SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 1-4300
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400
(Address of principal executive offices) (Zip Code)
Registrant’s telephone number, including area code (713) 296-6000
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Name of each exchange on which registered
Common Stock, $0.625 par value
New York Stock Exchange
Common Stock, $0.625 par value
Chicago Stock Exchange
Common Stock, $0.625 par value
Nasdaq Global Select Market
7.75% Notes Due 2029
New York Stock Exchange
Securities registered pursuant to section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act): Yes ☐ No ☒
Aggregate market value of the voting and non-voting common equity held by non-affiliates of registrant as of June 28, 2019
Number of shares of registrant’s common stock outstanding as of January 31, 2020
Documents Incorporated By Reference
Portions of registrant’s proxy statement relating to registrant’s 2020 annual meeting of stockholders have been incorporated by reference in Part II and Part III of this Annual Report on Form 10-K.
TABLE OF CONTENTS
FORWARD-LOOKING STATEMENTS AND RISK
This Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans, and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information that was used to prepare our estimate of proved reserves as of December 31, 2019, and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:
the market prices of oil, natural gas, natural gas liquids (NGLs), and other products or services;
our commodity hedging arrangements;
the supply and demand for oil, natural gas, NGLs, and other products or services;
production and reserve levels;
economic and competitive conditions;
the availability of capital resources;
capital expenditure and other contractual obligations;
currency exchange rates;
the availability of goods and services;
legislative, regulatory, or policy changes, including initiatives addressing the impact of global climate change or further regulating hydraulic fracturing, methane emissions, flaring, or water disposal;
our performance on environmental, social, and governance measures;
terrorism or cyberattacks;
occurrence of property acquisitions or divestitures;
the integration of acquisitions;
the securities or capital markets and related risks such as general credit, liquidity, market, and interest-rate risks; and
other factors disclosed under Items 1 and 2—Business and Properties—Estimated Proved Reserves and Future Net Cash Flows, 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.
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.
“bcf/d” means one bcf per day.
“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.
“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.
References to “Apache,” the “Company,” “we,” “us,” and “our” include Apache Corporation and its consolidated subsidiaries unless otherwise specifically stated.
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.
ITEMS 1 and 2.
BUSINESS AND PROPERTIES
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. Apache currently has exploration and production operations in three geographic areas: the U.S., Egypt, and offshore the U.K. in the North Sea (North Sea). Apache also has exploration interests in Suriname and other international locations that may, over time, result in reportable discoveries and development opportunities. Apache’s midstream business is operated by Altus Midstream Company (ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owns, develops, and operates a midstream energy asset network in the Permian Basin of West Texas, anchored by midstream service contracts to Apache’s production from its Alpine High resource play. Additionally, Altus owns equity interests in a total of four Permian Basin pipelines that will access various points along the Texas Gulf Coast, providing it with fully integrated, wellhead-to-water connectivity.
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 Global Select Market (Nasdaq) since 2004. 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 Ethics and Apache’s Corporate 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 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.
Our VISION is to be the premier exploration and production company, contributing to global progress by helping meet the world's energy needs.
Our MISSION is to grow in an innovative, safe, environmentally responsible, and profitable manner for the long-term benefit of our stakeholders.
Our STRATEGY is to take a differentiated approach to the exploration and production of cost-advantaged hydrocarbons through innovation, technology, optimization, continuous improvement, and relentless focus on costs to deliver top-tier, long-term returns.
Rigorous management of the Company’s asset portfolio plays a key role in optimizing shareholder value over the long term. Over the past several years, Apache has entered into a series of transactions that have upgraded its portfolio of assets, enhanced its capital allocation process to further optimize investment returns, and increased focus on internally generated exploration with full-cycle, returns-focused growth. These efforts included the monetization of certain non-strategic assets, including gas-weighted properties in the Midcontinent/Gulf Coast region and selling other non-core leasehold positions. The Company made strategic decisions to allocate the proceeds of these divestitures to more impactful development opportunities across its portfolio and exploration efforts in Suriname. In addition, in November 2018 the Company completed a transaction with Altus Midstream Company and its then wholly owned subsidiary Altus Midstream LP to create a publicly traded, pure-play, Permian Basin to Gulf Coast midstream C-corporation anchored by gathering, processing, and transmission assets at Alpine High. This transaction facilitated funding the capital requirements for midstream infrastructure and led to the acquisition of equity interests in four Permian Basin long-haul pipeline entities.
