EOG Resources Reports 2008 Results and Increases Dividend
- Recorded 26 Percent Return on Capital Employed
- Delivered 15 Percent Total Company Year-Over-Year Organic Production Growth
- Reported Progress in Barnett Oil, Bakken Extension and Haynesville Plays
- Posted Total Reserve Replacement of 228 Percent at Attractive Finding Costs
- Defines 2009 Operations Strategy
- Increases Dividend on Common Stock
The results for the fourth quarter 2008 included a previously disclosed
Operational Highlights
Meeting the full year production growth target set in
Stepping outside its established footprint in the natural gas area of the
During the past year EOG drilled five successful exploratory oil wells in the North Dakota Bakken outside its core area, the Parshall Field. By applying the same horizontal drilling and enhanced completion technology to this extension called the North Dakota Bakken Lite, EOG increased the potential for crude oil reserves on its acreage and added several years to its drilling inventory. EOG’s total position in both the North Dakota Bakken Core and Bakken Lite was approximately 400,000 net acres at year-end 2008.
Testing the Haynesville Shale in
“EOG had an outstanding year in 2008. We delivered conclusive results on the targets we laid out early last year and made significant progress in developing new plays such as the Horn River,
For the 10-year period ended 2008, EOG reported return on capital employed (ROCE) of 20 percent. On a non-GAAP net income basis, EOG reported ROCE of 20 percent for 2008. (Please refer to the attached tables for the calculation of ROCE and the related reconciliations of after-tax interest expense (non-GAAP), adjusted net income (non-GAAP) and net debt (non-GAAP), as used in the calculations of ROCE, to interest expense (GAAP), net income (GAAP) and current and long-term debt (GAAP).)
Reserves
At
- Total reserve replacement from all sources – the ratio of net reserve additions from drilling, acquisitions, total revisions and dispositions to total production – was 228 percent at a total reserve replacement cost of
$2.60 per thousand cubic feet equivalent (Mcfe). - In
the United States , EOG added 1,703 Bcfe of reserves from drilling and acquisitions, net of total revisions, with capital expenditures of$4,295 million , excluding gathering systems, processing plant and other expenditures. Total reserve replacement from all sources was 270 percent at a reserve replacement cost of$2.52 per Mcfe. - Excluding the impact of price related revisions of 75 Bcfe due to lower natural gas and crude oil prices, total reserve replacement was 238 percent at a reserve replacement cost of
$2.50 per Mcfe. Price related revisions were based on year-end 2008 benchmark Henry Hub natural gas pricing of$5.71 per million British thermal unit and year-end benchmark West Texas Intermediate crude oil pricing of$44.60 per barrel as posted on the New York Mercantile Exchange, as compared to year-end 2007 pricing of$6.80 and$95.98 , respectively. (Please see attached tables for supporting data for the reconciliation of non-GAAP drilling capital expenditures to GAAP total costs incurred in exploration and development activities and for the calculation of reserve replacement percentages and reserve replacement costs.)
For the 21st consecutive year, internal reserve estimates were within 5 percent of those prepared by the independent reserve engineering firm of DeGolyer and MacNaughton (D&M). For 2008, D&M prepared a complete independent engineering analysis of properties containing 79 percent of EOG’s proved reserves on a Bcfe basis.
“We are pleased with our 2008 results. We did not have any significant property impairments or any meaningful price related reserve revisions. This speaks to the efficacy of EOG’s long-term conservative strategy of growing production organically while focusing on returns,” said Papa.
Capital Structure
At
2009 Operational Plans and Targets
In response to the current weakness in commodity prices, EOG has structured this year’s operational plan with the goal of keeping its year-end 2009 net debt relatively flat with that of year-end 2008. While remaining flexible, EOG’s production growth targets and the capital expenditure program will be a function of cash flow generation and reinvestment rates of return. Based on the current futures market for natural gas and crude oil, EOG plans to execute a total capital program of approximately
In the North Dakota Bakken, EOG is temporarily reducing roughly half of its crude oil and associated natural gas production. This moderation is in response to current low crude oil prices coupled with high transportation costs related to trucking and correspondingly wide commodity price differentials due to location. Resumption of full production in this area will depend upon the strengthening of hydrocarbon prices and the development of crude oil transportation alternatives.
“With natural gas and crude oil prices thus far in 2009 reflecting a worldwide decline in demand, EOG’s long-term strategy of profitability and maintaining a strong balance sheet gives us the flexibility to successfully weather diverse economic cycles. Although we plan to keep capital expenditures in line with cash flow during 2009, we will balance that with an active horizontal exploration program to set us up for an expected rebound in commodity prices in 2010,” said Papa.
