APA Corp: Form 10-Q for the period ended Jun 30, 2021

The following discussion relates to APA Corporation (APA or the Company) and its consolidated subsidiaries and should be read together with the Company’s Consolidated Financial Statements and accompanying notes included in Part I, Item 1—Financial Statements of this Quarterly Report on Form 10-Q, as well as related information set forth in Apache Corporation’s Consolidated Financial Statements, accompanying Notes to Consolidated Financial Statements, and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020.

On January 4, 2021, Apache Corporation announced plans to implement a holding company reorganization (the Holding Company Reorganization), which was thereafter completed on March 1, 2021. In connection with the Holding Company Reorganization, Apache Corporation became a direct, wholly-owned subsidiary of APA Corporation, and all of Apache Corporation’s outstanding shares were automatically converted into equivalent corresponding shares of APA. Pursuant to the Holding Company Reorganization, APA became the successor issuer to Apache Corporation pursuant to Rule 12g-3(a) under the Exchange Act and replaced Apache Corporation as the public company trading on the Nasdaq Global Select Market under the ticker symbol “APA.” The Holding Company Reorganization modernized the Company’s operating and legal structure to more closely align with its growing international presence, making it more consistent with other companies that have subsidiaries operating around the globe.

Overview

APA is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids (NGLs). The Company’s upstream business 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). APA also has active exploration and planned appraisal operations ongoing in Suriname, as well as interests in other international locations that may, over time, result in reportable discoveries and development opportunities. The Company’s midstream business is operated by Altus Midstream Company (Nasdaq: 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.

The Company’s mission is to grow in an innovative, safe, environmentally responsible, and profitable manner for the long-term benefit of its stakeholders. The Company is focused on rigorous portfolio management, disciplined financial structure, and optimization of returns.

The global economy and the energy industry have been deeply impacted by the effects of the coronavirus disease 2019 (COVID-19) pandemic and related governmental actions. Uncertainty in the commodity and financial markets during 2020 and 2021 continue to impact oil supply and demand. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio, including advancement of ongoing exploration and appraisal activities offshore Suriname; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate cash flow in excess of its capital program that can be directed on a priority basis to debt reduction. The Company continues to aggressively manage its cost structure regardless of the oil price environment and closely monitors hydrocarbon pricing fundamentals to reallocate capital as part of its ongoing planning process.

In the second quarter of 2021, the Company reported net income of $316 million, or $0.82 per diluted common share, compared to a loss of $386 million, or $1.02 per diluted common share, in the second quarter of 2020. The increase in net income compared to the prior-year period is primarily the result of significantly improved commodity prices that had collapsed in the prior year when the COVID-19 pandemic began to negatively affect economic activity and the oil markets. In response to lower commodity prices, the Company materially reduced its upstream capital investment budget and drilling activity during the first half of 2020. Daily production decreased 9 percent from an average of 435 Mboe/d in the second quarter of 2020 to an average of 395 Mboe/d in the second quarter of 2021.

The Company generated $1.6 billion of cash from operating activities during the first six months of 2021, a 180 percent increase from the first six months of 2020 driven by higher commodity prices and associated revenues. The Company ended the quarter with $1.2 billion of cash.

Operational Highlights

Key operational highlights for the quarter include:

United States

• Equivalent production from the Company’s U.S. assets accounted for 61 percent of its total production during the second quarter of 2021. After halting all drilling and completion activity for most of 2020, in early 2021 the Company re-activated one rig in the Permian Basin and one rig in the Austin Chalk. A second rig was added in the Permian Basin in late June 2021. The Company was also active in completing its backlog of Permian wells previously drilled but not completed. For the second quarter, the Company placed 27 wells online in the Permian Basin, including five at Alpine High. Three wells were drilled in the Austin Chalk where the results are continuing to be evaluated. The Company is assessing the addition of a third rig in the U.S., which would provide a path to sustained oil production.

