are an integral part of this statement.
These consolidated financial statements have been prepared by Apache Corporation (Apache or the Company) without audit, pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). The Company files these consolidated financial statements with the SEC as a voluntary filer to comply with the terms of certain of the Company’s outstanding debt instruments. They reflect all adjustments that are, in the opinion of management, necessary for a fair presentation of the results for the interim periods, on a basis consistent with the annual audited financial statements.statements, with the exception of any recently adopted accounting pronouncements. All such adjustments are of a normal recurring nature. Certain information, accounting policies, and footnote disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP)(GAAP) have been condensed or omitted pursuant to such rules and regulations, although the Company believes that the disclosures are adequate to make the information presented not misleading. This Quarterly Report on Form 10-Q should be read along with Apache’sthe Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016,2022, which contains a summary of the Company’s significant accounting policies and other disclosures.
Certain assets and liabilities are reported at fair value on a recurring basis in Apache’sthe Company’s consolidated balance sheet. Accounting Standards Codification (ASC) 820-10-35, “Fair Value Measurement” (ASC 820), provides a hierarchy that prioritizes and defines the types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from inputs that are significant and unobservable; hence, these valuations have the lowest priority.
The valuation techniques that may be used to measure fair value include a market approach, an income approach, and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models, and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).
The Company follows the successful efforts method of accounting for its oil and gas property. Under this method of accounting, exploration costs, such as exploratory geological and geophysical costs, delay rentals, and exploration overhead, are expensed as incurred. All costs related to production, general corporate overhead, and similar activities are expensed as incurred. If an exploratory well provides evidence to justify potential development of reserves, drilling costs associated with the well are initially capitalized, or suspended, pending a determination as to whether a commercially sufficient quantity of proved reserves can be attributed to the area as a result of drilling. This determination may take longer than one year in certain areas depending on, among other things, the amount of hydrocarbons discovered, the outcome of planned geological and engineering studies, the need for additional appraisal drilling activities to determine whether the discovery is sufficient to support an economic development plan, and government sanctioning of development activities in certain international locations. At the end of each quarter, management reviews the status of all suspended exploratory well costs in light of ongoing exploration activities; in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts or, in the case of discoveries requiring government sanctioning, whether development negotiations are underway and proceeding as planned. If management determines that future appraisal drilling or development activities are unlikely to occur, associated suspended exploratory well costs are expensed.
Acquisition costs of unproved properties are assessed for impairment at least annually and are transferred to proved oil and gas properties to the extent the costs are associated with successful exploration activities. Significant undeveloped leases are assessed individually for impairment based on the Company’s current exploration plans. Unproved oil and gas properties with individually insignificant lease acquisition costs are amortized on a group basis over the average lease term at rates that provide for full amortization of unsuccessful leases upon lease expiration or abandonment. Costs of expired or abandoned leases are charged to exploration expense, while costs of productive leases are transferred to proved oil and gas properties. Costs of maintaining and retaining unproved properties, as well as amortization of individually insignificant leases and impairment of unsuccessful leases, are included in exploration costs in the statement of consolidated operations.
Costs to develop proved reserves, including the costs of all development wells and related equipment used in the production of crude oil and natural gas, are capitalized. Depreciation of the cost of proved oil and gas properties is calculated using the unit-of-production (UOP) method. The UOP calculation multiplies the percentage of estimated proved reserves produced each quarter by the carrying value of those reserves.associated proved oil and gas properties. The reserve base used to calculate depreciation for leasehold acquisition costs and the cost to acquire proved properties is the sum of proved developed reserves and proved undeveloped reserves. The reserve base used to calculate the depreciation for capitalized costs of exploratory wells and developmentwell costs is the sum of proved developed reserves only. Estimated future dismantlement, restoration and abandonment costs, net of salvage values, are included in the depreciable cost.
Oil and gas properties are grouped for depreciation in accordance with ASC 932, “Extractive Activities - Activities—Oil and Gas.” The basis for grouping is a reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field.
2016 Activity
Leasehold and Property Acquisitions
During the thirdfirst quarter and first nine months of 2016, Apache purchased $51 million and $169 million, respectively, of leasehold and property acquisitions primarily in its North America onshore regions and Egypt.
Discontinued Operations
Apache sold its operations in Argentina and Australia in 2014 and 2015, respectively. The results of operations related to the Argentina and Australia dispositions and the losses on disposals were classified as discontinued operations in the Company’s financial statements. During 2016,2023, the Company incurred additional losses oncompleted the sale of non-core assets and leasehold in multiple transactions for total cash proceeds of $21 million, recognizing a gain of approximately $1 million upon closing of these dispositions. The components of the Company’s loss from discontinued operations were as follows:transactions.
|
| | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (In millions) |
Loss from Australia divestiture | | $ | — |
| | $ | (23 | ) | | $ | — |
| | $ | (23 | ) |
Loss from Argentina divestiture | | — |
| | (10 | ) | | — |
| | (10 | ) |
Loss from discontinued operations, net of tax | | $ | — |
| | $ | (33 | ) | | $ | — |
| | $ | (33 | ) |
Transaction, Reorganization, and Separation2022 Activity
During the thirdfirst quarter of 2022, the Company completed a transaction to sell certain non-core mineral rights in the Delaware Basin. The Company received total cash proceeds of approximately $726 million after certain post-closing adjustments and recognized an associated gain of approximately $560 million. The Company also completed the sale of other non-core assets and leasehold in multiple transactions for total cash proceeds of $8 million. The Company recognized a gain of approximately $2 million upon closing of these transactions during the first nine monthsquarter of 2017,2022.
The BCP Business Combination was completed on February 22, 2022. As consideration for the contribution of the Contributed Interests, ALTM issued 50 million shares of Class C Common Stock (and Altus Midstream LP issued a corresponding number of common units) to BCP’s unitholders, which are principally funds affiliated with Blackstone and I Squared Capital. ALTM’s stockholders continued to hold their existing shares of common stock. As a result of the transaction, the Contributor, or its designees, collectively owned approximately 75 percent of the issued and outstanding shares of ALTM common stock. Apache recorded $20Midstream LLC, a wholly owned subsidiary of APA, which owned approximately 79 percent of the issued and outstanding shares of ALTM common stock prior to the BCP Business Combination, owned approximately 20 percent of the issued and outstanding shares of Kinetik common stock after the transaction closed.
As a result of the BCP Business Combination, the Company deconsolidated ALTM on February 22, 2022 and recognized a gain of approximately $609 million that reflects the difference between the Company’s share of ALTM’s deconsolidated balance sheet of $193 million and $14the fair value of $802 million respectively, in expense related to asset divestituresof its approximate 20 percent retained ownership in the U.S. and Canada and employee separation. combined entity.
During the thirdfirst quarter and first nine months of 2016, Apache recorded $122022, the Company sold four million of its shares of Kinetik Class A Common Stock for cash proceeds of $224 million and $36recognized a loss of $25 million, respectively, in expense relatedincluding transaction fees. Refer to various asset divestitures, company reorganization, and employee separation.Note 7—Equity Method Interests for further detail.
3. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Objectives and Strategies
The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production. Apache manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production. The Company utilizes various types of derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company’s derivatives are not designated as cash flow hedges, therefore, changes in fair value are recognized currently in earnings.
Counterparty Risk
The use of derivative instruments exposes the Company to credit loss in the event of nonperformance by the counterparty. To reduce the concentration of exposure to any individual counterparty, Apache utilizes a diversified group of investment-grade rated counterparties, primarily financial institutions, for its derivative transactions. As of September 30, 2017, Apache had derivative positions with 14 counterparties. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, Apache may not realize the benefit of some of its derivative instruments resulting from lower commodity prices.
Derivative Instruments
As of September 30, 2017, Apache had the following open crude oil derivative positions:
|
| | | | | | |
| | | | Put Options(1)(2) |
Production Period | | Settlement Index | | Mbbls | | Weighted Average Strike Price |
October—December 2017 | | NYMEX WTI | | 8,464 | | $50.00 |
October—December 2017 | | Dated Brent | | 7,636 | | $51.00 |
| |
(1) | The remaining unamortized premium paid as of September 30, 2017, was $50 million. |
| |
(2) | Subsequent to September 30, 2017, Apache entered into put option contracts settling against Dated Brent totaling 3,650 Mbbls with a strike price of $50 for the calendar year 2018. |
|
| | | | | | | | | | | | | | | | |
| | | | Fixed-Price Swaps | | Collars(3) | | Call Options(4) |
Production Period | | Settlement Index | | Mbbls | | Weighted Average Fixed Price | | Mbbls | | Weighted Average Floor Price | | Weighted Average Ceiling Price | | Mbbls | | Strike Price |
January—June 2018 | | NYMEX WTI | | 2,715 | | $51.23 | | 2,715 | | $45.00 | | $56.45 | | — | | — |
January—June 2018 | | Dated Brent | | 2,172 | | $54.57 | | 2,172 | | $50.00 | | $58.77 | | — | | — |
January—December 2018 | | NYMEX WTI | | — | | — | | 6,023 | | $45.00 | | $57.02 | | 6,023 | | $60.00 |
| |
(3) | Subsequent to September 30, 2017, Apache entered into crude oil contracts settling against NYMEX WTI totaling 730 Mbbls with a floor and ceiling of $45.00 and $56.90, respectively, for the calendar year 2018. |
| |
(4) | The remaining unamortized premium paid as of September 30, 2017, was $9 million. |
As of September 30, 2017, Apache had the following open natural gas derivative positions:
|
| | | | | | |
| | | | Fixed-Price Swaps(1) |
Production Period | | Settlement Index | | MMBtu (in 000’s) | | Weighted Average Fixed Price |
October—December 2017 | | NYMEX Henry Hub | | 4,370 | | $3.32 |
January—March 2018 | | NYMEX Henry Hub | | 13,500 | | $3.39 |
January—June 2018 | | NYMEX Henry Hub | | 22,625 | | $3.17 |
April—June 2018 | | NYMEX Henry Hub | | 16,835 | | $2.92 |
July—December 2018 | | NYMEX Henry Hub | | 18,400 | | $2.97 |
| |
(1) | Subsequent to September 30, 2017, Apache entered into fixed-price natural gas swaps settling against NYMEX Henry Hub totaling 15,180,000 MMBtu with a weighted average fixed-price of $2.95 for the second half of 2018. |
As of September 30, 2017, Apache had the following open natural gas financial basis swap contracts:
|
| | | | | | |
Production Period | | Settlement Index | | MMBtu (in 000’s) | | Weighted Average Price Differential |
January—March 2018 | | NYMEX Henry Hub/Waha | | 9,450 | | $(0.43) |
July—December 2018 | | NYMEX Henry Hub/Waha | | 33,120 | | $(0.53) |
October—December 2018 | | NYMEX Henry Hub/Waha | | 1,380 | | $(0.51) |
January—March 2019 | | NYMEX Henry Hub/Waha | | 1,350 | | $(0.54) |
January—June 2019 | | NYMEX Henry Hub/Waha | | 32,580 | | $(0.53) |
January—December 2019 | | NYMEX Henry Hub/Waha | | 14,600 | | $(0.45) |
Fair Value Measurements
Apache’s commodity derivative instruments consist of variable-to-fixed price commodity swaps, options, and collars. The fair values of the Company’s derivatives are not actively quoted in the open market. The Company uses a market approach to estimate the fair values of its derivative instruments on a recurring basis, utilizing commodity futures pricing for the underlying commodities provided by a reputable third party, a Level 2 fair value measurement.
The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis: |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Fair Value Measurements Using | | | | | | |
| | Quoted Price in Active Markets (Level 1) | | Significant Other Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | | Total Fair Value | | Netting(1) | | Carrying Amount |
| | (In millions) |
September 30, 2017 | | | | | | | | | | | | |
Assets: | | | | | | | | | | | | |
Commodity Derivative Instruments | | $ | — |
| | $ | 24 |
| | $ | — |
| | $ | 24 |
| | $ | (7 | ) | | $ | 17 |
|
Liabilities: | | | | | | | | | | | | |
Commodity Derivative Instruments | | — |
| | 7 |
| | — |
| | 7 |
| | (7 | ) | | — |
|
December 31, 2016 | | | | | | | | | | | | |
Assets: | | | | | | | | | | | | |
Commodity Derivative Instruments | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Liabilities: | | | | | | | | | | | | |
Commodity Derivative Instruments | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| |
(1) | The derivative fair values are based on analysis of each contract on a gross basis, excluding the impact of netting agreements with counterparties. |
All derivative instruments are reflected as either assets or liabilities at fair value in the consolidated balance sheet. These fair values are recorded by netting asset and liability positions where counterparty master netting arrangements contain provisions for net settlement. The carrying value of the Company’s derivative assets and liabilities and their locations on the consolidated balance sheet are as follows:
|
| | | | | | | | |
| | September 30, 2017 | | December 31, 2016 |
| | (In millions) |
Current Assets: Prepaid assets and other | | $ | 13 |
| | $ | — |
|
Other Assets: Deferred charges and other | | 4 |
| | — |
|
Total Assets | | $ | 17 |
| | $ | — |
|
Derivative Activity Recorded in the Statement of Consolidated Operations
The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations:
|
| | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (In millions) |
Realized gain (loss): | | | | | | | | |
Derivative settlements, realized gain | | $ | 23 |
| | $ | — |
| | $ | 23 |
| | $ | — |
|
Amortization of put premium, realized loss | | (50 | ) | | — |
| | (50 | ) | | — |
|
Unrealized loss | | (83 | ) | | — |
| | (42 | ) | | — |
|
Derivative instrument losses, net | | $ | (110 | ) | | $ | — |
| | $ | (69 | ) | | $ | — |
|
Unrealized gains and losses for derivative activity recorded in the statement of consolidated operations is reflected in the statement of consolidated cash flows separately as a component of “Unrealized derivative instrument losses, net” in “Adjustments to reconcile net income (loss) to net cash provided by operating activities.”
4. CAPITALIZED EXPLORATORY WELL COSTS
The Company’s capitalized exploratory well costs were $369$74 million and $264$50 million at September 30, 2017as of March 31, 2023 and December 31, 2016,2022, respectively. The increase is primarily attributable to additional drilling activitiesactivity in the U.S. during the period,Egypt, partially offset by successful transfers and dry hole write-offs. Notransfer of well costs during the quarter. Approximately $5 million of suspended exploratory well costs previously capitalized for greater than one year at December 31, 20162022 were charged to dry hole expense during the ninethree months ended September 30, 2017. March 31, 2023.
Projects with suspended exploratory well costs capitalized for a period greater than one year since the completion of drilling are those identified by management as exhibiting sufficient quantities of hydrocarbons to justify potential development. Management is actively pursuing efforts to assess whether proved reserves can be attributed to these projects.
| |
5. | OTHER CURRENT LIABILITIES |
5. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Objectives and Strategies
The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of its worldwide production, as well as fluctuations in exchange rates in connection with transactions denominated in foreign currencies. The Company manages the variability in its cash flows by occasionally entering into derivative transactions on a portion of its crude oil and natural gas production and foreign currency transactions. The Company may utilize various types of derivative financial instruments, including forward contracts, futures contracts, swaps, and options, to manage fluctuations in cash flows resulting from changes in commodity prices or foreign currency values.
In December 2022, counterparty agreements for Apache’s commodity derivative instruments were transferred from Apache to APA Corporation. Apache had no outstanding derivative positions as of March 31, 2023 or December 31, 2022.
Derivative Activity Recorded in the Statement of Consolidated Operations
The following table summarizes the effect of derivative instruments on the Company’s statement of consolidated operations:
| | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended March 31, | | |
| 2023 | | 2022 | | | | |
| | | | | | | | |
| | (In millions) |
Realized: | | | | | | | | |
Commodity derivative instruments | | $ | — | | | $ | (5) | | | | | |
| | | | | | | | |
Realized losses, net | | — | | | (5) | | | | | |
Unrealized: | | | | | | | | |
Commodity derivative instruments | | — | | | (24) | | | | | |
| | | | | | | | |
Foreign currency derivative instruments | | — | | | (2) | | | | | |
Preferred Units embedded derivative | | — | | | (31) | | | | | |
Unrealized losses, net | | — | | | (57) | | | | | |
Derivative instrument losses, net | | $ | — | | | $ | (62) | | | | | |
Derivative instrument gains and losses were recorded in “Derivative instrument losses, net” under “Revenues and Other” in the Company’s statement of consolidated operations. Unrealized losses for derivative activity recorded in the statement of consolidated operations are reflected in the statement of consolidated cash flows separately as “Unrealized derivative instrument losses, net” under “Adjustments to reconcile net income to net cash provided by operating activities.”
6. OTHER CURRENT ASSETS
The following table provides detail of the Company’s other current liabilitiesassets:
| | | | | | | | | | | | | | |
| | March 31, 2023 | | December 31, 2022 |
| | | | |
| | (In millions) |
Inventories | | $ | 487 | | | $ | 425 | |
Drilling advances | | 64 | | | 64 | |
| | | | |
Prepaid assets and other | | 89 | | | 54 | |
Current decommissioning security for sold Gulf of Mexico assets | | 450 | | | 450 | |
Total Other current assets | | $ | 1,090 | | | $ | 993 | |
7. EQUITY METHOD INTERESTS
The Kinetik Class A Common Stock held by the Company is treated as an interest in equity securities measured at fair value. The Company elected the fair value option for measuring its equity method interest in Kinetik based on practical expedience, variances in reporting timelines, and cost-benefit considerations. The fair value of the Company’s interest in Kinetik is determined using observable share prices on a major exchange, a Level 1 fair value measurement. Fair value adjustments and dividends received are recorded as a component of “Other, net” under “Revenues and other” in the Company’s statement of consolidated operations.