Dividend Increase
Following two increases during 2008, EOG’s Board of Directors has again increased the cash dividend on the common stock. Effective with the dividend payable on
Conference Call Scheduled for
EOG’s fourth quarter and full year 2008 results conference call will be available via live audio webcast at
EOG Resources, Inc. is one of the largest independent (non-integrated) oil and natural gas companies in
This press release includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical facts, including, among others, statements and projections regarding EOG’s future financial position, operations, performance, business strategy, budgets, reserve information, levels of production and costs and statements regarding the plans and objectives of EOG’s management for future operations, are forward-looking statements. EOG typically uses words such as “expect,” “anticipate,” “estimate,” “project,” “strategy,” “intend,” “plan,” “target,” “goal,” “may,” “will” and “believe” or the negative of those terms or other variations or comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning EOG’s future operating results and returns or EOG’s ability to replace or increase reserves, increase production or generate income or cash flows are forward-looking statements. Forward-looking statements are not guarantees of performance. Although EOG believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or that these expectations will be achieved or will prove to have been correct. Moreover, EOG’s forward-looking statements may be affected by known and unknown risks, events or circumstances that may be outside EOG’s control. Important factors that could cause EOG’s actual results to differ materially from the expectations reflected in EOG’s forward-looking statements include, among others:
- the timing and extent of changes in prices for natural gas, crude oil and related commodities;
- changes in demand for natural gas, crude oil and related commodities, including ammonia and methanol;
- the extent to which EOG is successful in its efforts to discover, develop, market and produce reserves and to acquire natural gas and crude oil properties;
- the extent to which EOG can optimize reserve recovery and economically develop its plays utilizing horizontal and vertical drilling and advanced completion technologies;
- the extent to which EOG is successful in its efforts to economically develop its acreage in the Barnett Shale, the Bakken Formation, its Horn River Basin and
Haynesville plays and its other exploration and development areas; - EOG’s ability to achieve anticipated production levels from existing and future natural gas and crude oil development projects, given the risks and uncertainties inherent in drilling, completing and operating natural gas and crude oil wells and the potential for interruptions of production, whether involuntary or intentional as a result of market or other conditions;
- the availability, proximity and capacity of, and costs associated with, gathering, processing, compression and transportation facilities;
- the availability, cost, terms and timing of issuance or execution of, and competition for, mineral licenses and leases and governmental and other permits and rights of way;
- competition in the oil and gas exploration and production industry for employees and other personnel, equipment, materials and services and, related thereto, the availability and cost of employees and other personnel, equipment, materials and services;
- EOG’s ability to obtain access to surface locations for drilling and production facilities;
- the extent to which EOG’s third party-operated natural gas and crude oil properties are operated successfully and economically;
- EOG’s ability to effectively integrate acquired natural gas and crude oil properties into its operations, fully identify existing and potential problems with respect to such properties and accurately estimate reserves, production and costs with respect to such properties;
- weather, including its impact on natural gas and crude oil demand, and weather-related delays in drilling and in the installation and operation of gathering and production facilities;
- the ability of EOG’s customers and other contractual counterparties to satisfy their obligations to EOG and, related thereto, to access the credit and capital markets to obtain financing needed to satisfy their obligations to EOG;
- EOG’s ability to access the commercial paper market and other credit and capital markets to obtain financing on terms it deems acceptable, if at all;
- the accuracy of reserve estimates, which by their nature involve the exercise of professional judgment and may therefore be imprecise;
- the timing and extent of changes in foreign currency exchange rates, interest rates, inflation rates, global and domestic financial market conditions and global and domestic general economic conditions;
- the extent and effect of any hedging activities engaged in by EOG;
- the timing and impact of liquefied natural gas imports;
- the use of competing energy sources and the development of alternative energy sources;
- political developments around the world, including in the areas in which EOG operates;
- changes in government policies, legislation and regulations, including environmental regulations;
- the extent to which EOG incurs uninsured losses and liabilities;
- acts of war and terrorism and responses to these acts; and
- the other factors described under Item 1A, “Risk Factors”, on pages 13 through 16 of EOG’s Annual Report on Form 10-K for the fiscal year ended
December 31, 2007 and any updates to those factors set forth in EOG’s subsequent Quarterly Reports on Form 10-Q.
In light of these risks, uncertainties and assumptions, the events anticipated by EOG’s forward-looking statements may not occur, and you should not place any undue reliance on any of EOG’s forward-looking statements. EOG’s forward-looking statements speak only as of the date made and EOG undertakes no obligation to update or revise its forward-looking statements, whether as a result of new information, future events or otherwise.
The United States Securities and Exchange Commission (SEC) currently permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. As noted above, statements of proved reserves are only estimates and may be imprecise. Any reserve estimates provided in this press release that are not specifically designated as being estimates of proved reserves may include not only proved reserves, but also other categories of reserves that the SEC’s guidelines strictly prohibit EOG from including in filings with the SEC. Investors are urged to consider closely the disclosure in EOG’s Annual Report on Form 10-K for the fiscal year ended
EOG RESOURCES, INC.
FINANCIAL REPORT
----------------
(Unaudited; in millions, except per share data)
Quarter Twelve Months
Ended December 31, Ended December 31,
------------------ ------------------
2008 2007 2008 2007
---- ---- ---- ----
Net Operating
Revenues $1,633.7 $1,286.0 $7,127.1 $4,239.3
======== ======== ======== ========
Net Income
Available to Common
Stockholders $461.5 $358.0 $2,436.5 $1,083.3
====== ====== ======== ========
Net Income Per Share
Available to Common
Stockholders
Basic $1.86 $1.46 $9.88 $4.45
===== ===== ===== =====
Diluted $1.84 $1.44 $9.72 $4.37
===== ===== ===== =====
Average Number of
Shares Outstanding
Basic 247.7 244.4 246.7 243.5
===== ===== ===== =====
Diluted 250.2 248.5 250.5 247.6
===== ===== ===== =====
SUMMARY INCOME STATEMENTS
-------------------------
(Unaudited; in thousands)
Quarter Twelve Months
Ended December 31, Ended December 31,
------------------ ------------------
2008 2007 2008 2007
---- ---- ---- ----
Net Operating Revenues
Natural Gas $814,733 $836,515 $4,452,058 $3,032,805
Crude Oil,
Condensate and
Natural Gas
Liquids 275,883 335,690 1,769,926 987,523
Gains on Mark-to-
Market Commodity
Derivative
Contracts 528,844 45,215 597,911 93,108
Gathering,
Processing and
Marketing 13,628 42,462 164,535 73,539
Other, Net 639 26,102 142,713 52,328
--- ------ ------- ------
Total 1,633,727 1,285,984 7,127,143 4,239,303
--------- --------- --------- ---------
Operating Expenses
Lease and Well 162,891 123,856 559,185 452,044
Transportation
Costs 70,885 42,784 274,090 152,236
Gathering and
Processing Costs 14,165 8,359 40,550 27,775
Exploration Costs 48,489 44,005 193,886 150,445
Dry Hole Costs 27,105 40,710 55,167 115,382
Impairments 79,268 60,657 192,859 147,517
Marketing Costs 12,431 39,248 152,842 66,680
Depreciation,
Depletion and
Amortization 368,135 282,234 1,326,875 1,065,545
General and
Administrative 58,249 66,047 243,708 205,210
Taxes Other Than
Income 40,930 58,267 320,796 208,073
------ ------ ------- -------
Total 882,548 766,167 3,359,958 2,590,907
------- ------- --------- ---------
Operating Income 751,179 519,817 3,767,185 1,648,396
Other Income, Net 2,257 7,014 31,012 29,250
----- ----- ------ ------
Income Before
Interest Expense
and Income Taxes 753,436 526,831 3,798,197 1,677,646
Interest Expense,
Net 18,343 15,751 51,658 46,778
------ ------ ------ ------
Income Before
Income Taxes 735,093 511,080 3,746,539 1,630,868
Income Tax Provision 273,621 149,885 1,309,620 540,950
------- ------- --------- -------
Net Income 461,472 361,195 2,436,919 1,089,918
Preferred Stock
Dividends - 3,161 443 6,663
--- ----- --- -----
Net Income
Available to Common
Stockholders $461,472 $358,034 $2,436,476 $1,083,255
======== ======== ========== ==========
EOG RESOURCES, INC.