International

• In May 2021, the Company reached an agreement in principle with the Egyptian Ministry of Petroleum and the Egyptian General Petroleum Corporation (EGPC) to modernize the terms of the majority of our production-sharing contracts. The changes simplify the contractual relationship with EGPC and include provisions to create a single cost recovery pool, adjust cost oil and gas and profit oil and gas participation, facilitate recovery of prior investment, update day-to-day operational governance, and refresh the term length of both exploration and development leases. The Apache entity that will become the sole contractor is owned two-thirds by Apache and one-third by Sinopec. The final draft of this agreement has been completed and is scheduled to move to the Egyptian Parliament and President in the fall for approvals to complete the process.
• The Company averaged six drilling rigs in Egypt and completed 15 wells during the first half of 2021. Second-quarter gross equivalent production in the Company’s Egypt assets decreased 17 percent from the second quarter of 2020, given reduced drilling activity over the preceding year. The Company continues to build and enhance its drilling inventory in Egypt, supplemented with recent seismic acquisitions and new play concept evaluations on both new and existing acreage. Upon ratification of the new PSC agreement, the Company expects to further increase drilling and workover activity.
• The Company averaged two rigs in the North Sea during the second quarter of 2021. Production from the Forties field was significantly impacted by compressor downtime, extended platform turnaround work, and third-party pipeline outages during the first half of the year. Further impacts are expected in the third quarter of 2021 from continued operational downtime and planned platform maintenance turnarounds on the Beryl platforms.
• In late 2020, the Company commenced drilling a fourth exploration well at the Keskesi prospect in Block 58 offshore Suriname. In January 2021, the Company and its partner TotalEnergies (formerly Total S.A.) announced a discovery that confirmed oil in the eastern portion of the block. The Company has subsequently transferred operatorship of Block 58 to TotalEnergies, with ongoing exploration and appraisal activities continuing to progress. During the second quarter of 2021, two rigs conducted appraisal work at the Sapakara and Keskesi discoveries.
• In July 2021, the Company announced drilling success at Sapakara South-1, an appraisal well located on the eastern edge of the Sapakara area, which encountered approximately 30 meters of net black oil pay in a single zone of high-quality Campano-Maastrichtian reservoir. The Maersk Valiant drillship will soon mobilize to the Bonboni exploration prospect in the northern portion of Block 58 before returning later in the year to flow test Sapakara South-1. APA holds a 50 percent working interest in Block 58, with TotalEnergies, the operator, holding a 50 percent working interest.

Results of Operations

Oil and Gas Production Revenues

The Company’s oil and gas production revenues and respective contribution to total revenues by country were as follows:

($ in millions)

(1) Includes revenues attributable to a noncontrolling interest in Egypt.

Production

The Company’s production volumes by country were as follows:

(1) Gross oil, natural gas, and NGL production in Egypt were as follows:

(2) Includes net production volumes per day attributable to a noncontrolling interest in Egypt of:

(3) The table shows production on a boe basis in which natural gas is converted to an equivalent barrel of oil based on a 6:1 energy equivalent ratio. This ratio is not reflective of the price ratio between the two products.

(4) Average sales volumes from the North Sea for the second quarter of 2021 and 2020 were 41,941 boe/d and 54,996 boe/d, respectively, and 48,208 boe/d and 64,133 boe/d for the first six months of 2021 and 2020, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings in the Beryl field.

Pricing

The Company’s average selling prices by country were as follows:

Second-Quarter 2021 compared to Second-Quarter 2020

Crude Oil Crude oil revenues for the second quarter of 2021 totaled $1.1 billion, a $628 million increase from the comparative 2020 quarter. A 158 percent increase in average realized prices increased second-quarter 2021 oil revenues by $810 million compared to the prior-year quarter, while 16 percent lower average daily production decreased revenues by $182 million. Crude oil revenues accounted for 75 percent of total oil and gas production revenues and 47 percent of worldwide production in the second quarter of 2021. The Company’s worldwide oil production decreased 35.3 Mb/d to 186.0 Mb/d during the second quarter of 2021 from the comparative prior-year period, primarily a result of natural production decline across all countries and extended operational downtime and extended platform turnaround work in the North Sea. Crude oil prices realized in the second quarter of 2021 averaged $66.40 per barrel, compared to $25.77 per barrel in the comparative prior-year quarter.

Natural Gas Gas revenues for the second quarter of 2021 totaled $226 million, a $96 million increase from the comparative 2020 quarter. A 78 percent increase in average realized prices increased second-quarter 2021 natural gas revenues by $100 million compared to the prior-year quarter, while 2 percent lower average daily production decreased revenues by $4 million. Natural gas revenues accounted for 15 percent of total oil and gas production revenues and 35 percent of worldwide production during the second quarter of 2021. The Company’s worldwide natural gas production decreased 16 MMcf/d to 834 MMcf/d during the second quarter of 2021 from the comparative prior-year period, primarily a result of production decline across all countries and extended operational downtime in the North Sea, offset by increased completion activity in the U.S.

NGL NGL revenues for the second quarter of 2021 totaled $147 million, a $93 million increase from the comparative 2020 quarter. A 179 percent increase in average realized prices increased second-quarter 2021 NGL revenues by $98 million compared to the prior-year quarter, while 3 percent lower average daily production decreased revenues by $5 million. NGL revenues accounted for 10 percent of total oil and gas production revenues and 18 percent of worldwide production during the second quarter of 2021. The Company’s worldwide NGL production decreased 2.3 Mb/d to 70.1 Mb/d during the second quarter of 2021 from the comparative prior-year period, primarily a result of production decline across all countries.

