APA, §1A diff (2020 → 2021)

Item 1A - Risk Factors, Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A - Quantitative and Qualitative Disclosures About Market Risk and elsewhere in this Form 10-K. All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. Except as required by law, we assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise. ii DEFINITIONS All defined terms under Rule 4-10(a) of Regulation S-X shall have their statutorily prescribed meanings when used in this report. As used in this document: “3-D” means three-dimensional. “4-D” means four-dimensional. “b/d” means barrels of oil or natural gas liquids per day. “bbl” or “bbls” means barrel or barrels of oil or natural gas liquids. “bcf” means billion cubic feet of natural gas. “boe” means barrel of oil equivalent, determined by using the ratio of one barrel of oil or NGLs to six Mcf of gas. “boe/d” means boe per day. “Btu” means a British thermal unit, a measure of heating value. “LIBOR” means London Interbank Offered Rate. “Liquids” means oil and natural gas liquids. “LNG” means liquefied natural gas. “Mb/d” means Mbbls per day. “Mbbls” means thousand barrels of oil or natural gas liquids. “Mboe” means thousand boe. “Mboe/d” means Mboe per day. “Mcf” means thousand cubic feet of natural gas. “Mcf/d” means Mcf per day. “MMbbls” means million barrels of oil or natural gas liquids. “MMboe” means million boe. “MMBtu” means million Btu. “MMBtu/d” means MMBtu per day. “MMcf” means million cubic feet of natural gas. “MMcf/d” means MMcf per day. “NGL” or “NGLs” means natural gas liquids, which are expressed in barrels. “NYMEX” means New York Mercantile Exchange. “oil” includes crude oil and condensate. “PUD” means proved undeveloped. “SEC” means United States Securities and Exchange Commission. “Tcf” means trillion cubic feet of natural gas. “U.K.” means United Kingdom. “U.S.” means United States. With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross. iii PART I ITEMS 1 AND 2. BUSINESS AND PROPERTIES 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 four countries: the U.S., Canada, Egypt, and the U.K. (North Sea). 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 May 18, 2015, 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 corporate charter, bylaws, 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. Business Strategy Apache’s mission is to grow a profitable 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: • rigorous portfolio management • financial flexibility • optimization of returns, earnings, and cash flow Rigorous management of our asset portfolio plays a key role in optimizing shareholder value over the long-term. In 2015, Apache completed a multi-year effort to refocus its portfolio and strengthen its financial position. As a part of this effort, the Company monetized certain capital intensive projects that were not accretive to earnings in the near-term and other non-strategic assets. These divestitures included Apache’s interest in LNG projects in Australia and Canada, its exploration and production operations in Australia and Argentina, and mature assets offshore in the Gulf of Mexico. The proceeds were used to reduce debt levels and redeployed to upgrade our portfolio. Preserving financial flexibility is also key to our overall business philosophy. In response to the decline in commodity prices, Apache immediately took proactive measures to reduce activity levels and focused on bringing costs into alignment with commodity prices. We reduced our capital investments by over 60 percent from 2014 levels and realized meaningful reductions in drilling, operating, and overhead costs. These steps, coupled with our strategic divestitures, enabled us to reduce debt $2.5 billion and increase cash $700 million from year-end 2014. We accomplished this in spite of a 47 percent decrease in crude oil realizations and a 44 percent decline in North American natural gas realizations. During 2016 we will continue to focus on our cost structure and expect to realize additional reductions in overhead, operating, and capital costs. In addition, we have chosen to reduce our capital spending to a level at which we believe we can achieve “cash flow neutrality” for the year. We intend to fund our capital program and dividends through cash from operations and a limited amount of non-core asset sales, without external financing. Our 2016 capital budget is over 60 percent lower than 2015 and 80 percent lower than 2014. Our 2016 capital will be allocated on a prioritized basis as follows: (i) maintain assets and keeping them running efficiently and preserve mineral rights and leases, (ii) further optimize and build high quality inventory for the future, (iii) conduct certain medium-cycle, high-impact exploration activities, and (iv) conduct limited-scale development activities that remain economically robust at these low prices. We currently plan capital investments in 2016 in the range of $1.4 to $1.8 billion excluding noncontrolling interest: $700 million to $800 million allocated to North American onshore plays, and the balance to international and U.S. offshore regions. This budget may be adjusted, up or down, with commodity price movements throughout the year. Given the further curtailment of capital spending, we are projecting a production decline of 7 percent to 11 percent in 2016 compared to 2015 levels, after adjusting for divestitures and volumes associated with Egypt’s noncontrolling interest and tax impacts. For a more in-depth discussion of our divestitures, strategy, 2015 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. Geographic Area Overviews We have exploration and production interests in four countries: the U.S., Canada, Egypt, and the U.K. North Sea. Apache also pursues exploration interests in other countries that may over time result in reportable discoveries and development opportunities. During 2015, the Company completed the sale of all of its operations in Australia. Results of operations and cash flows for Australia operations are reflected as discontinued operations in the Company’s financial statements and are not included in the tables below. The following table sets out a brief comparative summary of certain key 2015 data for each of our operating areas. Additional data and discussion is provided in Part II, Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K. (1) Includes production volumes, revenues, and reserves attributable to a noncontrolling interest in Egypt. North America Apache’s North American assets are primarily located in the Permian Basin, the Anadarko basin in western Oklahoma and the Texas Panhandle, Gulf Coast and the offshore Gulf of Mexico areas of the U.S., and in Western Canada. North America Onshore Overview We have access to significant liquid hydrocarbons across our 10.7 million gross acres onshore in the U.S. and Canada. Approximately 55 percent of this acreage is undeveloped. Additionally, 58 percent of Apache’s worldwide equivalent 2015 production and 72 percent of our estimated year-end proved reserves were in our U.S. and Canada onshore regions. Over the past several years, Apache’s drilling activity has centered on our North America onshore assets, which delivered liquids growth of 4 percent during 2015 excluding the impacts of divestitures. To manage our development efforts across our acreage positions within North America, our onshore assets are divided into a few key regions: Permian, MidContinent/Gulf Coast, and Canada. 