The Company’s initial interest in Kinetik was measured at fair value based on the Company’s ownership of approximately 12.9 million shares of Kinetik Class A Common stock as of September 30, 2017February 22, 2022. In March 2022, the Company sold four million of its shares of Kinetik Class A Common Stock for a loss, including underwriters fees, of $25 million, which was recorded as a component of “Gain on divestitures, net” under “Revenues and Decemberother” in the Company’s statement of consolidated operations. Refer to Note 3—Acquisitions and Divestitures for further detail. During the second quarter of 2022, Kinetik issued a two-for-one split of its common stock. As of March 31, 2016:2023, the Company’s ownership of 19.3 million shares represented approximately 13 percent of Kinetik’s outstanding Class A Common Stock.
During the first quarters of 2023 and 2022, the Company recorded changes in the fair value of its equity method interest in Kinetik totaling a loss of $19 million and a gain of $24 million, respectively, which were recorded as a component of “Revenues and other” in the Company’s statement of consolidated operations.
During the first quarters of 2023 and 2022, the Company recorded GPT costs for midstream services provided by Kinetik subsequent to the close of the BCP Business Combination transaction totaling $24 million and $10 million, respectively. As of March 31, 2023, the Company has recorded accrued GPT costs payable to Kinetik of approximately $17 million. In addition, the Company sold natural gas and NGLs to Kinetik during the first quarter of 2023 totaling $7 million. As of March 31, 2023, the Company has recorded receivables from Kinetik of approximately $4 million.
|
| | | | | | | | |
| | September 30, 2017 | | December 31, 2016 |
| | (In millions) |
Accrued operating expenses | | $ | 73 |
| | $ | 110 |
|
Accrued exploration and development | | 691 |
| | 463 |
|
Accrued compensation and benefits | | 99 |
| | 201 |
|
Accrued interest | | 108 |
| | 145 |
|
Accrued income taxes | | 68 |
| | 22 |
|
Current asset retirement obligation | | 35 |
| | 66 |
|
Refundable deposits | | 149 |
| | 174 |
|
Other | | 109 |
| | 77 |
|
Total other current liabilities | | $ | 1,332 |
| | $ | 1,258 |
|
8. OTHER CURRENT LIABILITIES | |
6. | ASSET RETIREMENT OBLIGATION |
The following table provides detail of the Company’s other current liabilities:
| | | | | | | | | | | | | | |
| | March 31, 2023 | | December 31, 2022 |
| | | | |
| | (In millions) |
Accrued operating expenses | | $ | 151 | | | $ | 139 | |
Accrued exploration and development | | 324 | | | 300 | |
Accrued compensation and benefits | | 216 | | | 514 | |
Accrued interest | | 66 | | | 96 | |
Accrued income taxes | | 136 | | | 90 | |
Current asset retirement obligation | | 55 | | | 55 | |
Current operating lease liability | | 142 | | | 167 | |
| | | | |
Current decommissioning contingency for sold Gulf of Mexico properties | | 433 | | | 450 | |
Other | | 209 | | | 238 | |
Total Other current liabilities | | $ | 1,732 | | | $ | 2,049 | |
9. ASSET RETIREMENT OBLIGATION
The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the nine-month period ended September 30, 2017:liability:
|
| | | | |
| | (In millions) |
Asset retirement obligation at December 31, 2016 | | $ | 2,498 |
|
Liabilities incurred | | 39 |
|
Liabilities divested | | (810 | ) |
Liabilities settled | | (30 | ) |
Accretion expense | | 103 |
|
Revisions in estimated liabilities | | 66 |
|
Asset retirement obligation at September 30, 2017 | | 1,866 |
|
Less current portion | | 35 |
|
Asset retirement obligation, long-term | | $ | 1,831 |
|
| | | | | | | | |
7. | INCOME TAXES | March 31, 2023 |
| | (In millions) |
Asset retirement obligation, December 31, 2022 | | $ | 1,991 | |
Liabilities incurred | | 5 | |
Liabilities settled | | (10) | |
| | |
| | |
| | |
Accretion expense | | 28 | |
| | |
Asset retirement obligation, March 31, 2023 | | 2,014 | |
Less current portion | | (55) | |
Asset retirement obligation, long-term | | $ | 1,959 | |
10. DEBT AND FINANCING COSTS
The following table presents the carrying values of the Company’s debt:
| | | | | | | | | | | | | | |
| | March 31, 2023 | | December 31, 2022 |
| | | | |
| | (In millions) |
Notes and debentures before unamortized discount and debt issuance costs(1) | | $ | 4,835 | | | $ | 4,908 | |
Syndicated credit facilities(2) | | 105 | | | — | |
Finance lease obligations | | 34 | | | 34 | |
Unamortized discount | | (27) | | | (27) | |
Debt issuance costs | | (27) | | | (28) | |
Total debt | | 4,920 | | | 4,887 | |
Current maturities | | (2) | | | (2) | |
Long-term debt | | $ | 4,918 | | | $ | 4,885 | |
(1) The fair values of the Company’s notes and debentures were $4.2 billion at each of March 31, 2023 and December 31, 2022.
Apache uses a market approach to determine the fair values of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).
(2) The carrying value of borrowings on credit facilities approximates fair value because interest rates are variable and reflective of market rates.
At each of March 31, 2023 and December 31, 2022, current debt included $2 million of finance lease obligations.
During the quarter ended March 31, 2023, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $74 million for an aggregate purchase price of $65 million in cash, including accrued interest and broker fees, reflecting a discount to par of an aggregate $10 million. The Company recognized a $9 million gain on these repurchases. The repurchases were partially financed by Apache’s borrowing under the US dollar-denominated revolving credit facility of APA Corporation described below.
During the quarter ended March 31, 2022, Apache closed cash tender offers for certain outstanding notes issued under its indentures, accepting for purchase $1.1 billion aggregate principal amount of notes. Apache paid holders an aggregate $1.2 billion in cash, reflecting principal, premium to par, and accrued and unpaid interest. The Company recognized a $66 million loss on extinguishment of debt, including $11 million of unamortized debt discount and issuance costs in connection with the note purchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.
During the quarter ended March 31, 2022, Apache purchased in the open market and canceled senior notes issued under its indentures in an aggregate principal amount of $15 million for an aggregate purchase price of $16 million in cash, including accrued interest and broker fees, reflecting a premium to par of $1 million. The Company recognized a $1 million loss on these repurchases. The repurchases were partially financed by borrowing under Apache’s former revolving credit facility.
On January 18, 2022, Apache redeemed the outstanding $213 million principal amount of 3.25% senior notes due April 15, 2022, at a redemption price equal to 100 percent of their principal amount, plus accrued and unpaid interest to the redemption date. The redemption was financed by borrowing under Apache’s former revolving credit facility.
Apache intends to reduce debt outstanding under its indentures from time to time.
On April 29, 2022, Apache entered into two unsecured guaranties of obligations under two unsecured syndicated credit agreements then entered into by APA, of which Apache is a wholly owned subsidiary. APA’s new credit agreements are for general corporate purposes and replaced and refinanced Apache’s 2018 unsecured syndicated credit agreement (the Former Facility).
•One credit agreement is denominated in US dollars (the USD Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of US$1.8 billion (including a letter of credit subfacility of up to US$750 million, of which US$150 million currently is committed). APA may increase commitments up to an aggregate US$2.3 billion by adding new lenders or obtaining the consent of any increasing existing lenders. This facility matures in April 2027, subject to APA’s two, one-year extension options.
•The second credit agreement is denominated in pounds sterling (the GBP Agreement) and provides for an unsecured five-year revolving credit facility, with aggregate commitments of £1.5 billion for loans and letters of credit. This facility matures in April 2027, subject to APA’s two, one-year extension options.
In connection with APA’s entry into the USD Agreement and the GBP Agreement (each, a New Agreement), Apache terminated US$4.0 billion of commitments under the Former Facility, borrowings then outstanding under the Former Facility were deemed outstanding under APA’s USD Agreement, and letters of credit then outstanding under the Former Facility were deemed outstanding under a New Agreement, depending upon whether denominated in US dollars or pounds sterling. Apache has guaranteed obligations under each New Agreement effective until the aggregate principal amount of indebtedness under senior notes and debentures outstanding under Apache’s existing indentures is less than US$1.0 billion.
Apache may borrow under APA’s USD Agreement up to an aggregate principal amount of US$300 million outstanding at any given time. As of March 31, 2023, there were $105 million of borrowings by Apache outstanding under the USD Agreement. As of December 31, 2022, there were no borrowings by Apache outstanding under the USD Agreement.
Apache, from time to time, has and uses uncommitted credit and letter of credit facilities for working capital and credit support purposes. As of March 31, 2023 and December 31, 2022, there were no outstanding borrowings under these facilities. As of March 31, 2023, there were £261 million and $17 million in letters of credit outstanding under these facilities. As of December 31, 2022, there were £199 million and $17 million in letters of credit outstanding under these facilities.
Financing Costs, Net
The following table presents the components of the Company’s financing costs, net:
| | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | | | | | | | |
| | (In millions) |
Interest expense | | $ | 75 | | | $ | 90 | | | | | |
Amortization of debt issuance costs | | 1 | | | 2 | | | | | |
| | | | | | | | |
(Gain) loss on extinguishment of debt | | (9) | | | 67 | | | | | |
Interest income | | (2) | | | (4) | | | | | |
Interest income from APA Corporation, net | | (16) | | | (15) | | | | | |
Financing costs, net | | $ | 49 | | | $ | 140 | | | | | |
11. INCOME TAXES
The Company estimates its annual effective income tax rate for continuing operations in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments ofon 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.
In August 2017, Apache completedDuring the sale of ACL. For more information regarding this transaction, please refer to Note 2—Acquisitions and Divestitures. As a result of this transaction, Apache recorded a deferred tax asset associated with its realizable capital loss on the sale of ACL, and a decrease in the Company’s deferred tax liability associated with its investment in foreign subsidiaries. In the third and second quarters of 2017, the Company recorded a $2 million deferred income tax expense and a $674 million deferred income tax benefit, respectively, in connection with these transactions.
Apache’s thirdfirst quarter of 20172023, the Company’s effective income tax rate was primarily impacted by gains on the sale of oil and gas properties and a $30 million current tax benefit associated with U.S. federal income tax credits. On September 15, 2016, U.K. Finance Act 2016 received Royal Assent. Under the enacted legislation, the corporate income tax rate on North Sea oil and gas profits was reduced from 50 percent to 40 percent effective January 1, 2016. As a result of the enacted legislation, in the third quarter of 2016 the Company recorded a deferred tax benefit of $235 millionexpense related to the remeasurement of taxes in the Company’s December 31, 2015 U.K. deferred income tax liability.
Apache’s 2017 year-to-date effective income tax rate is primarily impacted byas a result of the enactment of Finance Act 2023 on January 10, 2023, and a decrease in the amount of valuation allowance against its U.S. deferred taxes associated with its investments in foreign subsidiaries, gains ontax assets. During the salefirst quarter of oil and gas properties, non-cash impairments of2022, the Company’s PRT decommissioning asset, and the current tax benefit associated with U.S. federal income tax credits. Apache’s 2016 year-to-date effective income tax rate was primarily impacted by non-cash impairmentsthe gain associated with deconsolidation of Altus, the carrying valuegain on sale of certain non-core mineral rights in the Company’s oilDelaware Basin, and gas properties, non-cash impairments of the Company’s PRT decommissioning asset, the impact of the change in U.K. statutory income tax rate, and an increasea decrease in the amount of valuation allowances onallowance against its U.S. and Canadian deferred tax assets.
ApacheOn January 10, 2023, Finance Act 2023 was enacted, receiving Royal Assent, and included amendments to the Energy (Oil and Gas) Profits Levy Act of 2022, increasing the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. Therefore, in the first quarter of 2023, the Company recorded a deferred tax expense of $174 million related to the remeasurement of the December 31, 2022 U.K. deferred tax liability.
On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (Corporate AMT) on applicable corporations with an average annual financial statement income that exceeds $1 billion for any three consecutive years preceding the tax year at issue. The Corporate AMT is effective for tax years beginning after December 31, 2022. The Company is continuing to evaluate the provisions of the IRA and awaits further guidance from the U.S. Treasury Department to properly assess the impact of these provisions on the Company. Under the existing guidance, the Company does not believe the IRA will have a material impact for 2023.
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. However, given the Company’s current and anticipated future domestic earnings, the Company believes that there is a reasonable possibility that within the next 12 months sufficient positive evidence may become available to allow the Company to reach a conclusion that a significant portion of the U.S. valuation allowance will no longer be needed. A release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense, which could be material, for the period the release is recorded.
The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various statestates and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. In April 2017, the Internal Revenue Service (IRS) began their audit of the Company’s 2014 income tax year. The Company is also under audit in various states and in most of the Company’s foreign jurisdictions as part of its normal course of business.
| |
8. | DEBT AND FINANCING COSTS |
The following table presents the carrying amounts and estimated fair values of the Company’s outstanding debt as of September 30, 2017 and December 31, 2016:
|
| | | | | | | | | | | | | | | | |
| | September 30, 2017 | | December 31, 2016 |
| | Carrying Amount | | Fair Value | | Carrying Amount | | Fair Value |
| | (In millions) |
Commercial paper and committed bank facilities | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Notes and debentures | | 8,483 |
| | 9,094 |
| | 8,544 |
| | 9,183 |
|
Total Debt | | $ | 8,483 |
| | $ | 9,094 |
| | $ | 8,544 |
| | $ | 9,183 |
|
The Company’s debt is recorded at the carrying amount, net of related unamortized discount and debt issuance costs, on its consolidated balance sheet. When recorded, the carrying amount of the Company’s commercial paper, committed bank facilities, and uncommitted bank lines approximates fair value because the interest rates are variable and reflective of market rates. Apache uses a market approach to determine the fair value of its notes and debentures using estimates provided by an independent investment financial data services firm (a Level 2 fair value measurement).
The following table presents the carrying value of the Company’s debt as of September 30, 2017 and December 31, 2016:
|
| | | | | | | | |
| | September 30, 2017 | | December 31, 2016 |
| | (In millions) |
Debt before unamortized discount and debt issuance costs | | $ | 8,580 |
| | $ | 8,650 |
|
Unamortized discount | | (48 | ) | | (50 | ) |
Debt issuance costs | | (49 | ) | | (56 | ) |
Total debt | | 8,483 |
| | 8,544 |
|
Current maturities | | (550 | ) | | — |
|
Long-term debt | | $ | 7,933 |
| | $ | 8,544 |
|
12. COMMITMENTS AND CONTINGENCIES
As of September 30, 2017, current debt included $150 million of 7.0% senior notes due February 1, 2018 and $400 million of 6.9% senior notes due September 15, 2018.
As of September 30, 2017, the Company had a revolving credit facility that matures in June 2020, subject to Apache’s two one-year extension options. The facility provides for aggregate commitments of $3.5 billion (including a $750 million letter of credit subfacility), with rights to increase commitments up to an aggregate $4.5 billion. Proceeds from borrowings may be used for general corporate purposes. Apache’s available borrowing capacity under this facility supports its $3.5 billion commercial paper program. The commercial paper program, which is subject to market availability, facilitates Apache borrowing funds for up to 270 days at competitive interest rates. As of September 30, 2017, the Company had no commercial paper or borrowings under committed bank facilities or uncommitted bank lines outstanding.
As of September 30, 2017, the Company had a letter of credit facility, which provides for £900 million in commitments and rights to increase commitments to £1.075 billion. This facility matures in February 2020. The facility is available for letters of credit and loans to cash collateralize letters of credit or obligations to provide letters of credit, in each case, to the extent letters of credit are unavailable under the facility. As of September 30, 2017, three letters of credit aggregating approximately £147.5 million and no borrowings were outstanding under this facility.
In November 2016, the Company initiated a program to purchase in the open market up to $250 million in aggregate principal amount of senior notes issued under its indentures. In the fourth quarter of 2016, the Company purchased and canceled $181 million aggregate principal amount of its senior notes through open market repurchases for $182 million in cash, including accrued interest and $0.5 million of premium.
In January 2017, the Company purchased and canceled an additional $69 million aggregate principal amount of senior notes for $71 million in cash, including accrued interest and $1 million of premium, which completed the open market repurchase program. These repurchases resulted in a $1 million net loss on extinguishment of debt, which is included in “Financing costs, net” in the Company’s consolidated statement of operations. The net loss includes an acceleration of related discount and deferred financing costs.
In August 2017, the Company assumed the obligations of Apache Finance Canada Corporation (AFCC) in respect of $300 million 7.75% notes due in 2029 which AFCC issued and the Company guaranteed pursuant to the governing indenture. The assumption was permitted by the indenture and effected pursuant to a supplemental indenture thereto. As a result of the assumption, the Company is the obligor under the notes and indenture, and AFCC is released from its obligations thereunder. The $300 million 7.75% notes historically have been included in the Company’s long-term debt; accordingly, the assumption did not change the Company’s long-term debt or total debt.
