This Annual Report on Form 10-K and the documents incorporated herein by reference contain forward-looking statements based on expectations, estimates, and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties, and assumptions and are influenced by various factors. As a consequence, actual results may differ materially from those expressed in the forward-looking statements. See the risk factors set forth in Item 1A of this Form 10-K and Part II, Item 7A—Quantitative and Qualitative Disclosures About Market Risk—Forward-Looking Statements and Risk of this Form 10-K.

General

Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. We currently have exploration and production interests in six countries: the U.S., Canada, Egypt, Australia, the U.K. North Sea (North Sea), and Argentina. Apache also pursues exploration interests in other countries that may over time result in reportable discoveries and development opportunities. We treat all operations as one line of business.

Our common stock, par value $0.625 per share, has been listed on the New York Stock Exchange (NYSE) since 1969, on the Chicago Stock Exchange (CHX) since 1960, and on the NASDAQ National Market (NASDAQ) since 2004. On June 5, 2013, we filed certifications of our compliance with the listing standards of the NYSE and the NASDAQ, including our principal executive officer’s certification of compliance with the NYSE standards. Through our website, www.apachecorp.com , you can access, free of charge, electronic copies of the charters of the committees of our Board of Directors, other documents related to our corporate governance (including our Code of Business Conduct and Governance Principles), and documents we file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. Included in our annual and quarterly reports are the certifications of our principal executive officer and our principal financial officer that are required by applicable laws and regulations. Access to these electronic filings is available as soon as reasonably practicable after we file such material with, or furnish it to, the SEC. You may also request printed copies of our committee charters or other governance documents free of charge by writing to our corporate secretary at the address on the cover of this report. Our reports filed with the SEC are made available to read and copy at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C., 20549. You may obtain information about the Public Reference Room by contacting the SEC at 1-800-SEC-0330. Reports filed with the SEC are also made available on its website at www.sec.gov . From time to time, we also post announcements, updates, and investor information on our website in addition to copies of all recent press releases. Information on our website or any other website is not incorporated by reference into, and does not constitute a part of, this Annual Report on Form 10-K.

Properties to which we refer in this document may be held by subsidiaries of Apache Corporation. References to “Apache” or the “Company” include Apache Corporation and its consolidated subsidiaries unless otherwise specifically stated.

Growth Strategy

Apache’s mission is to grow a profitable global exploration and production company in a safe and environmentally responsible manner for the long-term benefit of our shareholders. Apache’s long-term perspective has many dimensions, which are centered on the following core strategic components:

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Throughout the cycles of our industry, these strategies have underpinned our ability to deliver long-term production and reserve growth and achieve competitive returns on invested capital for the benefit of our shareholders. We have increased reserves 23 out of the last 28 years and production 32 out of the past 35 years, a testament to our consistency over the long-term.

Apache pursues growth opportunities through exploration and development drilling, supplemented by occasional strategic acquisitions and portfolio highgrading through asset divestitures. At the end of 2012 and the beginning of 2013, Apache undertook a strategic review of our portfolio with the ultimate goal of keeping the right mix of assets that generate strong returns and excess cash flow and drive more predictable production growth to create shareholder value. In May 2013, Apache announced that it would divest approximately $4 billion in assets and use the proceeds to pay down debt and repurchase Apache common shares. Apache surpassed these goals, divesting approximately $7 billion of assets, paying down $2.6 billion in debt, and repurchasing $1 billion in Apache common shares during 2013. Significant transactions since announcing our strategic repositioning initiatives include:

Our growth portfolio going forward will be centered on (i) increasing onshore North American liquids production that provides for more predictable and attractive rates of return, (ii) generating excess cash flow from our international operations, and (iii) continuing longer-term growth initiatives, which include our Wheatstone and Kitimat LNG projects. In 2013, we demonstrated the effectiveness of our transition towards North American Onshore liquids growth, with all four of our onshore North American regions increasing liquids production and by replacing more than our worldwide production through our exploration and development activities.

For a more in-depth discussion of our growth strategy, 2013 results, and the Company’s capital resources and liquidity, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.

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Geographic Area Overviews

During 2013, we had exploration and production interests in six countries: the U.S., Canada, Egypt, Australia, the U.K. North Sea, and Argentina. Apache also pursues exploration interests in other countries that may over time result in reportable discoveries and development opportunities.

The following table sets out a brief comparative summary of certain key 2013 data for each of our operating areas. Additional data and discussion is provided in Part II, Item 7 of this Form 10-K.

North America

Apache’s North American asset base primarily comprises operations in the Permian Basin, the Anadarko basin in western Oklahoma and the Texas Panhandle, Gulf Coast onshore and offshore areas of the U.S., and in Western Canada. We also have leasehold acreage holdings in the Cook Inlet of Alaska and other areas where we are pursuing exploration opportunities. Over the past several years, the Company has acquired significant acreage positions in many attractive basins and plays across North America. This extensive portfolio expansion phase shifted during 2013 when we completed strategic divestitures to rebalance our portfolio to an asset mix that we believe will continue to generate strong returns, drive more predictable growth and deliver increased value to our shareholders. As part of this effort, Apache’s drilling activity has focused on our North America onshore assets, which had liquids growth of 34 percent during 2013, primarily in the Permian Basin and Anadarko basin.

North America contributed approximately 58 percent of our worldwide production and 50 percent of our oil and gas production revenues for the year. At year-end 2013, North America held 68 percent of our estimated worldwide proved reserves including noncontrolling interests in Egypt.

United States

Overview  We have access to significant liquid hydrocarbons across our 11.5 million gross acres in the U.S., approximately 75 percent of which is undeveloped. In 2013, 61 percent of our U.S. production and 67 percent of our U.S. year-end reserves were oil and natural gas liquids. Approximately 44 percent of Apache’s worldwide equivalent 2013 production and 51 percent of our estimated proved reserves were in the U.S. To better control our development efforts across broad acreage positions within the U.S., during 2013 our assets were divided into five regions: Permian, Central, Gulf Coast Onshore, Gulf of Mexico Deepwater, and the Gulf of Mexico Shelf. In 2014, the Gulf of Mexico Shelf region and Gulf of Mexico Deepwater region have been combined into the Gulf of Mexico region.

