproved properties $ 19,000 $ 1,000 $ 65,000 Proved properties 64,000 — 2,000

Exploration costs 24,000 103,000 85,000 Development costs 6,000 13,000 22,000

Net costs incurred $ 113,000 $ 114,000 $ 174,000

EXAMPLE 13 – DISCLOSURE OF PROVED RESERVES

Oil (MBbls) Natural Gas

Liquids (MBbls) Natural Gas

(MMcf) Total (Barrel Equivalents)

Total Proved Reserves: Balances—January 1, 2009 39,121 1,972 1,244 58,417 Extensions, discoveries and other

additions 3,938 48 42 4,478

Purchases of minerals in place 105,325 225 122 107,407 Production (6,111) (43) (26) (6,525) Revisions to previous estimates (3,748) (739) (612) (11,854) Balances—December 31, 2009 138,525 770 151,923 Extensions, discoveries and other

additions 91,917 880 63 97,575

Sales of minerals in place (3,641) — — (3,641) Production (8,852) (48) (24) (9,284) Revisions to previous estimates 11,548 (112) 3 10,894 Balances—December 31, 2010 229,497 2,183 812 247,467 Extensions, discoveries and other

additions 61,826 3,959 1,035 91,790

Sales of minerals in place (24,530) — — (24,530) Acquisitions 337 129 — 1,111 Production (8,896) (251) (18) (10,510) Revisions to previous estimates (15,951) 46 (585) (19,185) Balances—December 31, 2011 242,283 6,066 1,244 286,143

Proved Developed Reserves: December 31, 2009 58,808 466 394 63,968 December 31, 2010 78,210 693 387 84,690 December 31, 2011 64,695 1,514 245 75,249

The following is a discussion of the material changes in our 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 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 our [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.

EXAMPLE 14 – DISCLOSURE OF SMOG

As of December 31, 2009 2010 2011 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 150,000 340,000 465,000 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 For the Year Ended December 31, 2009 2010 2011 Balances, 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 2,000 190,000 250,000 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