Financing Costs, Net
The following table presents the components of Apache’s financing costs, net:
|
| | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (In millions) |
Interest expense | | $ | 113 |
| | $ | 116 |
| | $ | 344 |
| | $ | 348 |
|
Amortization of deferred loan costs | | 3 |
| | 2 |
| | 7 |
| | 5 |
|
Capitalized interest | | (12 | ) | | (13 | ) | | (39 | ) | | (36 | ) |
Loss on extinguishment of debt | | — |
| | — |
| | 1 |
| | — |
|
Interest income | | (3 | ) | | (3 | ) | | (13 | ) | | (6 | ) |
Financing costs, net | | $ | 101 |
| | $ | 102 |
| | $ | 300 |
| | $ | 311 |
|
| |
9. | COMMITMENTS AND CONTINGENCIES |
Legal Matters
ApacheThe Company is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls.controls, which also may include controls related to the potential impacts of climate change. As of September 30, 2017,March 31, 2023, the Company has an accrued liability of approximately $37$64 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. Apache’sThe Company’s estimates are based on information known about the matters and its experience in contesting, litigating, and settling similar matters. Although actual amounts could differ from management’s estimate, none of the actions are believed by management to involve future amounts that would be material to Apache’sthe Company’s financial position, results of operations, or liquidity after consideration of recorded accruals. For material matters that Apachethe Company believes an unfavorable outcome is reasonably possible, the Company has disclosed the nature of the matter and a range of potential exposure, unless an estimate cannot be made at this time. It is management’s opinion that the loss for any other litigation matters and claims that are reasonably possible to occur will not have a material adverse effect on the Company’s financial position, results of operations, or liquidity.
For additional information on each of the Legal Matters described below, please seerefer to Note 10—11—Commitments and Contingencies to the consolidated financial statements contained in Apache’sthe Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.2022.
Argentine Environmental Claims
On March 12, 2014, the Company and Argentina Tariff
No material change inits subsidiaries completed the statussale of all of the Company’s subsidiaries’ operations and properties in Argentina to YPF Sociedad AnónimaAnonima (YPF). As part of that sale, YPF assumed responsibility for all of the past, present, and future litigation in Argentina involving Company subsidiaries, except that Company subsidiaries have agreed to indemnify YPF for certain environmental, tax, and royalty obligations capped at an aggregate of $100 million. The indemnity is subject to specific agreed conditions precedent, thresholds, contingencies, limitations, claim deadlines, loss sharing, and other terms and conditions. On April 11, 2014, YPF provided its first notice of claims pursuant to the indemnity. Company subsidiaries have not paid any amounts under the indemnity but will continue to review and consider claims presented by YPF. Further, Company subsidiaries retain the right to enforce certain Argentina-related indemnification obligations against Pioneer Natural Resources Company indemnities matters has occurred since(Pioneer) in an amount up to $45 million pursuant to the filingterms and conditions of Apache’sstock purchase agreements entered in 2006 between Company subsidiaries and subsidiaries of Pioneer.
Louisiana Restoration
As more fully described in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.
2022, Louisiana Restoration
As more fully described in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016, numerous surface owners have filedoften file lawsuits or assert claims or sent demand letters to variousagainst oil and gas companies, including Apache,the Company, claiming that under either express or implied lease terms or Louisiana law,operators and working interest owners in the companieschain of title are liable for damageenvironmental damages on the leased premises, including damages measured by the cost of restoration of the leased premises to theirits original condition, as well as damages for contamination and cleanup.
On July 24, 2013, a lawsuit captioned Board of Commissionersregardless of the Southeast Louisiana Flood Protection Authority – East v. Tennessee Gas Pipelinevalue of the underlying property. From time to time, restoration lawsuits and claims are resolved by the Company et al., Case No. 2013-6911 was filed in the Civil District Court for the Parish of Orleans, State of Louisiana, in which plaintiff on behalf of itself and as the board governing the levee districts of Orleans, Lake Borgne Basin, and East Jefferson allegedamounts that Louisiana coastal lands have been damaged as a result of oil and gas industry activity, including a network of canals for access and pipelines. The defendants removed the case from state court to federal court and, on February 13, 2015, the federal court entered judgment in favor of defendants dismissing all of plaintiff’s claims with prejudice. Plaintiff appealed the lower court’s dismissalare not material to the 5th Circuit Court of AppealsCompany, while new lawsuits and additionally challengedclaims are asserted against the defendants’ rightCompany. With respect to remove the case to federal court. On March 3, 2017, the 5th Circuit Court of Appeals affirmed the propriety of federal jurisdiction based in part on Apache’s argument that plaintiff’s state-based claims required a resolution of substantial questions of federal law and also affirmed the dismissaleach of the action. The Plaintiff filed a Petition for a Writ of Certiorari withpending lawsuits and claims, the United States Supreme Court. On October 30, 2017,amount claimed is not currently determinable or is not material. Further, the United States Supreme Court denied reviewoverall exposure related to these lawsuits and declinedclaims is not currently determinable. While adverse judgments against the Company are possible, the Company intends to consider the plaintiff’s Petition of Certiorari.actively defend these lawsuits and claims.
Starting in November of 2013 and continuing into 2017,2023, several Parishesparishes in Louisiana have pending lawsuits against many oil and gas producers, including Apache. These cases are pending in federal and state courts in Louisiana.the Company. In these cases, the Parishes, as plaintiffs, allege that defendants’ oil and gas exploration, production, and transportation operations in specified fields were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended, and applicable regulations, rules, orders, and ordinances promulgated or adopted thereunder by the Parish or the State of Louisiana. Plaintiffs allege that defendants caused substantial damage to land and water bodies located in the coastal zone of Louisiana. Plaintiffs seek, among other things, unspecified damages for alleged violations of applicable state law within the coastal zone, the payment of costs necessary to clear, re-vegetate, detoxify, and otherwise restore the subject coastal zone as near as practicable to its original condition, and actual restoration of the coastal zone to its original condition. While an adverse judgmentjudgments against Apachethe Company might be possible, Apachethe Company intends to vigorously oppose these claims.
No other material change in the status of these matters has occurred since the filing of Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.
Apollo Exploration Lawsuit
In a fourth amended petition filed on March 21, 2016, in a case captioned Apollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the 385th Judicial District Court, Midland County, Texas, plaintiffs have reduced their alleged damages to approximately $500in excess of $200 million (having previously claimed in excess of $1.1 billion) relating to certain purchase and sale agreements, mineral leases, and areasarea of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. The trial court entered final judgment in favor of the Company, ruling that the plaintiffs take nothing by their claims and awarding the Company its attorneys’ fees and costs incurred in defending the lawsuit. The court of appeals affirmed in part and reversed in part the trial court’s judgment thereby reinstating some of plaintiff’s claims. The Texas Supreme Court recently granted twothe Company’s petition for review and heard oral argument in October 2022. On April 28, 2023, the Texas Supreme Court reversed the court of Apache’s motionsappeals’ decision and remanded the case back to the court of appeals for summary judgment further limitingproceedings.
Australian Operations Divestiture Dispute
Pursuant to a Sale and Purchase Agreement dated April 9, 2015 (Quadrant SPA), the plaintiffs’ theoriesCompany and potentialits subsidiaries divested Australian operations to Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. In April 2017, the Company filed suit against Quadrant for breach of the Quadrant SPA. In its suit, the Company seeks approximately AUD $80 million. In December 2017, Quadrant filed a defense of equitable set-off to the Company’s claim and a counterclaim seeking approximately AUD $200 million in the aggregate. The Company believes that Quadrant’s claims lack merit and will not have a material adverse effect on the Company’s financial position, results of operation, or liquidity.
Canadian Operations Divestiture Dispute
Pursuant to a Sale and Purchase Agreement dated July 6, 2017 (Paramount SPA), the Company and its subsidiaries divested their remaining Canadian operations to Paramount Resources LTD (Paramount). Closing occurred on August 16, 2017. On September 11, 2019, four ex-employees of Apache Canada LTD on behalf of themselves and individuals employed by Apache Canada LTD on July 6, 2017, filed an Amended Statement of Claim in a matter styled Stephen Flesch et. al. v Apache Corporation et. al., No. 1901-09160 Court of Queen’s Bench of Alberta against the Company and others seeking class certification and a finding that the Paramount SPA amounted to a Change of Control of the Company, entitling them to accelerated vesting under the Company’s equity plans. In the suit, the class seeks approximately $60 million USD and punitive damages. ApacheThe Company believes that plaintiffs’ claims lack merit and further that plaintiffs’ alleged damages, even as amended, are grossly inflated. Apache will vigorously opposenot have a material adverse effect on the claims. No other material changeCompany’s financial position, results of operation, or liquidity.
California and Delaware Litigation
On July 17, 2017, in three separate actions, San Mateo and Marin Counties, and the statusCity of these matters has occurred since the filing of Apache’s Annual ReportImperial Beach, California, all filed suit individually and on Form 10-K for the fiscal year ended December 31, 2016.
Escheat Audits
There has been no material change with respect to the reviewbehalf of the books and recordspeople of the Companystate of California against over 30 oil and its subsidiariesgas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and related entities byabatement under various tort theories. On December 20, 2017, in two separate actions, the City of Santa Cruz and Santa Cruz County filed similar lawsuits against many of the same defendants. On January 22, 2018, the City of Richmond filed a similar lawsuit. On November 14, 2018, the Pacific Coast Federation of Fishermen’s Associations, Inc. also filed a similar lawsuit against many of the same defendants.
On September 10, 2020, the State of Delaware Departmentfiled suit, individually and on behalf of Finance (Unclaimed Property),the people of the State of Delaware, against over 25 oil and gas companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories.
The Company believes that it is not subject to determine compliance withjurisdiction of the California courts and that claims made against it in the California and Delaware litigation are baseless. The Company intends to challenge jurisdiction in California and to vigorously defend the Delaware Escheat Laws, sincelawsuit.
Castex Lawsuit
In a case styled Apache Corporation v. Castex Offshore, Inc., et. al., Cause No. 2015-48580, in the filing113th Judicial District Court of Apache’s Annual ReportHarris County, Texas, Castex filed claims for alleged damages of approximately $200 million, relating to overspend on Form 10-Kthe Belle Isle Gas Facility upgrade, and the drilling of five sidetracks on the Potomac #3 well. After a jury trial, a verdict of approximately $60 million, plus fees, costs, and interest was entered against the Company. The Fourteenth Court of Appeals of Texas reversed the judgment, in part, reducing the judgment to approximately $13.5 million, plus fees, costs, and interest against the Company.
Kulp Minerals Lawsuit
On or about April 7, 2023, Apache was sued in a purported class action in New Mexico styled Kulp Minerals LLC v. Apache Corporation, Case No. D-506-CV-2023-00352 in the Fifth Judicial District. The Kulp Minerals case has not been certified and seeks to represent a group of owners allegedly owed statutory interest under New Mexico law as a result of purported late oil and gas payments. The amount of this claim is not yet reasonably determinable. The Company intends to vigorously defend against the claims asserted in this lawsuit.
Shareholder and Derivative Lawsuits
On February 23, 2021, a case captioned Plymouth County Retirement System v. Apache Corporation, et al. was filed in the United States District Court for the fiscal year ended December 31, 2016.Southern District of Texas (Houston Division) against the Company and certain current and former officers. The complaint, which is a shareholder lawsuit styled as a class action, alleges that (1) the Company intentionally used unrealistic assumptions regarding the amount and composition of available oil and gas in Alpine High; (2) the Company did not have the proper infrastructure in place to safely and/or economically drill and/or transport those resources even if they existed in the amounts purported; (3) certain statements and omissions artificially inflated the value of the Company’s operations in the Permian Basin; and (4) as a result, the Company’s public statements were materially false and misleading. The Company believes that plaintiffs’ claims lack merit and intends to vigorously defend this lawsuit.
On January 18, 2023, a case captioned Jerry Hight, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al. was filed in the 61st District Court of Harris County, Texas. Then, on February 21, 2023, a case captioned Steve Silverman, Derivatively and on behalf of Nominal Defendant APA Corp. v. John J. Christmann IV, et al. was filed in federal district court for the Southern District of Texas. Then, on April 20, 2023, a case captioned William Wessels, Derivatively and on behalf of APA Corporation v. John J. Christmann IV et al. was filed in the 151st District Court of Harris County, Texas. These cases purport to be derivative actions brought against senior management and Company directors over many of the same allegations included in the Plymouth County Retirement System matter and asserts claims of (1) breach of fiduciary duty; (2) waste of corporate assets; and (3) unjust enrichment. The defendants believe that plaintiffs’ claims lack merit and intend to vigorously defend these lawsuits.
Environmental Matters
As of September 30, 2017,March 31, 2023, the Company had an undiscounted reserve for environmental remediation of approximately $4$1 million.
On September 11, 2020, the Company received a Notice of Violation and Finding of Violation, and accompanying Clean Air Act Information Request, from the U.S. Environmental Protection Agency (EPA) following site inspections in April 2019 at several of the Company’s oil and natural gas production facilities in Lea and Eddy Counties, New Mexico. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and has responded to the information request. The EPA has referred the notice for civil enforcement proceedings; however, at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs.
On December 29, 2020, the Company received a Notice of Violation and Opportunity to Confer, and accompanying Clean Air Act Information Request, from the EPA following helicopter flyovers in September 2019 of several of the Company’s oil and natural gas production facilities in Reeves County, Texas. The notice and information request involve alleged emissions control and reporting violations. The Company is cooperating with the EPA and has responded to the information request. The EPA has referred the notice for civil enforcement proceedings; however, at this time the Company is unable to reasonably estimate whether such proceedings will result in monetary sanctions and, if so, whether they would be more or less than $100,000, exclusive of interest and costs.
The Company is not aware of any environmental claims existing as of September 30, 2017,March 31, 2023 that have not been provided for or would otherwise have a material impact on its financial position, results of operations, or liquidity. There can be no assurance, however, that current regulatory requirements will not change or past non-compliance with environmental laws will not be discovered on the Company’s properties.
Potential Decommissioning Obligations on Sold Properties
In 2013, Apache sold its Gulf of Mexico (GOM) Shelf operations and properties and its GOM operating subsidiary, GOM Shelf LLC (GOM Shelf) to Fieldwood Energy LLC (Fieldwood). Under the terms of the Company, previously reported produced water spillspurchase agreement, Apache received cash consideration of $3.75 billion and Fieldwood assumed the obligation to decommission the properties held by GOM Shelf and the properties acquired from Apache and its other subsidiaries (collectively, the Legacy GOM Assets). In respect of such abandonment obligations, Fieldwood posted letters of credit in favor of Apache (Letters of Credit) and established trust accounts (Trust A and Trust B) of which Apache was a remote areabeneficiary and which were funded by two net profits interests (NPIs) depending on future oil prices. On February 14, 2018, Fieldwood filed for protection under Chapter 11 of the Bellow FieldU.S. Bankruptcy Code. In connection with the 2018 bankruptcy, Fieldwood confirmed a plan under which Apache agreed, inter alia, to (i) accept bonds in exchange for certain of the Letters of Credit and (ii) amend the Trust A trust agreement and one of the NPIs to consolidate the trusts into a hydrogen sulfidesingle Trust (Trust A) funded by both remaining NPIs. Currently, Apache holds two bonds (Bonds) and oil emulsion leakfive Letters of Credit to secure Fieldwood’s asset retirement obligations on the Legacy GOM Assets as and when Apache is required to perform or pay for decommissioning any Legacy GOM Asset 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. 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. On August 27, 2021, Fieldwood’s bankruptcy plan became effective. Pursuant to the plan, the Legacy GOM Assets were separated into a standalone company, which was subsequently merged into GOM Shelf. Under GOM Shelf’s limited liability company agreement, the proceeds of production of the Legacy GOM Assets will be used to fund decommissioning of Legacy GOM Assets.
By letter dated April 5, 2022, replacing two prior letters dated September 8, 2021 and February 22, 2022, and by subsequent letter dated March 1, 2023, GOM Shelf notified the Bureau of Safety and Environmental Enforcement (BSEE) that it was unable to fund the decommissioning obligations that it is currently obligated to perform on certain of the Legacy GOM Assets. As a result, Apache and other current and former owners in these assets have received orders from BSEE to decommission certain of the Legacy GOM Assets included in GOM Shelf’s notifications to BSEE. Apache expects to receive similar orders on the other Legacy GOM Assets included in GOM Shelf’s notification letters. Apache has also received orders to decommission other Legacy GOM Assets that were not included in GOM Shelf’s notification letters. Further, Apache anticipates that GOM Shelf may send additional such notices to BSEE in the Zama area. The Company sold ACLfuture and that it may receive additional orders from BSEE requiring it to decommission other Legacy GOM Assets.
As of March 31, 2023, Apache has incurred $291 million in decommissioning costs related to several Legacy GOM Assets. GOM Shelf did not, and has confirmed that it will not, reimburse Apache for these decommissioning costs. As a transaction that was completed inresult, Apache has sought and will continue to seek reimbursement from its security for these costs, of which $195 million had been reimbursed from Trust A as of March 31, 2023. If GOM Shelf does not reimburse Apache for further decommissioning costs incurred with respect to Legacy GOM Assets, then Apache will continue to seek reimbursement from Trust A, to the third quarterextent of 2017. The Canadian environmental litigationavailable funds, and liabilities remained with ACLthereafter, will seek reimbursement from the Bonds and the Letters of Credit until all such funds and securities are now the responsibility of the acquirer.
fully utilized. In addition, after such sources have been exhausted, Apache has agreed to provide a standby loan to GOM Shelf of up to $400 million to perform decommissioning (Standby Loan Agreement), with such standby loan secured by a first and prior lien on the matters for whichLegacy GOM Assets.
