EOG RESOURCES INC annual report, FY2012

EOG Resources, Inc. — 2012 Form 10-K

Reporting period: Fiscal year ended December 31, 2012. The filing also reports fourth-quarter results. EOG is an independent oil and gas exploration, production and marketing company, with operations concentrated in the United States and Canada and additional production in Trinidad and other international areas. This summary reflects the supplied filing text.

Financial and operating performance

Metric	2012	2011	Change
Net operating revenues	$11.683 billion	$10.126 billion	+15%
Operating income	$1.480 billion	$2.113 billion	-30%
Net income	$570 million	$1.091 billion	-48%
Diluted earnings per share	$2.11	$4.10	-49%
Cash flow from operating activities	$5.237 billion	$4.578 billion	+14%
Net cash used in investing activities	$6.119 billion	$5.755 billion	Cash use increased

Operating margin was approximately 12.7% versus 20.9% in 2011; net margin was approximately 4.9% versus 10.8%. These calculations use reported net operating revenues.

Revenue mix and production: Wellhead revenue increased 16% to $7.958 billion. Crude oil and condensate revenue rose 47% to $5.659 billion as deliveries grew 39% and the composite realized price increased 5% to $97.77 per barrel. NGL revenue fell 7% to $727 million as the composite price declined 30% to $35.54 per barrel, partly offset by 32% volume growth. Natural gas revenue fell 30% to $1.572 billion, reflecting a 26% decline in composite price to $2.83/Mcf and a 5% volume decline.

Total production grew 10% to 466.4 thousand Boe per day. Liquids—crude oil, condensate and NGLs—accounted for approximately 46% of production, compared with 37% in 2011. Eagle Ford production reached 94.4 thousand Boe per day, up approximately 150% year over year. The filing reports $394 million in net mark-to-market gains on commodity derivatives in 2012, including $711 million of realized gains; these gains are included in reported results.

Costs and unusual items: Total operating expenses were $10.203 billion, up $2.190 billion. Impairments were $1.271 billion, up from $1.031 billion, and DD&A rose to $3.170 billion from $2.516 billion. Fourth-quarter 2012 included a $1.020 billion pretax impairment charge, primarily on natural gas properties in Canada and the United States, and an additional $135 million income-tax provision for Canadian valuation allowances. The quarter reported a $505 million net loss, compared with positive net income in each of the first three quarters.

Balance sheet, liquidity and capital allocation

Cash and cash equivalents were $876 million at year-end, versus $616 million in 2011. Current assets were $3.590 billion and current liabilities $2.924 billion, implying a current ratio of approximately 1.23.
Debt principal increased to $6.290 billion from $5.040 billion; reported current and long-term debt, including the capital lease and discount presentation, totaled $6.312 billion. Debt-to-total capitalization increased to 32% from 28%. EOG had no commercial paper or revolving-credit borrowings outstanding at year-end and reported $2.0 billion of revolving-credit capacity.
Operating cash flow of $5.237 billion was below total 2012 expenditures of $7.754 billion. EOG funded investment using operating cash flow, $1.234 billion of net proceeds from its 2.625% senior notes due 2023, and $1.310 billion of asset-sale proceeds, among other sources.
Dividends paid were $181 million. The Board raised the quarterly dividend from $0.17 to $0.1875 per share effective with the April 2013 payment. EOG did not repurchase shares under its authorized repurchase program in 2012; reported treasury-share purchases related to employee compensation plans.
Total contractual obligations were $14.355 billion, including $6.290 billion of debt and $5.130 billion of transportation and storage commitments. The filing reports no off-balance-sheet arrangements.