Year-to-Date 2021 compared to Year-to-Date 2020

Crude Oil Crude oil revenues for the first six months of 2021 totaled $2.1 billion, a $0.6 billion increase from the comparative 2020 period. A 68 percent increase in average realized prices increased 2021 oil revenues by $1.1 billion compared to the prior-year period, while 18 percent lower average daily production decreased revenues by $471 million. Crude oil revenues accounted for 73 percent of total oil and gas production revenues and 47 percent of worldwide production for the first six months of 2021. Crude oil prices realized during the first six months of 2021 averaged $63.06 per barrel, compared to $37.44 per barrel in the comparative prior-year period. The Company’s worldwide oil production decreased 41.0 Mb/d to 184.7 Mb/d in the first six months of 2021 compared to the prior-year period, primarily a result of production decline across all countries, extended operational downtime, and extended platform turnaround work in the North Sea.

Natural Gas Gas revenues for the first six months of 2021 totaled $538 million, a $285 million increase from the comparative 2020 period. A 127 percent increase in average realized prices increased 2021 natural gas revenues by $321 million compared to the prior-year period, while 6 percent lower average daily production decreased revenues by $36 million. Natural gas revenues accounted for 18 percent of total oil and gas production revenues and 36 percent of worldwide production for the first six months of 2021. Natural gas prices realized during the first six months of 2021 averaged $3.56 per Mcf, compared to $1.57 per Mcf in the comparative prior-year period. Gas prices for the U.S. during the first six months of 2021 also reflect the extreme price volatility during the month of February due to the Texas freeze event. The Company’s worldwide natural gas production decreased 50 MMcf/d to 835 MMcf/d in the first six months of 2021 compared to the prior-year period, primarily a result of production decline across all countries, impacts of winter storms in the U.S., and extended operational downtime and platform turnaround work in the North Sea.

NGL NGL revenues for the first six months of 2021 totaled $275 million, a $140 million increase from the comparative 2020 period. A 147 percent increase in average realized prices increased 2021 NGL revenues by $199 million compared to the prior-year period, while 17 percent lower average daily production decreased revenues by $59 million. NGL revenues accounted for 9 percent of total oil and gas production revenues and 17 percent of worldwide production for the first six months of 2021. NGL prices realized during the first six months of 2021 averaged $23.41 per barrel, compared to $9.48 per barrel in the comparative prior-year period. The Company’s worldwide NGL production decreased 13.4 Mb/d to 65.0 Mb/d in the first six months of 2021 compared to the prior-year period, primarily a result of production decline across all countries and the impacts of winter storms in the U.S.

Altus Midstream Revenues

Altus Midstream services revenues generated through its fee-based contractual arrangements with the Company totaled $32 million and $31 million during the second quarters of 2021 and 2020, respectively, and $64 million and $72 million during the first six months of 2021 and 2020, respectively. These affiliated revenues are eliminated upon consolidation. Changes in revenue compared to the prior periods were primarily driven by fluctuations in natural gas throughput volumes processed by Altus for the Company’s Alpine High production.

Purchased Oil and Gas Sales

Purchased oil and gas sales represent volumes primarily attributable to transport, fuel, and physical in-basin gas purchases that were sold by the Company to fulfill natural gas takeaway obligations. Sales related to these purchased volumes totaled $242 million and $55 million during the second quarters of 2021 and 2020, respectively, and $682 million and $163 million during the first six months of 2021 and 2020, respectively. Purchased oil and gas sales were offset by associated purchase costs of $262 million and $46 million during the second quarters of 2021 and 2020, respectively, and $756 million and $132 million during the first six months of 2021 and 2020, respectively. When compared to the prior-year periods, gross purchased oil and gas sales values and the associated net losses in the second quarter and first six months of 2021 increased as a result of production shortfalls following reduced capital investment and drilling activity in 2020. The year-to-date net loss was exacerbated by extreme price volatility during the month of February due to Winter Storm Uri in Texas.

Operating Expenses

The Company’s operating expenses were as follows:

(In millions)

Lease Operating Expenses (LOE)

LOE increased $47 million and decreased $24 million in the second quarter and the first six months of 2021, respectively, from the comparative prior-year periods. On a per-unit basis, LOE increased 28 percent and 12 percent in the second quarter and the first six months of 2021, respectively, from the comparative prior-year periods. The increase was driven by higher turnaround and maintenance costs in the North Sea, strengthening foreign exchange rates against the U.S. dollar, increased workover activity in the U.S. in the second quarter of 2021, and per-unit operating costs trending with higher oil and gas prices.

Gathering, Processing, and Transmission (GPT)

The Company’s GPT expenses were as follows:

(In millions)

GPT costs decreased $11 million and $24 million in the second quarter and the first six months 2021, respectively, from the comparative prior-year periods. Third-party processing and transmission costs decreased $9 million and $19 million in the second quarter and the first six months of 2021, respectively, from the comparative prior-year periods, primarily driven by a decrease in contracted pricing and lower processed volumes. Midstream service affiliate costs remained flat in the second quarter of 2021 and decreased $9 million in the first six months of 2021, compared to their respective prior-year periods. The overall decrease in the first six months of 2021 was primarily driven by lower throughput of rich natural gas volumes at Alpine High. Midstream operating expenses, primarily incurred by Altus Midstream, decreased $2 million and $5 million in the second quarter and the first six months of 2021, respectively, from the comparative prior-year periods, driven by increased operational efficiency and continued cost cutting efforts.