If the combination of GOM Shelf’s net cash flow from its producing properties, the Trust A funds, the Bonds, and the remaining Letters of Credit are insufficient to fully fund decommissioning of any Legacy GOM Assets that Apache may be required to perform or fund, or if GOM Shelf’s net cash flow from its remaining producing properties after the Trust A funds, Bonds, and Letters of Credit are exhausted is insufficient to repay any loans made by Apache under the Standby Loan Agreement, then Apache may be forced to effectively use its available cash to fund the deficit.
As of March 31, 2023, Apache estimates that its potential liability to fund the remaining decommissioning of Legacy GOM Assets it may be ordered to perform or fund ranges from $1.1 billion to $1.3 billion on an undiscounted basis. Management does not believe any specific estimate within this range is a better estimate than any other. Accordingly, the Company has already accrued,recorded a contingent liability of $1.1 billion as of March 31, 2023, representing the estimated costs of decommissioning it may be required to perform or fund on July 17, 2017,Legacy GOM Assets. Of the total liability recorded, $656 million is reflected under the caption “Decommissioning contingency for sold Gulf of Mexico properties,” and $433 million is reflected under “Other current liabilities” in three separate actions, San Mateo County, California, Marin County, California,the Company’s consolidated balance sheet. Changes in significant assumptions impacting Apache’s estimated liability, including expected decommissioning rig spread rates, lift boat rates, and planned abandonment logistics could result in a liability in excess of the amount accrued.
As of March 31, 2023, the Company has also recorded a $582 million asset, which represents the amount the Company expects to be reimbursed from the Trust A funds, the Bonds, and the CityLetters of Imperial Beach, California, all filed suit individually andCredit for decommissioning it may be required to perform on behalf ofLegacy GOM Assets. Of the people of the state of California against over 30 oil, gas, and coal companies alleging damages as a result of global warming. Plaintiffs seek unspecified damages and abatement under various tort theories. Apache believes that the claims made against it are baseless and intends to vigorously defend these lawsuits.
Australian Operations Divestiture Dispute
By a Sale and Purchase Agreement dated April 9, 2015 (SPA), the Company and its subsidiaries divested their remaining Australian operations to Viraciti Energy Pty Ltd, which has since been renamed Quadrant Energy Pty Ltd (Quadrant). Closing occurred on June 5, 2015. By letter dated June 6, 2016, Quadrant provided the Company with a placeholder notice of claimtotal asset recorded, $132 million is reflected under the SPA concerning taxcaption “Decommissioning security for sold Gulf of Mexico properties,” and other issues totaling approximately $200$450 million inis reflected under “Other current assets.”
13. BUSINESS SEGMENT INFORMATION
As of March 31, 2023, the aggregate. The Company believes that these claims lack merit and intends to vigorously defend against them. Moreover, on September 22, 2017, subsidiaries of the Company filed suit against Quadrant for breaching the SPA and wrongfully withholding tax refunds owed under the SPA. This claim totals approximately $80 million AUD.
Net Income (Loss) per Common Share
A reconciliation of the components of basic and diluted net income (loss) per common share for the quarters and nine months ended September 30, 2017 and 2016, is presented in the table below.
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| | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, |
| | 2017 | | 2016 |
| | Income | | Shares | | Per Share | | Loss | | Shares | | Per Share |
| | (In millions, except per share amounts) |
Basic: | | | | | | | | | | | | |
Income (loss) from continuing operations | | $ | 63 |
| | 381 |
| | $ | 0.16 |
| | $ | (574 | ) | | 380 |
| | $ | (1.51 | ) |
Loss from discontinued operations | | — |
| | 381 |
| | — |
| | (33 | ) | | 380 |
| | (0.09 | ) |
Income (loss) attributable to common stock | | $ | 63 |
| | 381 |
| | $ | 0.16 |
| | $ | (607 | ) | | 380 |
| | $ | (1.60 | ) |
Effect of Dilutive Securities: | | | | | | | | | | | | |
Stock options and other | | $ | — |
| | 2 |
| | $ | — |
| | $ | — |
| | — |
| | $ | — |
|
Diluted: | | | | | | | | | | | | |
Income (loss) from continuing operations | | $ | 63 |
| | 383 |
| | $ | 0.16 |
| | $ | (574 | ) | | 380 |
| | $ | (1.51 | ) |
Loss from discontinued operations | | — |
| | 383 |
| | — |
| | (33 | ) | | 380 |
| | (0.09 | ) |
Income (loss) attributable to common stock | | $ | 63 |
| | 383 |
| | $ | 0.16 |
| | $ | (607 | ) | | 380 |
| | $ | (1.60 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2017 | | 2016 |
| | Income | | Shares | | Per Share | | Loss | | Shares | | Per Share |
| | (In millions, except per share amounts) |
Basic: | | | | | | | | | | | | |
Income (loss) from continuing operations | | $ | 848 |
| | 381 |
| | $ | 2.23 |
| | $ | (1,190 | ) | | 379 |
| | $ | (3.14 | ) |
Loss from discontinued operations | | — |
| | 381 |
| | — |
| | (33 | ) | | 379 |
| | (0.08 | ) |
Income (loss) attributable to common stock | | $ | 848 |
| | 381 |
| | $ | 2.23 |
| | $ | (1,223 | ) | | 379 |
| | $ | (3.22 | ) |
Effect of Dilutive Securities: | | | | | | | | | | | | |
Stock options and other | | $ | — |
| | 2 |
| | $ | (0.01 | ) | | $ | — |
| | — |
| | $ | — |
|
Diluted: | | | | | | | | | | | | |
Income (loss) from continuing operations | | $ | 848 |
| | 383 |
| | $ | 2.22 |
| | $ | (1,190 | ) | | 379 |
| | $ | (3.14 | ) |
Loss from discontinued operations | | — |
| | 383 |
| | — |
| | (33 | ) | | 379 |
| | (0.08 | ) |
Income (loss) attributable to common stock | | $ | 848 |
| | 383 |
| | $ | 2.22 |
| | $ | (1,223 | ) | | 379 |
| | $ | (3.22 | ) |
The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive totaling 8.4 million and 4.7 million for the quarters ended September 30, 2017 and 2016, respectively, and 7.5 million and 6.5 million for the nine months ended September 30, 2017 and 2016, respectively.
Common Stock Dividends
For each of the quarters ended September 30, 2017, and 2016, Apache paid $95 million in dividends on its common stock. For the nine months ended September 30, 2017 and 2016, the Company paid $285 million and $284 million, respectively.
Stock Repurchase Program
Apache’s Board of Directors has authorized the purchase of up to 40 million shares of the Company’s common stock. Shares may be purchased either in the open market or through privately negotiated transactions. The Company initiated the buyback program on June 10, 2013, and through September 30, 2017, had repurchased a total of 32.2 million shares at an average price of $88.96 per share. The Company is not obligated to acquire any specific number of shares and has not purchased any shares during 2017.
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11. | ACCUMULATED OTHER COMPREHENSIVE LOSS |
The following table describes changes to the Company’s accumulated other comprehensive loss by component for the nine-month period ended September 30, 2017:
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| | | | | | | | | | | | |
| | Currency Translation Adjustment | | Pension and Postretirement Benefit Plan | | Total |
| | (In millions) |
Accumulated other comprehensive loss at December 31, 2016 | | $ | (109 | ) | | $ | (3 | ) | | $ | (112 | ) |
Currency translation adjustment divested(1) | | 109 |
| | — |
| | 109 |
|
Accumulated other comprehensive loss at September 30, 2017 | | $ | — |
| | $ | (3 | ) | | $ | (3 | ) |
| |
(1) | Currency translation adjustments resulting from translating the Canadian subsidiaries’ financial statements into U.S. dollar equivalents, prior to adoption of the U.S. dollar as their functional currency, were reported separately and accumulated in other comprehensive loss. This currency translation loss was recognized as a reduction of the net gain on divestiture during the third quarter of 2017 in connection with the Canada divestitures. For more information regarding these divestitures, please refer to Note 2—Acquisitions and Divestitures. |
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12. | BUSINESS SEGMENT INFORMATION |
Apache is engaged in a single line of business. Both domesticallyexploration and internationally,production (Upstream) activities across three operating segments: Egypt, North Sea, and the CompanyU.S. The Company’s Upstream business explores for, develops, and produces crude oil, natural gas, crude oil, and natural gas liquids. At September 30, 2017,Prior to the Company had production in three reporting segments:deconsolidation of Altus on February 22, 2022, the United States, Egypt,Company’s Midstream business was operated by ALTM, which owned, developed, and offshore the United Kingdomoperated a midstream energy asset network in the North Sea (North Sea). Apache also has exploration interests in Suriname that may, over time, result in a reportable discovery and development opportunity.Permian Basin of West Texas. Financial information for each areasegment is presented below:
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| | Egypt(1) | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total(4) |
| | Upstream | | | |
| | | | | | | | | | | | |
For the Quarter Ended March 31, 2023 | | (In millions) |
Revenues: | | | | | | | | | | | | |
Oil revenues | | $ | 629 | | | $ | 282 | | | $ | 439 | | | $ | — | | | $ | — | | | $ | 1,350 | |
Natural gas revenues | | 93 | | | 60 | | | 85 | | | — | | | — | | | 238 | |
Natural gas liquids revenues | | — | | | 10 | | | 108 | | | — | | | — | | | 118 | |
Oil, natural gas, and natural gas liquids production revenues | | 722 | | | 352 | | | 632 | | | — | | | — | | | 1,706 | |
Purchased oil and gas sales | | — | | | — | | | 239 | | | — | | | — | | | 239 | |
| | | | | | | | | | | | |
| | 722 | | | 352 | | | 871 | | | — | | | — | | | 1,945 | |
Operating Expenses: | | | | | | | | | | | | |
Lease operating expenses | | 97 | | | 77 | | | 140 | | | — | | | — | | | 314 | |
Gathering, processing, and transmission | | 7 | | | 11 | | | 55 | | | — | | | — | | | 73 | |
Purchased oil and gas costs | | — | | | — | | | 216 | | | — | | | — | | | 216 | |
Taxes other than income | | — | | | — | | | 50 | | | — | | | — | | | 50 | |
Exploration | | 36 | | | 5 | | | 3 | | | — | | | — | | | 44 | |
Depreciation, depletion, and amortization | | 123 | | | 58 | | | 127 | | | — | | | — | | | 308 | |
Asset retirement obligation accretion | | — | | | 18 | | | 10 | | | — | | | — | | | 28 | |
| | | | | | | | | | | | |
| | 263 | | | 169 | | | 601 | | | — | | | — | | | 1,033 | |
Operating Income(2) | | $ | 459 | | | $ | 183 | | | $ | 270 | | | $ | — | | | $ | — | | | 912 | |
| | | | | | | | | | | | |
Other Income (Expense): | | | | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | |
Gain on divestitures, net | | | | | | | | | | | | 1 | |
Other, net | | | | | | | | | | | | (32) | |
General and administrative | | | | | | | | | | | | (58) | |
Transaction, reorganization, and separation | | | | | | | | | | | | (4) | |
Financing costs, net | | | | | | | | | | | | (49) | |
Income Before Income Taxes | | | | | | | | | | | | $ | 770 | |
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Total Assets(3) | | $ | 3,334 | | | $ | 1,836 | | | $ | 9,089 | | | $ | — | | | $ | — | | | $ | 14,259 | |
| | | | | | | | | | | | | | | | Egypt(1) | | North Sea | | U.S. | | Altus Midstream | | Intersegment Eliminations & Other | | Total(4) |
| | United States | | Canada(1) | | Egypt(2) | | North Sea | | Other International | | Total | | Upstream | |
| | (In millions) | | | | | | | | |
For the Quarter Ended September 30, 2017 | | | | | | | | | | | | | |
Oil and Gas Production Revenues | | $ | 550 |
| | $ | 36 |
| | $ | 543 |
| | $ | 260 |
| | $ | — |
| | $ | 1,389 |
| |
Operating Income (Loss)(3) | | $ | (114 | ) | | $ | (1 | ) | | $ | 226 |
| | $ | 16 |
| | $ | (1 | ) | | $ | 126 |
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For the Quarter Ended March 31, 2022 | | For the Quarter Ended March 31, 2022 | | (In millions) |
Revenues: | | Revenues: | |
Oil revenues | | Oil revenues | | $ | 790 | | | $ | 328 | | | $ | 599 | | | $ | — | | | $ | — | | | $ | 1,717 | |
Natural gas revenues | | Natural gas revenues | | 98 | | | 99 | | | 183 | | | — | | | — | | | 380 | |
Natural gas liquids revenues | | Natural gas liquids revenues | | 3 | | | 16 | | | 207 | | | — | | | (3) | | | 223 | |
Oil, natural gas, and natural gas liquids production revenues | | Oil, natural gas, and natural gas liquids production revenues | | 891 | | | 443 | | | 989 | | | — | | | (3) | | | 2,320 | |
Purchased oil and gas sales | | Purchased oil and gas sales | | — | | | — | | | 344 | | | 5 | | | — | | | 349 | |
Midstream service affiliate revenues | | Midstream service affiliate revenues | | — | | | — | | | — | | | 16 | | | (16) | | | — | |
| | | 891 | | | 443 | | | 1,333 | | | 21 | | | (19) | | | 2,669 | |
Operating Expenses: | | Operating Expenses: | |
Lease operating expenses | | Lease operating expenses | | 131 | | | 96 | | | 118 | | | — | | | (1) | | | 344 | |
Gathering, processing, and transmission | | Gathering, processing, and transmission | | 5 | | | 12 | | | 77 | | | 5 | | | (18) | | | 81 | |
Purchased oil and gas costs | | Purchased oil and gas costs | | — | | | — | | | 351 | | | — | | | — | | | 351 | |
Taxes other than income | | Taxes other than income | | — | | | — | | | 67 | | | 3 | | | — | | | 70 | |
Exploration | | Exploration | | 15 | | | 5 | | | 4 | | | — | | | 1 | | | 25 | |
Depreciation, depletion, and amortization | | Depreciation, depletion, and amortization | | 97 | | | 62 | | | 130 | | | 2 | | | — | | | 291 | |
Asset retirement obligation accretion | | Asset retirement obligation accretion | | — | | | 20 | | | 8 | | | 1 | | | — | | | 29 | |
| | | | 248 | | | 195 | | | 755 | | | 11 | | | (18) | | | 1,191 | |
Operating Income (Loss)(2) | | Operating Income (Loss)(2) | | $ | 643 | | | $ | 248 | | | $ | 578 | | | $ | 10 | | | $ | (1) | | | 1,478 | |
| Other Income (Expense): | | | | | | | | | | | | | Other Income (Expense): | |
| Derivative instrument losses, net | | Derivative instrument losses, net | | (62) | |
Gain on divestitures, net | | | | | | | | | | | | 296 |
| Gain on divestitures, net | | 1,176 | |
Derivative instrument losses, net | | | | | | | | | | | | (110 | ) | |
Other, net | | Other, net | | 45 | |
General and administrative | | | | | | | | | | | | (98 | ) | General and administrative | | (151) | |
Transaction, reorganization, and separation | | | | | | | | | | | | (20 | ) | Transaction, reorganization, and separation | | (14) | |
Financing costs, net | | | | | | | | | | | | (101 | ) | Financing costs, net | | (140) | |
Income Before Income Taxes | | | | | | | | | | | | $ | 93 |
| Income Before Income Taxes | | $ | 2,332 | |
| | | | | | | | | | | | | | |
For the Nine Months Ended September 30, 2017 | | | | | | | | | | | | | |
Oil and Gas Production Revenues | | $ | 1,593 |
| | $ | 231 |
| | $ | 1,655 |
| | $ | 768 |
| | $ | — |
| | $ | 4,247 |
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Operating Income (Loss)(3) | | $ | (71 | ) | | $ | (33 | ) | | $ | 740 |
| | $ | 59 |
| | $ | (24 | ) | | $ | 671 |
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Other Income (Expense): | | | | | | | | | | | | | |
Gain on divestitures, net | | | | | | | | | | | | 616 |
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Derivative instrument losses, net | | | | | | | | | | | | (69 | ) | |
Other | | | | | | | | | | | | 43 |
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General and administrative | | | | | | | | | | | | (307 | ) | |
Transaction, reorganization, and separation | | | | | | | | | | | | (14 | ) | |
Financing costs, net | | | | | | | | | | | | (300 | ) | |
Income Before Income Taxes | | | | | | | | | | | | $ | 640 |
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Total Assets | | $ | 13,105 |
| | $ | — |
| | $ | 4,906 |
| | $ | 3,770 |
| | $ | 54 |
| | $ | 21,835 |
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| | | | | | | | | | | | | |
| | | | Total Assets(3) | | Total Assets(3) | | $ | 2,966 | | | $ | 2,169 | | | $ | 8,359 | | | $ | — | | | $ | — | | | $ | 13,494 | |
(1) Includes revenue from non-customers for the quarters ended March 31, 2023 and 2022 of:
| | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | | | | | | | |
| | (In millions) | | | | |
Oil | | $ | 172 | | | $ | 250 | | | | | |
Natural gas | | 26 | | | 31 | | | | | |
Natural gas liquids | | — | | | 1 | | | | | |
(2)Operating income of U.S. and North Sea includes leasehold impairments of $2 million and $3 million, respectively, for the first quarter of 2023.
Operating income of U.S. and Egypt includes leasehold impairments of $3 million, and $1 million, respectively, for the first quarter of 2022.
(3)Intercompany balances are excluded from total assets.
(4)Includes noncontrolling interests of Sinopec, Altus prior to deconsolidation, and APA.