Apache’s U.S. upstream oil and gas assets are complemented by its international assets in Egypt and the North Sea, each of which adds to the Company’s inventory of exploration and development opportunities and generates cash flows in excess of current
capital investments, providing the Company greater ability to develop its onshore Permian Basin properties while maintaining financial flexibility in a volatile commodity price environment. Apache’s diverse regional portfolio and asset inventory includes, at scale, both conventional and unconventional resources covering oil, rich gas with NGLs, and lean gas. This range of assets provides optionality to fund a capital program capable of delivering a sustainable combination of long-term returns with a moderate pace of growth.
For a more in-depth discussion of the Company’s 2019 results, divestitures, strategy, and its 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.
The following business overview further describes the operations and activities for the Company’s upstream exploration and production properties, by geographic region, and Altus midstream. Apache has historically employed a decentralized, geographic region-focused approach to operations. In recent years, the Company has centralized certain operational activities in an effort to capture greater efficiencies through shared services. In light of the continued streamlining of the Company’s asset portfolio through divestitures and strategic transactions, in late 2019 management initiated a comprehensive redesign of Apache’s organizational structure and operations that it believes will better position the Company to be competitive for the long-term and further reduce recurring costs. The reorganization is ongoing and is expected to be substantially completed for the technical functions by the end of the first quarter of 2020. Changes for the corporate support functions will be ongoing through most of 2020.
UPSTREAM EXPLORATION AND PRODUCTION PROPERTIES
Apache has exploration and production operations in three geographic areas: the U.S., Egypt, and the North Sea. Apache also has exploration interests in Suriname and other international locations that may, over time, result in reportable discoveries and development opportunities.
The following table sets out a brief comparative summary of certain key 2019 data for each of Apache’s operating areas. Additional data and discussion are provided in Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.
Apache’s operations in Egypt, excluding the impacts of a one-third noncontrolling interest, contributed 21 percent of 2019 production and accounted for 13 percent of year-end estimated proved reserves.
Sales volumes from the North Sea for 2019 were 21.8 MMboe. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.
In 2019, Apache’s U.S. upstream oil and gas operations contributed approximately 59 percent of production and 68 percent of estimated year-end proved reserves. Apache has access to significant liquid hydrocarbons across its 5.2 million gross acres in the U.S., 78 percent of which are undeveloped.
Permian Region The Permian region located in West Texas and New Mexico includes the Permian sub-basins: Midland Basin, Central Basin Platform/Northwest Shelf, and Delaware Basin. Examples of shale plays within this region include the Woodford, Barnett, Pennsylvanian, Cline, Wolfcamp, Bone Spring, and Spraberry. The Permian region is one of Apache’s core growth areas. Highlights of the Company’s operations in the region include:
Over 2.9 million gross acres (1.8 million net acres) with exposure to numerous plays focused primarily in the Midland Basin, the Central Basin Platform/Northwest Shelf, and the Delaware Basin.
Estimated proved reserves of 665.8 MMboe at year-end 2019, representing 66 percent of the Company’s worldwide proved reserves.
In 2019, the Permian region averaged 11 rigs and drilled or participated in 232 wells, 206 of which were horizontal, with a 100 percent success rate.
Annual production of 254.3 Mboe/d increased 21 percent from 2018. Fourth-quarter 2019 production increased 13 percent from the prior sequential quarter and 22 percent from the fourth quarter of 2018, a reflection of the success of the Company’s Midland Basin oil-focused drilling program and production from its Alpine High field.
In late 2016, Apache announced the discovery of a new resource play, “Alpine High.” Apache’s Alpine High acreage lies in the southern portion of the Delaware Basin, primarily in Reeves County, Texas, and contains multiple geologic formations and target zones spanning the full hydrocarbon phase window from dry gas to wet gas to oil. Over the past two years, the Company focused on geological testing and transitioned to initial tests of full-field development of the Alpine High play, drilling 100 wells and 82 wells in 2018 and 2019, respectively. Given the prevailing gas and NGL price environment and disappointing performance of recent multi-well development pads in the second half of 2019, Apache materially reduced planned investment and currently has no future drilling plans at Alpine High.