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 14,300 producing wells in 163 fields, including 58 waterfloods and seven CO2 floods. The Permian region’s year-end 2015 estimated proved reserves were 684 MMboe, representing 44 percent of the Company’s worldwide reserves. Total region production for 2015 was up 6 percent sequentially, despite operating an average rig count of 12 compared to 40 rigs in the prior year. The reduced rig count reflected the Company’s decisive action to reduce capital spending in response to rapidly declining commodity prices. During the year, we drilled or participated in drilling 378 wells, 217 of which were horizontal, with a 97 percent success rate. In recent years, the region has been testing numerous formations and building a large inventory of horizontal opportunities in several plays across our acreage position. In 2015, we ran a streamlined capital program that focused on efficiency improvements, downspacing and other strategic tests to further delineate several plays. Production growth was driven by Wolfcamp wells in the Barnhart, Wildfire and Azalea areas of the Southern Midland Basin, the Bone Spring development program in the Delaware basin, and Yeso drilling on the Northwest shelf. In addition, the region continued to manage its completion inventory as costs continued to fall throughout the year. Given its acreage holdings and recent seismic data acquisitions, the region’s deep portfolio of drilling inventory and opportunities allows us to focus efforts on the most economic wells and capital projects as the industry continues to adjust to current commodity price levels. Heading into 2016, we will continue to operate in a reduced capital spending program and will balance larger development programs with exploration activity in several new areas. MidContinent/Gulf Coast Region As part of our 2015 strategic efforts to reduce our operating cost structure, we streamlined our organization by closing our regional office in Tulsa and combining our MidContinent and Gulf Coast onshore regions. Apache’s MidContinent/Gulf Coast region holds 2.8 million gross acres and includes 3,402 producing wells primarily in western Oklahoma, the Texas Panhandle, and south Texas. Total region production in 2015 was 73 Mboe/d, comprising 13 percent of Apache’s worldwide production. The region’s year-end 2015 estimated proved reserves were 154 MMboe. In 2015, Apache drilled or participated in drilling 127 wells with a 99 percent success rate. The region focused on drilling activities in the Canyon Lime, Eagle Ford, Marmaton, and Woodford formations with consistently strong results. Apache is active in the Woodford-SCOOP play in Central Oklahoma targeting the Woodford formation, where we drilled or participated in drilling 33 wells. The region continues to work on optimizing fracture geometry and well spacing to reduce costs in this play. Apache’s prolific Canyon Lime and Woodford plays will again be a focus area for region drilling activity in 2016. Canada Region Apache entered the Canadian market in 1995 and currently holds nearly 3.6 million gross acres across the provinces of British Columbia, Alberta, and Saskatchewan. The region’s large acreage position presents significant drilling opportunities and portfolio diversification with exposure to oil, gas, and liquids rich fairways. Our Canadian region provided approximately 13 percent of Apache’s 2015 worldwide production and held 280 MMboe of estimated proved reserves at year-end. In 2015, Apache drilled or participated in drilling 38 wells in the region with a 100 percent success rate. Drilling operations continued in our established Swan Hills, Bluesky, and Glauconite plays, and we de-risked our Montney and Duvernay emerging growth plays. The results from the first seven-well pad in the Duvernay were encouraging. Moving to a pad development decreased costs by 40 percent from 2014. The pad commenced production during the fourth quarter, with average 30 day initial production rates of 1,632 boe/d per well. Our Montney drilling has been focused in the Karr-Simonette and Wapiti areas. The two initial wells in Karr-Simonette exceeded expectations with peak oil rates of 450 and 630 boe/d. We have also successfully tested the lower Montney in the Wapiti area. The region’s development activity in 2016 will primarily be centered on the Duvernay and Montney programs. As part of our assessment and rationalization of the Company’s North American portfolio, in the second quarter of 2015 we divested our working interest in the Kitimat LNG development and approximately 333,000 of our net acres in the Horn River and Liard natural gas basins of British Columbia. North America Offshore Gulf of Mexico Region The Gulf of Mexico region comprises assets in the offshore waters of the Gulf of Mexico and onshore Louisiana. Apache’s offshore technical teams continue to focus on subsalt and other deeper exploration opportunities in water depths less than 1,000 feet, which have been relatively untested by the industry. In addition to the exploration and development of properties in shallower water, Apache continues to pursue joint venture and other monetization opportunities for its deepwater prospects, which offer exposure to significant reserve and production potential in underexplored and oil-prone areas in water depths greater than 1,000 feet. During 2015, Apache’s Gulf of Mexico region contributed 9.2 Mboe/d to the Company’s total production. North America Marketing In general, most of our North American 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. We transport some of our Canadian natural gas under firm transportation contracts to delivery points into the U.S. in order to diversify our market exposure. Apache primarily markets its North American 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. In the U.S., our 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. In Canada, 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 are delivered and sold at rail terminals. We evaluate our transport options monthly to maximize our netback prices. 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. International Apache’s international assets are located in Egypt and offshore U.K. in the North Sea. In 2015, international assets contributed 40 percent of our production and 51 percent of our oil and gas revenues. Approximately 28 percent of our estimated proved reserves at year-end were located outside North America. Egypt Overview Our operations in Egypt are conducted pursuant to production sharing contracts (PSCs). Under the terms of the PSCs, the contractor partners bear the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the contractor partners receive entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of production after cost recovery. Additionally, the contractor income taxes, which remain the liability of the contractor under domestic law, are paid by Egyptian General Petroleum Corporation (EGPC) on behalf of the contractor out of EGPC’s production entitlement. Income taxes paid to the Arab Republic of Egypt on behalf of the contractor are recognized as oil and gas sales revenue and income tax expense and reflected as production and estimated reserves. Because our cost recovery entitlement and income taxes paid on our behalf are determined as a monetary amount, the quantities of production entitlement and estimated reserves attributable to these monetary amounts will fluctuate with commodity prices. In addition, because the contractors’ income taxes are paid by EGPC, the amount of the income tax has no economic impact on the contractors despite impacting our production and reserves. 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 2015, we held 6.7 million gross acres in 24 separate concessions. Approximately 73 percent of our acreage in Egypt is undeveloped, providing us with considerable exploration and development opportunities for the future. Development leases within concessions currently have expiration dates ranging from 4 to 24 years, with extensions possible for additional commercial discoveries or on a negotiated basis. Our estimated proved reserves in Egypt are reported under the economic interest method and exclude the host country’s share of reserves. Our operations in Egypt, including a one-third noncontrolling interest, contributed 27 percent of our 2015 production and accounted for 19 percent of our year-end estimated proved reserves and 36 percent of our estimated discounted future net cash flows. Excluding the noncontrolling interest, Egypt contributed 20 percent of our 2015 production and accounted for 14 percent of our year-end estimated proved reserves and 27 percent of our estimated discounted future net cash flows. We have historically been one of the most active drillers in the Western Desert, however, 2015 activity was curtailed in all regions in response to reduction in commodity prices. We drilled 97 development and 25 exploration wells in 2015. 