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| | United States | | Canada(1) | | Egypt(2) | | North Sea | | Other International | | Total |
| | (In millions) |
For the Quarter Ended September 30, 2016 | | | | | | | | | | | | |
Oil and Gas Production Revenues | | $ | 524 |
| | $ | 87 |
| | $ | 581 |
| | $ | 247 |
| | $ | — |
| | $ | 1,439 |
|
Operating Income (Loss)(4) | | $ | (17 | ) | | $ | (466 | ) | | $ | 263 |
| | $ | (455 | ) | | $ | (13 | ) | | $ | (688 | ) |
Other Income (Expense): | | | | | | | | | | | | |
Gain on divestitures, net | | | | | | | | | | | | 5 |
|
Other | | | | | | | | | | | | (6 | ) |
General and administrative | | | | | | | | | | | | (102 | ) |
Transaction, reorganization, and separation | | | | | | | | | | | | (12 | ) |
Financing costs, net | | | | | | | | | | | | (102 | ) |
Loss From Continuing Operations Before Income Taxes | | | | | | | | | | | | $ | (905 | ) |
| | | | | | | | | | | | |
For the Nine Months Ended September 30, 2016 | | | | | | | | | | | | |
Oil and Gas Production Revenues | | $ | 1,453 |
| | $ | 243 |
| | $ | 1,515 |
| | $ | 701 |
| | $ | — |
| | $ | 3,912 |
|
Operating Income (Loss)(4) | | $ | (283 | ) | | $ | (586 | ) | | $ | 525 |
| | $ | (557 | ) | | $ | (13 | ) | | $ | (914 | ) |
Other Income (Expense): | | | | | | | | | | | | |
Gain on divestitures, net | | | | | | | | | | | | 21 |
|
Other | | | | | | | | | | | | (30 | ) |
General and administrative | | | | | | | | | | | | (298 | ) |
Transaction, reorganization, and separation | | | | | | | | | | | | (36 | ) |
Financing costs, net | | | | | | | | | | | | (311 | ) |
Loss From Continuing Operations Before Income Taxes | | | | | | | | | | | | $ | (1,568 | ) |
Total Assets | | $ | 12,299 |
| | $ | 1,630 |
| | $ | 5,320 |
| | $ | 3,851 |
| | $ | 49 |
| | $ | 23,149 |
|
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(1) | During the third quarter of 2017, Apache completed the sale of its Canadian operations. For more information regarding this divestiture, please refer to Note 2—Acquisitions and Divestitures. |
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(2) | Includes a noncontrolling interest in Egypt. |
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(3) | Operating income (loss) consists of oil and gas production revenues less lease operating expenses, gathering and transportation costs, taxes other than income, exploration costs, depreciation, depletion, and amortization, asset retirement obligation accretion, and impairments. The operating income (loss) of U.S. includes leasehold impairments totaling $160 million for the third quarter of 2017. The operating income (loss) of U.S., Canada, and North Sea includes leasehold and other asset impairments totaling $212 million, $2 million, and $8 million, respectively, for the first nine months of 2017. |
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(4) | The operating income (loss) of U.S., Canada, and North Sea includes leasehold, property, and other asset impairments totaling $46 million, $423 million, and $481 million, respectively, for the third quarter of 2016. The operating income (loss) of U.S., Canada, and North Sea includes leasehold, property, and other asset impairments totaling $212 million, $433 million, and $586 million, respectively, for the first nine months of 2016. |
ITEM 2. MANAGEMENT’S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
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ITEM 2.
| MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
The following discussion relates to Apache Corporation (Apache or the Company) and its consolidated subsidiaries and should be read in conjunctiontogether with the Company’s consolidated financial statementsConsolidated Financial Statements and accompanying notes included underin Part I, Item 1, “Financial Statements”1—Financial Statements of this Quarterly Report on Form 10-Q, as well as related information set forth in the Company’s consolidated financial statements,Consolidated Financial Statements, accompanying notesNotes to Consolidated Financial Statements, and Management’s Discussion andNarrative Analysis of Financial Condition and Results of Operations included in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.2022. Overview
Apache, a direct, wholly owned subsidiary of APA Corporation a Delaware corporation formed in 1954,(APA), is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids.liquids (NGLs). The CompanyCompany’s upstream business currently has exploration and production operations in three geographic areas: the United States (U.S.)U.S., Egypt, and offshore the United Kingdom (U.K.)U.K. in the North Sea (North Sea). Apache also has exploration interestsPrior to the BCP Business Combination (as defined in Suriname that may, over time, result in a reportable discovery and development opportunity.
During the
quarter, Apache completed its strategic exit from Canada that was enabled by its Alpine High discovery. We believe this portfolio shift is a significant upgradeNotes to the Company’s
portfolioConsolidated Financial Statements set forth in Part I, Item 1—Financial Statements of assets, as the Alpine High discovery offers higher returns and significantly more long-term growth potential. Apache’s U.S. assets are complemented by its international assets in Egypt and the North Sea, each of which adds tothis Quarterly Report on Form 10-Q), the Company’s deep inventorymidstream business was operated by Altus Midstream Company (ALTM) through its subsidiary Altus Midstream LP (collectively, Altus). Altus owned, developed, and operated a midstream energy asset network in the Permian Basin of explorationWest Texas.The Company’s mission is to grow in an innovative, safe, environmentally responsible, and development opportunitiesprofitable manner for the long-term benefit of its stakeholders. The Company is focused on rigorous portfolio management, disciplined financial structure, and optimization of returns.
Early in 2020, impacts of the coronavirus disease 2019 (COVID-19) pandemic and related governmental actions began to exert significant downward pressure on crude oil and natural gas prices. Since that time, commodity prices worldwide have largely rebounded; however, uncertainties in the global supply chain and financial markets, including the impact of inflation, rising interest rates, the conflict in Ukraine, and actions taken by foreign oil and gas producing nations, including OPEC+, continue to impact oil supply and demand and contribute to commodity price volatility. Despite these uncertainties, the Company remains committed to its longer-term objectives: (1) to maintain a balanced asset portfolio; (2) to invest for long-term returns over production growth; and (3) to budget conservatively to generate cash flowsflow in excess of currentits upstream exploration, appraisal, and development capital investments, facilitatingprogram that can be directed to debt reduction, share repurchases, and other return of capital to its shareholders. The Company continues to aggressively manage its cost structure regardless of the Company’s abilityoil price environment and closely monitors hydrocarbon pricing fundamentals to develop Alpine High while maintaining financial flexibility.reallocate capital as part of its ongoing planning process.
ApacheIn the first quarter of 2023, the Company reported third-quarter net income of $63$137 million or $0.16 per common share, compared to a lossnet income of $607 million, or $1.60 per common share,$1.9 billion in the thirdfirst quarter of 2016. The increase2022. Results from the first quarter of 2022 included approximately $1.2 billion of transaction gains recognized for divesting certain non-core mineral rights in the Delaware Basin and completing the BCP Business Combination. In addition, net income for the first quarter of 2023 was impacted by lower revenues attributable to lower realized commodity prices when compared to the prior-year quarter is primarily the result of gains on divestitures in the current-year quarter, as well as lower impairment charges in the current period. Revenue gains from significant increases in realized commodity prices partially mitigated the impact of production declines.
Daily production in the third quarter of 2017 averaged 448 thousand barrels of oil equivalent per day (Mboe/d), a decrease of 14 percent from the comparative prior-year quarter driven by the sale of the Company’s Canadian operations. Excluding production from Canada, Apache’s worldwide equivalent daily production decreased 8 percent due to natural decline. The production decline was driven by strategic decisions to curtail capital investments in the two preceding years in order to allow costs to re-align with the lower commodity price environment and to allocate a significant portion of this year’s capital investments to the development of the Alpine High field and infrastructure.
During the first nine months of 2017, the Company generated $1.8 billion in$288 million of cash from operating activities an 8during the first three months of 2023, 66 percent increase fromlower than the comparative prior-year period,first three months of 2022. The Company’s lower operating cash flows for the first three months of 2023 were driven by lower commodity prices and $1.4 billionassociated revenues and the timing of working capital items. The Company had $117 million of cash proceeds from non-core asset divestments. Apache exited the quarter with $1.9 billion of cash, cash equivalents, and restricted cash, an increase of $565 million from year-end 2016. In addition, the Company reduced debt from year-end levels and has $3.5 billion of available committed borrowing capacity. In response to continued commodity price volatility, the Company entered commodity derivatives to secure deployment of high priority investments without compromising its financial strength or flexibility. We continuously monitor changes in our operating environment and have the ability, due to our dynamic capital allocation process, to adjust our capital investment program to levels that maximize value for our shareholders over the long-term.on hand at March 31, 2023.
Operating
Operational Highlights
Significant operating activitiesKey operational highlights for the quarter include the following:include:
North AmericaUnited States
North America equivalent production decreased 17 percent for the quarter relative to the 2016 period, reflecting Apache’s exit from Canada. Excluding Canada, Apache’s North America equivalent production decreased 6 percent, in line with the Company’s expectations given the significant reduction in capital investments over the preceding two years and the allocation of a significant portion of our 2017 capital investments to infrastructure at Alpine High.
Third-quarter equivalent•Daily boe production from the PermianCompany’s U.S. assets accounted for 49 percent of its total production during the first quarter of 2023. The Company averaged five drilling rigs in the U.S. during the quarter, including two rigs in the Southern Midland Basin region, which accountsand three rigs in the Delaware Basin. The Company’s core Midland Basin development program continues to represent a key growth area for more than halfthe U.S. assets.
International
•In Egypt, the Company averaged 17 drilling rigs and drilled 19 new productive wells during the first quarter of Apache’s total North American2023. First quarter 2023 gross equivalent production increasedin the Company’s Egypt assets decreased 1 percent from the thirdfirst quarter of 2016, which was driven by our Alpine High discovery2022, and strong performancenet production decreased 2 percent. The Company increased drilling and workover activity throughout the past year with a heavier focus on oil prospects. As a result, gross and net oil production for the first three months of 2023 increased approximately 5 percent and 3 percent, respectively, when compared to the first three months of 2022.
•The Company averaged two rigs in the Midland Basin. Third-quarter production increased 11 percent fromNorth Sea during the prior sequential quarter, a reflection of increased activity and the startup of Alpine High production.
Drilling and infrastructure development activities continue at Alpine High; specifically:
| |
◦ | First production from the Alpine High play was achieved in early May 2017. Net production averaged approximately 13.3 Mboe/d during the third quarter, and we anticipate production of 25 Mboe/d by the end of the year. |
| |
◦ | During the first nine months of 2017, Apache invested $389 million in midstream facilities at Alpine High, with development ongoing. |
| |
◦ | Three processing facilities are currently operating with a combined gross inlet capacity of 200 million cubic feet of natural gas per day (MMcf/d). Infrastructure buildout for two additional central processing facilities has been slightly delayed by a quarter as a result of Hurricane Harvey-related damage to Houston-area manufacturing facilities that are providing key infrastructure equipment. |
In 2017, Apache announced three separate transactions to sell its subsidiary Apache Canada Ltd. (ACL) and exit its Canadian operations. The sale of assets at Midale and House Mountain, located in Saskatchewan and Alberta, closed on June 30, 2017 for approximately $228 million of cash proceeds. The two remaining transactions to sell ACL and Provost assets in Alberta closed in August 2017 for approximately $478 million of cash proceeds. The sale of Apache’s Canadian operations further streamlines its portfolio, enabling the Company to allocate a higher percentage of capital to the Permian Basin.
International
The Egypt region net equivalent production decreased 12 percent from the third quarter of 2016 despite a decline2023. Production increased at Beryl and Forties during the first quarter of only 3 percent in gross production, a function2023 following the completion of the Company’s production-sharing contracts. In August 2017, the Company received final award of two new concessions totaling 1.6 million net acres. Atmaintenance activities at the end of September 2017,2022 and improved facility operating efficiency compared to the prior year. The Company began acquiring high resolution 3D seismicwill release the Ocean Patriot semi-submersible drilling rig around mid-year 2023, once it completes its scheduled drilling campaign in the West Kalabsha concession and plans to expand this seismic activity to cover the majority of its acreage.
The North Sea, region average daily production decreased 5 percent fromand thereafter, the third quarter of 2016, primarily the result of extended turnaround activities in the third quarter of 2017 and natural well decline. The Callater discovery, which came online in late May 2017, has two wells producing with a third offset well expectedassociated investment capital will be reallocated to commence production later in the fourth quarter of 2017.
other areas.