Purchased Oil and Gas Costs

Purchased oil and gas costs totaled $262 million and $756 million during the second quarter and the first six months of 2021, respectively, compared to $46 million and $132 million during the second quarter and the first six months of 2020, respectively. Purchased oil and gas costs were offset by associated purchase sales of $242 million and $682 million during the second quarter and the first six months of 2021, respectively, compared to $55 million and $163 million during the second quarter and the first six months of 2020, respectively, as further discussed above.

Taxes Other Than Income

Taxes other than income increased $28 million and $39 million from the second quarter and the first six months of 2020, respectively, primarily from higher severance taxes driven by higher commodity prices as compared to the prior-year period.

Exploration Expenses

The Company’s exploration expenses were as follows:

(In millions)

Exploration expenses decreased $46 million and $54 million from the second quarter and the first six months of 2020, respectively, primarily the result of lower dry hole expense and exploration overhead, a function of decreased exploration activities. The Company also had lower unproved leasehold impairments driven by improved commodity prices.

General and Administrative (G&A) Expenses

G&A expenses decreased $8 million in the second quarter of 2021 compared to the second quarter of 2020, and increased $7 million in the first six months of 2021 compared to the first six months of 2020. The reduction in second-quarter 2021 G&A compared to the prior-year quarter was driven by organizational redesign efforts during 2019 and 2020. The increase in the first six months of 2021 from the comparative prior-year period was primarily related to higher cash-based stock compensation expense resulting from an increase in the Company’s stock price, offset by lower overhead during the year as previously discussed.

Transaction, Reorganization, and Separation (TRS) Costs

TRS costs decreased $6 million and $33 million from the second quarter and the first six months of 2020, respectively, driven by costs associated with the Company’s reorganization efforts incurred in the prior year.

In recent years, the Company has streamlined its portfolio through strategic divestitures and centralized certain operational activities in an effort to capture greater efficiencies and cost savings through shared services. During the second half of 2019, management initiated a comprehensive redesign of the Company’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. Reorganization efforts were substantially completed during 2020.

Depreciation, Depletion, and Amortization (DD&A)

DD&A expenses on the Company’s oil and gas properties decreased $65 million and $284 million from the second quarter and the first six months of 2020, respectively. The Company’s DD&A rate on its oil and gas properties decreased $0.93 per boe and $2.18 per boe from the second quarter and the first six months of 2020, respectively. The decrease was driven by lower production volumes and lower asset property balances associated with proved property impairments recorded during the first quarter of 2020. DD&A expense on the Company’s GPT assets remained essentially flat compared to the second quarter and the first six months of 2020.

Impairments

The Company recognized no asset impairments in connection with fair value assessments during the first six months of 2021.

The Company recognized $4.5 billion in asset impairments in connection with fair value assessments during the first six months of 2020. During the second quarter of 2020, the Company recognized impairments totaling $20 million related to proved oil and gas properties in Egypt. During the first quarter of 2020, the Company recognized impairments totaling $4.3 billion related to proved oil and gas properties in the U.S., Egypt, and the North Sea, $68 million related to GPT facilities in Egypt, $87 million related to goodwill valuations in Egypt, and $18 million related to inventory and other miscellaneous assets, including charges for the early termination of drilling rig leases.

Financing Costs, Net

The Company’s Financing costs were as follows:

(In millions)

Net financing costs increased $141 million and $148 million from the second quarter and the first six months of 2020, respectively, driven by the $140 million gain on extinguishment of debt recorded in the second quarter of 2020.

Provision for Income Taxes

The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments on the carrying value of the Company’s oil and gas properties, gains and losses on the sale of assets, statutory tax rate changes, and other significant or unusual items are recognized as discrete items in the quarter in which they occur.

During the second quarter and the first six months of 2021, the Company’s effective income tax rate was primarily impacted by a decrease in the amount of valuation allowance against its U.S. deferred tax assets. During the second quarter and first six months of 2020, the Company’s effective income tax rate was primarily impacted by an increase in the amount of valuation allowance against its U.S. deferred tax assets and impairments recorded during the period. The Company’s 2020 year-to-date effective income tax rate was primarily impacted by oil and gas asset impairments, a goodwill impairment, and an increase in the amount of valuation allowance against its U.S. deferred tax assets.

The Company recorded a full valuation allowance against its U.S. net deferred tax assets. The Company will continue to maintain a full valuation allowance on its U.S. net deferred tax assets until there is sufficient evidence to support the reversal of all or some portion of this allowance.