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. Following several years of political turmoil, Apache’s operations, located in remote locations in the Western Desert, continue to experience no production interruptions. We have also continued to receive development lease approvals for our drilling program. However, a 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, forced renegotiation or modification of our existing contracts with EGPC, or threats or acts of terrorism by groups such as ISIS, could materially and adversely affect our business, financial condition, and results of operations. Apache purchases and maintains limited insurance covering its investments in Egypt. For information regarding such coverage, please see Part II, Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations-Insurance Program of this Form 10-K. 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 $2.92 per Mcf in 2015. 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 sold to EGPC is sold on a spot basis priced at Brent with a monthly EGPC official differential applied. North Sea Overview Apache entered the North Sea in 2003 after acquiring an approximate 97 percent working interest in the Forties field (Forties). Since acquiring 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, in 2011 Apache acquired Mobil North Sea Limited, 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 field. In total, Apache has interests in approximately 1 million gross acres in the U.K. North Sea. The North Sea region continues to play an important role in the overall Apache portfolio by providing competitive investment opportunities across multiple horizons and potential reserve upside with high-impact exploration potential. In 2015, the North Sea region contributed 13 percent of worldwide consolidated production and 9 percent of year-end estimated proved reserves. During the year, 23 development wells were drilled in the North Sea, of which 19 were productive. Apache has invested approximately $2.7 billion in infrastructure improvements across all of its fields over the past decade resulting in significantly improved production efficiency and lower unit operating costs. With basin-wide leading production efficiency, our infrastructure and offtake capabilities have positioned the region to be allocated a higher percentage of capital dollars for drilling and production. The Beryl field, which is a geologically complex area with multiple fields and stacked pay potential, provides for significant exploration opportunity. Following the completion of the first full-field 3-D acquisition since 1997, Apache recently announced two exceptional discoveries in the area, the K and Corona discoveries, and is moving ahead with development and additional exploration efforts. The K discovery encompasses multiple commercial zones across three distinct fault blocks, including one fault block with over 1,500 feet of net pay and is projected to begin production mid-2017. The Corona discovery logged 225 feet vertical depth net pay in reservoir-quality sandstone. Apache has 55 percent and 100 percent working interests in K and Corona, respectively. The 3-D acquisition has also indicated the potential for several future prospects similar to K and Corona on Apache acreage in the Beryl area. In addition to the K and Corona discoveries, Apache also announced an appraisal well drilled approximately 50 miles (80 kilometers) south of the Forties complex. The Seagull discovery logged 672 feet of net oil pay over a 1,092-foot column in Triassic-age sands. Further appraisal work will continue following the recent acquisition of a multi-azimuth 3-D survey. Apache is now operator of the license and has a 35 percent working interest in the project. Marketing We have traditionally sold our North Sea crude oil under term contracts, with a market-based index price plus a premium, which reflects the higher market value for term arrangements. 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. Australia/Argentina During the second quarter of 2015, Apache completed the sale of its Australian LNG business and oil and gas assets. In March 2014, Apache completed the sale of all of its operations in Argentina. Results of operations and consolidated cash flows for the divested Australia assets and Argentina operations are reflected as discontinued operations in the Company’s financial statements for all periods presented in this Annual Report on Form 10-K. 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, higher-reward exploration opportunities located in frontier basins as well as new plays in more mature basins. Plans for 2016 include continued analysis and review of our deepwater prospects in offshore Suriname. Major Customers In 2015, 2014, and 2013 purchases by Royal Dutch Shell plc and its subsidiaries accounted for 11 percent, 19 percent, and 24 percent, respectively, of the Company’s worldwide oil and gas production revenues. Drilling Statistics Worldwide in 2015 we participated in drilling 693 gross wells, with 660 (95 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 North America 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: 41 gross (18.1 net) in the U.S., 45 gross (42.5 net) in Egypt, 7 gross (7 net) in Canada, and 3 gross (2.2 net) in the North Sea. The following table shows the results of the oil and gas wells drilled and completed for each of the last three fiscal years: Productive Oil and Gas Wells The number of productive oil and gas wells, operated and non-operated, in which we had an interest as of December 31, 2015, is set forth below: Gross natural gas and crude oil wells include 625 wells with multiple completions. Production, Pricing, and Lease Operating Cost Data The following table describes, for each of the last three fiscal years, oil, NGL, and gas production volumes, average lease operating costs per boe (including transportation costs but excluding severance and other taxes), and average sales prices for each of the countries where we have operations: (1) Includes production volumes attributable to a one-third noncontrolling interest in Egypt. Gross and Net Undeveloped and Developed Acreage The following table sets out our gross and net acreage position as of December 31, 2015, in each country where we have operations: As of December 31, 2015, Apache had 2.3 million net undeveloped acres scheduled to expire by year-end 2016 if production is not established or we take no other action to extend the terms. Additionally, Apache has 1.5 million and 700,000 net undeveloped acres set to expire in 2017 and 2018, 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 1.8 million and 700,000 net undeveloped acres set to expire in 2016 and 2017, respectively. 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. There were no reserves recorded on this undeveloped acreage. As of December 31, 2015, 25 percent of U.S. net undeveloped acreage and 42 percent of Canadian net undeveloped acreage was held by production. Apache also holds 1.8 million net undeveloped acreage in two blocks in Suriname expiring in 2017 and 2018. Estimated Proved Reserves and Future Net Cash Flows Proved oil and gas reserves are those quantities of natural gas, crude oil, condensate, and NGLs, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations. 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. The following table shows proved oil, NGL, and gas reserves as of December 31, 2015, based on average commodity prices in effect on the first day of each month in 2015, 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 ratio of 6 Mcf to 1 bbl. This ratio is not reflective of the current price ratio between the two products. (1) Includes total proved reserves of 101 MMboe attributable to a one-third noncontrolling interest in Egypt As of December 31, 2015, Apache had total estimated proved reserves of 794 MMbbls of crude oil, 198 MMbbls of NGLs, and 3.4 Tcf of natural gas. Combined, these total estimated proved reserves are the volume equivalent of 1.6 billion barrels of oil or 9.4 Tcf of natural gas, of which oil represents 51 percent. As of December 31, 2015, the Company’s proved developed reserves totaled 1,332 MMboe and estimated PUD reserves totaled 232 MMboe, or approximately 15 percent of worldwide total proved reserves. Apache has elected not to disclose probable or possible reserves in this filing. During 2015, Apache added 117 MMboe of proved reserves through exploration and development activity and 7 MMboe through purchases of minerals in-place. We sold a combined 385 MMboe through several divestiture transactions. We recognized a 368 MMboe downward revision in proved reserves, of which 339 MMboe was related to lower product prices. The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2015, 2014, and 2013, 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 232 MMboe as of December 31, 2015, decreased by 513 MMboe from 745 MMboe of PUD reserves reported at the end of 2014. During the year, Apache converted 73 MMboe of PUD reserves to proved developed reserves through development drilling activity. In North America, we converted 40 MMboe, with the remaining 33 MMboe in our international areas. We sold 240 MMboe and acquired 7 MMboe of PUD reserves during the year. We added 56 MMboe of new PUD reserves through extensions and discoveries. We recognized a 263 MMboe downward revision in proved undeveloped reserves during the year, of which 202 MMboe was associated with lower product prices. During the year, a total of approximately $1.4 billion was spent on projects associated with reserves that were carried as PUD reserves at the end of 2014. 