Results of Operations
Oil, Natural Gas, and Natural Gas Liquids Production Revenues
Revenue
The table below presentsCompany’s production revenues and respective contribution to total revenues by geographic region and each region’s percent contributioncountry were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | $ Value | | % Contribution | | $ Value | | % Contribution | | | | | | | | |
| | | | | | | | | | | | | | | | |
| | ($ in millions) |
Oil Revenues: | | | | | | | | | | | | | | | | |
United States | | $ | 439 | | | 33 | % | | $ | 599 | | | 35 | % | | | | | | | | |
Egypt(1) | | 629 | | | 46 | % | | 790 | | | 46 | % | | | | | | | | |
North Sea | | 282 | | | 21 | % | | 328 | | | 19 | % | | | | | | | | |
Total(1) | | $ | 1,350 | | | 100 | % | | $ | 1,717 | | | 100 | % | | | | | | | | |
| | | | | | | | | | | | | | | | |
Natural Gas Revenues: | | | | | | | | | | | | | | |
United States | | $ | 85 | | | 36 | % | | $ | 183 | | | 48 | % | | | | | | | | |
Egypt(1) | | 93 | | | 39 | % | | 98 | | | 26 | % | | | | | | | | |
North Sea | | 60 | | | 25 | % | | 99 | | | 26 | % | | | | | | | | |
Total(1) | | $ | 238 | | | 100 | % | | $ | 380 | | | 100 | % | | | | | | | | |
| | | | | | | | | | | | | | | | |
NGL Revenues: | | | | | | | | | | | | | | | | |
United States | | $ | 108 | | | 92 | % | | $ | 204 | | | 91 | % | | | | | | | | |
Egypt(1) | | — | | | — | % | | 3 | | | 2 | % | | | | | | | | |
North Sea | | 10 | | | 8 | % | | 16 | | | 7 | % | | | | | | | | |
Total(1) | | $ | 118 | | | 100 | % | | $ | 223 | | | 100 | % | | | | | | | | |
| | | | | | | | | | | | | | | | |
Oil and Gas Revenues: | | | | | | | | | | | | | | |
United States | | $ | 632 | | | 37 | % | | $ | 986 | | | 43 | % | | | | | | | | |
Egypt(1) | | 722 | | | 42 | % | | 891 | | | 38 | % | | | | | | | | |
North Sea | | 352 | | | 21 | % | | 443 | | | 19 | % | | | | | | | | |
Total(1) | | $ | 1,706 | | | 100 | % | | $ | 2,320 | | | 100 | % | | | | | | | | |
(1) Includes revenues attributable to revenues for 2017 and 2016.a noncontrolling interest in Egypt.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | $ Value | | % Contribution | | $ Value | | % Contribution | | $ Value | | % Contribution | | $ Value | | % Contribution |
| | ($ in millions) |
Total Oil Revenues: | | | | | | | | | | | | | | | | |
United States | | $ | 381 |
| | 36 | % | | $ | 377 |
| | 34 | % | | $ | 1,133 |
| | 35 | % | | $ | 1,099 |
| | 36 | % |
Canada | | 14 |
| | 1 | % | | 47 |
| | 4 | % | | 110 |
| | 3 | % | | 132 |
| | 4 | % |
North America | | 395 |
| | 37 | % | | 424 |
| | 38 | % | | 1,243 |
| | 38 | % | | 1,231 |
| | 40 | % |
Egypt (1) | | 442 |
| | 41 | % | | 476 |
| | 43 | % | | 1,351 |
| | 41 | % | | 1,209 |
| | 40 | % |
North Sea | | 233 |
| | 22 | % | | 217 |
| | 19 | % | | 698 |
| | 21 | % | | 617 |
| | 20 | % |
International (1) | | 675 |
| | 63 | % | | 693 |
| | 62 | % | | 2,049 |
| | 62 | % | | 1,826 |
| | 60 | % |
Total (1) | | $ | 1,070 |
| | 100 | % | | $ | 1,117 |
| | 100 | % | | $ | 3,292 |
| | 100 | % | | $ | 3,057 |
| | 100 | % |
Total Natural Gas Revenues: | | | | | | | | | | | | | | | | |
United States | | $ | 97 |
| | 41 | % | | $ | 98 |
| | 37 | % | | $ | 266 |
| | 37 | % | | $ | 222 |
| | 32 | % |
Canada | | 19 |
| | 8 | % | | 36 |
| | 14 | % | | 104 |
| | 14 | % | | 100 |
| | 14 | % |
North America | | 116 |
| | 49 | % | | 134 |
| | 51 | % | | 370 |
| | 51 | % | | 322 |
| | 46 | % |
Egypt (1) | | 98 |
| | 41 | % | | 103 |
| | 39 | % | | 295 |
| | 41 | % | | 298 |
| | 43 | % |
North Sea | | 24 |
| | 10 | % | | 26 |
| | 10 | % | | 61 |
| | 8 | % | | 75 |
| | 11 | % |
International (1) | | 122 |
| | 51 | % | | 129 |
| | 49 | % | | 356 |
| | 49 | % | | 373 |
| | 54 | % |
Total (1) | | $ | 238 |
| | 100 | % | | $ | 263 |
| | 100 | % | | $ | 726 |
| | 100 | % | | $ | 695 |
| | 100 | % |
Total Natural Gas Liquids (NGL) Revenues: | | | | | | | | | | | | | | | | |
United States | | $ | 72 |
| | 89 | % | | $ | 49 |
| | 83 | % | | $ | 194 |
| | 85 | % | | $ | 132 |
| | 82 | % |
Canada | | 3 |
| | 4 | % | | 4 |
| | 7 | % | | 17 |
| | 7 | % | | 11 |
| | 7 | % |
North America | | 75 |
| | 93 | % | | 53 |
| | 90 | % | | 211 |
| | 92 | % | | 143 |
| | 89 | % |
Egypt (1) | | 3 |
| | 4 | % | | 2 |
| | 3 | % | | 9 |
| | 4 | % | | 8 |
| | 5 | % |
North Sea | | 3 |
| | 3 | % | | 4 |
| | 7 | % | | 9 |
| | 4 | % | | 9 |
| | 6 | % |
International (1) | | 6 |
| | 7 | % | | 6 |
| | 10 | % | | 18 |
| | 8 | % | | 17 |
| | 11 | % |
Total (1) | | $ | 81 |
| | 100 | % | | $ | 59 |
| | 100 | % | | $ | 229 |
| | 100 | % | | $ | 160 |
| | 100 | % |
Total Oil and Gas Revenues: | | | | | | | | | | | | | | | | |
United States | | $ | 550 |
| | 40 | % | | $ | 524 |
| | 36 | % | | $ | 1,593 |
| | 38 | % | | $ | 1,453 |
| | 37 | % |
Canada | | 36 |
| | 2 | % | | 87 |
| | 6 | % | | 231 |
| | 5 | % | | 243 |
| | 6 | % |
North America | | 586 |
| | 42 | % | | 611 |
| | 42 | % | | 1,824 |
| | 43 | % | | 1,696 |
| | 43 | % |
Egypt (1) | | 543 |
| | 39 | % | | 581 |
| | 41 | % | | 1,655 |
| | 39 | % | | 1,515 |
| | 39 | % |
North Sea | | 260 |
| | 19 | % | | 247 |
| | 17 | % | | 768 |
| | 18 | % | | 701 |
| | 18 | % |
International (1) | | 803 |
| | 58 | % | | 828 |
| | 58 | % | | 2,423 |
| | 57 | % | | 2,216 |
| | 57 | % |
Total (1) | | $ | 1,389 |
| | 100 | % | | $ | 1,439 |
| | 100 | % | | $ | 4,247 |
| | 100 | % | | $ | 3,912 |
| | 100 | % |
| |
(1) | Includes revenues attributable to a noncontrolling interest in Egypt. |
Production
The Company’s production volumes by country were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended March 31, | | |
| | 2023 | | Increase (Decrease) | | 2022 | | | | | | |
Oil Volume (b/d) | | | | | | | | | | | | |
United States | | 64,913 | | | (7)% | | 69,636 | | | | | | | |
Egypt(1)(2) | | 87,795 | | | 3% | | 85,018 | | | | | | | |
North Sea | | 37,502 | | | 6% | | 35,242 | | | | | | | |
Total | | 190,210 | | | —% | | 189,896 | | | | | | | |
| | | | | | | | | | | | |
Natural Gas Volume (Mcf/d) | | | | | | | | | | | | |
United States | | 412,045 | | | (14)% | | 477,637 | | | | | | | |
Egypt(1)(2) | | 356,350 | | | (8)% | | 386,577 | | | | | | | |
North Sea | | 40,360 | | | 5% | | 38,466 | | | | | | | |
Total | | 808,755 | | | (10)% | | 902,680 | | | | | | | |
| | | | | | | | | | | | |
NGL Volume (b/d) | | | | | | | | | | | | |
United States | | 51,239 | | | (17)% | | 61,711 | | | | | | | |
Egypt(1)(2) | | — | | | NM | | 491 | | | | | | | |
North Sea | | 1,255 | | | (16)% | | 1,498 | | | | | | | |
Total | | 52,494 | | | (18)% | | 63,700 | | | | | | | |
| | | | | | | | | | | | |
BOE per day(3) | | | | | | | | | | | | |
United States | | 184,827 | | | (12)% | | 210,953 | | | | | | | |
Egypt(1)(2) | | 147,186 | | | (2)% | | 149,938 | | | | | | | |
North Sea(4) | | 45,483 | | | 5% | | 43,151 | | | | | | | |
Total | | 377,496 | | | (7)% | | 404,042 | | | | | | | |
(1) Gross oil, natural gas, and NGL production in Egypt were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended March 31, | | |
| | 2023 | | | | 2022 | | | | | | |
Oil (b/d) | | 140,764 | | | | | 134,397 | | | | | | | |
Natural Gas (Mcf/d) | | 545,049 | | | | | 597,812 | | | | | | | |
NGL (b/d) | | — | | | | | 735 | | | | | | | |
(2) Includes net production volumes per day attributable to noncontrolling interests in Egypt of:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended March 31, | | |
| | 2023 | | | | 2022 | | | | | | |
Oil (b/d) | | 58,559 | | | | | 45,332 | | | | | | | |
Natural Gas (Mcf/d) | | 237,686 | | | | | 206,079 | | | | | | | |
NGL (b/d) | | — | | | | | 262 | | | | | | | |
(3) The table below presentsshows 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 third-quarter and year-to-date 2017 and 2016 production andprice ratio between the relative increase or decreasetwo products.
(4) Average sales volumes from the prior period.North Sea for the first quarters of 2023 and 2022 were 46,632 boe/d and 43,668 boe/d, respectively. Sales volumes may vary from production volumes as a result of the timing of liftings.
NM — Not Meaningful
|
| | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | Increase (Decrease) | | 2016 | | 2017 | | Increase (Decrease) | | 2016 |
Oil Volume – b/d | | | | | | | | | | | | |
United States | | 90,883 |
| | (8 | )% | | 98,269 |
| | 89,228 |
| | (17 | )% | | 106,924 |
|
Canada | | 3,441 |
| | (73 | )% | | 12,619 |
| | 8,881 |
| | (33 | )% | | 13,331 |
|
North America | | 94,324 |
| | (15 | )% | | 110,888 |
| | 98,109 |
| | (18 | )% | | 120,255 |
|
Egypt(1)(2) | | 93,749 |
| | (15 | )% | | 110,809 |
| | 97,447 |
| | (7 | )% | | 105,118 |
|
North Sea | | 49,945 |
| | 2 | % | | 49,192 |
| | 49,274 |
| | (11 | )% | | 55,071 |
|
International | | 143,694 |
| | (10 | )% | | 160,001 |
| | 146,721 |
| | (8 | )% | | 160,189 |
|
Total | | 238,018 |
| | (12 | )% | | 270,889 |
| | 244,830 |
| | (13 | )% | | 280,444 |
|
Natural Gas Volume – Mcf/d | | | | | | | | | | | | |
United States | | 404,486 |
| | 2 | % | | 395,062 |
| | 378,625 |
| | (6 | )% | | 404,282 |
|
Canada | | 107,524 |
| | (54 | )% | | 233,635 |
| | 175,787 |
| | (29 | )% | | 248,912 |
|
North America | | 512,010 |
| | (19 | )% | | 628,697 |
| | 554,412 |
| | (15 | )% | | 653,194 |
|
Egypt(1)(2) | | 378,426 |
| | (7 | )% | | 405,863 |
| | 389,533 |
| | (4 | )% | | 403,832 |
|
North Sea | | 50,057 |
| | (28 | )% | | 69,509 |
| | 42,800 |
| | (36 | )% | | 66,884 |
|
International | | 428,483 |
| | (10 | )% | | 475,372 |
| | 432,333 |
| | (8 | )% | | 470,716 |
|
Total | | 940,493 |
| | (15 | )% | | 1,104,069 |
| | 986,745 |
| | (12 | )% | | 1,123,910 |
|
NGL Volume – b/d | | | | | | | | | | | | |
United States | | 49,149 |
| | (13 | )% | | 56,355 |
| | 48,063 |
| | (14 | )% | | 55,897 |
|
Canada | | 2,183 |
| | (64 | )% | | 6,039 |
| | 3,780 |
| | (36 | )% | | 5,879 |
|
North America | | 51,332 |
| | (18 | )% | | 62,394 |
| | 51,843 |
| | (16 | )% | | 61,776 |
|
Egypt(1)(2) | | 916 |
| | (19 | )% | | 1,124 |
| | 917 |
| | (18 | )% | | 1,120 |
|
North Sea | | 1,219 |
| | (28 | )% | | 1,697 |
| | 1,044 |
| | (33 | )% | | 1,557 |
|
International | | 2,135 |
| | (24 | )% | | 2,821 |
| | 1,961 |
| | (27 | )% | | 2,677 |
|
Total | | 53,467 |
| | (18 | )% | | 65,215 |
| | 53,804 |
| | (17 | )% | | 64,453 |
|
BOE per day(3) | | | | | | | | | | | | |
United States | | 207,447 |
| | (6 | )% | | 220,468 |
| | 200,396 |
| | (13 | )% | | 230,202 |
|
Canada | | 23,544 |
| | (59 | )% | | 57,597 |
| | 41,959 |
| | (31 | )% | | 60,695 |
|
North America | | 230,991 |
| | (17 | )% | | 278,065 |
| | 242,355 |
| | (17 | )% | | 290,897 |
|
Egypt(2) | | 157,737 |
| | (12 | )% | | 179,575 |
| | 163,286 |
| | (6 | )% | | 173,544 |
|
North Sea(4) | | 59,507 |
| | (5 | )% | | 62,475 |
| | 57,451 |
| | (15 | )% | | 67,775 |
|
International | | 217,244 |
| | (10 | )% | | 242,050 |
| | 220,737 |
| | (9 | )% | | 241,319 |
|
Total | | 448,235 |
| | (14 | )% | | 520,115 |
| | 463,092 |
| | (13 | )% | | 532,216 |
|
| |
(1) | Gross oil, natural gas, and NGL production in Egypt for the third quarter and nine-month period of 2017 and 2016 were as follows: |
|
| | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
Oil (b/d) | | 201,151 |
| | 210,755 |
| | 196,781 |
| | 210,939 |
|
Natural Gas (Mcf/d) | | 818,350 |
| | 826,548 |
| | 813,880 |
| | 828,950 |
|
NGL (b/d) | | 1,526 |
| | 1,853 |
| | 1,514 |
| | 1,918 |
|
| |
(2) | Includes production volumes per day attributable to a noncontrolling interest in Egypt for the third quarter and nine-month period of 2017 and 2016 of: |
|
| | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
Oil (b/d) | | 31,275 |
| | 36,839 |
| | 32,573 |
| | 34,964 |
|
Natural Gas (Mcf/d) | | 126,459 |
| | 135,233 |
| | 130,263 |
| | 134,591 |
|
NGL (b/d) | | 305 |
| | 374 |
| | 306 |
| | 373 |
|
| |
(3) | The table shows production on a barrel of oil equivalent basis (boe) 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 were 57,207 boe/d and 65,171 boe/d for the third quarter of 2017 and 2016, respectively, and 57,963 boe/d and 67,222 boe/d for the first nine months of 2017 and 2016, 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:
The table below presents third-quarter and year-to-date 2017 and 2016 pricing and the relative increase or decrease from the prior period. | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended March 31, | | |
| | 2023 | | Increase (Decrease) | | 2022 | | | | | | |
Average Oil Price – Per barrel | | | | | | | | | | | | |
United States | | $ | 75.16 | | | (21)% | | $ | 95.58 | | | | | | | |
Egypt | | 79.58 | | | (23)% | | 103.22 | | | | | | | |
North Sea | | 81.57 | | | (20)% | | 102.20 | | | | | | | |
Total | | 78.48 | | | (22)% | | 100.23 | | | | | | | |
| | | | | | | | | | | | |
Average Natural Gas Price – Per Mcf | | | | | | | | | | | | |
United States | | $ | 2.28 | | | (46)% | | $ | 4.25 | | | | | | | |
Egypt | | 2.89 | | | 2% | | 2.83 | | | | | | | |
North Sea | | 17.58 | | | (46)% | | 32.35 | | | | | | | |
Total | | 3.28 | | | (30)% | | 4.70 | | | | | | | |
| | | | | | | | | | | | |
Average NGL Price – Per barrel | | | | | | | | | | | | |
United States | | $ | 23.61 | | | (36)% | | $ | 36.67 | | | | | | | |
Egypt | | — | | | NM | | 77.81 | | | | | | | |
North Sea | | 56.92 | | | (24)% | | 74.64 | | | | | | | |
Total | | 24.76 | | | (35)% | | 38.33 | | | | | | | |
NM — Not Meaningful
|
| | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | Increase (Decrease) | | 2016 | | 2017 | | Increase (Decrease) | | 2016 |
Average Oil Price - Per barrel | | | | | | | | | | | | |
United States | | $ | 45.68 |
| | 9 | % | | $ | 41.83 |
| | $ | 46.54 |
| | 24 | % | | $ | 37.53 |
|
Canada | | 42.23 |
| | 5 | % | | 40.17 |
| | 45.25 |
| | 26 | % | | 36.04 |
|
North America | | 45.56 |
| | 9 | % | | 41.65 |
| | 46.42 |
| | 24 | % | | 37.36 |
|
Egypt | | 51.23 |
| | 10 | % | | 46.54 |
| | 50.78 |
| | 21 | % | | 41.97 |
|
North Sea | | 53.11 |
| | 17 | % | | 45.47 |
| | 51.35 |
| | 24 | % | | 41.28 |
|
International | | 51.87 |
| | 12 | % | | 46.20 |
| | 50.97 |
| | 22 | % | | 41.74 |
|
Total | | 49.34 |
| | 11 | % | | 44.35 |
| | 49.15 |
| | 23 | % | | 39.86 |
|
Average Natural Gas Price - Per Mcf | | | | | | | | | | | | |
United States | | $ | 2.62 |
| | (2 | )% | | $ | 2.66 |
| | $ | 2.58 |
| | 29 | % | | $ | 2.00 |
|
Canada | | 1.90 |
| | 11 | % | | 1.71 |
| | 2.17 |
| | 48 | % | | 1.47 |
|
North America | | 2.47 |
| | 7 | % | | 2.31 |
| | 2.45 |
| | 36 | % | | 1.80 |
|
Egypt | | 2.81 |
| | 2 | % | | 2.75 |
| | 2.77 |
| | 3 | % | | 2.69 |
|
North Sea | | 5.27 |
| | 27 | % | | 4.14 |
| | 5.27 |
| | 28 | % | | 4.12 |
|
International | | 3.10 |
| | 5 | % | | 2.96 |
| | 3.02 |
| | 4 | % | | 2.89 |
|
Total | | 2.75 |
| | 6 | % | | 2.59 |
| | 2.70 |
| | 19 | % | | 2.26 |
|
Average NGL Price - Per barrel | | | | | | | | | | | | |
United States | | $ | 15.77 |
| | 64 | % | | $ | 9.59 |
| | $ | 14.75 |
| | 71 | % | | $ | 8.65 |
|
Canada | | 15.80 |
| | 159 | % | | 6.10 |
| | 16.39 |
| | 148 | % | | 6.61 |
|
North America | | 15.77 |
| | 70 | % | | 9.25 |
| | 14.87 |
| | 76 | % | | 8.46 |
|
Egypt | | 36.47 |
| | 30 | % | | 28.12 |
| | 35.98 |
| | 31 | % | | 27.54 |
|
North Sea | | 26.92 |
| | 10 | % | | 24.45 |
| | 30.51 |
| | 40 | % | | 21.82 |
|
International | | 31.02 |
| | 20 | % | | 25.91 |
| | 33.07 |
| | 37 | % | | 24.21 |
|
Total | | 16.38 |
| | 64 | % | | 9.97 |
| | 15.53 |
| | 70 | % | | 9.11 |
|
Third-Quarter 2017First-Quarter 2023 compared to Third-Quarter 2016First-Quarter 2022
Crude Oil Revenues Crude oil revenues for the thirdfirst quarter of 20172023 totaled $1.1$1.4 billion, a $47$367 million decrease from the comparative 20162022 quarter. A 1222 percent decrease in average daily production reduced third-quarter 2017realized prices decreased first-quarter 2023 oil revenues by $172$372 million compared to the prior-year quarter, while 11 percenta slightly higher average realized pricesdaily production increased revenues by $125$5 million. Crude oil revenues accounted for 7779 percent of Apache’stotal oil and gas production revenues and 5350 percent of its equivalentworldwide production in the thirdfirst quarter of 2017.2023. Crude oil prices realized in the thirdfirst quarter of 20172023 averaged $49.34$78.48 per barrel, compared with $44.35$100.23 per barrel in the comparative prior-year quarter.
WorldwideThe Company’s worldwide oil production decreased 32.9increased 0.3 Mb/d to 238.0190.2 Mb/d induring the thirdfirst quarter of 20172023 from the comparative prior-year period, primarily the result of the Canada divestitures and natural decline. Decreases were slightly offset by a 2 percent increase in the North Sea region, a result of the Callater field coming online in late May 2017.increased drilling activity and recompletions, partially offset by natural production decline across all assets.
Natural Gas Revenues Gas revenues for the thirdfirst quarter of 20172023 totaled $238 million, a $25$142 million decrease from the comparative 20162022 quarter. A 1530 percent decrease in average daily production reduced third-quarterrealized prices decreased first-quarter 2023 natural gas revenues by $42$115 million compared to the prior-year quarter, while 610 percent higherlower average realized prices increaseddaily production decreased revenues by $17$27 million. Natural gas revenues accounted for 1714 percent of Apache’s oil and gas production revenues and 35 percent of its equivalent production during the third quarter of 2017.