Permian region drilling activity outside of Alpine High primarily focused in the Southern Midland Basin, with an average of 3.5 rigs running throughout the year targeting oil plays in the Wolfcamp, Spraberry, and lower Cline formations. The region also ran an average of 1.5 rigs during 2019 on the Company’s Delaware Basin acreage in New Mexico focused on oil plays in the Bone Spring formation. For 2019, the region drilled or participated in 150 wells excluding Alpine High activity, with a 100 percent success rate. Since 2017, the region has operated its unconventional oil-focused program at a relatively steady and deliberate pace. This has generated competitive well results, solid returns, and an attractive oil production growth rate. For 2020, the Company plans to reduce its operated rig count in the Permian region but deliver on a low-to-mid-single digit oil growth rate.
Midcontinent/Gulf Coast Region The Midcontinent/Gulf Coast region has historically included developed and undeveloped acreage in western Oklahoma, the Texas Panhandle and the Eagle Ford shale in east Texas. In the second quarter of 2019, Apache completed the sale of non-core, gas-weighted assets in the Woodford-SCOOP and STACK plays for aggregate cash proceeds of approximately $223 million. In the third quarter of 2019, Apache completed the sale of non-core, gas-weighted assets in the western Anadarko Basin of Oklahoma and Texas for aggregate cash proceeds of approximately $322 million and the assumption of asset retirement obligations of $49 million. The asset sales reflect the divestiture of a significant portion of the Company’s Midcontinent/Gulf Coast onshore region and further streamlines Apache’s portfolio. The region retained acreage of approximately 664,000 gross acres (263,000 net acres) and nearly 240 gross wells (150 net), primarily located in Eagle Ford shale and Austin Chalk areas of Southeast Texas.
Gulf of Mexico Region The Gulf of Mexico region comprises assets in the offshore waters of the Gulf of Mexico and onshore Louisiana. In addition to its interest in several deepwater exploration and development offshore leases, when the Company sold in 2013 substantially all of its offshore assets in water depths less than 1,000 feet, it retained a 50 percent ownership interest in all exploration blocks and in horizons below production in development blocks, and access to existing infrastructure. During 2019, Apache’s Gulf of Mexico region continued to operate on a reduced capital budget, having participated in 2 non-operated exploratory wells with an average 15 percent working interest, both of which were successful. The region contributed 4.7 Mboe/d to the Company’s total production for the year.
U.S. Marketing In general, most of the Company’s U.S. natural gas production is sold at either monthly or daily index-based prices. The tenor of the Company’s sales contracts span from daily to multi-year transactions. Natural gas is sold to a variety of customers that include local distribution, utility, and midstream companies as well as end-users, marketers, and integrated major oil companies. Apache strives to maintain a diverse client portfolio, which is intended to reduce the concentration of credit risk. Beginning in 2017, Apache began selling gas to markets in Mexico and to LNG export facilities in the U.S.
Apache primarily markets its U.S. crude oil production to integrated major oil companies, marketing, and transportation companies, and refiners based on a West Texas Intermediate (WTI) price or other regional pricing indices (e.g. WTI Houston, West Texas Sour (WTS), or WTI Midland), adjusted for quality, transportation, and a market-reflective differential.
Apache’s 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. These term contracts typically have a firm transportation commitment and often provide for a higher than prevailing market price.
Apache’s U.S. NGL production is sold under contracts with prices based on Gulf Coast supply and demand conditions, less the costs for transportation and fractionation, or on a weighted-average sales price received by the purchaser.
U.S. Delivery Commitments The Company has entered into long-term delivery commitments for natural gas and crude oil, which require Apache to deliver an average of 270 Bcf of natural gas per year for the period from 2020 through 2029 at variable, market-based pricing and deliver an average of 6.7 MMbbl of crude oil per year from 2020 through 2025 at variable, market-based pricing.
Apache currently expects to fulfill its delivery commitments with production from its proved reserves, production from continued development and/or spot market purchases as necessary. Apache may also enter into contractual arrangements to reduce its delivery commitments. The Company has not experienced any significant constraints in satisfying the committed quantities required by its delivery commitments.
For more information regarding the Company’s commitments, please see Part II, Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Contractual Obligations.
In 2019, international assets contributed 41 percent of Apache’s production and 56 percent of oil and gas revenues. Approximately 32 percent of estimated proved reserves at year-end were located outside the U.S.