OPERATING HIGHLIGHTS
--------------------
(Unaudited)
Quarter Twelve Months
Ended Ended
December 31, December 31,
------------- -------------
2008 2007 2008 2007
---- ---- ---- ----
Wellhead Volumes and Prices
---------------------------
Natural Gas Volumes (MMcfd) (A)
United States 1,231 1,010 1,162 971
Canada 231 225 222 224
Trinidad 184 241 218 252
Other International (B) 18 20 17 23
-- -- -- --
Total 1,664 1,496 1,619 1,470
Average Natural Gas Prices
($/Mcf) (C)
United States $5.65 $6.48 $8.22 $6.27
Canada 5.71 6.36 7.64 6.25
Trinidad 2.53 3.84 3.58 2.71
Other International (B) 6.23 9.45 8.18 6.19
Composite 5.32 6.08 7.51 5.65
Crude Oil and Condensate Volumes
(MBbld) (A)
United States 50.4 27.6 39.5 24.6
Canada 2.7 2.3 2.7 2.4
Trinidad 2.5 3.8 3.2 4.1
Other International (B) 0.1 0.1 0.1 0.1
--- --- --- ---
Total 55.7 33.8 45.5 31.2
Average Crude Oil and Condensate
Prices ($/Bbl) (C)
United States $46.03 $84.83 $87.68 $68.85
Canada 45.60 79.98 89.70 65.27
Trinidad 47.67 78.37 92.90 69.84
Other International (B) 84.33 86.70 99.30 66.84
Composite 46.12 83.77 88.18 68.69
Natural Gas Liquids Volumes
(MBbld) (A)
United States 15.9 13.7 15.0 11.1
Canada 0.9 1.1 1.0 1.1
--- --- --- ---
Total 16.8 14.8 16.0 12.2
Average Natural Gas Liquids
Prices ($/Bbl) (C)
United States $26.45 $56.27 $53.33 $47.63
Canada 30.08 53.18 54.77 44.54
Composite 26.65 56.04 53.42 47.36
Natural Gas Equivalent Volumes
(MMcfed) (D)
United States 1,629 1,257 1,490 1,184
Canada 253 246 244 245
Trinidad 199 264 237 276
Other International (B) 18 20 17 24
-- -- -- --
Total 2,099 1,787 1,988 1,729
Total Bcfe (D) 193.1 164.4 727.6 631.3
(A) Million cubic feet per day or thousand barrels per day,
as applicable.
(B) Other International includes EOG's United Kingdom operations
and, effective July 1, 2008, EOG's China operations.
(C) Dollars per thousand cubic feet or per barrel, as applicable.
(D) Million cubic feet equivalent per day or billion cubic feet
equivalent, as applicable; includes natural gas, crude oil,
condensate and natural gas liquids. Natural gas equivalents
are determined using the ratio of 6.0 thousand cubic feet of
natural gas to 1.0 barrel of crude oil, condensate or natural
gas liquids.
EOG RESOURCES, INC.
SUMMARY BALANCE SHEETS
----------------------
(Unaudited; in thousands, except share data)
December 31, December 31,
2008 2007
---- ----
ASSETS
Current Assets
Cash and Cash Equivalents $331,311 $54,231
Accounts Receivable, Net 722,695 835,670
Inventories 187,970 102,322
Assets from Price Risk Management
Activities 779,483 100,912
Income Taxes Receivable 27,053 110,370
Deferred Income Taxes - 33,533
Other 59,939 55,001
------ ------
Total 2,108,451 1,292,039
Property, Plant and Equipment
Oil and Gas Properties (Successful
Efforts Method) 20,803,629 16,981,836
Other Property, Plant and Equipment 1,057,888 581,402
--------- -------
Total Property, Plant and Equipment 21,861,517 17,563,238
Less: Accumulated Depreciation,
Depletion and Amortization (8,204,215) (7,133,984)
---------- ----------
Total Property, Plant and Equipment,
Net 13,657,302 10,429,254
Long-Term Assets Held for Sale - 254,376
Other Assets 185,473 113,238
------- -------
Total Assets $15,951,226 $12,088,907
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts Payable $1,122,209 $1,152,140
Accrued Taxes Payable 86,265 104,647
Dividends Payable 33,461 22,045
Liabilities from Price Risk Management
Activities 4,429 3,404
Deferred Income Taxes 368,231 108,980
Current Portion of Long-Term Debt 37,000 -
Other 113,321 82,954
------- ------
Total 1,764,916 1,474,170
Long-Term Debt 1,860,000 1,185,000
Other Liabilities 498,291 368,336
Deferred Income Taxes 2,813,522 2,071,307
Stockholders' Equity
Preferred Stock, $0.01 Par, Zero Shares
and 10,000,000 Shares
Authorized at December 31, 2008
and 2007, respectively:
Series B, Cumulative, $1,000 Liquidation
Preference per Share,
Zero Shares and 5,000 Shares
Outstanding at December 31,
2008 and 2007, respectively - 4,977
Common Stock, $0.01 Par, 640,000,000 Shares
Authorized:
249,758,577 Shares and 249,460,000 Shares
Issued at December 31, 2008 and 2007,
respectively 202,498 202,495
Additional Paid In Capital 323,805 221,102
Accumulated Other Comprehensive Income 27,787 466,702
Retained Earnings 8,466,143 6,156,721
Common Stock Held in Treasury, 126,911 Shares
and 2,935,313 Shares at December 31, 2008
and 2007, respectively (5,736) (61,903)
------ -------
Total Stockholders' Equity 9,014,497 6,990,094
--------- ---------
Total Liabilities and Stockholders' Equity $15,951,226 $12,088,907
=========== ===========
EOG RESOURCES, INC.