Worldwide natural gas production decreased 164 MMcf/d to 940 MMcf/d in the third quarter of 2017 from the comparative prior-year period, primarily the result of the Canada divestitures and maintenance activity in the North Sea. Decreases were slightly offset by a 2 percent increase in the U.S., primarily on drilling activity at Alpine High.
NGL Revenues NGL revenues for the third quarter of 2017 totaled $81 million, a $22 million increase from the comparative 2016 quarter. An 18 percent decrease in average daily production reduced third-quarter 2017 revenues by approximately $17 million, while 64 percent higher average realized prices increased revenues by $39 million. NGLs accounted for 6 percent of Apache’s oil and gas production revenues and 12 percent of its equivalent production during the third quarter of 2017.
Worldwide production of NGLs decreased 11.7 Mb/d to 53.5 Mb/d in the third quarter of 2017 from the comparative prior-year period, primarily the result of the Canada divestitures and natural decline in all regions.
Year-to-Date 2017 compared to Year-to-Date 2016
Crude Oil Revenues Crude oil revenues for the first nine months of 2017 totaled $3.3 billion, a $235 million increase from the comparative 2016 period. A 13 percent decrease in average daily production reduced 2017 oil revenues by $478 million compared to the prior-year period, while 23 percent higher average realized prices increased revenues by $713 million. Crude oil accounted for 78 percent of Apache’s oil and gas production revenues and 53 percent of its equivalent production for the first nine months of 2017. Crude oil prices realized in the first nine months of 2017 averaged $49.15 per barrel, compared with $39.86 per barrel in the comparative prior-year period.
Worldwide production decreased 35.6 Mb/d to 244.8 Mb/d in the first nine months of 2017 from the comparative prior-year period, primarily the result of the Canada divestitures and natural decline in all regions.
Natural Gas Revenues Gas revenues for the first nine months of 2017 totaled $726 million, a $31 million increase from the comparative 2016 period. A 12 percent decrease in average daily production reduced 2017 natural gas revenues by $104 million compared to the prior-year period, while 19 percent higher average realized prices increased revenues by $135 million. Natural gas accounted for 17 percent of Apache’stotal oil and gas production revenues and 36 percent of its equivalentworldwide production during the first nine monthsquarter of 2017.
Worldwide2023. The Company’s worldwide natural gas production decreased 13793.9 MMcf/d to 987808.8 MMcf/d induring the first nine monthsquarter of 20172023 from the comparative prior-year period, primarily thea result of the Canada divestitures, maintenance activities in the North Sea,natural production decline across all assets, partially offset by increased drilling activity and natural decline in all regions.recompletions.
NGL Revenues NGL revenues for the first nine monthsquarter of 20172023 totaled $229$118 million, a $69$105 million increasedecrease from the comparative 2016 period.2022 quarter. A 1735 percent decrease in average production reduced 2017realized prices decreased first-quarter 2023 NGL revenues by $45$79 million compared to the prior-year period,quarter, while 7018 percent higherlower average realized prices increaseddaily production decreased revenues by $114$26 million. NGLsNGL revenues accounted for 57 percent of Apache’stotal oil and gas production revenues and 1114 percent of its equivalentworldwide production forduring the first nine monthsquarter of 2017.
Worldwide2023. The Company’s worldwide NGL production of NGLs decreased 10.611.2 Mb/d to 53.852.5 Mb/d induring the first nine monthsquarter of 20172023 from the comparative prior-year period, primarily thea result of natural production decline, partially offset by increased drilling activity and recompletions.
Altus Midstream Revenues
Prior to the Canada divestituresBCP Business Combination and associated deconsolidation of Altus on February 22, 2022, Altus Midstream’s services revenues generated through its fee-based contractual arrangements with the Company totaled $16 million during the first quarter of 2022. These revenues were eliminated upon consolidation.
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 declinegas takeaway obligations. Sales related to these purchased volumes totaled $239 million and $349 million during the first quarters of 2023 and 2022, respectively. Purchased oil and gas sales were offset by associated purchase costs of $216 million and $351 million during the first quarters of 2023 and 2022, respectively. Gross purchased oil and gas sales values were lower in all regions.
the first quarter primarily due to lower average natural gas prices in the first quarter of 2023 compared to the prior-year period.
Operating Expenses
The table below presents a comparison of Apache’sCompany’s operating expenses on an absolute dollar basis and a boe basis. Apache’s discussion may reference expenses on a boe basis, on an absolute dollar basis or both, depending on their relevance. Operating expenses include costs attributable to a noncontrolling interest in Egypt.were as follows:
| | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | | | | | | | |
| | (In millions) |
Lease operating expenses | | $ | 314 | | | $ | 344 | | | | | |
Gathering, processing, and transmission | | 73 | | | 81 | | | | | |
Purchased oil and gas costs | | 216 | | | 351 | | | | | |
Taxes other than income | | 50 | | | 70 | | | | | |
Exploration | | 44 | | | 25 | | | | | |
General and administrative | | 58 | | | 151 | | | | | |
Transaction, reorganization, and separation | | 4 | | | 14 | | | | | |
Depreciation, depletion, and amortization: | | | | | | | | |
Oil and gas property and equipment | | 301 | | | 278 | | | | | |
Gathering, processing, and transmission assets | | 2 | | | 5 | | | | | |
Other assets | | 5 | | | 8 | | | | | |
Asset retirement obligation accretion | | 28 | | | 29 | | | | | |
| | | | | | | | |
Financing costs, net | | 49 | | | 140 | | | | | |
Total Operating Expenses | | $ | 1,144 | | | $ | 1,496 | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
| | (In millions) | | (Per boe) | | (In millions) | | (Per boe) |
Lease operating expenses(1) | | $ | 358 |
| | $ | 382 |
| | $ | 8.74 |
| | $ | 7.94 |
| | $ | 1,066 |
| | $ | 1,119 |
| | $ | 8.42 |
| | $ | 7.68 |
|
Gathering and transportation(1) | | 39 |
| | 51 |
| | 0.91 |
| | 1.08 |
| | 144 |
| | 155 |
| | 1.13 |
| | 1.06 |
|
Taxes other than income | | 46 |
| | 9 |
| | 1.12 |
| | 0.19 |
| | 117 |
| | 85 |
| | 0.93 |
| | 0.58 |
|
Exploration | | 231 |
| | 161 |
| | 5.60 |
| | 3.36 |
| | 431 |
| | 347 |
| | 3.41 |
| | 2.38 |
|
General and administrative | | 98 |
| | 102 |
| | 2.39 |
| | 2.13 |
| | 307 |
| | 298 |
| | 2.43 |
| | 2.04 |
|
Transaction, reorganization, and separation | | 20 |
| | 12 |
| | 0.48 |
| | 0.25 |
| | 14 |
| | 36 |
| | 0.11 |
| | 0.24 |
|
Depreciation, depletion, and amortization: | | | | | | | | | | | | | | | | |
Oil and gas property and equipment(1) | | 524 |
| | 610 |
| | 12.76 |
| | 12.67 |
| | 1,598 |
| | 1,875 |
| | 12.63 |
| | 12.87 |
|
Other assets | | 35 |
| | 38 |
| | 0.83 |
| | 0.79 |
| | 109 |
| | 120 |
| | 0.86 |
| | 0.82 |
|
Asset retirement obligation accretion | | 30 |
| | 40 |
| | 0.75 |
| | 0.83 |
| | 103 |
| | 116 |
| | 0.82 |
| | 0.79 |
|
Impairments | | — |
| | 836 |
| | — |
| | 17.47 |
| | 8 |
| | 1,009 |
| | 0.06 |
| | 6.92 |
|
Financing costs, net | | 101 |
| | 102 |
| | 2.45 |
| | 2.13 |
| | 300 |
| | 311 |
| | 2.38 |
| | 2.13 |
|
(1) For expenses impacted by the timing of 2017 liftings in the North Sea, per-boe calculations are based on sales volumes rather than production volumes.
Lease Operating Expenses (LOE)
LOE decreased $24$30 million or 6 percent, forin the thirdfirst quarter of 2017, and decreased $53 million, or 5 percent for2023 from the first nine months of 2017, on an absolute dollar basis relative to the comparable periods of 2016.comparative prior-year period. On a per-unit basis, LOE increased 10decreased 7 percent to $8.74 per boe forin the thirdfirst quarter of 2017,2023 from the comparative prior-year period. The decrease was primarily driven by the impact from changes in foreign currency exchange rates against the US dollar and 10 percent to $8.42 per boemark-to-market adjustments for cash-based stock compensation expense resulting from changes in APA’s stock price. These decreases were partially offset by overall higher labor costs, chemical and other operating costs trending with global inflation and increased workover activity in the U.S.
Gathering, Processing, and Transmission (GPT)
The Company’s GPT expenses were as follows:
| | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | | | | | | | |
| | (In millions) |
Third-party processing and transmission costs | | $ | 49 | | | $ | 66 | | | | | |
Midstream service costs – ALTM | | — | | | 18 | | | | | |
Midstream service costs – Kinetik | | 24 | | | 10 | | | | | |
Upstream processing and transmission costs | | 73 | | | 94 | | | | | |
Midstream operating expenses | | — | | | 5 | | | | | |
Intersegment eliminations | | — | | | (18) | | | | | |
Total Gathering, processing, and transmission | | $ | 73 | | | $ | 81 | | | | | |
GPT costs decreased $8 million in the first nine monthsquarter of 2017,2023 from the comparative prior-year period, the result of lower upstream processing and transmission costs, partially offset by impacts of the BCP Business Combination. Upstream processing and transmission costs decreased $21 million in the first quarter of 2023 from the comparative prior-year period, primarily driven by a decrease in production volumes when compared to the prior-year period. Costs for services provided by ALTM in the first quarter of 2022 and prior to the BCP Business Combination totaling $18 million were eliminated in the Company’s consolidated financial statements and reflected as “Intersegment eliminations” in the table above. Subsequent to the BCP Business Combination and the Company’s deconsolidation of Altus on February 22, 2022, these midstream services continue to be provided by Kinetik Holdings Inc. (Kinetik) but are no longer eliminated. Midstream services provided by Kinetik totaled $24 million and $10 million in the first quarters of 2023 and 2022, respectively.
Purchased Oil and Gas Costs
Purchased oil and gas costs totaled $216 million during the first quarter of 2023 compared to $351 million during the first quarter of 2022. Purchased oil and gas costs were offset by associated purchase sales of $239 million during the first quarter of 2023 compared to $349 million during the first quarter of 2022, as discussed above.
Taxes Other Than Income
Taxes other than income decreased $20 million from the first quarter of 2022 primarily from lower severance taxes driven by lower commodity prices as compared to the prior-year periods. period.
Exploration Expenses
The per-barrel increaseCompany’s exploration expenses were as follows:
| | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | | | | | | | |
| | (In millions) |
Unproved leasehold impairments | | $ | 5 | | | $ | 4 | | | | | |
Dry hole expense | | 27 | | | 5 | | | | | |
Geological and geophysical expense | | 1 | | | 1 | | | | | |
Exploration overhead and other | | 11 | | | 15 | | | | | |
Total Exploration | | $ | 44 | | | $ | 25 | | | | | |
Exploration expenses for both comparative periods isthe first quarter of 2023 increased $19 million from the first quarter of 2022 primarily the result of a declinehigher dry hole expenses in production in all regions and generally rising costs commensurate with higher commodity prices.
Gathering and Transportation Gathering and transportation costs totaled $39 million and $144 million in the third quarter and first nine months of 2017, respectively,Egypt, partially offset by a decrease of $12 million from the third quarter of 2016in geological and a decrease of $11 million from the first nine months of 2016. The decrease was directly related to the Canadian divestitures.
Taxes other than Income Taxes other than income totaled $46 million and $117 million for the third quarter and first nine months of 2017, respectively, an increase of $37 million and $32 million from the third quarter and first nine months of 2016, respectively. Third-quarter 2017 expense consists primarily of severance and ad valorem taxes, which combined increased $4 million on higher commodity prices during the third quarter compared to the prior year quarter. For the first nine months of 2017, severance taxgeophysical expense and ad valorem tax expense increased $12exploration overhead.
General and Administrative (G&A) Expenses
G&A expenses decreased $93 million and $5 million, respectively, compared to the first nine months of 2016. In addition, in the third quarter and first nine months of 2016, Apache recognized a $33 million benefit related to the U.K. Petroleum Revenue Tax (PRT). The U.K. PRT rate, historically assessed on qualifying fields in the U.K. North Sea, was reduced to zero during 2016.
Exploration Expense Exploration expense includes unproved leasehold impairments, exploration dry hole expense, geological and geophysical expenses, and the costs of maintaining and retaining unproved leasehold properties. Exploration expenses in the third quarter and first nine months of 2017 increased $70 million and $84 million, respectively, compared to the prior-year periods.
The following table presents a summary of exploration expense:
|
| | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (In millions) |
Unproved leasehold impairments | | $ | 160 |
| | $ | 114 |
| | $ | 214 |
| | $ | 222 |
|
Dry hole expense | | 38 |
| | 7 |
| | 136 |
| | 38 |
|
Geological and geophysical expense | | 12 |
| | 21 |
| | 24 |
| | 30 |
|
Exploration overhead and other | | 21 |
| | 19 |
| | 57 |
| | 57 |
|
| | $ | 231 |
| | $ | 161 |
| | $ | 431 |
| | $ | 347 |
|
Unproved leasehold impairments in the third quarter of 2017 increased $46 million compared to2022. The decrease in expenses for the thirdfirst quarter of 2016, primarily relate to legacy acreage and a reallocation of capital budgets in the U.S. For the first nine months of 2017, unproved leasehold impairments decreased $8 million2023 compared to the prior-year period was primarily a result of stabilizing commoditydriven by lower cash-based stock compensation expense resulting from changes in APA’s stock price.
Transaction, Reorganization, and leasehold prices. Dry hole expense increased $31Separation (TRS) Costs
TRS costs decreased $10 million and $98 million for the third quarter and first nine months of 2017, respectively, from the comparative prior-year periods primarily related to unsuccessful international offshore exploration.
General and Administrative (G&A) Expenses G&A expense for the thirdfirst quarter of 2017 was $4 million lower than2022. The decrease in costs during the thirdfirst quarter of 2016. For the first nine months of 2017, G&A expense increased $9 million2023 compared to the prior-year period was primarily related to non-cash stock-based compensation expense and other corporate costs.
Transaction, Reorganization, and Separation (TRS) Costs The Company recorded TRS expensea result of $20 million and $14 million fortransaction costs from the third quarter and first nine months of 2017, respectively, related to asset divestituresBCP Business Combination in the U.S. and Canada and employee separation. The Company recorded TRS expensefirst quarter of $12 million and $36 million in the third quarter and first nine months of 2016, respectively, related to various asset divestitures, company reorganization, and employee separation.2022.
Depreciation, Depletion, and Amortization (DD&A)Oil and gas property
DD&A expense of $524 million inexpenses on the third quarter of 2017 decreased $86 million compared to the third quarter of 2016. For the first nine months of 2017, oil and gas property DD&A expense decreased $277 million compared to the prior-year period. The Company’s oil and gas property DD&A rateproperties increased $0.09 per boe and decreased $0.24 per boe in the third quarter and first nine months of 2017, respectively, compared to the comparable prior-year periods. The primary factor driving lower absolute dollar expense was a decrease in production volumes$23 million from the comparative prior-year periods.
Impairments The Company did not record any asset impairments in connection with fair value assessments in the third quarter of 2017. During the first quarter of 2017,2022. The Company’s DD&A rate on its oil and gas properties increased $0.82 per boe from the Company recorded asset impairmentsfirst quarter of 2022 driven by general cost inflation. The increase on an absolute basis was also impacted by an increase in connection with fair value assessments totaling $8 million for a U.K. PRT decommissioning asset that is no longer expected to be realizable from future abandonment activitiescapital investment activity in Egypt and acquisitions in the North Sea. The Company recorded $836 million and $1.0 billion of impairments in connection with fair value assessments inU.S. over the third quarter and first nine months of 2016, respectively. For more information regarding asset impairments, please refer to “Fair Value Measurements” within Note 1—Summary of Significant Accounting Policies in the Notes to Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q.past year.
Financing Costs, Net
The Company’s Financing costs incurred during the period comprised the following:were as follows:
|
| | | | | | | | | | | | | | | | |
| | For the Quarter Ended September 30, | | For the Nine Months Ended September 30, |
| | 2017 | | 2016 | | 2017 | | 2016 |
| | (In millions) |
Interest expense | | $ | 113 |
| | $ | 116 |
| | $ | 344 |
| | $ | 348 |
|
Amortization of deferred loan costs | | 3 |
| | 2 |
| | 7 |
| | 5 |
|
Capitalized interest | | (12 | ) | | (13 | ) | | (39 | ) | | (36 | ) |
Loss on extinguishment of debt | | — |
| | — |
| | 1 |
| | — |
|
Interest income | | (3 | ) | | (3 | ) | | (13 | ) | | (6 | ) |
Financing costs, net | | $ | 101 |
| | $ | 102 |
| | $ | 300 |
| | $ | 311 |
|
| | | | | | | | | | | | | | | | | | |
| | For the Quarter Ended March 31, | | |
| | 2023 | | 2022 | | | | |
| | | | | | | | |
| | (In millions) |
Interest expense | | $ | 75 | | | $ | 90 | | | | | |
Amortization of debt issuance costs | | 1 | | | 2 | | | | | |
| | | | | | | | |
(Gain) loss on extinguishment of debt | | (9) | | | 67 | | | | | |
Interest income | | (2) | | | (4) | | | | | |
Interest income from APA Corporation, net | | (16) | | | (15) | | | | | |
Total Financing costs, net | | $ | 49 | | | $ | 140 | | | | | |
Net financing costs decreased $1$91 million and $11 million in the third quarter and first nine months of 2017, respectively. The $11 million decrease infrom the first nine monthsquarter of 2017 was2022, primarily the result of higher capitalized interestlosses incurred on the extinguishment of debt during the first quarter of 2022 and interest income.gains on extinguishment of debt in the first quarter of 2023.