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Permian Region  Our Permian region controls over 3.3 million gross acres with exposure to numerous plays across the Permian Basin. Apache is one of the largest operators in the Permian Basin, with more than 13,500 producing wells in 155 fields, including 47 waterfloods and seven CO ² floods. Total region production for 2013 was up over 17 percent sequentially as a result of an active drilling program where we ran an average of 42 rigs during the year. Production in the region has increased for 12 consecutive quarters. During the year, we drilled or participated in drilling 785 wells, of which 186 were horizontal. The Permian region’s year-end 2013 estimated proved reserves were 910 MMboe, representing 14 percent growth over year-end 2012.

A key focus area of our activity during the year continued to be the multi-zone development of the Deadwood area. Deadwood is the most active of our plays in the Midland basin where we ran an average of nearly 10 rigs and drilled 189 wells. Our activity in the Deadwood area is primarily drilling vertical wells targeting the Wolfwood and the Fusselman zones.

Over the past several years, the region has been testing numerous formations and building a large inventory of horizontal opportunities in several plays across our acreage position. Our success has led the region to increase the number of horizontal drilling rigs being utilized throughout 2013, and now approximately half of our rigs are drilling horizontal wells. In 2013, we ramped up multi-rig development programs in several horizontal plays in the Midland basin, targeting the Wolfcamp and Cline Shales. We have also increased development activity in our Yeso area of New Mexico and across the Permian’s Central Basin Platform. These extensive programs will carry into 2014 and drive the region’s growth.

We continue to balance large development programs with exploration activity in several new areas. Given its acreage holdings, recent seismic data acquisitions and continued exploration efforts, the region has built a deep portfolio of drilling inventory and opportunities to sustain our activity for many years. For 2014, the Permian region plans to invest approximately $2.55 billion. The region’s capital program covers planned expenditures for drilling, completions, recompletion projects, equipment upgrades, expansion of existing facilities and equipment, plugging and abandonment, seismic studies, and leasing additional acreage.

Central Region  The Central region controls 1.8 million gross acres that are mostly held-by-production and includes more than 3,800 producing wells primarily in western Oklahoma and the Texas Panhandle. The region was Apache’s first core area and has historically grown through low-risk, highly predictable exploitation. Over the last several years, the region has aggressively targeted oil and liquids-rich gas plays through horizontal drilling across its acreage holdings. Oil and liquids production expanded during 2013, with oil production growth of 61 percent and NGL production more than doubling compared to the prior year. Total region production in 2013 was 91 Mboe/d, of which 50 percent was oil and natural gas liquids. As of year-end, the Central region’s estimated proved reserves totaled 304 MMboe, an increase of nearly 14 percent from year-end 2012.

The primary factor driving the region’s growth in 2013 was an active drilling program where we ran an average of 24 rigs during the year, over a 30 percent increase from the prior year. We drilled or participated in drilling 322 wells during 2013, with 98 percent being completed as producers.

The vast majority of our drilling activity has been in the Anadarko basin, which consists of a series of thick, stacked formations of liquids-rich, low-permeability sandstones. The Company’s significant acreage position in the basin provides a robust drilling inventory for the next several years across numerous horizontal liquids plays, notably the Granite Wash, Tonkawa, Marmaton, Cottage Grove, and Cleveland. In addition, in 2013 the region continued to invest in infrastructure facilities and contractually secure takeaway capacity.

In addition, in 2011 Apache acquired 92,000 contiguous net acres in the Whittenburg basin, located approximately 70 miles west of our Anadarko basin properties. The region has operated two drilling rigs targeting vertical objectives in 2012 and 2013, completing 26 vertical wells into the Canyon Wash sand and achieving a peak production rate of 10 Mb/d and 16 MMcf/d. Apache has now turned its attention to the prolific Canyon lime and is currently drilling its first horizontal test.

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The Central region plans to run an average of 34 rigs during 2014 and invest approximately $1.75 billion for drilling, recompletions, equipment upgrades, and production enhancement projects.

Gulf Coast Regions  Our Gulf Coast assets are primarily located in and along the Gulf of Mexico, in the areas onshore and offshore Texas, Louisiana, Alabama, and Mississippi. During 2013 the area was divided into three regions, which include the Gulf Coast Onshore, Gulf of Mexico Deepwater, and Gulf of Mexico Shelf. In 2014, the Gulf of Mexico Shelf region and Gulf of Mexico Deepwater region have been combined into the Gulf of Mexico region.

Apache’s Gulf Coast Onshore region is known for its proven onshore and near-shore basins of Texas, Louisiana and Mississippi where it has a significant acreage position of approximately 1.3 million gross acres, including approximately 275,000 mineral fee acres. During the year, the region primarily drilled shallow and moderate-depth development wells and completed the construction of gathering and processing facilities in our Atchafalaya Bay development project. The region also continued evaluating deeper exploitation opportunities and several unconventional resource plays, which included drilling three Eagle Ford shale wells on our Southeast Texas acreage with plans to substantially increase activity in 2014. For the year, the region drilled or participated in drilling 43 wells and projects drilling approximately 90 wells in 2014.

In offshore waters greater than 500 feet deep, the Gulf of Mexico Deepwater region is a relatively underexplored and oil-prone area that provides exposure to significant reserve and production potential. The Company owns over 900,000 gross acres across nearly 170 blocks as of the end of 2013. The Deepwater region contributed approximately two percent of Apache’s worldwide production with multiple projects and developments underway. The non-operated Lucius project, where Apache holds an 11.7 percent working interest, is currently under development with first production projected by year-end 2014. In addition, the large scale non-operated Heidelberg project was sanctioned in late 2012. Apache has a 12.5 percent working interest in this development with first production projected for 2016.

Apache’s former Gulf of Mexico Shelf region, constituting Gulf assets in waters less than 500 feet deep, experienced a significant shift during 2013 as the region’s producing base and associated infrastructure was sold to Fieldwood in September. As part of the transaction, Apache retained 50 percent of its ownership interest in all exploration blocks and in horizons below production in developed blocks, and access to existing infrastructure. These retained interests cover approximately 2.5 million gross acres across 515 offshore blocks. Several wells are expected to be drilled during 2014, and we expect future activities to provide a platform for continued exploration growth in this basin. Total region production in 2013 was 71 Mboe/d, reflecting nine months of Shelf production prior to the divestiture.