Apache has two international regions:
The Egypt region, which includes onshore conventional assets in Egypt’s Western Desert.
The North Sea region, which includes offshore assets based in the United Kingdom.
The Company also has an offshore exploration program in Suriname.
Egypt Apache has 24 years of exploration, development and operations experience in Egypt and is one of the largest acreage holders in Egypt’s Western Desert. At year-end 2019, the Company held 5.1 million gross acres in 24 separate concessions. 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. Approximately 70 percent of the Company’s gross acreage in Egypt is undeveloped, providing Apache with considerable exploration and development opportunities for the future.
Apache’s Egypt operations are conducted pursuant to production sharing contracts (PSCs). Under the terms of the Company’s PSCs, the contractor partner (Contractor) bears the risk and cost of exploration, development, and production activities. In return, if exploration is successful, the Contractor receives 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’s 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 Contractor cost recovery entitlement and income taxes paid on its 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 Contractor income taxes are paid by EGPC, the amount of the income tax has no economic impact on Apache’s Egypt operations despite impacting Apache’s production and reserves.
The Company’s estimated proved reserves in Egypt are reported under the economic interest method and exclude the host country’s share of reserves. In addition, Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in Apache’s oil and gas operations in Egypt. The Egypt region, including the one-third noncontrolling interest, contributed 28 percent of 2019 production and 19 percent of year-end estimated proved reserves. Excluding the impacts of the noncontrolling interest, Egypt contributed 21 percent of 2019 production and 13 percent of year-end estimated proved reserves.
In 2019, the region drilled 41 development and 23 exploration wells. A key component of the region’s success has been the ability to acquire and evaluate 3-D seismic surveys that enable Apache’s technical teams to consistently high-grade existing prospects and identify new targets across multiple pay horizons in the Cretaceous, Jurassic, and deeper Paleozoic formations. The Company has completed seismic surveys covering over 3 million acres to date. The region continues to build and enhance its drilling inventory, supplemented with recent seismic acquisitions and new play concept evaluations, on both new and existing acreage. Heading into 2020, the region plans to advance its large-scale seismic shoot and continue to build its prospect inventory.
North Sea Apache has interests in approximately 419,000 gross acres in the U.K. North Sea. The region contributed 13 percent of Apache’s 2019 production and approximately 13 percent of year-end estimated proved reserves.
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 4-D seismic. 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, Ness, Nevis, Nevis South, Skene, and Buckland fields and a non-operated interest in the Maclure field. Apache also has a non-operated interest in the Nelson field acquired in 2011. The Beryl field, which is a geologically complex area with multiple fields and stacked pay potential, provides for significant exploration opportunity. The North Sea region plays a strategic role in Apache’s portfolio by providing competitive investment opportunities and potential reserve upside with high-impact exploration potential.
During 2019, the region drilled 11 development wells with a 100 percent success rate: five platform wells in the Forties field, three platform wells in the Beryl field, and three subsea wells in the Beryl area.
The North Sea region’s Storr exploration discovery came on-line in the fourth quarter of 2019, and its second well at Garten came on-line in the first quarter of 2020. The first well at the Company’s Storr development is a high-rate gas condensate well that is tied back to existing infrastructure at the Beryl Alpha platform. The Garten #2 well encountered approximately 1,200 feet of net pay and compares favorably to the Garten #1 well, which came on-line in November 2018 with initial 30-day production rates of 13 Mb/d and 17 MMcf/d from 700 feet of net pay. Apache holds a 100 percent working interest in the Garten complex.
In 2020, the Company plans to run one to two platform rigs in the North Sea between the Forties and Beryl assets as well as a semi-submersible rig drilling principally in the Beryl area where the Company has short-cycle subsea tie-back opportunities.
International Marketing Apache’s natural gas production in Egypt 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. Crude oil production is sold to third parties in the export market or to EGPC when called upon to supply domestic demand. Oil production sold to third parties is sold and exported from one of two terminals on the northern coast of Egypt. Oil production sold to EGPC is sold at prices related to the export market.
Apache’s North Sea crude oil production is sold under term, entitlement volume contracts and fixed volume spot contracts with a market-based index price plus a differential to capture the higher market value under each type of arrangement. Natural gas from the Beryl field is processed through the Scottish Area Gas Evacuation (SAGE) gas plant, which Apache divested to Ancala Midstream Acquisitions Limited in late 2017. 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.