SUMMARY STATEMENTS OF CASH FLOWS
--------------------------------
(Unaudited; in thousands)
Twelve Months
Ended December 31,
------------------
2008 2007
---- ----
Cash Flows from Operating Activities
Reconciliation of Net Income to Net Cash
Provided by Operating Activities:
Net Income $2,436,919 $1,089,918
Items Not Requiring (Providing) Cash
Depreciation, Depletion and Amortization 1,326,875 1,065,545
Impairments 192,859 147,517
Stock-Based Compensation Expenses 97,493 67,253
Deferred Income Taxes 1,133,630 426,827
Other, Net (138,392) (44,138)
Dry Hole Costs 55,167 115,382
Mark-to-Market Commodity Derivative Contracts
Total Gains (597,911) (93,108)
Realized (Losses) Gains (136,625) 127,969
Other, Net 13,229 24,268
Changes in Components of Working Capital and
Other Assets and Liabilities
Accounts Receivable 95,165 (85,024)
Inventories (92,049) 9,638
Accounts Payable 30,253 228,354
Accrued Taxes Payable 66,021 (40,002)
Other Assets (10,715) (8,416)
Other Liabilities 9,061 12,614
Changes in Components of Working Capital
Associated with Investing and
Financing Activities 152,269 (143,594)
------- --------
Net Cash Provided by Operating Activities 4,633,249 2,901,003
Investing Cash Flows
Additions to Oil and Gas Properties (4,718,860) (3,401,986)
Additions to Other Property, Plant and
Equipment (476,611) (277,076)
Proceeds from Sales of Assets 383,559 83,295
Changes in Components of Working Capital
Associated with Investing Activities (152,374) 143,668
Other, Net (2,232) (3,675)
------ ------
Net Cash Used in Investing Activities (4,966,518) (3,455,774)
Financing Cash Flows
Long-Term Debt Borrowings 750,000 610,000
Long-Term Debt Repayments (38,000) (158,442)
Dividends Paid (115,204) (84,020)
Redemptions of Preferred Stock (5,395) (51,197)
Excess Tax Benefits from Stock-Based
Compensation 6,446 27,339
Treasury Stock Purchased (17,834) (7,638)
Proceeds from Stock Options Exercised and
Employee Stock Purchase Plan 72,572 55,320
Debt Issuance Costs (7,585) (5,206)
Other, Net 105 (71)
--- ---
Net Cash Provided by Financing Activities 645,105 386,085
Effect of Exchange Rate Changes on Cash (34,756) 4,662
------- -----
Increase (Decrease) in Cash and Cash Equivalents 277,080 (164,024)
Cash and Cash Equivalents at Beginning of Period 54,231 218,255
------ -------
Cash and Cash Equivalents at End of Period $331,311 $54,231
======== =======
EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF ADJUSTED NET INCOME AVAILABLE TO COMMON
----------------------------------------------------------------------
STOCKHOLDERS (Non-GAAP) TO NET INCOME AVAILABLE TO COMMON
---------------------------------------------------------
STOCKHOLDERS (GAAP)
-------------------
(Unaudited; in thousands, except per share data)
The following chart adjusts three-month and twelve-month periods ended
December 31, 2008 and 2007, reported Net Income Available to Common
Stockholders (GAAP) to reflect actual net cash realized from financial
commodity price transactions by eliminating the unrealized mark-to-market
gains from these transactions and to eliminate the gain on the sale of
Appalachian assets in the first quarter of 2008, to add the premium and
fees for preferred stock redemptions in the third and fourth quarter of
2007, and to eliminate the effect of the income tax rate reductions
enacted by the Canadian federal government in the second and fourth
quarters of 2007. EOG believes this presentation may be useful to
investors who follow the practice of some industry analysts who adjust
reported company earnings to match realizations to production settlement
months and make certain other adjustments to exclude one-time items.
EOG management uses this information for comparative purposes within the
industry.
Quarter Twelve Months
Ended December 31, Ended December 31,
------------------ ------------------
2008 2007 2008 2007
---- ---- ---- ----
Reported Net Income
Available to Common
Stockholders (GAAP) $461,472 $358,034 $2,436,476 $1,083,255
Mark-to-Market (MTM)
Commodity Derivative
Contracts Impact
Total Gains (528,844) (45,215) (597,911) (93,108)
Realized Gains (Losses) 100,701 28,782 (136,625) 127,969
------- ------ -------- -------
Subtotal (428,143) (16,433) (734,536) 34,861
-------- ------- -------- ------
After Tax MTM Impact (275,510) (10,575) (472,674) 22,433
-------- ------- -------- ------
Add: Premium and Fees
for Preferred Stock
Redemptions - 2,296 - 2,937
Less: Gain on Sale of
Appalachian Assets, Net
of Tax - - (84,748) -
Less: Tax Benefit
Related to Canadian
Federal Tax Rate
Reduction - (30,338) - (34,419)
--- ------- --- -------
Adjusted Net Income
Available to Common
Stockholders (Non-GAAP) $185,962 $319,417 $1,879,054 $1,074,206
======== ======== ========== ==========
Net Income Per Share
Available to Common
Stockholders (GAAP)
Basic $1.86 $1.46 $9.88 $4.45
===== ===== ===== =====
Diluted $1.84 $1.44 $9.72 $4.37
===== ===== ===== =====
Adjusted Net Income Per
Share Available to Common
Stockholders (Non-GAAP)
Basic $0.75 $1.31 $7.62 $4.41
===== ===== ===== =====
Diluted $0.74 $1.29 $7.50 $4.34
===== ===== ===== =====
Average Number of Shares
Outstanding
Basic 247,672 244,440 246,662 243,469
======= ======= ======= =======
Diluted 250,162 248,537 250,542 247,637
======= ======= ======= =======
EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF DISCRETIONARY CASH FLOW AVAILABLE TO
-------------------------------------------------------------------
COMMON STOCKHOLDERS (Non-GAAP) TO NET CASH PROVIDED BY OPERATING
----------------------------------------------------------------
ACTIVITIES (GAAP)
-----------------
(Unaudited; in thousands)
The following chart reconciles three-month and twelve-month periods ended
December 31, 2008 and 2007, Net Cash Provided by Operating Activities
(GAAP) to Discretionary Cash Flow Available to Common Stockholders (Non-
GAAP). EOG believes this presentation may be useful to investors who
follow the practice of some industry analysts who adjust Net Cash
Provided by Operating Activities for Exploration Costs (excluding Stock-
Based Compensation Expenses), Changes in Components of Working Capital
and Other Assets and Liabilities, Changes in Components of Working
Capital Associated with Investing and Financing Activities and Preferred
Stock Dividends. EOG management uses this information for comparative
purposes within the industry.