In 2014, Apache plans to invest approximately $550 million and $450 million in its Gulf Coast (formerly Gulf Coast Onshore) and Gulf of Mexico regions, respectively. The capital will be spent on drilling, recompletion, and development projects, equipment upgrades, production enhancement projects, seismic acquisitions, additional leasing activity, and plugging and abandonment of wells and platforms.

U.S. Marketing  In general, most of our U.S. gas is sold at either monthly or daily market prices. Also, from time to time, the Company will enter into fixed physical sales contracts for durations of up to one-year. These physical sales volumes are typically sold at fixed prices over the term of the contract. Our natural gas is sold primarily to local distribution companies (LDCs), utilities, end-users, marketers, and integrated major oil companies. We strive to maintain a diverse client portfolio, which is intended to reduce the concentration of credit risk.

Apache primarily markets its U.S. crude oil to integrated major oil companies, marketing and transportation companies, and refiners based on a West Texas Intermediate (WTI) price, adjusted for quality, transportation and a market-reflective differential. The objective is to maximize the value of crude oil sold by identifying the best markets and most economical transportation routes available to move the product. Sales contracts are generally 30-day evergreen contracts that renew automatically until canceled by either party. These contracts provide for sales that are priced daily at prevailing market prices. Also, from time to time, the Company will enter into physical term sales contracts for durations up to five years. These term contracts typically have a firm transport commitment and often provide for the higher of prevailing market prices from multiple market hubs.

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Apache’s NGL production is sold under contracts with prices based on local supply and demand conditions, less the costs for transportation and fractionation, or on a weighted-average sales price received by the purchaser.

Canada

Overview Apache entered the Canadian market in 1995 and currently holds nearly 5.4 million gross acres across the provinces of British Columbia, Alberta, and Saskatchewan. The region’s large acreage position provides portfolio diversification as well as significant drilling opportunities. Our Canadian region provided approximately 14 percent of Apache’s 2013 worldwide production.

In 2013, Apache drilled or participated in drilling 143 wells in Canada, with a continued focus on increasing oil and liquids-rich gas production. Reservoir modeling and horizontal drilling technology advanced several oil and liquids-rich gas plays in the Montney, Swan Hills, Viking, Bluesky, and Glauconite formations. Success with multi-stage fracture completions continues to increase the scope of oil and liquids-rich gas drilling opportunities.

We also furthered our region’s shift toward an oil and liquids-rich gas asset portfolio through several strategic divestitures of primarily dry gas assets during 2013. In September we completed the sale of certain Alberta producing assets for approximately $214 million. The assets comprised 621,000 gross acres (530,000 net acres) and more than 2,700 wells in the Nevis, North Grant Lands, and South Grant Lands areas. In October 2013, we completed two additional sales of producing properties in Saskatchewan and Alberta for $112 million. The divested assets comprised approximately 4,000 operated and 1,300 non-operated wells, including our Hatton, St. Lina, Marten Hills, Snipe Lake, and Valhalla developments, as well as a portion of our Hawkeye producing properties. Combined, our 2013 divestitures totaled 13 percent of the region’s production.

The Kitimat LNG project will allow us to monetize large unconventional natural gas resources in the Liard and Horn River basins in northern British Columbia. In February 2013, Apache completed a transaction with Chevron Canada Limited (Chevron Canada) under which each company became a 50 percent owner of the Kitimat LNG plant, the Pacific Trail Pipelines Limited Partnership (PTP), and 644,000 gross undeveloped acres in the Horn River and Liard basins. Chevron Canada will operate the LNG plant and pipeline while Apache Canada will continue to operate the upstream assets. The Kitimat plant has received all significant environmental approvals and a 20-year export license from the Canadian federal government. Although the project has not reached a final investment decision, we believe Chevron’s experience in developing LNG projects and marketing expertise will assist in moving the development forward. In 2014, we plan to invest approximately $1.0 billion of capital in the Kitimat project, which includes the LNG plant as well as our upstream assets in the Horn River and Liard basins. With a 50 percent project participation, Apache is actively evaluating ways to right-size its level of participation in the Kitimat LNG project.

Additionally, the region plans to invest approximately $600 million in drilling and development projects, equipment upgrades, and production enhancement projects for our other upstream assets.

Marketing Our Canadian natural gas marketing activities focus on sales to utilities, end-users, integrated major oil companies, supply aggregators, and marketers. We maintain a diverse client portfolio, which is intended to reduce the concentration of credit risk in our portfolio. To diversify our market exposure, we transport natural gas under firm transportation contracts to delivery points into the United States. We sell the majority of our Canadian gas on a monthly basis at either first-of-the-month or daily AECO index prices. Also, from time to time, the Company will enter into fixed physical sales contracts for durations of up to one-year. These physical sales volumes are typically sold at fixed prices over the term of the contract.

Canadian crude oil production is sold to integrated major companies, refiners, and marketing companies based on a WTI price, adjusted for quality, transportation, and a market-reflective differential. The crude is transported by pipeline or truck within Western Canada to market hubs in Alberta and Manitoba where it is sold, allowing for a more diversified group of purchasers and a higher netback price. A portion of our trucked barrels

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are delivered and sold at rail terminals. We evaluate our transport options monthly to maximize our netback prices.

The region’s NGL production is sold under contracts with prices based on local supply and demand conditions, less the costs for transportation and fractionation, or on a weighted-average sales price received by the purchaser.

International

Apache’s international assets are located in Egypt, Australia, offshore the U.K. in the North Sea, and Argentina. In 2013, international assets contributed 42 percent of our production and 50 percent of our oil and gas revenues. At year-end 2013, 32 percent of our estimated proved reserves were located outside North America.

Egypt

Overview Our activity in Egypt began in 1994 with our first Qarun discovery well, and today we are one of the largest acreage holders in Egypt’s Western Desert. At year-end, we held 9.8 million gross acres, with gross oil production of 198 Mb/d and gross natural gas production of 912 MMcf/d in 2013, or 90 Mb/d and 356 MMcf/d net to Apache’s consolidated holdings. Although 3.0 million gross undeveloped acres expired in January 2014, we continue to pursue longer term extensions on areas we believe provide attractive growth opportunities. Of our remaining acreage, 72 percent is undeveloped, providing us with considerable exploration and development opportunities for the future.