Material changes versus 2011

Revenue and production increased, led by crude oil growth, particularly in the Eagle Ford and Bakken; earnings and operating margin declined substantially.
Natural gas prices and volumes weakened, while NGL prices fell sharply. Revenue growth also included increased third-party gathering, processing and marketing activity and derivative gains.
Capital spending continued to rise. EOG reported $7.5 billion of exploration, development and other property, plant and equipment expenditures excluding asset retirement obligations, compared with $7.0 billion in 2011.
Year-end proved reserves declined by 243 MMBoe to 1,811 MMBoe. Liquids proved reserves increased by 276 million barrels, but natural gas reserves decreased by 519 MMBoe. The filing attributes a 531 MMBoe negative revision primarily to lower natural gas prices used in reserve estimates.
Canadian impairments and tax valuation allowances were significant contributors to the annual and fourth-quarter results. EOG also signed an agreement to sell its Kitimat LNG Terminal and Pacific Trail Pipelines interests and approximately 28,500 undeveloped Horn River acres; the sale closed in February 2013.

Outlook, risks and contingencies

Management expected 2013 production to increase 4% overall from 2012, with total liquids up 23% (crude oil and condensate up 28%; NGLs up 10%) and North American natural gas production down 15%. Planned 2013 capital expenditures were $7.0–$7.2 billion, excluding acquisitions, and management expected spending to exceed operating cash flow. EOG planned approximately $550 million of non-core asset sales to help cover the expected shortfall and retained debt, commercial paper, credit-facility and equity financing options.

Capital priorities centered on U.S. crude oil plays, especially Eagle Ford, Bakken and Three Forks; natural gas drilling was expected to be limited, primarily to acreage retention. For 2013, EOG estimated that each $1/barrel change in crude oil price, combined with the estimated NGL price effect, would change net income by approximately $28 million and operating cash flow by $41 million. Each $0.10/Mcf change in natural gas price was estimated to change net income by approximately $18 million and operating cash flow by $27 million. These sensitivities incorporate specified hedge positions and assumptions in the filing.

Key business risks include volatile commodity prices, reserve-estimation uncertainty, drilling and operating hazards, service and transportation availability, and the ability to replace produced reserves.
Environmental, climate-change and hydraulic-fracturing regulation could increase costs, delay operations or restrict development. EOG also faces foreign-country, currency, counterparty, financing and derivative-market risks; insurance may not cover all losses.
EOG disclosed potential air-emissions violations at certain North Dakota wells. It self-reported, implemented additional controls and expected to finalize a consent agreement with the North Dakota Department of Health in the first quarter of 2013, with reduced fines anticipated. The filing does not state a final penalty amount.
Various ordinary-course lawsuits and claims were pending; management did not expect their resolution, individually or in aggregate, to have a material adverse effect. EOG reported $636 million of standby letters of credit and guarantees outstanding and no demands for payment as of February 21, 2013.
The filing identifies $33 million of unrecognized tax benefits. It also notes that potential U.S. taxes on approximately $2.5 billion of foreign undistributed earnings were not provided because those earnings were considered indefinitely reinvested; possible additional tax on distribution could be significant, but the amount was not practicable to determine.

Deloitte & Touche LLP issued an unqualified opinion on the financial statements and internal control over financial reporting. Management concluded that disclosure controls and internal control over financial reporting were effective at December 31, 2012.

Important facts for investors to verify

Whether 2013 production growth and the forecast liquids mix were achieved, particularly in the Eagle Ford, Bakken and Permian Basin.
Whether planned asset sales generated the projected proceeds and how the capital-spending shortfall was financed; track debt and leverage against the stated balance-sheet objective.
How much of earnings and operating cash flow depended on realized derivative gains, and how hedge volumes, prices and counterparty options compared with production.
Whether gas-price-driven reserve revisions, Canadian impairment charges and valuation allowances continued, and how reserve replacement and proved undeveloped reserves developed.
The outcome and cost of the North Dakota air-emissions matter, as well as developments in environmental, hydraulic-fracturing and other regulatory requirements.
The effects of transportation commitments, asset sales and the Kitimat/PTP divestiture on production access, costs and future cash flows.