Quarter Twelve Months
Ended December 31, Ended December 31,
------------------ ------------------
2008 2007 2008 2007
---- ---- ---- ----
Net Cash Provided by
Operating Activities
(GAAP) $1,033,563 $748,558 $4,633,249 $2,901,003
Adjustments
Exploration Costs
(excluding Stock-Based
Compensation Expenses) 43,448 40,275 175,357 137,117
Changes in Components of
Working Capital and Other
Assets and Liabilities
Accounts Receivable (315,112) 163,307 (95,165) 85,024
Inventories 46,695 (5,406) 92,049 (9,638)
Accounts Payable 191,196 (185,524) (30,253) 228,354)
Accrued Taxes Payable 69,726 17,168 (66,021) 40,002
Other Assets (8,041) 636 10,715 8,416
Other Liabilities (12,458) (9,882) (9,061) (12,614)
Changes in Components of
Working Capital Associated
with Investing and
Financing Activities (137,880) 99,280 (152,269) 143,594
Preferred Stock Dividends - (3,161) (443) (6,663)
--- ------ ---- ------
Discretionary Cash Flow
Available to Common
Stockholders (Non-GAAP) $911,137 $865,251 $4,558,158 $3,057,887
======== ======== ========== ==========
EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF AFTER-TAX INTEREST EXPENSE (Non-GAAP) AND
------------------------------------------------------------------------
NET DEBT (Non-GAAP) AS USED IN THE CALCULATION OF RETURN ON CAPITAL
-------------------------------------------------------------------
EMPLOYED (ROCE) TO INTEREST EXPENSE (GAAP) AND CURRENT AND
---------------------------------------------------------
LONG-TERM DEBT (GAAP), RESPECTIVELY
-----------------------------------
(Unaudited; in millions, except ratio data)
The following chart reconciles Interest Expense (GAAP) and Current and
Long-Term Debt (GAAP) to After-Tax Interest Expense (Non-GAAP) and Net
Debt (Non-GAAP), respectively, as used in the Return on Capital Employed
(ROCE) calculation. EOG believes this presentation may be useful to
investors who follow the practice of some industry analysts who utilize
After-Tax Interest Expense and Net Debt in their ROCE calculation. EOG
management uses this information for comparative purposes within the
industry.
1998 1999 2000 2001
---- ---- ---- ----
Interest Expense $61.8 $61.0 $45.1
Tax Benefit Imputed (based on 35%) (21.6) (21.4) (15.8)
----- ----- -----
After-Tax Interest Expense
(Non-GAAP) - (a) $40.2 $39.6 $29.3
===== ===== =====
Net Income - (b) $569.1 $396.9 $398.6
Total Stockholders'
Equity - (c) $1,280.3 $1,129.6 $1,380.9 $1,642.7
Current and Long-Term Debt 1,142.8 990.3 859.0 856.0
Less: Cash (6.3) (24.8) (20.2) (2.5)
---- ----- ----- ----
Net Debt (Non-GAAP) - (d) 1,136.5 965.5 838.8 853.5
------- ----- ----- -----
Total Capitalization
(Non-GAAP) - (c) + (d) $2,416.8 $2,095.1 $2,219.7 $2,496.2
======== ======== ======== ========
Average Total Capitalization
(Non-GAAP)* - (e) $2,256.0 $2,157.4 $2,358.0
======== ======== ========
Return on Capital Employed
(ROCE) - [(a) + (b)] / (e) 27.0% 20.2% 18.1%
==== ==== ====
Average ROCE 1999 - 2008
2002 2003 2004 2005
---- ---- ---- ----
Interest Expense $59.7 $58.7 $63.1 $62.5
Tax Benefit Imputed (based on 35%) (20.9) (20.5) (22.1) (21.9)
----- ----- ----- -----
After-Tax Interest Expense
(Non-GAAP) - (a) $38.8 $38.2 $41.0 $40.6
===== ===== ===== =====
Net Income - (b) $87.2 $430.1 $624.9 $1,259.6
Total Stockholders'
Equity - (c) $1,672.4 $2,223.4 $2,945.4 $4,316.3
Current and Long-Term Debt 1,145.1 1,108.9 1,077.6 985.1
Less: Cash (9.8) (4.4) (21.0) (643.8)
---- ---- ----- ------
Net Debt (Non-GAAP) - (d) 1,135.3 1,104.5 1,056.6 341.3
------- ------- ------- -----
Total Capitalization
(Non-GAAP) - (c) + (d) $2,807.7 $3,327.9 $4,002.0 $4,657.6
======== ======== ======== ========
Average Total Capitalization
(Non-GAAP)* - (e) $2,652.0 $3,067.8 $3,665.0 $4,329.8
======== ======== ======== ========
Return on Capital Employed
(ROCE) - [(a) + (b)] / (e) 4.8% 15.3% 18.2% 30.0%
=== ==== ==== ====
Average ROCE 1999 - 2008
2006 2007 2008
---- ---- ----
Interest Expense $43.2 $46.8 $51.7
Tax Benefit Imputed (based on 35%) (15.1) (16.4) (18.1)
----- ----- -----
After-Tax Interest Expense
(Non-GAAP) - (a) $28.1 $30.4 $33.6
===== ===== =====
Net Income - (b) $1,299.9 $1,089.9 $2,436.9
Total Stockholders'
Equity - (c) $5,599.7 $6,990.1 $9,014.5
Current and Long-Term Debt 733.4 1,185.0 1,897.0