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.
In December 2019, Apache entered into a joint venture agreement with Total S.A. to explore and develop Block 58 offshore Suriname. Apache holds a 50 percent working interest in Block 58, which comprises approximately 1.4 million acres in water depths ranging from less than 100 meters to more than 2,100 meters. During 2019, the Company drilled an exploration well, the Maka Central-1, in Block 58 and announced a significant oil discovery in January 2020. The well successfully tested for the presence of hydrocarbons in multiple stacked targets in the upper Cretaceous-aged Campanian and Santonian intervals and encountered both oil and gas condensate. The Company began drilling its second exploration well, Sapakara West-1, in January 2020. Following completion of the Sapakara West-1, the Company will drill a third, and likely a fourth exploration test in Block 58 during 2020.
Worldwide in 2019, Apache drilled or participated in drilling 315 gross wells, with 299 (95 percent) completed as producers. Historically, Apache’s drilling activities in the U.S. have generally concentrated on exploitation and extension of existing producing fields rather than exploration. As a general matter, Apache’s operations outside of the U.S. focus on a mix of exploration and development wells. In addition to Apache’s completed wells, at year-end a number of wells had not yet reached completion: 105 gross (99.8 net) in the U.S., 25 gross (23.7 net) in Egypt, 5 gross (3.8 net) in the North Sea, and 1 gross (0.5 net) in Suriname.
The following table shows the results of the oil and gas wells drilled and completed for each of the last three fiscal years:
Total Net Wells
Productive Oil and Gas Wells
The number of productive oil and gas wells, operated and non-operated, in which the Company had an interest as of December 31, 2019, is set forth below:
Gross natural gas and crude oil wells include 585 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 the Company has operations:
Cost per Boe
Average Sales Price
Year Ended December 31,
Includes production volumes attributable to a one-third noncontrolling interest in Egypt.
Sales volumes from the North Sea for 2019, 2018, and 2017 were 21.8 MMboe, 20.3 MMboe, and 21.2 MMboe, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.
During the third quarter of 2017, Apache finalized the sale and complete exit of its Canadian operations.
Gross and Net Undeveloped and Developed Acreage
The following table sets out Apache’s gross and net acreage position as of December 31, 2019, in each country where the Company has operations:
As of December 31, 2019, approximately 19 percent of U.S. net undeveloped acreage was held by production.
As of December 31, 2019, Apache had 257,000 net undeveloped acres scheduled to expire by year-end 2020 if production is not established or Apache takes no other action to extend the terms. Additionally, Apache has 1.4 million and 561,000 net undeveloped acres set to expire in 2021 and 2022, respectively. The Company strives 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 Apache’s Egypt region comprise a significant portion of Apache’s net undeveloped acreage expiring over the next three years. Apache has 98,000 net undeveloped acres expiring in Egypt during 2020. Approximately 1.3 million and 98,000 net undeveloped acres are set to expire in 2021 and 2022, respectively. There were no reserves recorded on this undeveloped acreage. Apache will continue to pursue acreage extensions and access to new concessions in areas in which it believes exploration opportunities exist.
Additionally, Apache has exploration interests in Suriname consisting of 390,000 net undeveloped acres in Block 53 and 720,000 net undeveloped acres in Block 58 set to expire in 2022 and 2026, respectively, contingent on planned drilling activity. Apache has acquired 3-D seismic surveys over all the acreage. No reserves have been booked on this undeveloped acreage.
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 the Company’s 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, 2019, based on average commodity prices in effect on the first day of each month in 2019, 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.
Total Proved Developed
Total Proved Undeveloped
Includes total proved developed and total proved undeveloped reserves of 59 MMboe and 5 MMboe, respectively, attributable to a one-third noncontrolling interest in Egypt.
As of December 31, 2019, Apache had total estimated proved reserves of 551 MMbbls of crude oil, 186 MMbbls of NGLs, and 1.6 Tcf of natural gas. Combined, these total estimated proved reserves are the volume equivalent of 1.0 billion barrels of oil or 6.1 Tcf of natural gas, of which oil represents 55 percent. As of December 31, 2019, the Company’s proved developed reserves totaled 893 MMboe and estimated PUD reserves totaled 118 MMboe, or approximately 12 percent of worldwide total proved reserves. Apache has elected not to disclose probable or possible reserves in this filing. The Company does not have any fields that contain 15 percent or more of its total proved reserves for the years ended December 31, 2019, 2018, and 2017.