The Company is subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. The Company is currently under audit by the Internal Revenue Service for the 2014-2017 tax years and is also under audit in various states and foreign jurisdictions as part of its normal course of business.

Capital Resources and Liquidity

Operating cash flows are the Company’s primary source of liquidity. The Company’s short-term and long-term operating cash flows are impacted by highly volatile commodity prices, as well as production costs and sales volumes. Significant changes in commodity prices impact the Company’s revenues, earnings, and cash flows. These changes potentially impact the Company’s liquidity if costs do not trend with related changes in commodity prices. Historically, costs have trended with commodity prices, albeit on a lag. Sales volumes also impact cash flows; however, they have a less volatile impact in the short term.

The Company’s long-term operating cash flows are dependent on reserve replacement and the level of costs required for ongoing operations. Cash investments are required to fund activity necessary to offset the inherent declines in production and proved crude oil and natural gas reserves. Future success in maintaining and growing reserves and production is highly dependent on the success of the Company’s drilling program and its ability to add reserves economically. Changes in commodity prices also impact estimated quantities of proved reserves.

The Company’s capital investment for the second quarter of 2021 was below its planned budget announced earlier in the year, but the Company remains on-track for its full-year guidance and estimated upstream capital program of $1.1 billion. The program consists of approximately $900 million for development activities across its portfolio and approximately $200 million for exploration activities, predominantly in Suriname.

The Company believes the liquidity and capital resource alternatives available to the Company, combined with proactive measures to adjust its capital budget to reflect volatile commodity prices and anticipated operating cash flows, will be adequate to fund short-term and long-term operations, including the Company’s capital development program, repayment of debt maturities, payment of dividends, and amounts that may ultimately be paid in connection with commitments and contingencies.

The Company may also elect to utilize available cash on hand, committed subsidiary borrowing capacity, access to both debt and equity capital markets, or proceeds from the sale of nonstrategic assets for all other liquidity and capital resource needs.

For additional information, refer to Part I, Items 1 and 2—Business and Properties, and Item 1A—Risk Factors, in Apache Corporation’s Annual Report on Form 10-K of Apache Corporation for the fiscal year ended December 31, 2020.

Sources and Uses of Cash

The following table presents the sources and uses of the Company’s cash and cash equivalents for the periods presented.

(In millions)

(1) The table presents capital expenditures on a cash basis; therefore, the amounts may differ from those discussed elsewhere in this Quarterly Report on Form 10-Q, which include accruals.

Sources of Cash and Cash Equivalents

Net Cash Provided by Operating Activities Operating cash flows are the Company’s primary source of capital and liquidity and are impacted, both in the short term and the long term, by volatile commodity prices. The factors that determine operating cash flows are largely the same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, exploratory dry hole expense, asset impairments, asset retirement obligation (ARO) accretion, and deferred income tax expense.

Net cash provided by operating activities increased $1.1 billion from the first six months of 2020, primarily due to higher commodity prices.

For a detailed discussion of commodity prices, production, and operating expenses, refer to “Results of Operations” in this Item 2. For additional detail on the changes in operating assets and liabilities and the non-cash expenses that do not impact net cash provided by operating activities, refer to the Statement of Consolidated Cash Flows in the Consolidated Financial Statements set forth in Part I, Item 1, Financial Statements of this Quarterly Report on Form 10-Q.

Proceeds from Apache Credit Facility, Net During the first six months of 2020, Apache borrowed $565 million under its revolving credit facility.

Proceeds from Altus Credit Facility, Net The construction of Altus’ gathering and processing assets and the associated equity method pipelines has historically required capital expenditures in excess of Altus’ cash on hand and operational cash flows. During the first six months of 2021 and 2020, Altus Midstream LP borrowed $33 million and $97 million, respectively, under its revolving credit facility to meet this short fall. With the midstream infrastructure complete and all of the equity method interest pipelines now in service, the Company anticipates that Altus’ existing capital resources will be sufficient to fund its continuing obligations and dividend program during 2021.

Proceeds from Asset Divestitures The Company received $181 million and $126 million of proceeds from the divestiture of certain non-core assets during the first six months of 2021 and 2020, respectively. For more information regarding the Company’s acquisitions and divestitures, refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Uses of Cash and Cash Equivalents

Additions to Upstream Oil & Gas Property Exploration and development cash expenditures were $558 million and $838 million during the first six months of 2021 and 2020, respectively. The decrease in capital investment is reflective of the Company’s reduced capital program to align with anticipated operating cash flows. The Company operated an average of 10 drilling rigs during the second quarter of 2021, compared to an average of 12 drilling rigs during the second quarter of 2020.