Our operations in Egypt are conducted pursuant to production-sharing agreements in 24 separate concessions, under which the contractor partners pay all operating and capital expenditure costs for exploration and development. Development leases within concessions currently have expiration dates ranging from 2 to 25 years, with extensions possible for additional commercial discoveries or on a negotiated basis. A percentage of the production on development leases, usually up to 40 percent, is available to the contractor partners to recover operating and capital expenditure costs, with the balance generally allocated between the contractor partners and the Egyptian General Petroleum Corporation (EGPC) on a contractually defined basis. In 2013 Apache was granted 20 new development leases, representing one of our most successful years since our entry into Egypt.

Our growth in Egypt has been driven by an ongoing drilling program, and we have historically been one of the most active drillers in the Western Desert. During 2013, we drilled 181 development and injection wells and 54 exploration wells. Approximately 60 percent of our exploration wells were successful, further expanding our presence in the westernmost concessions and unlocking additional opportunities in existing plays. A key component of the region’s success has been the ability to acquire and evaluate 3-D seismic surveys that enable our technical teams to consistently high-grade existing prospects and identify new targets across multiple pay horizons in the Cretaceous, Jurassic, and deeper Paleozoic formations.

Apache has also made a strategic decision to advance the application of horizontal drilling technology to unlock new plays in Egypt. During the year, we drilled our first well of a multi-well horizontal drilling program in the Abu Gharadig field. During December, this well produced an average of 1,681 b/d and 3 MMcf/d from a 1,970 foot lateral. This well was one of eight horizontal wells initiated during 2013 to test the technology’s ability to increase recoveries in a variety of conventional and unconventional reservoirs. Additional horizontal drilling is planned in the Abu Gharadig and surrounding fields in 2014.

In November 2013, Apache announced the completion of the sale of a one-third minority interest in its Egypt oil and gas business to Sinopec. After customary closing adjustments, Apache received cash consideration of $2.95 billion. At year-end 2013, our Egypt region’s estimated proved reserves were 271 MMboe, of which 90

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MMboe is attributable to Sinopec’s noncontrolling interest. Our estimated proved reserves in Egypt are reported under the economic interest method and exclude the host country’s share of reserves.

Heading into 2014, the region will continue an active drilling program and plans to invest approximately $1.4 billion, including approximately $460 million attributable to Sinopec’s noncontrolling interest, for drilling, recompletion projects, development projects, and seismic acquisition.

Marketing Our gas production is sold to EGPC primarily under an industry-pricing formula, a sliding scale based on Dated Brent crude oil with a minimum of $1.50 per MMBtu and a maximum of $2.65 per MMBtu, plus an upward adjustment for liquids content. The region averaged $2.99 per Mcf in 2013.

Oil from the Khalda Concession, the Qarun Concession, and other nearby Western Desert blocks is sold to third parties in the export market or to EGPC when called upon to supply domestic demand. Oil sales are exported from or sold at one of two terminals on the northern coast of Egypt. Oil production that is presently sold to EGPC is sold on a spot basis priced at Brent with a monthly EGPC official differential applied.

Egypt political unrest In February 2011, former Egyptian president Hosni Mubarak stepped down, and the Egyptian Supreme Council of the Armed Forces took power, announcing that it would remain in power until presidential and parliamentary elections could be held. In June 2012, President Mohamed Morsi of the Muslim Brotherhood’s Freedom and Justice Party was elected as Egypt’s new president.

In July 2013, the Egyptian military removed President Morsi from power and installed Egypt’s Chief Justice, Adly Mansour, as acting president of a temporary government, which announced that it would seek to schedule parliamentary and presidential elections in early to mid-2014. In January 2014, Egyptians voted on and overwhelmingly approved a new constitution, and Mr. Mansour announced that the presidential election will be held prior to the parliamentary elections. While the date of the presidential election has not been announced, it is expected to be held by mid-April 2014.

Apache’s operations, located in remote locations in the Western Desert, have not experienced production interruptions, and we have continued to receive development lease approvals for our drilling program. However, a further deterioration in the political, economic, and social conditions or other relevant policies of the Egyptian government, such as changes in laws or regulations, export restrictions, expropriation of our assets or resource nationalization, and/or forced renegotiation or modification of our existing contracts with EGPC could materially and adversely affect our business, financial condition, and results of operations.

Apache purchases multi-year political risk insurance from the Overseas Private Investment Corporation (OPIC) and other highly rated international insurers covering a portion of its investments in Egypt. In the aggregate, these insurance policies, subject to the policy terms and conditions, provide approximately $856 million of coverage to Apache for losses arising from confiscation, nationalization, and expropriation risks, with a $149 million sub-limit for currency inconvertibility.

In addition, Apache has a separate policy with OPIC, which provides $300 million of coverage for losses arising from (1) non-payment by EGPC of arbitral awards covering amounts owed Apache on past due invoices and (2) expropriation of exportable petroleum in the event that actions taken by the government of Egypt prevent Apache from exporting our share of production. In October 2012, the Multilateral Investment Guarantee Agency (MIGA), a member of the World Bank Group, announced that it was providing $150 million in reinsurance to OPIC for the remainder of the policy term. This provision of long-term reinsurance to OPIC will allow Apache to maintain the $300 million of insurance coverage through 2024.

Australia

Overview  Apache’s holdings in Australia are focused offshore Western Australia in the Carnarvon, Exmouth, and Browse basins, with production operations in the Carnarvon and Exmouth basins. We have

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operated in the Carnarvon basin since acquiring the gas processing facilities on Varanus Island and adjacent producing properties in 1993. In total, we control approximately 7.9 million gross acres offshore Western Australia through 30 exploration permits, 18 production licenses, and 9 retention leases. Approximately 89 percent of our acreage is undeveloped, and the region continues to actively pursue additional acreage opportunities.

During 2013, the region had net production of 19 Mb/d and 223 MMcf/d, contributing 7 percent of Apache’s worldwide consolidated production revenue, 7 percent of worldwide consolidated production and 12 percent of year-end consolidated proved reserves. Production compared to the prior year was 12 percent lower primarily as a result of natural decline in the Pyrenees and Van Gogh oil fields.