Less: Cash (218.3) (54.2) (331.3)
------ ----- ------
Net Debt (Non-GAAP) - (d) 515.1 1,130.8 1,565.7
----- ------- -------
Total Capitalization
(Non-GAAP) - (c) + (d) $6,114.8 $8,120.9 $10,580.2
======== ======== =========
Average Total Capitalization
(Non-GAAP)* - (e) $5,386.2 $7,117.9 $9,350.6
======== ======== ========
Return on Capital Employed
(ROCE) - [(a) + (b)] / (e) 24.7% 15.7% 26.4%
==== ==== ====
Average ROCE 1999 - 2008 20.0%
====
*Average of "Total Capitalization (Non-GAAP)" for the current and
immediately preceding year
EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF AFTER-TAX INTEREST EXPENSE
---------------------------------------------------------
(Non-GAAP), NET DEBT (Non-GAAP) AND ADJUSTED NET INCOME (Non-GAAP)
------------------------------------------------------------------
AS USED IN THE CALCULATIONS OF RETURN ON CAPITAL EMPLOYED (ROCE)
----------------------------------------------------------------
TO INTEREST EXPENSE (GAAP), CURRENT AND LONG-TERM DEBT (GAAP) AND
-----------------------------------------------------------------
NET INCOME (GAAP), RESPECTIVELY
--------------------------------
(Unaudited; in millions, except ratio data)
The following chart reconciles Interest Expense (GAAP), Current and
Long-Term Debt (GAAP) and Net Income (GAAP) to After-Tax Interest
Expense (Non-GAAP), Net Debt (Non-GAAP) and Adjusted Net Income
(Non-GAAP), respectively, as used in the Return on Capital Employed
(ROCE) calculations. EOG believes this presentation may be useful to
investors who follow the practice of some industry analysts who
utilize After-Tax Interest Expense, Net Debt and Adjusted Net Income in
their ROCE calculations. EOG management uses this information for
comparative purposes within the industry.
2007 2008
---- ----
Interest Expense $51.7
Tax Benefit Imputed (based on 35%) (18.1)
-----
After-Tax Interest Expense (Non-GAAP) - (a) $33.6
=====
Reported Net Income - (b) $2,436.9
After-Tax Mark-to-Market Impact (472.7)
After-Tax Gain on Sale of Appalachian Assets (84.7)
-----
Adjusted Net Income (Non-GAAP) (c) $1,879.5
========
Total Stockholders' Equity - (d) $6,990.1 $9,014.5
Current and Long-Term Debt $1,185.0 $1,897.0
Less: Cash (54.2) (331.3)
----- ------
Net Debt (Non-GAAP) - (e) $1,130.8 $1,565.7
======== ========
Total Capitalization (Non-GAAP) - (d) + (e) $8,120.9 $10,580.2
======== =========
Average Total Capitalization (Non-GAAP)* - (f) $9,350.6
========
Return on Capital Employed (ROCE) - GAAP
Net Income [(a) + (b)] / (f) 26.4%
====
Return on Capital Employed (ROCE) - Non-GAAP
Adjusted Net Income [(a) + (c)] / (f) 20.5%
====
* Average of "Total Capitalization (Non-GAAP)" for the current and
immediately preceding year
EOG RESOURCES, INC.
RESERVES SUPPLEMENTAL DATA
--------------------------
(Unaudited)
2008 NET PROVED RESERVES RECONCILIATION SUMMARY
United North
NATURAL GAS (Bcf) States Canada America Trinidad
------ ------ ------- --------
Beginning Reserves 4,220.1 1,219.8 5,439.9 1,216.3
Revisions (110.3) 22.9 (87.4) 62.2
Purchases in place 31.0 15.0 46.0 -
Extensions, discoveries and
other additions 1,384.4 60.6 1,445.0 -
Sales in place (200.2) - (200.2) -
Production (436.0) (81.1) (517.1) (80.4)
------ ----- ------ -----
Ending Reserves 4,889.0 1,237.2 6,126.2 1,198.1
======= ======= ======= =======
LIQUIDS (MMBbls) (a)
Beginning Reserves 160.0 10.4 170.4 8.9
Revisions (1.6) 0.9 (0.7) 0.4
Purchases in place - - - 0.2
Extensions, discoveries and
other additions 67.9 0.9 68.8 -
Sales in place (0.5) - (0.5) -
Production (20.0) (1.4) (21.4) (1.2)
----- ---- ----- ----
Ending Reserves 205.8 10.8 216.6 8.3
===== ==== ===== ===
NATURAL GAS EQUIVALENTS (Bcfe)
Beginning Reserves 5,180.2 1,282.0 6,462.2 1,269.7
Revisions (119.9) 28.1 (91.8) 64.7
Purchases in place 31.1 15.0 46.1 1.1
Extensions, discoveries and
other additions 1,791.6 66.1 1,857.7 -
Sales in place (203.2) - (203.2) -
Production (555.8) (89.2) (645.0) (87.4)
------ ----- ------ -----
Ending Reserves 6,124.0 1,302.0 7,426.0 1,248.1
======= ======= ======= =======
Net Proved Developed Reserves (Bcfe)
At December 31, 2007 3,861.5 1,140.3 5,001.8 960.0
At December 31, 2008 4,502.3 1,166.2 5,668.5 929.6
(a) Includes crude oil, condensate and natural gas liquids.