During 2019, Apache added 176 MMboe of proved reserves through exploration and development activity, partially offset by combined downward revisions of previously estimated reserves of 119 MMboe. Engineering and performance upward revisions accounted for 20 MMboe and downward revisions related to changes in product prices accounted for 139 MMboe. The Company also sold 107 MMboe of proved reserves associated with U.S. divestitures, primarily related to the sale of the Company’s Woodford-SCOOP and STACK plays and western Anadarko Basin assets.
The Company’s estimates of proved reserves, proved developed reserves, and PUD reserves as of December 31, 2019, 2018, and 2017, changes in estimated proved reserves during the last three years, and estimates of future net cash flows from proved reserves are contained in Note 18—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 118 MMboe as of December 31, 2019, decreased by 35 MMboe from 153 MMboe of PUD reserves reported at the end of 2018. During the year, Apache converted 85 MMboe of PUD reserves to proved developed reserves through development drilling activity. In the U.S., Apache converted 72 MMboe, with the remaining 13 MMboe in Apache’s international areas. Apache sold 18 MMboe of PUD reserves in the U.S. and did not acquire any PUD reserves during the year. Apache added 119 MMboe of new PUD reserves through extensions and discoveries. Apache recognized a 7 MMboe upward engineering revision in proved undeveloped reserves during the year. Downward engineering revisions included 28 MMboe associated with product prices, 29 MMboe associated with revised development plans, and 1 MMboe associated with interest revisions.
During the year, a total of approximately $1.0 billion was spent on projects associated with proved undeveloped reserves. A portion of Apache’s costs incurred each year relate to development projects that will convert undeveloped reserves to proved developed reserves in future years. During 2019, Apache spent approximately $749 million on PUD reserve development activity in the U.S. and $264 million in the international areas. As of December 31, 2019, Apache 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 Development, Planning, Reserves and Fundamentals 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 Bachelor of Science and Master of Science degrees in Petroleum Engineering and over 30 years of experience in the energy industry and energy sector of the banking industry. The Executive Vice President of Development, Planning, Reserves and Fundamentals 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. The Company engages Ryder Scott Company, L.P. Petroleum Consultants (Ryder Scott) to conduct a reserves audit, which includes a review of our processes and the reasonableness of our estimates of proved hydrocarbon liquid and gas reserves. The Company selects the properties for review by Ryder Scott based primarily on relative reserve value. The Company also considers other factors such as geographic location, new wells drilled during the year and reserves volume. During 2019, the properties selected for each country ranged from 83 to 95 percent of the total future net cash flows discounted at 10 percent. These properties also accounted for over 91 percent of the reserves value of Apache’s international proved reserves and 95 percent of the reserves value of Apache’s new wells drilled worldwide. 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 85 percent of total proved reserves by volume.
Ryder Scott’s review for the years 2019, 2018, and 2017 covered 87, 86, and 92 percent, respectively, of the value and 85, 83, and 84 percent, respectively, of the volume of the Company’s worldwide estimated proved reserves. Ryder Scott’s 2019 review covered 85, 86, and 80 percent of the estimated proved reserve volume in the U.S., Egypt, and U.K., respectively.
Ryder Scott’s review of 2018 covered 82 percent of U.S., 85 percent of Egypt, and 81 percent of the U.K.’s total proved reserves.
Ryder Scott’s review of 2017 covered 84 percent of U.S., 85 percent of Egypt, and 81 percent of the U.K.’s total proved reserves.
The Company has 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.
ALTUS MIDSTREAM ASSETS
In November 2018, Apache completed a transaction with Altus Midstream Company and its then wholly-owned subsidiary Altus Midstream LP (collectively, Altus) to create a pure-play, Permian Basin to Gulf Coast midstream C-corporation anchored by gathering, processing, and transmission assets at Alpine High. Pursuant to the agreement, Apache contributed certain Alpine High midstream assets and options to acquire equity interests in five separate third-party pipeline projects (the Pipeline Options) to Altus Midstream LP and/or its subsidiaries. In exchange for the assets, Apache received economic voting and non-economic voting shares in Altus Midstream Company and limited partner interests in Altus Midstream LP, representing an approximate 79 percent ownership interest in the combined entities.