Partially offsetting production declines from Pyrenees and Van Gogh was production through the BHP Billiton-operated Macedon gas plant, which commenced operations in the third quarter of 2013. The $1.5 billion natural gas facility, Western Australia’s fourth domestic gas hub, has a production capacity of approximately 200 MMcf/d. Gas is delivered to the facility via a 60-mile pipeline from four completed subsea gas wells in the Macedon field. Apache has successfully marketed production in the Macedon field under long-term contracts at prices higher than historical realizations. We have a 28.57 percent non-operating working interest in the field and gas plant. Apache has a participating interest in three of the four domestic gas hubs in Australia.

The region participated in drilling 12 offshore wells during 2013, of which 4 were exploration or appraisal wells, compared to 15 wells drilled in 2012. Over the past decade, the region’s exploration activity has established a significant pipeline of projects that are expected to contribute to production growth as they are brought online in the coming years.

Development of the Coniston oil field project, which lies just north of the Van Gogh field, continued toward projected first production in 2014. The field will be produced via subsea completions tied back to the Ningaloo Vision Floating Production Storage and Offloading Vessel (FPSO) at Van Gogh. Required modifications to the FPSO and the final phase of subsea installation work is planned for the first half of 2014. Apache has a 52.5 percent working interest in the field.

The region also continued development of the Balnaves field, an oil discovery located near the Brunello gas field. Development well drilling commenced in the third quarter of 2013, and the project is expected to begin production by the third quarter of 2014 utilizing a leased FPSO vessel. Apache has a 65 percent working interest in the project.

In 2013, further advances were made on the region’s largest development effort, which is the Chevron-operated Wheatstone LNG project (Wheatstone). The first phase of the Wheatstone project will comprise two LNG processing trains with a combined capacity of approximately 8.9 million metric tons per annum (mtpa), a domestic gas plant, and associated infrastructure. Apache has a 13 percent interest in the project and expects to invest approximately $4 billion over five years for the field and LNG facility development. Apache will supply gas to Wheatstone from its operated Julimar and Brunello complex. The 65 percent interest in the Julimar development project is expected to generate average net sales to Apache of approximately 140 MMcf/d of gas (equivalent to 1.07 million mtpa of LNG) at prices pegged to world oil markets, 22 MMcf/d of sales gas into the domestic market, and 3,250 barrels of condensate per day. First production is projected for the end of 2016.

These development projects require significant capital investments above those for traditional drilling programs. During 2014, the region plans to invest approximately $800 million for drilling, recompletion projects, development projects, equipment upgrades, production enhancement projects, and seismic acquisition. Approximately $1.4 billion of additional 2014 capital will be invested in the Wheatstone development project.

Marketing Western Australia has historically had a local market for natural gas with a limited number of buyers and sellers resulting in sales under mostly long-term, fixed-price contracts, many of which contain

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periodic price revision clauses based on either the Australian consumer price index or a commodity linkage. As of December 31, 2013, Apache had 21 active gas contracts in Australia with expiration dates ranging from August 2014 to December 2026. Recent increases in demand and higher development costs have increased the prices required from the local market in order to support the development of new supplies. As a result, market prices negotiated on recent contracts are substantially higher than historical levels.

We directly market all of our Australian crude oil production into Australian domestic and international markets at prices generally indexed to Dated Brent benchmark crude oil prices plus premiums, which typically result in sales well above crude sold at WTI-based prices.

During 2013 Apache finalized binding Sales and Purchase Agreements with two Asian customers for the delivery of approximately 25 percent of Apache’s net LNG offtake from Wheatstone.

North Sea

Overview Apache entered the North Sea in 2003 after acquiring an approximate 97 percent working interest in the Forties field (Forties). Apache has actively invested in the region and has established a large inventory of drilling prospects through successful exploration programs and the interpretation of acquired 3-D and 4-D seismic data. Building upon its success in Forties, Apache in 2012 acquired Mobil North Sea Limited (Mobil North Sea), providing the region with additional exploration and development opportunities across numerous fields, including operated interests in the Beryl, Nevis, Nevis South, Skene, and Buckland fields and non-operated interests in the Maclure, Scott, and Telford fields. In total, Apache has interests in approximately 1.2 million gross acres in the U.K. North Sea.

In 2013, the North Sea region produced 65 Mb/d and 51 MMcf/d, contributing 17 percent of Apache’s worldwide consolidated production revenue, 10 percent of worldwide consolidated production, and 6 percent of year-end consolidated proved reserves. During the year we drilled 19 wells in the North Sea, of which 17 were productive. Apache’s drilling success was highlighted with discoveries in the Tonto oil field. The Tonto-1 well, completed in April, had initial production of 10.3 Mb/d, and the Tonto-2 well, completed in September, had initial production of 8.3 Mb/d. Apache has a 100 percent working interest in the wells. The Tonto discovery follows Maule and Bacchus as the third new field brought online by Apache in the Forties area over the last three years. All three fields qualify for the U.K.’s small field allowance, which provides economic incentives for operators to bring discoveries from small fields into production. During the fourth quarter the region continued to commission the Forties Alpha Satellite Platform, adjacent to the main Forties Alpha platform. This platform has been constructed to exploit new opportunities at Forties and provides an additional 18 drilling slots as well as power generation, fluid separation, and gas lift compression.

In 2014, the region plans to invest approximately $900 million on drilling, recompletion projects, development projects, equipment upgrades, production enhancement projects, and seismic acquisition, focusing on both the Beryl field and Forties area.

Marketing We have traditionally sold our North Sea crude oil under both term contracts and spot cargoes. The Forties term sales are composed of a market-based index price plus a premium, which reflects the higher market value for term arrangements. The prices received for Beryl spot cargoes are market driven and can trade at a premium to the market-based index.

Natural gas from the Beryl field is processed through the SAGE gas plant operated by Apache. The gas is sold to a third party at the St. Fergus entry point of the national grid on a National Balancing Point index price basis. The condensate mix from the SAGE plant is processed further downstream. The split streams of propane and butane are sold on a monthly entitlement basis, and condensate is sold on a spot basis at the Braefoot Bay terminal using index pricing less transportation.