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 approximately $900 million on PUD reserve development activity in North America and $500 million in the international areas. As of December 31, 2015, we had no material amounts of proved undeveloped reserves scheduled to be developed beyond five years from initial disclosure. 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 35 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 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 2015, the properties selected for each country ranged from 82 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 91 percent 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 83 percent of total proved reserves by volume. During 2015, 2014, and 2013, Ryder Scott’s review covered 90, 91, and 92 percent, respectively, of the Company’s worldwide estimated proved reserves value and 83, 85, and 86 percent, respectively, of the Company’s total proved reserves volume. Ryder Scott’s review of 2015 covered 81 percent of U.S., 81 percent of Canada, 86 percent of Egypt, and 88 percent of the U.K.’s total proved reserves. Ryder Scott’s review of 2014 covered 83 percent of U.S., 75 percent of Canada, 99.5 percent of Australia, 86 percent of Egypt, and 94 percent of the U.K.’s total proved reserves. 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. We have filed Ryder Scott’s independent report as an exhibit to this Form 10-K. 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, 2015, we had 3,860 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 2015, we maintained regional exploration and/or production offices in Midland, Texas; San Antonio, Texas; Houston, Texas; Calgary, Alberta; Cairo, Egypt; and Aberdeen, Scotland. Apache leases all of its primary office space. The current lease on our principal executive offices runs through December 31, 2019. We have two, five-year options to extend the lease through 2024 and 2029, which may be exercised in five or ten-year increments. 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). 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. 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 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. In addition, ADW is 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. The equipment and resources available to MSRC and NRC change from time to time, and current information is generally available on each company’s website. 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, 2015, Apache’s investment in MWCC totals $172 million and is reflected in “Deferred charges and other” in the Company’s consolidated balance sheet. 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 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. However, we believe our diversified portfolio of core assets, which comprises large acreage positions and well-established production bases across four countries, 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 four 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. ITEM 1A. RISK FACTORS Our business activities and the value of our securities are subject to significant hazards and risks, including those described below. If any of such events should occur, our business, financial condition, liquidity, and/or results of operations could be materially harmed, and holders and purchasers of our securities could lose part or all of their investments. Additional risks relating to our securities may be included in the prospectuses for securities we issue in the future. Crude oil and natural gas price volatility, including the recent decline in prices for oil and natural gas, could adversely affect our operating results and the price of our common stock. Our revenues, operating results, and future rate of growth depend highly upon the prices we receive for our crude oil and natural gas production. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily settlement price for the prompt month oil contract in 2015 ranged from a high of $61.43 per barrel to a low of $34.73 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2015 ranged from a high of $3.23 per MMBtu to a low of $1.76 per MMBtu. The market prices for crude oil and natural gas depend on factors beyond our control. These factors include demand for crude oil and natural gas, which fluctuates with changes in market and economic conditions, and other factors, including: • worldwide and domestic supplies of crude oil and natural gas; • actions taken by foreign oil and gas producing nations; • political conditions and events (including instability, changes in governments, or armed conflict) in crude oil or natural gas producing regions; • the level of global crude oil and natural gas inventories; • the price and level of imported foreign crude oil and natural gas; • the price and availability of alternative fuels, including coal and biofuels; • the availability of pipeline capacity and infrastructure; • the availability of crude oil transportation and refining capacity; • weather conditions; • domestic and foreign governmental regulations and taxes; and • the overall economic environment. Our results of operations, as well as the carrying value of our oil and gas properties, are substantially dependent upon the prices of oil and natural gas, which have declined significantly since June 2014. The recent declines in oil and natural gas prices have adversely affected our revenues, operating income, cash flow, and proved reserves. Continued low prices could have a material adverse impact on our operations and limit our ability to fund capital expenditures. Without the ability to fund capital expenditures, we would be unable to replace reserves and production. Sustained low prices of crude oil and natural gas may further adversely impact our business as follows: • limiting our financial condition, liquidity, and/or ability to fund planned capital expenditures and operations; • reducing the amount of crude oil and natural gas that we can produce economically; • causing us to delay or postpone some of our capital projects; • reducing our revenues, operating income, and cash flows; • limiting our access to sources of capital, such as equity and long-term debt; • reducing the carrying value of our crude oil and natural gas properties, resulting in additional non-cash write-downs; • reducing the carrying value of our gathering, transmission, and processing facilities, resulting in additional impairments; or • reducing the carrying value of goodwill. Our ability to sell natural gas or oil and/or receive market prices for our natural gas or oil may be adversely affected by pipeline and gathering system capacity constraints and various transportation interruptions. A portion of our natural gas and oil production in any region may be interrupted, limited, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline or gathering system access, field labor issues or strikes, or capital constraints that limit the ability of third parties to construct gathering systems, processing facilities, or interstate pipelines to transport our production, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flows. Future economic conditions in the U.S. and certain international markets may materially adversely impact our operating results. Current global market conditions, and uncertainty, including economic instability in Europe and certain emerging markets, is likely to have significant long-term effects. Global economic growth drives demand for energy from all sources, including fossil fuels. A lower future economic growth rate could