Apache fully consolidates the assets and liabilities of Altus in its consolidated financial statements, with a corresponding noncontrolling interest reflected separately.
Gathering, Processing, and Transmission Assets
Altus owns, develops, and operates gas gathering, processing, and transmission assets in the Permian Basin of West Texas. Altus generates revenue by providing fee-based natural gas gathering, compression, processing, and transmission services for Apache’s production from its Alpine High resource play. As of December 31, 2019, Altus’ assets included approximately 178 miles of in-service natural gas gathering pipelines, approximately 55 miles of residue-gas pipelines with four market connections, and approximately 38 miles of NGL pipelines. Three cryogenic processing trains, each with nameplate capacity of 200 MMcf/d, were placed into service during 2019. Other assets include an NGL truck loading terminal with six Lease Automatic Custody Transfer units and eight NGL bullet tanks with 90,000 gallon capacity per tank. Altus’ existing gathering, processing, and transmission infrastructure is expected to provide capacity levels capable of fulfilling its midstream contracts to service Apache’s production from Alpine High and additional third-party customers as the market activity in the area continues to develop.
Apache, as part of its fourth quarter 2019 capital planning review, notified Altus of its intention to materially reduce funding to Alpine High. This notification prompted Altus management to assess its long-lived infrastructure assets for impairment given the expected reduction to future throughput volumes. Altus subsequently recorded impairments on its gathering, processing, and transmission assets. For further discussion of these impairments, please see Note 1 “Summary of Significant Accounting Policies” in the Notes to Consolidated Financial Statements included in within Part IV, Item 15 of this Form 10-K.
Pipeline Options and Equity Interests
Gulf Coast Express Pipeline In December 2018, Altus Midstream LP closed on the exercise of its option to acquire a 15 percent equity interest in the Gulf Coast Express Pipeline (GCX) from Kinder Morgan Texas Pipeline LLC (Kinder Morgan). Altus Midstream LP acquired an additional 1 percent equity interest in May 2019, for a total 16 percent equity interest in GCX. GCX is a long-haul natural gas pipeline with capacity of approximately 2.0 Bcf/d and transports natural gas from the Waha area in northern Pecos County, Texas to the Agua Dulce Hub near the Texas Gulf Coast. GCX is operated by Kinder Morgan and was placed into service in September 2019.
EPIC Crude Oil Pipeline In March 2019, Altus Midstream LP’s subsidiary closed on the exercise of its option with EPIC Pipeline LP, thereby acquiring a 15 percent equity interest in the EPIC crude oil pipeline (EPIC). The long-haul crude oil pipeline extends from the Orla area in northern Reeves County, Texas to the Port of Corpus Christi, Texas, and has Permian Basin initial throughput capacity of approximately 600 Mb/d. The project includes terminals in Orla, Pecos, Crane, Wink, Midland, Hobson, and Gardendale, Texas with Port of Corpus Christi connectivity and export access. It services Delaware Basin, Midland Basin, and Eagle Ford Shale production. EPIC is operated by EPIC Consolidated Operations, LLC and was commissioned in February 2020.
Permian Highway Pipeline In May 2019, Altus Midstream LP’s subsidiary closed on the exercise of its option with Kinder Morgan, thereby acquiring an approximate 26.7 percent equity interest in the Permian Highway Pipeline (PHP). Upon completion, the long-haul natural gas pipeline is expected to have capacity of approximately 2.1 Bcf/d and will transport natural gas from the Waha area in northern Pecos County, Texas to the Katy, Texas area with connections to U.S. Gulf Coast and Mexico markets. PHP will be operated by Kinder Morgan and is expected to be in service in early 2021.
Shin Oak NGL Pipeline In July 2019, Altus Midstream LP’s subsidiary closed on the exercise of its option with Enterprise Products Operating LLC (Enterprise Products), thereby acquiring a 33 percent equity interest in Breviloba LLC, which owns Shin Oak NGL Pipeline (Shin Oak). The long-haul NGL pipeline has capacity of up to 550 Mb/d and transports NGL production from the Orla area in northern Reeves County, Texas through the Waha area in northern Pecos County, Texas, and on to Mont Belvieu, Texas. Shin Oak is operated by Enterprise Products and was placed into service during 2019.