Additions to Altus Gathering, Processing, and Transmission (GPT) Facilities The Company’s cash expenditures for GPT facilities totaled $1 million and $25 million during the first six months of 2021 and 2020, respectively, nearly all comprising midstream infrastructure expenditures incurred by Altus, which were substantially completed as of December 31, 2019. Altus management believes its existing GPT infrastructure capacity is capable of fulfilling its midstream contracts to service the Company’s production from Alpine High and any third-party customers. As such, Altus expects capital requirements for its existing infrastructure assets for the remainder of 2021 to be minimal.

Leasehold and Property Acquisitions The Company completed leasehold and property acquisitions for total cash consideration of $3 million during the first six months of 2021 and 2020.

Contributions to Altus Equity Method Interests Altus contributed $24 million and $154 million in cash during the first six months of 2021 and 2020, respectively, for equity interests in the equity method interest pipelines. For more information regarding the Company’s equity method interests, refer to Note 6—Equity Method Interests in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Payments on Apache Credit Facility Apache paid $150 million during the first six months of 2021 on its revolving credit facility borrowings.

Payments on Fixed-Rate Debt During the first six months of 2021, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $22 million for an aggregate purchase price of $20 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $2 million. The Company recognized a $1 million net gain on extinguishment of debt as part of these transactions.

During the second quarter of 2020, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $410 million for an aggregate purchase price of $267 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $147 million. These repurchases resulted in a $140 million net gain on extinguishment of debt, which is included in “Financing costs, net” in the Company’s statement of consolidated operations. The net gain includes an acceleration of related discount and debt issuance costs. The repurchases were financed by borrowings under Apache’s revolving credit facility.

The Company expects that Apache intends to reduce debt outstanding under its indentures from time to time.

Dividends The Company paid $19 million and $104 million during the first six months of 2021 and 2020, respectively, for dividends on its common stock. In the first quarter of 2020, the Company’s Board of Directors approved a reduction in the Company’s quarterly dividend per share from $0.25 per share to $0.025 per share, effective for all dividends payable after March 12, 2020.

Distributions to Noncontrolling Interest - Egypt Sinopec International Petroleum Exploration and Production Corporation (Sinopec) holds a one-third minority participation interest in the Company’s oil and gas operations in Egypt. The Company paid $60 million and $40 million during the first six months of 2021 and 2020, respectively, in cash distributions to Sinopec.

Distributions to Altus Preferred Units limited partners Altus Midstream LP paid $23 million during the first six months of 2021 in cash distributions to its limited partners holding Preferred Units. No cash distributions were made during the first six months of 2020. For more information regarding the Preferred Units, refer to Note 12—Redeemable Noncontrolling Interest - Altus in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q.

Liquidity

The following table presents a summary of the Company’s key financial indicators:

(In millions)

Cash and Cash Equivalents As of June 30, 2021, the Company had $1.2 billion in cash and cash equivalents, of which approximately $75 million was held by Altus. The majority of the Company’s cash is invested in highly liquid, investment-grade instruments with maturities of three months or less at the time of purchase.

Debt As of June 30, 2021, the Company had $8.6 billion in total debt outstanding, which consisted of notes, debentures, credit facility borrowings, and finance lease obligations. As of June 30, 2021, current debt included $213 million, net of discount, of 3.625% senior notes due April 15, 2022 and $2 million of finance lease obligations.

Committed Credit Facilities In March 2018, Apache entered into a revolving credit facility with commitments totaling $4.0 billion. In March 2019, the term of this facility was extended by one year to March 2024 (subject to Apache’s remaining one-year extension option) pursuant to Apache’s exercise of an extension option. Apache can increase commitments up to $5.0 billion by adding new lenders or obtaining the consent of any increasing existing lenders. The facility includes a letter of credit subfacility of up to $3.0 billion, of which $2.08 billion was committed as of June 30, 2021. The facility is for general corporate purposes. Letters of credit are available for security needs, including in respect of North Sea decommissioning obligations. The facility has no collateral requirements, is not subject to borrowing base redetermination, and has no drawdown restrictions or prepayment obligations in the event of a decline in credit ratings.

As of June 30, 2021, there were no borrowings and aggregate £561 million and $20 million in letters of credit outstanding under this facility. As of December 31, 2020, there were $150 million of borrowings and an aggregate £633 million and $40 million in letters of credit outstanding under this facility. The outstanding letters of credit denominated in pounds were issued to support North Sea decommissioning obligations, the terms of which required such support after Standard & Poor’s reduced Apache’s credit rating from BBB to BB+ on March 26, 2020.

In November 2018, Altus Midstream LP entered into a revolving credit facility for general corporate purposes that matures in November 2023 (subject to Altus Midstream LP’s two, one-year extension options). The agreement for this facility, as amended, provides aggregate commitments from a syndicate of banks of $800 million. All aggregate commitments include a letter of credit subfacility of up to $100 million and a swingline loan subfacility of up to $100 million. Altus Midstream LP may increase commitments up to an aggregate $1.5 billion by adding new lenders or obtaining the consent of any increasing existing lenders. As of June 30, 2021, there were $657 million of borrowings and a $2 million letter of credit outstanding under this facility. As of December 31, 2020, there were $624 million of borrowings and no letters of credit outstanding under this facility. The Altus Midstream LP credit facility is unsecured and is not guaranteed by APA or any of its subsidiaries, including Apache.