result in decreased demand growth for our crude oil and natural gas production as well as lower commodity prices, which would reduce our cash flows from operations and our profitability. Weather and climate may have a significant adverse impact on our revenues and productivity. Demand for oil and natural gas are, to a degree, dependent on weather and climate, which impact the price we receive for the commodities we produce. In addition, our exploration and development activities and equipment can be adversely affected by severe weather, such as freezing temperatures, hurricanes in the Gulf of Mexico or storms in the North Sea, which may cause a loss of production from temporary cessation of activity or lost or damaged equipment. Our planning for normal climatic variation, insurance programs, and emergency recovery plans may inadequately mitigate the effects of such weather conditions, and not all such effects can be predicted, eliminated, or insured against. Our operations involve a high degree of operational risk, particularly risk of personal injury, damage, or loss of equipment, and environmental accidents. Our operations are subject to hazards and risks inherent in the drilling, production, and transportation of crude oil and natural gas, including: • well blowouts, explosions, and cratering; • pipeline or other facility ruptures and spills; • fires; • formations with abnormal pressures; • equipment malfunctions; • hurricanes, storms, and/or cyclones, which could affect our operations in areas such as on and offshore the Gulf Coast and North Sea and other natural disasters and weather conditions; and • surface spillage and surface or ground water contamination from petroleum constituents, saltwater, or hydraulic fracturing chemical additives. Failure or loss of equipment as the result of equipment malfunctions, cyber attacks, or natural disasters such as hurricanes, could result in property damages, personal injury, environmental pollution and other damages for which we could be liable. Litigation arising from a catastrophic occurrence, such as a well blowout, explosion, or fire at a location where our equipment and services are used, or ground water contamination from hydraulic fracturing chemical additives may result in substantial claims for damages. Ineffective containment of a drilling well blowout or pipeline rupture, or surface spillage and surface or ground water contamination from petroleum constituents or hydraulic fracturing chemical additives could result in extensive environmental pollution and substantial remediation expenses. If a significant amount of our production is interrupted, our containment efforts prove to be ineffective or litigation arises as the result of a catastrophic occurrence, our cash flows, and, in turn, our results of operations could be materially and adversely affected. Cyber attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations. Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, and production activities. We depend on digital technology to estimate quantities of oil and gas reserves, process and record financial and operating data, analyze seismic and drilling information, communicate with our employees and third party partners, and conduct many of our activities. Unauthorized access to our digital technology could lead to operational disruption, data corruption or exposure, communication interruption, loss of intellectual property, loss of confidential and fiduciary data, and loss or corruption of reserves or other proprietary information. Also, external digital technologies control nearly all of the oil and gas distribution and refining systems in the United States and abroad, which are necessary to transport and market our production. A cyber attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets, and make it difficult or impossible to accurately account for production and settle transactions. While we have experienced cyber attacks, we have not suffered any material losses relating to such attacks; however, there is no assurance that we will not suffer such losses in the future. Further, as cyber attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyber attacks. Our commodity price risk management and trading activities may prevent us from benefiting fully from price increases and may expose us to other risks. To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from realizing the benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which: • our production falls short of the hedged volumes; • there is a widening of price-basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; • the counterparties to our hedging or other price risk management contracts fail to perform under those arrangements; or • an unexpected event materially impacts oil and natural gas prices. The credit risk of financial institutions could adversely affect us. We have exposure to different counterparties, and we have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, other investment funds, and other institutions. These transactions expose us to credit risk in the event of default of our counterparty. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. In the future, we may have exposure to financial institutions in the form of derivative transactions in connection with any hedges. We also have exposure to insurance companies in the form of claims under our policies. In addition, if any lender under our credit facilities is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facilities. If we were to enter into hedging transactions, we would be exposed to a risk of financial loss if a counterparty fails to perform under a derivative contract. This risk of counterparty non-performance is of particular concern given the recent volatility of the financial markets and significant decline in oil and natural gas prices, which could lead to sudden changes in a counterparty’s liquidity and impair its ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. Furthermore, the bankruptcy of one or more of our hedge providers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed to us by the distressed entity or entities. During periods of falling commodity prices our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss. The distressed financial conditions of our purchasers and partners could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or to reimburse us for their share of costs. Concerns about global economic conditions and the volatility of oil and natural gas prices have had a significant adverse impact on the oil and gas industry. We are exposed to risk of financial loss from trade, joint venture, joint interest billing, and other receivables. We sell our crude oil, natural gas, and NGLs to a variety of purchasers. As operator, we pay expenses and bill our non-operating partners for their respective shares of costs. As a result of current economic conditions and the severe decline in oil and natural gas prices, some of our customers and non-operating partners may experience severe financial problems that may have a significant impact on their creditworthiness. We cannot provide assurance that one or more of our financially distressed customers or non-operating partners will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows. Furthermore, the bankruptcy of one or more of our customers or non-operating partners, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. Nonperformance by a trade creditor or non-operating partner could result in significant financial losses. A downgrade in our credit rating could negatively impact our cost of and ability to access capital. We receive debt ratings from the major credit rating agencies in the United States. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales, and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, product mix, and commodity pricing levels and others are also considered by the rating agencies. A ratings downgrade could adversely impact our ability to access debt markets in the future, increase the cost of future debt, and potentially require us to post letters of credit or other forms of collateral for certain obligations. On February 2, 2016, our credit rating was downgraded by Standard and Poor’s to BBB/Stable, and on February 25, 2016, our credit rating was downgraded by Moody’s to Baa3/negative outlook, in each case as part of an industry-wide review and downgrade of U.S. exploration and production and oilfield services companies due to deteriorating commodity prices. Further downgrades could result in additional postings of between $500 million and $1.1 billion, depending upon timing and availability of tax relief. Market conditions may restrict our ability to obtain funds for future development and working capital needs, which may limit our financial flexibility. The credit markets are subject to fluctuation and are vulnerable to unpredictable shocks. We have a significant development project inventory and an extensive exploration portfolio, which will require substantial future investment. We and/or our partners may need to seek financing in order to fund these or other future activities. Our future access to capital, as well as that of our partners and contractors, could be limited if the debt or equity markets are constrained. This could significantly delay development of our property interests. Our ability to declare and pay dividends is subject to limitations. The payment of future dividends on our capital stock is subject to the discretion of our board of directors, which considers, among other factors, our operating results, overall financial condition, credit-risk considerations, and capital requirements, as well as general business and market conditions. Our board of directors is not required to declare dividends on our common stock and may decide not to declare dividends. Any indentures and other financing agreements that we enter into in the future may limit our ability to pay cash dividends on our capital stock, including common stock. In addition, under Delaware law, dividends on capital stock may only be paid from “surplus,” which is the amount by which the fair value of our total assets exceeds the sum of our total liabilities, including contingent liabilities, and the amount of our capital; if there is no surplus, cash dividends on capital stock may only be paid from our net profits for the then current and/or the preceding fiscal year. Further, even if we are permitted under our contractual obligations and Delaware law to pay cash dividends on common stock, we may not have sufficient cash to pay dividends in cash on our common stock. Discoveries or acquisitions of additional reserves are needed to avoid a material decline in reserves and production. The production rate from oil and gas properties generally declines as reserves are depleted, while related per-unit production costs generally increase as a result of decreasing reservoir pressures and other factors. Therefore, unless we add reserves through exploration and development activities or, through engineering studies, identify additional behind-pipe zones, secondary recovery reserves, or tertiary recovery reserves, or acquire additional properties containing proved reserves, our estimated proved reserves will decline materially as reserves are produced. Future oil and gas production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves on an economic basis. Furthermore, if oil or gas prices increase, our cost for additional reserves could also increase. We may not realize an adequate return on wells that we drill. Drilling for oil and gas involves numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The wells we drill or participate in may not be productive, and we may not recover all or any portion of our investment in those wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that crude or natural gas is present or may be produced economically. The costs of drilling, completing, and operating wells are often uncertain, and drilling operations may be curtailed, delayed, or canceled as a result of a variety of factors including, but not limited to: • unexpected drilling conditions; • pressure or irregularities in formations; • equipment failures or accidents; • fires, explosions, blowouts, and surface cratering; • marine risks such as capsizing, collisions, and hurricanes; • other adverse weather conditions; and • increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment. Future drilling activities may not be successful, and, if unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. While all drilling, whether developmental or exploratory, involves these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. Material differences between the estimated and actual timing of critical events or costs may affect the completion and commencement of production from development projects. We are involved in several large development projects and the completion of these projects may be delayed beyond our anticipated completion dates. Our projects may be delayed by project approvals from joint venture partners, timely issuances of permits and licenses by governmental agencies, weather conditions, manufacturing and delivery schedules of critical equipment, and other unforeseen events. Delays and differences between estimated and actual timing of critical events may adversely affect our large development projects and our ability to participate in large-scale development projects in the future. In addition, our estimates of future development costs are based on current expectation of prices and other costs of equipment and personnel we will need to implement such projects. Our actual future development costs may be significantly higher than we currently estimate. If costs become too high, our development projects may become uneconomic to us, and we may be forced to abandon such development projects. We may fail to fully identify potential problems related to acquired reserves or to properly estimate those reserves. Although we perform a review of properties that we acquire that we believe is consistent with industry practices, such reviews are inherently incomplete. It generally is not feasible to review in-depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher-value properties and will sample the remainder. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us as a buyer to become sufficiently familiar with the properties to assess fully and accurately their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties. There are numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and future production rates and costs with respect to acquired properties, and actual results may vary substantially from those assumed in the estimates. In addition, there can be no assurance that acquisitions will not have an adverse effect upon our operating results, particularly during the periods in which the operations of acquired businesses are being integrated into our ongoing operations. Our liabilities could be adversely affected in the event one or more of our transaction counterparties become the subject of a bankruptcy case. Over the last several years, we have taken action to enhance and streamline our North American portfolio through not only the acquisition of assets in key operating regions but also the divestitures of noncore domestic assets and the monetization of certain nonstrategic international assets. The agreements relating to these transactions contain provisions pursuant to which liabilities related to past and future operations have been allocated between the parties by means of liability assumptions, indemnities, escrows, trusts, and similar arrangements. One or more of the counterparties in these transactions could, either as a result of the severe decline in oil and natural gas prices or other factors related to the historical or future operations of their respective businesses, face financial problems that may have a significant impact on its ability to perform its obligations under these agreements and its solvency and ability to continue as a going concern. In the event that any such counterparty were to become unable financially to perform its liabilities or obligations assumed and as a result become the subject of a case or proceeding under Title 11 of the United States Code (the bankruptcy code) or any other relevant insolvency law or similar law (which we collectively refer to as Insolvency Laws) the counterparty may not perform its obligations under the agreements related to these transactions. In that case, our remedy would be a claim in the proceeding for damages for the breach of the contractual arrangement, which may be either a secured claim or an unsecured claim depending on whether or not we have collateral from the counterparty for the performance of the obligations. Resolution of