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Argentina

Overview We have had a continuous presence in Argentina since 2001 and have grown our holdings in the region through an active drilling program and targeted acquisitions. The region has active operations in the provinces of Neuquén, Rio Negro, and Tierra del Fuego. As of year-end 2013, Apache held interests in 31 concessions, exploration permits, and other interests totaling 3.3 million gross acres in three of the main Argentine hydrocarbon basins: Neuquén, Austral, and Cuyo. These concessions have varying expiration dates ranging from one year to over 15 years remaining, subject to potential extensions. In 2013, Argentina produced 6 percent of our worldwide consolidated production and held 4 percent of our year-end consolidated proved reserves.

On February 12, 2014, Apache announced an agreement to sell all of its operations in Argentina to YPF for cash consideration of $800 million plus the assumption of $52 million of bank debt as of June 30, 2013. The transaction is expected to close in the first quarter of 2014.

Marketing

Natural Gas Apache sells its natural gas in Argentina through three different pricing structures:

In 2013, we realized an average price of $2.96 per Mcf in the region.

Crude Oil The crude oil in Argentina is subject to an export tax which effectively limits the prices buyers are willing to pay for domestic sales. In 2013 there was an increase on the price of the crude paid by refiners, a combination of an increase of the sales price of fuels to end-users and the decrease of domestic production. Apache´s average sales price in Argentina during 2013 was $79.05 per barrel.

Other Exploration

New Ventures

Apache’s global New Ventures team provides exposure to new growth opportunities by looking outside of the Company’s traditional core areas and targeting higher-risk, high-reward exploration opportunities located in frontier basins as well as new plays in more mature basins. During 2014, we plan to invest approximately $75 million to further several projects and continue pursuing additional exploration opportunities.

Major Customers

In 2013, 2012, and 2011 purchases by Royal Dutch Shell plc and its subsidiaries accounted for 24 percent, 20 percent, and 11 percent, respectively, of the Company’s worldwide oil and gas production revenues. In 2011, purchases by the Vitol Group accounted for 13 percent of the Company’s worldwide oil and gas production revenues.

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Drilling Statistics

Worldwide in 2013 we participated in drilling 1,591 gross wells, with 1,520 (96 percent) completed as producers. Historically, our drilling activities in the U.S. have generally concentrated on exploitation and extension of existing producing fields rather than exploration. As a general matter, our operations outside of the U.S. focus on a mix of exploration and development wells. In addition to our completed wells, at year-end a number of wells had not yet reached completion: 160 in the U.S. (115.4 net); 17 in Egypt (17.0 net); and 2 in Argentina (0.3 net).

The following table shows the results of the oil and gas wells drilled and completed for each of the last three fiscal years:

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Gross natural gas and crude oil wells include 650 wells with multiple completions.

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As of December 31, 2013, Apache had 3.2 million net undeveloped acres scheduled to expire by year-end 2014 if production is not established or we take no other action to extend the terms. Additionally, Apache has 2.7 million and 1.9 million net undeveloped acres set to expire in 2015 and 2016, respectively. We strive to extend the terms of many of these licenses and concession areas through operational or administrative actions, but cannot assure that such extensions can be achieved on an economic basis or otherwise on terms agreeable to both the Company and third parties including governments.

Exploration concessions in our Egypt region comprise a significant portion of our net undeveloped acreage expiring over the next three years. We have 1.5 million net acres in Egypt scheduled to expire in 2014, and 1.0 million and 0.9 million net undeveloped acres set to expire in 2015 and 2016, respectively. Nearly all of the acreage expiring in 2014 was relinquished in January. There were no reserves recorded on this undeveloped acreage. Apache will continue to pursue acreage extensions in areas in which it believes exploration opportunities exist and over the past year has been successful in being awarded six-month extensions on targeted concessions. Longer term extensions are also being finalized with EGPC.

As of December 31, 2013, 23 percent of U.S. net undeveloped acreage and 54 percent of Canadian undeveloped acreage was held by production.

Estimated Proved Reserves and Future Net Cash Flows

Proved oil and gas reserves are the estimated quantities of natural gas, crude oil, condensate, and NGLs that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing conditions, operating conditions, and government regulations. Estimated proved developed oil and gas reserves can be expected to be recovered through existing wells with existing equipment and operating methods. The Company reports all estimated proved reserves held under production-sharing arrangements utilizing the “economic interest” method, which excludes the host country’s share of reserves.

Estimated reserves that can be produced economically through application of improved recovery techniques are included in the “proved” classification when successful testing by a pilot project or the operation of an active, improved recovery program using reliable technology establishes the reasonable certainty for the engineering analysis on which the project or program is based. Economically producible means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. Reasonable certainty means a high degree of confidence that the quantities will be recovered. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In estimating its proved reserves, Apache uses several different traditional methods that can be classified in three general categories: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy with similar properties. Apache will, at times, utilize additional technical analysis, such as computer reservoir models, petrophysical techniques, and proprietary 3-D seismic interpretation methods, to provide additional support for more complex reservoirs. Information from this additional analysis is combined with traditional methods outlined above to enhance the certainty of our reserve estimates.

Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time period.

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The following table shows proved oil, NGL, and gas reserves as of December 31, 2013, based on average commodity prices in effect on the first day of each month in 2013, held flat for the life of the production, except where future oil and gas sales are covered by physical contract terms. This table shows reserves on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the current price ratio between the two products.

As of December 31, 2013, Apache had total estimated proved reserves of 1,131 MMbbls of crude oil, 292 MMbbls of NGLs, and 7.3 Tcf of natural gas. Combined, these total estimated proved reserves are the energy equivalent of 2.65 billion barrels of oil or 15.9 Tcf of natural gas, of which oil represents 43 percent. As of December 31, 2013, the Company’s proved developed reserves totaled 1,833 MMboe and estimated PUD reserves totaled 813 MMboe, or approximately 31 percent of worldwide total proved reserves. Apache has elected not to disclose probable or possible reserves in this filing.

The Company’s estimates of proved reserves, proved developed reserves and PUD reserves as of December 31, 2013, 2012, and 2011, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 14—Supplemental Oil and Gas Disclosures in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K. Estimated future net cash flows were calculated using a discount rate of 10 percent per annum, end of period costs, and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements.