Apache and Altus Midstream LP were in compliance with the terms of their respective credit facilities as of June 30, 2021.

Uncommitted Credit Facilities Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of June 30, 2021 and December 31, 2020, there were no borrowings and £34 million and $17 million in letters of credit outstanding under these facilities.

Commercial Paper Program Apache has not used its commercial paper program during 2021 and terminated the program. As of June 30, 2021 and December 31, 2020, no commercial paper was outstanding.

Off-Balance Sheet Arrangements The Company enters into customary agreements in the oil and gas industry for drilling rig commitments, firm transportation agreements, and other obligations as described in “Contractual Obligations” in Part II, Item 7 of Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020. There have been no material changes to the contractual obligations described therein.

Potential Asset Retirement Obligations

The Company has potential exposure to future obligations related to divested properties. Apache has divested various leases, wells, and facilities located in the Gulf of Mexico (GOM) where the purchasers typically assume all obligations to plug, abandon, and decommission the associated wells, structures, and facilities acquired. 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 their solvency and ability to continue as a going concern. If a purchaser of the Company’s GOM assets becomes the subject of a case or proceeding under relevant insolvency laws or otherwise fails to perform required abandonment obligations, APA could be required to perform such actions under applicable federal laws and regulations. In such event, APA may be forced to use available cash to cover the costs of such liabilities and obligations should they arise.

In 2013, the Company sold its GOM Shelf operations and properties (Legacy GOM Assets) to Fieldwood Energy LLC (Fieldwood). Under the terms of the purchase agreement, the Company received cash consideration of $3.75 billion and Fieldwood assumed $1.5 billion of discounted asset abandonment liabilities as of the disposition date. In respect of such abandonment liabilities, Fieldwood posted letters of credit in favor of the Company (Letters of Credit) and established a trust account (Trust A), which is funded by a 10 percent net profits interest depending on future oil prices and of which the Company is the beneficiary. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which the Company agreed, inter alia, to accept bonds in exchange for certain of the Letters of Credit. Currently, the Company holds two bonds (Bonds) and the remaining Letters of Credit to secure Fieldwood’s asset retirement obligations (AROs) on the Legacy GOM Assets as and when such abandonment and decommissioning obligations are required to be performed over the remaining life of the Legacy GOM Assets.

On August 3, 2020, Fieldwood again filed for protection under Chapter 11 of the U.S. Bankruptcy Code. Fieldwood has submitted a plan of reorganization, and the Company has been engaged in discussions with Fieldwood and other interested parties regarding such plan. If approved by the bankruptcy court, the submitted plan would separate the Legacy GOM Assets into a standalone company, and proceeds of production of the Legacy GOM Assets will be used for the AROs. If the proceeds of production are insufficient for such AROs, then the Company expects that it may be required by the relevant governmental authorities to perform such AROs, in which case it will apply the Bonds, remaining Letters of Credit, and Trust A to pay for the AROs. In addition, after such sources have been exhausted, the Company has agreed to provide a standby loan of up to $400 million to perform decommissioning, with such standby loan secured by a first and prior lien on the Legacy GOM assets. If the foregoing is insufficient, the Company may be forced to use available cash to cover any additional costs it incurs for performing such AROs.

On June 25, 2021, the United States Bankruptcy Court for the Southern District of Texas (Houston Division) entered an order confirming Fieldwood’s bankruptcy plan.

Commodity Price Risk

The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices the Company receives for its crude oil, natural gas, and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather, political climate, and global supply and demand. These factors have only been heightened as the result of continuing negative demand implications of the COVID-19 pandemic became more apparent. The Company continually monitors its market risk exposure, including the impact and developments related to the COVID-19 pandemic, which introduced significant volatility in the financial markets subsequent to the year ended December 31, 2019.

The Company’s average crude oil realizations increased 158 percent from $25.77 per barrel to $66.40 per barrel during the second quarters of 2020 and 2021, respectively. The Company’s average natural gas price realizations increased 78 percent from $1.68 per Mcf to $2.99 per Mcf during the second quarters of 2020 and 2021, respectively. The Company’s average NGL realizations increased 179 percent from $8.28 per barrel to $23.10 per barrel during the second quarters of 2020 and 2021, respectively. Based on average daily production for the second quarter of 2021, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the quarter by approximately $17 million, a $0.10 per Mcf change in the weighted average realized natural gas price would have increased or decreased revenues for the quarter by approximately $8 million, and a $1.00 per barrel change in the weighted average realized NGL price would have increased or decreased revenues for the quarter by approximately $6 million.