our damage claim in such a proceeding may be delayed, and we may be forced to use available cash to cover the costs of the obligations assumed by the counterparties under such agreements should they arise. Despite the provisions in our agreements requiring purchasers of our state or federal leasehold interests to assume certain liabilities and obligations related to such interests, if a purchaser of such interests becomes the subject of a case or proceeding under relevant Insolvency Laws and/or becomes unable financially to perform such liabilities or obligations, the relevant governmental authorities could require us to perform, and hold us responsible for, such liabilities and obligations, such as the decommissioning of such transferred assets. In such event, we may be forced to use available cash to cover the costs of such liabilities and obligations should they arise. If a court or a governmental authority were to make any of the foregoing determinations or take any of the foregoing actions, or any similar determination or action, it could adversely impact our cash flows, operations, or financial condition. Crude oil and natural gas reserves are estimates, and actual recoveries may vary significantly. There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their value. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. Because of the high degree of judgment involved, the accuracy of any reserve estimate is inherently imprecise, and a function of the quality of available data and the engineering and geological interpretation. Our reserves estimates are based on 12-month average prices, except where contractual arrangements exist; therefore, reserves quantities will change when actual prices increase or decrease. In addition, results of drilling, testing, and production may substantially change the reserve estimates for a given reservoir over time. The estimates of our proved reserves and estimated future net revenues also depend on a number of factors and assumptions that may vary considerably from actual results, including: • historical production from the area compared with production from other areas; • the effects of regulations by governmental agencies, including changes to severance and excise taxes; • future operating costs and capital expenditures; and • workover and remediation costs. For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of those reserves and estimates of the future net cash flows expected from them prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reserves estimates may be subject to upward or downward adjustment, and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates. Additionally, because some of our reserves estimates are calculated using volumetric analysis, those estimates are less reliable than the estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure. In addition, realization or recognition of proved undeveloped reserves will depend on our development schedule and plans. A change in future development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved. Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage. A sizeable portion of our acreage is currently undeveloped. Unless production in paying quantities is established on units containing certain of these leases during their terms, the leases will expire. If our leases expire, we will lose our right to develop the related properties. Our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling, and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals. We may incur significant costs related to environmental matters. As an owner or lessee and operator of oil and gas properties, we are subject to various 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 and other remediation activities resulting from operations, subject the lessee to liability for pollution and other damages, limit or constrain operations in affected areas, and require suspension or cessation of operations in affected areas. Our efforts to limit our exposure to such liability and cost may prove inadequate and result in significant adverse effects to our results of operations. In addition, it is possible that the increasingly strict requirements imposed by environmental laws and enforcement policies could require us to make significant capital expenditures. Such capital expenditures could adversely impact our cash flows and our financial condition. Our North American operations are subject to governmental risks that may impact our operations. Our North American operations have been, and at times in the future may be, affected by political developments and by federal, state, provincial, and local laws and regulations such as restrictions on production, changes in taxes, royalties and other amounts payable to governments or governmental agencies, price or gathering rate controls, and environmental protection laws and regulations. In response to the Deepwater Horizon incident in the U.S. Gulf of Mexico in April 2010, and as directed by the Secretary of the U.S. Department of the Interior, the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE) issued new guidelines and regulations regarding safety, environmental matters, drilling equipment, and decommissioning applicable to drilling in the Gulf of Mexico. These regulations imposed additional requirements and caused delays with respect to development and production activities in the Gulf of Mexico. With respect to oil and gas operations in the Gulf of Mexico, the BOEM is currently planning to issue a new Notice to Lessees (NTL) significantly revising the obligations of companies operating in the Gulf of Mexico to provide supplemental assurances of performance with respect to plugging, abandonment, and decommissioning obligations associated with wells, platforms, structures, and facilities located upon or used in connection with such companies’ oil and gas leases. We currently expect such new NTL may require that Apache provide additional security to BOEM with respect to plugging, abandonment, and decommissioning obligations relating to Apache’s current ownership interests in various Gulf of Mexico leases. We are working closely with BOEM to make arrangements for the provision of such additional required security, if such security becomes necessary under the new NTL. Additionally, we are not able to predict the effect that these changes might have on counterparties to which Apache has sold Gulf of Mexico assets or with whom Apache has joint ownership. Such changes could cause the bonding obligations of such parties to increase substantially, thereby causing a significant impact on the counterparties’ solvency and ability to continue as a going concern. New political developments, laws, and the enactment of new or stricter regulations in the Gulf of Mexico or otherwise impacting our North American operations, and increased liability for companies operating in this sector may adversely impact our results of operations. Changes to existing regulations related to emissions and the impact of any changes in climate could adversely impact our business. Certain countries where we operate, including Canada and the United Kingdom, either tax or assess some form of greenhouse gas (GHG) related fees on our operations. Exposure has not been material to date, although a change in existing regulations could adversely affect our cash flows and results of operations. In the event the predictions for rising temperatures and sea levels suggested by reports of the United Nations Intergovernmental Panel on Climate Change do transpire, we do not believe those events by themselves are likely to impact our assets or operations. However, any increase in severe weather could have a material adverse effect on our assets and operations. The proposed U.S. federal budget for fiscal year 2017 includes certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations, and cash flows. On February 9, 2016, the Office of Management and Budget released a summary of the proposed U.S. federal budget for fiscal year 2017. The proposed budget repeals many tax incentives and deductions that are currently used by U.S. oil and gas companies, and includes proposals to increase royalties and lease fees on oil and gas produced from federal lands in the United States. These provisions include elimination of the ability to fully deduct intangible drilling costs in the year incurred; increases in the taxation of foreign