2008 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ in millions)
Acquisition Cost of Unproved
Properties $376.0 $141.1 $517.1 $0.3
Exploration Costs 550.7 95.6 646.3 6.7
Development Costs 3,298.5 243.1 3,541.6 70.7
------- ----- ------- ----
Total Drilling 4,225.2 479.8 4,705.0 77.7
Acquisition Cost of Proved
Properties 69.6 14.1 83.7 14.8
---- ---- ---- ----
Total Exploration & Development
Expenditures 4,294.8 493.9 4,788.7 92.5
Gathering, Processing and Other 474.6 1.2 475.8 0.3
Asset Retirement Costs 107.1 38.4 145.5 28.7
----- ---- ----- ----
Total Expenditures 4,876.5 533.5 5,410.0 121.5
Proceeds from Sales in Place (419.1) (3.8) (422.9) -
------ ---- ------ -
Net Expenditures $4,457.4 $529.7 $4,987.1 $121.5
======== ====== ======== ======
RESERVE REPLACEMENT COSTS ($ / Mcfe) *
Total Drilling, Before Revisions $2.36 $7.26 $2.53 $-
All-in Total, Net of Revisions $2.52 $4.52 $2.64 $1.41
RESERVE REPLACEMENT *
Drilling Only 322% 74% 288% 0%
All-in Total, Net of Revisions
& Dispositions 270% 122% 249% 75%
* See attached reconciliation schedule for calculation methodology
Other Total
NATURAL GAS (Bcf) Int'l Int'l Total
----- ----- -----
Beginning Reserves 12.9 1,229.2 6,669.1
Revisions (4.2) 58.0 (29.4)
Purchases in place 12.2 12.2 58.2
Extensions, discoveries and other
additions - - 1,445.0
Sales in place - - (200.2)
Production (6.0) (86.4) (603.5)
---- ----- ------
Ending Reserves 14.9 1,213.0 7,339.2
==== ======= =======
LIQUIDS (MMBbls) (a)
Beginning Reserves - 8.9 179.3
Revisions - 0.4 (0.3)
Purchases in place 0.1 0.3 0.3
Extensions, discoveries and
other additions - - 68.8
Sales in place - - (0.5)
Production - (1.2) (22.6)
- ---- -----
Ending Reserves 0.1 8.4 225.0
=== === =====
NATURAL GAS EQUIVALENTS (Bcfe)
Beginning Reserves 13.2 1,282.9 7,745.1
Revisions (4.3) 60.4 (31.4)
Purchases in place 12.5 13.6 59.7
Extensions, discoveries and
other additions - - 1,857.7
Sales in place - - (203.2)
Production (6.1) (93.5) (738.5)
---- ----- ------
Ending Reserves 15.3 1,263.4 8,689.4
==== ======= =======
Net Proved Developed Reserves (Bcfe)
At December 31, 2007 13.2 973.2 5,975.0
At December 31, 2008 15.3 944.9 6,613.4
(a) Includes crude oil, condensate and natural gas liquids.
2008 EXPLORATION AND DEVELOPMENT EXPENDITURES ($ in million)
Acquisition Cost of Unproved
Properties $3.4 $3.7 $520.8
Exploration Costs 16.7 23.4 669.7
Development Costs - 70.7 3,612.3
- ---- -------
Total Drilling 20.1 97.8 4,802.8
Acquisition Cost of Proved
Properties 10.3 25.1 108.8
---- ---- -----
Total Exploration & Development
Expenditures 30.4 122.9 4,911.6
Gathering, Processing and Other 0.4 0.7 476.5
Asset Retirement Costs 7.2 35.9 181.4
--- ---- -----
Total Expenditures 38.0 159.5 5,569.5
Proceeds from Sales in Place - - (422.9)
- - ------
Net Expenditures $38.0 $159.5 $5,146.6
===== ====== ========
RESERVE REPLACEMENT COSTS ($ / Mcfe) *
Total Drilling, Before Revisions $- $- $2.59
All-in Total, Net of Revisions $- $1.66 $2.60
RESERVE REPLACEMENT *
Drilling Only - 0% 252%
All-in Total, Net of Revisions &
Dispositions - 79% 228%
* See attached reconciliation schedule for calculation methodology
EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF TOTAL EXPLORATION AND DEVELOPMENT
-----------------------------------------------------------------
EXPENDITURES FOR DRILLING ONLY (Non-GAAP) AND TOTAL EXPLORATION
---------------------------------------------------------------
AND DEVELOPMENT EXPENDITURES (Non-GAAP) AS USED IN THE CALCULATION
------------------------------------------------------------------
OF RESERVE REPLACEMENT COSTS ($ / MCFE) TO TOTAL COSTS INCURRED IN
-------------------------------------------------------------------
EXPLORATION AND DEVELOPMENT ACTIVITIES (GAAP)
----------------------------------------------
(Unaudited; in millions, except ratio information)
The following chart reconciles Total Costs Incurred in Exploration and
Development Activities (GAAP) to Total Exploration and Development
Expenditures for Drilling Only (Non-GAAP) and Total Exploration and
Development Expenditures (Non-GAAP), as used in the calculation of
Reserve Replacement Costs per Mcfe. There are numerous ways that
industry participants present Reserve Replacement Costs, including
"Drilling Only" and "All-In", which reflect total exploration and
development expenditures divided by total net reserve additions from
extensions and discoveries only, or from all sources. Combined with
Reserve Replacement, these statistics provide management and investors
with an indication of the results of the current year capital investment
program. Reserve Replacement Cost statistics are widely recognized and
reported by industry participants and are used by EOG management and
other third parties for comparative purposes within the industry. Please
note that the actual cost of adding reserves will vary from the reported
statistics due to timing differences in reserve bookings and capital
expenditures. Accordingly, some analysts use three or five year averages
of reported statistics, while others prefer to estimate future costs.