The Company periodically enters into derivative positions on a portion of its projected oil and natural gas production through a variety of financial and physical arrangements intended to manage fluctuations in cash flows resulting from changes in commodity prices. Such derivative positions may include the use of futures contracts, swaps, and/or options. The Company does not hold or issue derivative instruments for trading purposes. As of June 30, 2021, the Company had open natural gas derivatives not designated as cash flow hedges in a liability position with a fair value of less than $1 million. A 10 percent increase in gas prices would increase the liability by approximately $3 million, while a 10 percent decrease in gas prices would move the derivatives to an asset position of $3 million. As of June 30, 2021, the Company had open oil derivatives not designated as cash flow hedges in a liability position with a fair value of $62 million. A 10 percent increase in oil prices would increase the liability by approximately $57 million, while a 10 percent decrease in oil prices would decrease the liability by approximately $57 million. These fair value changes assume volatility based on prevailing market parameters at June 30, 2021. Refer to Note 4—Derivative Instruments and Hedging Activities in the Notes to Consolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q for notional volumes and terms with the Company’s derivative contracts.

Interest Rate Risk

As of June 30, 2021, the Company had $8.0 billion, net, in outstanding notes and debentures, all of which was fixed-rate debt, with a weighted average interest rate of 4.98 percent. Although near-term changes in interest rates may affect the fair value of fixed-rate debt, such changes do not expose the Company to the risk of earnings or cash flow loss associated with that debt. The Company is also exposed to interest rate risk related to its interest-bearing cash and cash equivalents balances and amounts outstanding under the indentures and credit facilities. As of June 30, 2021, the Company had approximately $1.2 billion in cash and cash equivalents, approximately 72 percent of which was invested in money market funds and short-term investments with major financial institutions. As of June 30, 2021, Altus Midstream LP had outstanding borrowings of $657 million under its revolving credit facility. A change in the interest rate applicable to short-term investments and credit facility borrowings would have an immaterial impact on earnings and cash flows but could impact interest costs associated with future debt issuances or any future borrowings.

Foreign Currency Exchange Rate Risk

The Company’s cash activities relating to certain international operations is based on the U.S. dollar equivalent of cash flows measured in foreign currencies. The Company’s North Sea production is sold under U.S. dollar contracts, while the majority of costs incurred are paid in British pounds. The Company’s Egypt production is primarily sold under U.S. dollar contracts and the majority of costs incurred are denominated in U.S. dollars. Transactions denominated in British pounds are converted to U.S. dollar equivalents based on the average exchange rates during the period.

Foreign currency gains and losses also arise when monetary assets and monetary liabilities denominated in foreign currencies are translated at the end of each month. Foreign currency gains and losses are included as either a component of “Other” under “Revenues and Other” or, as is the case when the Company re-measures its foreign tax liabilities, as a component of the Company’s provision for income tax expense on the statement of consolidated operations. A foreign currency net gain or loss of $6 million would result from a 10 percent weakening or strengthening, respectively, in the British pound as of June 30, 2021.

The Company is subject to increased foreign currency risk associated with the effects of the U.K.’s withdrawal from the European Union. The Company has periodically entered into foreign exchange contracts in order to minimize the impact of fluctuating exchange rates for the British pound on the Company’s operating expenses. The Company had no outstanding foreign exchange derivative contracts as of June 30, 2021.

Disclosure Controls and Procedures

John J. Christmann IV, the Company’s Chief Executive Officer and President, in his capacity as principal executive officer, and Stephen J. Riney, the Company’s Executive Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of June 30, 2021, the end of the period covered by this report. Based on that evaluation and as of the date of that evaluation, these officers concluded that the Company’s disclosure controls and procedures were effective, providing effective means to ensure that the information the Company is required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the Commission’s rules and forms and accumulated and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

The Company periodically reviews the design and effectiveness of its disclosure controls, including compliance with various laws and regulations that apply to its operations, both inside and outside the United States. The Company makes modifications to improve the design and effectiveness of our disclosure controls, and may take other corrective action, if the Company’s reviews identify deficiencies or weaknesses in its controls.

Changes in Internal Control Over Financial Reporting

There were no changes in the Company’s internal controls over financial reporting that occurred during the quarter ended June 30, 2021 that have materially affected, or are reasonably likely to materially affect, the Company’s internal controls over financial reporting.

Refer to Part I, Item 1A—Risk Factors of Apache Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020 and Part II, Item 1A—Risk Factors of the Company’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2021.

Given the nature of their respective businesses, Apache Corporation and Altus Midstream Company may be subject to different or additional risks than those applicable to the Company. For a description of these risks, refer to the applicable disclosures in Apache Corporation’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2021 and June 30, 2021 and Altus Midstream Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2020 and Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2021 and June 30, 2021.