Proved Undeveloped Reserves

The Company’s total estimated PUD reserves of 813 MMboe as of December 31, 2013, decreased by 57 MMboe from 870 MMboe of PUD reserves estimated at the end of 2012. During the year, Apache converted 154 MMboe of PUD reserves to proved developed reserves through development drilling activity. In North America, we converted 124 MMboe, with the remaining 30 MMboe in our international areas. We sold 109 MMboe and acquired 1 MMboe of PUD reserves during the year. We added 205 MMboe of new PUD reserves through extensions and discoveries.

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During the year, a total of approximately $3.7 billion was spent on projects associated with reserves that were carried as PUD reserves at the end of 2012. A portion of our costs incurred each year relate to development projects that will be converted to proved developed reserves in future years. We spent $2.1 billion on PUD reserve development activity in North America and $1.6 billion in the international areas. Other than our Julimar/Brunello development project, which is tied to the construction schedule of the Wheatstone LNG project, with projected first production in 2016, we had no material amounts of PUD reserves that have remained undeveloped for five years or more after they were initially disclosed as PUD reserves and no material amounts of PUD reserves which are scheduled to be developed beyond five years from December 31, 2013.

Preparation of Oil and Gas Reserve Information

Apache’s reported reserves are reasonably certain estimates which, by their very nature, are subject to revision. These estimates are reviewed throughout the year and revised either upward or downward, as warranted.

Apache’s proved reserves are estimated at the property level and compiled for reporting purposes by a centralized group of experienced reservoir engineers that is independent of the operating groups. These engineers interact with engineering and geoscience personnel in each of Apache’s operating areas and with accounting and marketing employees to obtain the necessary data for projecting future production, costs, net revenues, and ultimate recoverable reserves. All relevant data is compiled in a computer database application, to which only authorized personnel are given security access rights consistent with their assigned job function. Reserves are reviewed internally with senior management and presented to Apache’s Board of Directors in summary form on a quarterly basis. Annually, each property is reviewed in detail by our corporate and operating region engineers to ensure forecasts of operating expenses, netback prices, production trends, and development timing are reasonable.

Apache’s Executive Vice President of Corporate Reservoir Engineering is the person primarily responsible for overseeing the preparation of our internal reserve estimates and for coordinating any reserves audits conducted by a third-party engineering firm. He has a Bachelor of Science degree in Petroleum Engineering and over 30 years of industry experience with positions of increasing responsibility within Apache’s corporate reservoir engineering department. The Executive Vice President of Corporate Reservoir Engineering reports directly to our Chairman and Chief Executive Officer.

The estimate of reserves disclosed in this Annual Report on Form 10-K is prepared by the Company’s internal staff, and the Company is responsible for the adequacy and accuracy of those estimates. However, the Company engages Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) to review our processes and the reasonableness of our estimates of proved hydrocarbon liquid and gas reserves. Apache selects the properties for review by Ryder Scott based primarily on relative reserve value. We also consider other factors such as geographic location, new wells drilled during the year and reserves volume. During 2013, the properties selected for each country ranged from 83 to 100 percent of the total future net cash flows discounted at 10 percent. These properties also accounted for over 86 percent of the reserves value of our international proved reserves and of the new wells drilled in each country. In addition, all fields containing five percent or more of the Company’s total proved reserves volume were included in Ryder Scott’s review. The review covered 86 percent of total proved reserves, including 89 percent of proved developed reserves and 79 percent of PUD reserves.

During 2013, 2012, and 2011, Ryder Scott’s review covered 92, 88, and 81 percent, respectively, of the Company’s worldwide estimated proved reserves value and 86, 83, and 70 percent, respectively, of the Company’s total proved reserves volume. Ryder Scott’s review of 2013 covered 84 percent of U.S., 82 percent of Canada, 63 percent of Argentina, 99 percent of Australia, 88 percent of Egypt, and 88 percent of the U.K.’s total proved reserves. Ryder Scott’s review of 2012 covered 81 percent of U.S., 78 percent of Canada, 64 percent of Argentina, 99 percent of Australia, 84 percent of Egypt, and 88 percent of the U.K.’s total proved reserves. Ryder Scott’s review of 2011 covered 68 percent of U.S., 69 percent of Canada, 58 percent of Argentina, 99 percent of Australia, 62 percent of Egypt, and 61 percent of the U.K.’s total proved reserves. We have filed Ryder Scott’s independent report as an exhibit to this Form 10-K.

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According to Ryder Scott’s opinion, based on their review, including the data, technical processes, and interpretations presented by Apache, the overall procedures and methodologies utilized by Apache in determining the proved reserves comply with the current SEC regulations, and the overall proved reserves for the reviewed properties as estimated by Apache are, in aggregate, reasonable within the established audit tolerance guidelines as set forth in the Society of Petroleum Engineers auditing standards.

Employees

On December 31, 2013, we had 5,342 employees.

Offices

Our principal executive offices are located at One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. At year-end 2013, we maintained regional exploration and/or production offices in Midland, Texas; Tulsa, Oklahoma; Houston, Texas; Calgary, Alberta; Cairo, Egypt; Perth, Western Australia; Aberdeen, Scotland; and Buenos Aires, Argentina. Apache leases all of its primary office space. The current lease on our principal executive offices runs through December 31, 2018. For information regarding the Company’s obligations under its office leases, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Contractual Obligations and Note 8—Commitments and Contingencies in the Notes to Consolidated Financial Statements set forth in Part IV, Item 15 of this Form 10-K.

Title to Interests

As is customary in our industry, a preliminary review of title records, which may include opinions or reports of appropriate professionals or counsel, is made at the time we acquire properties. We believe that our title to all of the various interests set forth above is satisfactory and consistent with the standards generally accepted in the oil and gas industry, subject only to immaterial exceptions that do not detract substantially from the value of the interests or materially interfere with their use in our operations. The interests owned by us may be subject to one or more royalty, overriding royalty, or other outstanding interests (including disputes related to such interests) customary in the industry. The interests may additionally be subject to obligations or duties under applicable laws, ordinances, rules, regulations, and orders of arbitral or governmental authorities. In addition, the interests may be subject to burdens such as production payments, net profits interests, liens incident to operating agreements and current taxes, development obligations under oil and gas leases, and other encumbrances, easements, and restrictions, none of which detract substantially from the value of the interests or materially interfere with their use in our operations.