Pipeline Option Outstanding
Salt Creek NGL Pipeline Altus Midstream LP’s subsidiary’s option to acquire a 50 percent equity interest in the Salt Creek NGL Pipeline, an intra-basin NGL pipeline, was originally set to expire on January 31, 2020; however, the parties executed an extension for the option until March 2, 2020.
For the years ended 2019, 2018, and 2017, the customers, including their subsidiaries, that represented more than 10 percent of the Company’s worldwide oil and gas production revenues were as follows:
For the Year Ended December 31,
China Petroleum & Chemical Corporation (Sinopec)(2)
Egyptian General Petroleum Corporation(3)
Sales to BP plc were reported as revenue in the Company’s U.S., Egypt, and North Sea upstream segments in the years ended 2019, 2018, and 2017.
Sales to Sinopec were reported as revenue in the Company’s Egypt upstream segment in the year ended 2019 and in the Company’s Egypt and North Sea upstream segments in the years ended 2018 and 2017.
Sales to EGPC were reported as revenue in the Company’s Egypt upstream segment in the years ended 2019, 2018, and 2017.
On December 31, 2019, the Company had 3,163 employees.
Our principal executive offices are located at One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400. At year-end 2019, the Company maintained regional exploration and/or production offices in Midland, Texas; San Antonio, Texas; Houston, Texas; Cairo, Egypt; and Aberdeen, Scotland. Apache leases its primary office space. The current lease on our principal executive offices runs through December 31, 2024. The Company has an option to extend the lease through 2029. 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 11—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
Response Plans and Available Resources
Apache and its wholly owned subsidiary, Apache Deepwater LLC (ADW), developed Oil Spill Response Plans (the Plans) for their respective Gulf of Mexico operations and offshore operations in the North Sea and Suriname, which ensure rapid and effective responses to spill events that may occur on such entities’ operated properties. Annually, drills are conducted to measure and maintain the effectiveness of the Plans.
Apache is a member of Oil Spill Response Limited (OSRL), a large international oil spill response cooperative, which entitles any Apache entity worldwide to access OSRL’s services. Apache also has a contract for response resources and services with National Response Corporation (NRC). NRC is the world’s largest commercial Oil Spill Response Organization and is the global leader in providing end-to-end environmental, industrial, and emergency response solutions with operating bases in 13 countries.
In the event of a spill in the Gulf of Mexico, Clean Gulf Associates (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.
Additionally, Apache is an active member of Wild Well Control’s WellCONTAINED Subsea Containment System for Suriname operations. This membership includes contingency planning, and response, to an uncontrolled subsea well event. Apache utilizes a detailed Source Control Emergency Response Plan (SCERP) for offshore Suriname planning. The SCERP has been designed to ensure that the goals of Apache’s source control emergency preparedness efforts will be met in the unlikely event of an actual response to an uncontrolled well event. This includes the use of subsea dispersant systems and field deployment of one of Wild Well Control’s containment system capping stacks.
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 three geographic areas, 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 geographic areas 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.
As an owner or lessee and operator of oil and gas properties and facilities, we are subject to numerous federal, 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.
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, natural gas, and NGL price volatility 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, natural gas, and NGL production. Historically, the markets for these commodities 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 2019 ranged from a high of $66.30 per barrel to a low of $45.89 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 2019 ranged from a high of $3.59 per MMBtu to a low of $2.07 per MMBtu. The market prices for crude oil, natural gas, and NGLs depend on factors beyond our control. These factors include demand, which fluctuates with changes in market and economic conditions, and other factors, including:
worldwide and domestic supplies of crude oil, natural gas, and NGLs;
actions taken by foreign oil and gas producing nations, including the Organization of the Petroleum Exporting Countries (OPEC);
political conditions and events (including instability, changes in governments, or armed conflict) in oil and gas producing regions;
the level of global crude oil and natural gas inventories;
the price and level of imported foreign crude oil, natural gas, and NGLs;
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;
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, natural gas, and NGLs, which have declined significantly since June 2014. Despite slight increases in oil and natural gas prices in 2019, prices have remained significantly lower than levels seen in recent years, which has 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, natural gas, and NGLs 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, natural gas, and NGLs 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 oil and gas properties, resulting in additional non-cash impairments;