source income; repeal of the manufacturing tax deduction for oil and natural gas companies; an increase in the geological and geophysical amortization period for independent producers; and the imposition of a $10.25 per-barrel fee on oil production to fund investments in a clean transportation system. Should some or all of these provisions become law, our taxes will increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also cause us to reduce our drilling activities in the U.S. Since none of these proposals have yet to be voted on or become law, we do not know the ultimate impact these proposed changes may have on our business. Proposed federal, state, or local regulation regarding hydraulic fracturing could increase our operating and capital costs. Several proposals are before the U.S. Congress that, if implemented, would either prohibit or restrict the practice of hydraulic fracturing or subject the process to regulation under the Safe Drinking Water Act. Several states are considering legislation to regulate hydraulic fracturing practices that could impose more stringent permitting, transparency, and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. Hydraulic fracturing of wells and subsurface water disposal are also under public and governmental scrutiny due to potential environmental and physical impacts, including possible contamination of groundwater and drinking water and possible links to earthquakes. In addition, some municipalities have significantly limited or prohibited drilling activities and/or hydraulic fracturing, or are considering doing so. We routinely use fracturing techniques in the U.S. and other regions to expand the available space for natural gas and oil to migrate toward the wellbore. It is typically done at substantial depths in very tight formations. Although it is not possible at this time to predict the final outcome of the legislation regarding hydraulic fracturing, any new federal, state, or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could result in increased compliance costs or additional operating restrictions in the U.S. International operations have uncertain political, economic, and other risks. Our operations outside North America are based primarily in Egypt and the United Kingdom. On a barrel equivalent basis, approximately 40 percent of our 2015 production was outside North America, and approximately 28 percent of our estimated proved oil and gas reserves on December 31, 2015, were located outside North America. As a result, a significant portion of our production and resources are subject to the increased political and economic risks and other factors associated with international operations including, but not limited to: • general strikes and civil unrest; • the risk of war, acts of terrorism, expropriation and resource nationalization, forced renegotiation or modification of existing contracts; • import and export regulations; • taxation policies, including royalty and tax increases and retroactive tax claims, and investment restrictions; • price control; • transportation regulations and tariffs; • constrained natural gas markets dependent on demand in a single or limited geographical area; • exchange controls, currency fluctuations, devaluation, or other activities that limit or disrupt markets and restrict payments or the movement of funds; • laws and policies of the United States affecting foreign trade, including trade sanctions; • the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licenses to operate and concession rights in countries where we currently operate; • the possible inability to subject foreign persons, especially foreign oil ministries and national oil companies, to the jurisdiction of courts in the United States; and • difficulties in enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations. Foreign countries have occasionally asserted rights to oil and gas properties through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to us by another country, our interests could decrease in value or be lost. Even our smaller international assets may affect our overall business and results of operations by distracting management’s attention from our more significant assets. Certain regions of the world in which we operate have a history of political and economic instability. This instability could result in new governments or the adoption of new policies that might result in a substantially more hostile attitude toward foreign investments such as ours. In an extreme case, such a change could result in termination of contract rights and expropriation of our assets. This could adversely affect our interests and our future profitability. The impact that future terrorist attacks by groups such as ISIS or regional hostilities as have occurred in Egypt and Libya may have on the oil and gas industry in general, and on our operations in particular, is not known at this time. Uncertainty surrounding military strikes or a sustained military campaign may affect operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants, and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. We may be required to incur significant costs in the future to safeguard our assets against terrorist activities. A deterioration of conditions in Egypt or changes in the economic and political environment in Egypt could have an adverse impact on our business. 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, or threats or acts of terrorism by groups such as ISIS, could materially and adversely affect our business, financial condition, and results of operations. Our operations in Egypt, excluding Sinopec’s one-third noncontrolling interest, contributed 20 percent of our 2015 production and accounted for 14 percent of our year-end estimated proved reserves and 27 percent of our estimated discounted future net cash flows. Our operations are sensitive to currency rate fluctuations. Our operations are sensitive to fluctuations in foreign currency exchange rates, particularly between the U.S. dollar and the Canadian dollar, and between the U.S. dollar and the British Pound. Our financial statements, presented in U.S. dollars, may be affected by foreign currency fluctuations through both translation risk and transaction risk. Volatility in exchange rates may adversely affect our results of operations, particularly through the weakening of the U.S. dollar relative to other currencies. We face strong industry competition that may have a significant negative impact on our results of operations. Strong competition exists in all sectors of the oil and gas exploration and production industry. We compete with major integrated and other independent oil and gas companies for acquisition of oil and gas leases, properties, and reserves, equipment, and labor required to explore, develop, and operate those properties, and marketing of oil and natural gas production. Crude oil and natural gas prices impact the costs of properties available for acquisition and the number of companies with the financial resources to pursue acquisition opportunities. Many of our competitors have financial and other resources substantially larger than we possess and 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 drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for oil and natural gas production, such as fluctuating worldwide commodity prices and levels of production, the cost and availability of alternative fuels, and the application of government regulations. We also compete in attracting and retaining personnel, including geologists, geophysicists, engineers, and other specialists. These competitive pressures may have a significant negative impact on our results of operations. Our insurance policies do not cover all of the risks we face, which could result in significant financial exposure. Exploration for and production of crude oil and natural gas can be hazardous, involving natural disasters and other events such as blowouts, cratering, fire and explosion and loss of well control, which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property and the environment. Our international operations are also subject to political risk. The insurance coverage that we maintain against certain losses or liabilities arising from our operations may be inadequate to cover any such resulting liability; moreover, insurance is not available to us against all operational risks. ITEM 1B.