Additional Information about Apache

In this section, references to “we,” “us,” “our,” and “Apache” include Apache Corporation and its consolidated subsidiaries, unless otherwise specifically stated.

Remediation Plans and Procedures

Apache and its wholly owned subsidiary, Apache Deepwater LLC (ADW), developed Oil Spill Response Plans (the Plans) for their respective Gulf of Mexico operations to ensure rapid and effective responses to spill events that may occur on such entities’ operated properties as required by the Bureau of Safety and Environmental Enforcement (BSEE) 30 CFR 254.30. Annually, drills are conducted to measure and maintain the effectiveness of the Plans. These drills include the participation of spill response contractors, representatives of Clean Gulf Associates (CGA), and representatives of governmental agencies. In the event of a spill, CGA is the primary oil spill response association available to Apache and ADW. Apache and ADW have received approval for the Plans from BSEE. Apache and ADW personnel each review their respective Plan biennially and update where necessary.

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Both Apache and ADW are members of CGA, a not-for-profit association of producing and pipeline companies operating in the Gulf of Mexico. CGA was created to provide a means of effectively staging response equipment and providing immediate spill response for its member companies’ operations in the Gulf of Mexico. In the event of a spill, CGA’s equipment, which is positioned at various staging points around the Gulf, is ready to be mobilized. In addition, CGA has contracted with Airborne Support Inc. to provide aircraft and dispersant capabilities for CGA member companies. In 2013, Apache incurred charges for CGA of approximately $700,000 based on a per-member fee and annual production.

In the event that CGA resources are already being utilized, other resources are available to Apache. Apache is a member of Oil Spill Response Limited (OSRL), which entitles any Apache entity worldwide to access OSRL’s service. OSRL has access to resources from the Global Response Network, a collaboration of seven major oil industry funded spill response organizations worldwide. If necessary, OSRL’s resources may be, and have been, deployed to areas across the globe, including the Gulf of Mexico. In addition, in February 2012, ADW became a member of Marine Spill Response Corporation (MSRC) and National Response Corporation (NRC), and their resources are available to ADW for its deepwater Gulf of Mexico operations. Furthermore, the spill response resources of other organizations are also available to both Apache and ADW as non-members, albeit at a higher cost. MSRC has an extensive inventory of oil spill response equipment, independent of and in addition to CGA’s equipment. MSRC has contracts in place with over 100 environmental contractors around the country, in addition to hundreds of other companies that provide support services during spill response. In the event of a spill, MSRC will activate these contractors as necessary to provide additional resources or support services requested by its customers. NRC owns a variety of equipment, currently including shallow water portable barges, boom, high capacity skimming systems, inland workboats, vacuum transfer units, and mobile communication centers. NRC has access to hundreds of offshore vessels and supply boats worldwide. The equipment and resources available to MSRC and NRC changes from time to time, and current information is generally available on each company’s website. In 2013, Apache’s Gulf of Mexico Deepwater region incurred charges for NRC of $12,248 based on annual production and charges for MSRC of approximately $1.4 million based on annual production and total wells spud during the year.

An Apache subsidiary is also a member of the Marine Well Containment Company (MWCC) to help the Company fulfill the government’s permit requirements for containment and oil spill response plans in deepwater Gulf of Mexico operations. MWCC is a not-for-profit, stand-alone organization whose goal is to improve capabilities for containing an underwater well control incident in the U.S. Gulf of Mexico. Members and their affiliates have access to MWCC’s extensive containment network and systems. As of December 31, 2013, Apache’s investment in MWCC totals approximately $136 million.

Apache also participates in a number of industry-wide task forces that are studying ways to better access and control blowouts in subsea environments and increase containment and recovery methods. Two such task forces are the Subsea Well Control and Containment Task Force and the Offshore Operating Procedures Task Force.

Competitive Conditions

The oil and gas business is highly competitive in the exploration for and acquisitions of reserves, the acquisition of oil and gas leases, equipment and personnel required to find and produce reserves, and in the gathering and marketing of oil, gas, and natural gas liquids. Our competitors include national oil companies, major integrated oil and gas companies, other independent oil and gas companies, and participants in other industries supplying energy and fuel to industrial, commercial, and individual consumers.

Certain of our competitors may possess financial or other resources substantially larger than we possess or have established strategic long-term positions and maintain strong governmental relationships in countries in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for leases or drilling rights.

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However, we believe our diversified portfolio of core assets, which comprises large acreage positions and well-established production bases across six countries, and our balanced production mix between oil and gas, our management and incentive systems, and our experienced personnel give us a strong competitive position relative to many of our competitors who do not possess similar geographic and production diversity. Our global position provides a large inventory of geologic and geographic opportunities in the six countries in which we have producing operations to which we can reallocate capital investments in response to changes in commodity prices, local business environments, and markets. It also reduces the risk that we will be materially impacted by an event in a specific area or country.

Environmental Compliance

As an owner or lessee and operator of oil and gas properties and facilities, we are subject to numerous federal, provincial, state, local, and foreign country laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on the lessee under an oil and gas lease for the cost of pollution clean-up resulting from operations, subject the lessee to liability for pollution damages and require suspension or cessation of operations in affected areas. Although environmental requirements have a substantial impact upon the energy industry, as a whole, we do not believe that these requirements affect us differently, to any material degree, than other companies in our industry.

We have made and will continue to make expenditures in our efforts to comply with these requirements, which we believe are necessary business costs in the oil and gas industry. We have established policies for continuing compliance with environmental laws and regulations, including regulations applicable to our operations in all countries in which we do business. We have established operating procedures and training programs designed to limit the environmental impact of our field facilities and identify and comply with changes in existing laws and regulations. The costs incurred under these policies and procedures are inextricably connected to normal operating expenses such that we are unable to separate expenses related to environmental matters; however, we do not believe expenses related to training and compliance with regulations and laws that have been adopted or enacted to regulate the discharge of materials into the environment will have a material impact on our capital expenditures, earnings, or competitive position.

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