EOG has not included future capital costs to develop proved undeveloped
reserves in Total Exploration & Development Expenditures
United North
States Canada America Trinidad
------ ------ ------- --------
Total Costs Incurred in
Exploration and Development
Activities (GAAP) $4,401.9 $532.3 $4,934.2 $121.2
Less: Asset Retirement Costs (107.1) (38.4) (145.5) (28.7)
Less: Acquisition Cost
of Proved Properties (69.6) (14.1) (83.7) (14.8)
----- ----- ----- -----
Total Exploration & Development
Expenditures for Drilling
Only (Non-GAAP) (a) $4,225.2 $479.8 $4,705.0 $77.7
======== ====== ======== =====
Total Costs Incurred in
Exploration and Development
Activities (GAAP) $4,401.9 $532.3 $4,934.2 $121.2
Less: Asset Retirement Costs (107.1) (38.4) (145.5) (28.7)
------ ----- ------ -----
Total Exploration & Development
Expenditures (Non-GAAP) (b) $4,294.8 $493.9 $4,788.7 $92.5
======== ====== ======== =====
Net Reserve Additions From
All Sources
- Natural Gas
Equivalents (Bcfe)
Revisions due to price (c) (154.9) (19.7) (174.6) 99.6
Revisions other than price 35.0 47.8 82.8 (34.9)
Purchases in place 31.1 15.0 46.1 1.1
Extensions, discoveries
and other additions (d) 1,791.6 66.1 1,857.7 -
------- ---- ------- ---
Total Reserve Additions (e) 1,702.8 109.2 1,812.0 65.8
Sales in place (203.2) - (203.2) -
------ --- ------ ---
Net Reserve Additions From
All Sources (f) 1,499.6 109.2 1,608.8 65.8
======= ===== ======= ====
Production (g) 555.8 89.2 645.0 87.4
RESERVE REPLACEMENT COSTS
($ / Mcfe)
Total Drilling, Before
Revisions (a / d) $2.36 $7.26 $2.53 $-
All-in Total, Net of
Revisions (b / e) $2.52 $4.52 $2.64 $1.41
All-in Total, Excluding
Revisions Due to Price
(b / (e - c)) $2.31 $3.83 $2.41 $(2.74)
RESERVE REPLACEMENT
Drilling Only (d / g) 322% 74% 288% -
All-in Total, Net of Revisions
& Dispositions (f / g) 270% 122% 249% 75%
All-in Total, Excluding
Revisions Due to Price
((f - c) / g) 298% 145% 276% -39%
Other Total
Int'l Int'l Total
----- ----- -----
Total Costs Incurred in Exploration and
Development Activities (GAAP) $37.6 $158.8 $5,093.0
Less: Asset Retirement Costs (7.2) (35.9) (181.4)
Less: Acquisition Cost of Proved
Properties (10.3) (25.1) (108.8)
----- ----- ------
Total Exploration & Development
Expenditures for Drilling
Only (Non-GAAP) (a) $20.1 $97.8 $4,802.8
===== ===== ========
Total Costs Incurred in Exploration and
Development Activities (GAAP) $37.6 $158.8 $5,093.0
Less: Asset Retirement Costs (7.2) (35.9) (181.4)
---- ----- ------
Total Exploration & Development
Expenditures (Non-GAAP) (b) $30.4 $122.9 $4,911.6
===== ====== ========
Net Reserve Additions From All Sources
- Natural Gas Equivalents (Bcfe)
Revisions due to price (c) - 99.6 (75.0)
Revisions other than price (4.3) (39.2) 43.6
Purchases in place 12.5 13.6 59.7
Extensions, discoveries and other
additions (d) - - 1,857.7
--- --- -------
Total Reserve Additions (e) 8.2 74.0 1,886.0
Sales in place - - (203.2)
--- --- ------
Net Reserve Additions From All
Sources (f) 8.2 74.0 1,682.8
=== ==== =======
Production (g) 6.1 93.5 738.5
RESERVE REPLACEMENT COSTS ($ / Mcfe)
Total Drilling, Before
Revisions (a / d) $- $- $2.59
All-in Total, Net of Revisions (b / e) $- $1.66 $2.60
All-in Total, Excluding Revisions
Due to Price (b / (e - c)) $3.71 $(4.80) $2.50
RESERVE REPLACEMENT
Drilling Only (d / g) - - 252%
All-in Total, Net of Revisions &
Dispositions (f / g) - 79% 228%
All-in Total, Excluding Revisions
Due to Price ((f - c) / g) 134% -27% 238%
EOG RESOURCES, INC.
QUANTITATIVE RECONCILIATION OF NET DEBT (Non-GAAP) AND TOTAL
-------------------------------------------------------------
CAPITALIZATION (Non-GAAP) AS USED IN THE CALCULATION OF
--------------------------------------------------------
THE NET DEBT-TO-TOTAL CAPITALIZATION RATIO
------------------------------------------
TO CURRENT AND LONG-TERM DEBT (GAAP) AND TOTAL CAPITALIZATION (GAAP)
--------------------------------------------------------------------
(Unaudited; in millions, except ratio information)
The following chart reconciles Current and Long-Term Debt (GAAP) to Net
Debt (Non-GAAP) and Total Capitalization (GAAP) to Total Capitalization
(Non-GAAP), as used in the Net Debt-to-Total Capitalization ratio
calculation. A portion of the cash is associated with international
subsidiaries; tax considerations may impact debt paydown. EOG believes
this presentation may be useful to investors who follow the practice of
some industry analysts who utilize Net Debt in their Net Debt-to-Total
Capitalization ratio calculation. EOG management uses this information
for comparative purposes within the industry.
12/31/2008 12/31/2007
---------- ----------
Total Stockholders' Equity (GAAP) - (a) $9,014 $6,990
Current and Long-Term Debt (GAAP) - (b) 1,897 1,185
Less: Cash (GAAP) (331) (54)
---- ---
Net Debt (Non-GAAP) - (c) 1,566 1,131
----- -----
Total Capitalization (Non-GAAP) - (a) + (c) $10,580 $8,121
======= ======
Total Capitalization (GAAP) - (a) + (b) $10,911 $8,175
======= ======
Net Debt-to-Total Capitalization (Non-GAAP) -
(c) / [(a) + (c)] 15% 14%
== ==
Debt-to-Total Capitalization (GAAP) - (b) /
[(a) + (b)] 17% 14%
== ==
SOURCE EOG Resources, Inc.