Provision for Income Taxes
The Company estimates its annual effective income tax rate for continuing operations in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Non-cash impairments ofon 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.
In August 2017, Apache completedDuring the salefirst quarter of ACL. For more information regarding this transaction, please refer to Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q. As a result of this transaction, Apache recorded a deferred tax asset associated with its realizable capital loss on the sale of ACL, and a decrease in2023, the Company’s deferred tax liability associated with its investment in foreign subsidiaries. In the third and second quarters of 2017, the Company recorded a $2 million deferred income tax expense and a $674 million deferred income tax benefit, respectively, in connection with these transactions.
Apache’s third quarter of 2017 effective income tax rate was primarily impacted by gains on the sale of oil and gas properties and a $30 million current tax benefit associated with U.S. federal income tax credits. On September 15, 2016, U.K. Finance Act 2016 received Royal Assent. Under the enacted legislation, the corporate income tax rate on North Sea oil and gas profits was reduced from 50 percent to 40 percent effective January 1, 2016. As a result of the enacted legislation, in the third quarter of 2016 the Company recorded a deferred tax benefit of $235 millionexpense related to the remeasurement of taxes in the Company’s December 31, 2015 U.K. deferred income tax liability.
Apache’s 2017 year-to-date effective income tax rate is primarily impacted byas a result of the enactment of Finance Act 2023 on January 10, 2023, and a decrease in the amount of valuation allowance against its U.S. deferred taxes associated with its investments in foreign subsidiaries, gains ontax assets. During the salefirst quarter of oil and gas properties, non-cash impairments of2022, the Company’s PRT decommissioning asset, and the current tax benefit associated with U.S. federal income tax credits. Apache’s 2016 year-to-date effective income tax rate was primarily impacted by non-cash impairmentsthe gain associated with deconsolidation of Altus, the carrying valuegain on sale of certain non-core mineral rights in the Company’s oilDelaware Basin, and gas properties, non-cash impairments of the Company’s PRT decommissioning asset, the impact of the change in U.K. statutory income tax rate, and an increasea decrease in the amount of valuation allowances onallowance against its U.S. and Canadian deferred tax assets.
ApacheOn January 10, 2023, Finance Act 2023 was enacted, receiving Royal Assent, and included amendments to the Energy (Oil and Gas) Profits Levy Act of 2022, increasing the levy from a 25 percent rate to a 35 percent rate, effective for the period of January 1, 2023 through March 31, 2028. Under U.S. GAAP, the financial statement impact of new legislation is recorded in the period of enactment. Therefore, in the first quarter of 2023, the Company recorded a deferred tax expense of $174 million related to the remeasurement of the December 31, 2022 U.K. deferred tax liability.
On August 16, 2022, the U.S. enacted the Inflation Reduction Act of 2022 (IRA). The IRA includes a new 15 percent corporate alternative minimum tax (Corporate AMT) on applicable corporations with an average annual financial statement income that exceeds $1 billion for any three consecutive years preceding the tax year at issue. The Corporate AMT is effective for tax years beginning after December 31, 2022. The Company is continuing to evaluate the provisions of the IRA and awaits further guidance from the U.S. Treasury Department to properly assess the impact of these provisions on the Company. Under the existing guidance, the Company does not believe the IRA will have a material impact for 2023.
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. However, given the Company’s current and anticipated future domestic earnings, the Company believes that there is a reasonable possibility that within the next 12 months sufficient positive evidence may become available to allow the Company to reach a conclusion that a significant portion of the U.S. valuation allowance will no longer be needed. A release of the valuation allowance would result in the recognition of certain deferred tax assets and a decrease to income tax expense, which could be material, for the period the release is recorded.
The Company and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various statestates and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. In April 2017,
Critical Accounting Estimates
The Company prepares its financial statements and accompanying notes in conformity with accounting principles generally accepted in the Internal Revenue Service (IRS) beganU.S., which require management to make estimates and assumptions about future events that affect reported amounts in the financial statements and the accompanying notes. The Company identifies certain accounting policies involving estimation as critical accounting estimates based on, among other things, their auditimpact on the portrayal of the Company’s 2014 income tax year. The Company is also under auditfinancial condition, results of operations, or liquidity, as well as the degree of difficulty, subjectivity, and complexity in various statestheir deployment. Critical accounting estimates address accounting matters that are inherently uncertain due to unknown future resolution of such matters. Management routinely discusses the development, selection, and in mostdisclosure of each critical accounting estimate. For a discussion of the Company’s foreign jurisdictions as part of its normal course of business.
Capital Resources and Liquidity
Operating cash flows aremost critical accounting estimates, please see the Company’s primary sourceAnnual Report on Form 10-K for the fiscal year ended December 31, 2022. Some of liquidity. The Company may also elect to use available cash on hand, available committed 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.
Apache’s operating cash flows, both in the short term and the long term, are impacted by highly volatilemore significant estimates include reserve estimates, oil and natural gas prices, as well asexploration costs, offshore decommissioning contingency, long-lived asset impairments, asset retirement obligations, and sales volumes. Significantincome taxes.
New Accounting Pronouncements
There were no material changes in commodity prices impact Apache’s revenues, earnings, and cash flows. These changes potentially impact Apache’s liquidity if costs do not trend with changes in commodity prices. Historically, costs have trended with commodity prices, albeit with a lag. Sales volumes also impact cash flows; however, they have a less volatile impact in the short term.
Apache’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 Apache’s drilling program and its ability to add reserves economically. Changes in commodity prices also impact estimated quantities of proved reserves. In the first nine months of 2017, Apache recognized positive reserve revisions of approximately 2 percent of its year-end 2016 estimated proved reserves as a result of higher prices.
Apache 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 Apache’s capital spending program, repayment of debt maturities, payment of dividends, and any amount that may ultimately be paid in connection with commitments and contingencies.
For additional information, please see Part I, Items 1 and 2, “Business and Properties,” and Item 1A, “Risk Factors,”recently issued or adopted accounting standards from those disclosed in the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.2022.
Sources and Uses of Cash
The following table presents the sources and uses of the Company’s cash, cash equivalents, and restricted cash for the periods presented.
|
| | | | | | | | |
| | For the Nine Months Ended September 30, |
| | 2017 | | 2016 |
| | (In millions) |
Sources of Cash, Cash Equivalents, and Restricted Cash: | | | | |
Net cash provided by operating activities | | $ | 1,760 |
| | $ | 1,634 |
|
Proceeds from sale of oil and gas properties | | 1,404 |
| | 74 |
|
Other | | — |
| | 38 |
|
| | 3,164 |
| | 1,746 |
|
Uses of Cash and Cash Equivalents: | | | | |
Capital expenditures(1) | | $ | 1,855 |
| | $ | 1,314 |
|
Leasehold and property acquisitions | | 142 |
| | 169 |
|
Payments on fixed-rate debt | | 70 |
| | 1 |
|
Dividends paid | | 285 |
| | 284 |
|
Distributions to noncontrolling interest | | 212 |
| | 215 |
|
Other | | 35 |
| | — |
|
| | 2,599 |
| | 1,983 |
|
Increase (decrease) in cash, cash equivalents, and restricted cash | | $ | 565 |
| | $ | (237 | ) |
| |
(1) | The table presents capital expenditures on a cash basis; therefore, the amounts may differ from those discussed elsewhere in this document, which include accruals. |
Net Cash Provided by Operating Activities Operating cash flows are Apache’s primary source of capital and liquidity and are impacted, both in the short term and the long term, by volatile oil and natural gas prices. The factors that determine operating cash flow 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, which affect earnings but do not affect cash flows.
Net cash provided by operating activities for the first nine months of 2017 totaled $1.8 billion, an increase of $126 million from the first nine months of 2016. The increase primarily reflects higher commodity prices compared to the prior-year period.
For a detailed discussion of commodity prices, production, and expenses, refer to the “Results of Operations” of 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, please see the statement of consolidated cash flows in Item 1, Financial Statements of this Quarterly Report on Form 10-Q.
Asset Divestitures The Company recorded proceeds from asset divestitures totaling $1.4 billion and $74 million in the first nine months of 2017 and 2016, respectively. For more information regarding the Company’s acquisitions and divestitures, please see Note 2—Acquisitions and Divestitures in the Notes to Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q.
Capital Expenditures Worldwide exploration and development (E&D) cash expenditures for the first nine months of 2017 totaled $1.5 billion, compared to $1.3 billion for the first nine months of 2016. Apache operated an average of 36 drilling rigs during the third quarter of 2017.
Apache also completed leasehold and property acquisitions totaling $142 million and $169 million during the first nine months of 2017 and 2016, respectively.
Apache’s investment in gas gathering, transmission, and processing (GTP) facilities totaled $384 million and $33 million during the first nine months of 2017 and 2016, respectively. Expenditures in 2017 primarily comprise investments in infrastructure for the Alpine High play.
Dividends For the nine-month periods ended September 30, 2017 and 2016, the Company paid $285 million and $284 million, respectively, in dividends on its common stock.
Liquidity
The following table presents a summary of the Company’s key financial indicators at the dates presented:
|
| | | | | | | | |
| | September 30, 2017 | | December 31, 2016 |
| | (In millions) |
Cash and cash equivalents | | $ | 1,846 |
| | $ | 1,377 |
|
Total debt | | 8,483 |
| | 8,544 |
|
Equity | | 8,377 |
| | 7,679 |
|
Available committed borrowing capacity | | 3,500 |
| | 3,500 |
|
Cash and cash equivalents The Company had $1.8 billion in cash and cash equivalents as of September 30, 2017, compared to $1.4 billion at December 31, 2016. At September 30, 2017, approximately $1.3 billion of the cash was held by foreign subsidiaries. The cash held by foreign subsidiaries should not be subject to additional U.S. income taxes if repatriated. The majority of the cash is invested in highly liquid, investment grade securities with maturities of three months or less at the time of purchase. The Company also had $96 million of restricted cash at September 30, 2017, expected to be released in the fourth quarter of 2017.
Debt As of September 30, 2017, outstanding debt, which consisted of notes and debentures, totaled $8.5 billion. Current debt as of September 30, 2017, included $150 million of 7.0% senior notes due February 1, 2018 and $400 million of 6.9% senior notes due September 15, 2018.
In November 2016, the Company initiated a program to purchase in the open market up to $250 million in aggregate principal amount of senior notes issued under its indentures. In the fourth quarter of 2016, the Company purchased and canceled $181 million aggregate principal amount of its senior notes through open market repurchases for $182 million in cash, including accrued interest and $0.5 million of premium.
In January 2017, the Company purchased and canceled an additional $69 million aggregate principal amount of senior notes for $71 million in cash, including accrued interest and $1 million of premium, which completed the open market repurchase program. These repurchases resulted in a $1 million net loss on extinguishment of debt, which is included in “Financing costs, net” in the Company’s consolidated statement of operations. The net loss includes an acceleration of related discount and deferred financing costs.
In August 2017, the Company assumed the obligations of Apache Finance Canada Corporation (AFCC) in respect of $300 million 7.75% notes due in 2029 which AFCC issued and the Company guaranteed pursuant to the governing indenture. The assumption was permitted by the indenture and effected pursuant to a supplemental indenture thereto. As a result of the assumption, the Company is the obligor under the notes and indenture, and AFCC is released from its obligations thereunder. The $300 million 7.75% notes historically have been included in the Company’s long-term debt; accordingly, the assumption did not change the Company’s long-term debt or total debt.
Available committed borrowing capacity In June 2015, the Company entered into a five-year revolving credit facility which matures in June 2020, subject to Apache’s two, one-year extension options. The facility provides for aggregate commitments of $3.5 billion (including a $750 million letter of credit subfacility) and rights to increase commitments to $4.5 billion. Proceeds from borrowings may be used for general corporate purposes. Apache’s available borrowing capacity under this facility supports its commercial paper program, currently $3.5 billion. The commercial paper program, which is subject to market availability, facilitates Apache borrowing funds for up to 270 days at competitive interest rates. As of September 30, 2017, the Company had no commercial paper or borrowings under committed bank facilities or uncommitted bank lines outstanding.
In February 2016, the Company entered into a letter of credit facility providing £900 million in commitments and rights to increase commitments to £1.075 billion. This facility matures in February 2020 and is available for the Company’s letter of credit needs, particularly those which may arise in respect of abandonment obligations assumed in various North Sea acquisitions. The facility also is available for loans to cash collateralize letters of credit or obligations to provide letters of credit, in each case, to the extent letters of credit are unavailable under the facility. As of September 30, 2017, three letters of credit aggregating approximately £147.5 million and no borrowings were outstanding under this facility.
The Company was in compliance with the terms of these credit facilities as of September 30, 2017.
ITEM 3 –3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity RiskOmitted.
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. The Company’s average crude oil realizations have increased 11 percent to $49.34 per barrel in the third quarter of 2017 from $44.35 per barrel in the comparable period of 2016. The Company’s average natural gas price realizations have increased 6 percent to $2.75 per Mcf in the third quarter of 2017 from $2.59 per Mcf in the comparable period of 2016. Based on average daily production for the third quarter of 2017, a $1.00 per barrel change in the weighted average realized oil price would have increased or decreased revenues for the quarter by approximately $22 million, and a $0.10 per Mcf change in the weighted average realized price of natural gas would have increased or decreased revenues for the quarter by approximately $9 million.
Apache 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. Apache does not hold or issue derivative instruments for trading purposes. As of September 30, 2017, the Company had open natural gas derivatives not designated as cash flow hedges in an asset position with a fair value of $6 million. A 10 percent increase in gas prices would move the derivatives to a liability position of $17 million, while a 10 percent decrease in prices would increase the asset by approximately $17 million. As of September 30, 2017, the Company had open oil derivatives not designated as cash flow hedges in an asset position with a fair value of $11 million. A 10 percent increase in oil prices would move the derivatives to a liability position of $50 million, while a 10 percent decrease in prices would increase the asset by approximately $84 million. These fair value changes assume volatility based on prevailing market parameters at September 30, 2017. See Note 3—Derivative Instruments and Hedging Activities of the Notes to Consolidated Financial Statements in Part 1, Item 1 of this Quarterly Report on Form 10-Q for notional volumes and terms associated with the Company’s derivative contracts.
Foreign Currency Risk
The Company’s cash flow stream 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, and the majority of costs incurred are paid in British pounds. In Egypt, all oil and gas production is sold under U.S. dollar contracts, and the majority of the costs incurred are denominated in U.S. dollars. Revenue and disbursement transactions denominated in British pounds are converted to U.S. dollar equivalents based on 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. 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 September 30, 2017.
ITEM 4 –4. CONTROLS AND PROCEDURES
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 ourthe Company’s disclosure controls and procedures as of September 30, 2017,March 31, 2023, 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 we arethe Company is required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the SEC’sCommission’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.
WeThe Company periodically reviewreviews the design and effectiveness of ourits disclosure controls, including compliance with various laws and regulations that apply to ourits operations, both inside and outside the United States. We makeThe Company makes modifications to improve the design and effectiveness of our disclosure controls, and may take other corrective action, if ourthe Company’s reviews identify deficiencies or weaknesses in ourits controls.
Changes in Internal Control Over Financial Reporting
There were no changes in ourthe Company’s internal controlcontrols over financial reporting that occurred during the quarter ended September 30, 2017March 31, 2023 that have materially affected, or are reasonably likely to materially affect, ourthe Company’s internal controlcontrols over financial reporting.
PART II - OTHER INFORMATION
Please referITEM 1. LEGAL PROCEEDINGS
Refer to Part I, Item 33—Legal Proceedings of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016 (filed with the SEC on February 24, 2017)2022 and Note 9—12—Commitments and Contingencies in the notesNotes to the consolidated financial statementsConsolidated Financial Statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q (which is hereby incorporated by reference herein), for a description of material legal proceedings.
Please referITEM 1A. RISK FACTORS
There have been no material changes to the risk factors disclosed in Part I, Item 1A—Risk Factors of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016, and Part I, Item 3—Quantitative and Qualitative Disclosures About Market Risk2022.
Given the nature of thisits business, APA Corporation may be subject to different or additional risks than those applicable to the Company. For a description of these risks, refer to the disclosures in APA Corporation’s Quarterly Report on Form 10-Q. There have been no material changes to our risk factors since our annual report10-Q for the quarterly period ended March 31, 2023 and APA Corporation’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016.2022.
| |
ITEM 2. | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
Apache’s Board of Directors has authorized the purchase of up to 40 million shares of the Company’s common stock. Shares may be purchased either in the open market or through privately negotiated transactions. The Company initiated the buyback program on June 10, 2013, and through September 30, 2017, had repurchased a total of 32.2 million shares at an average price of $88.96 per share. The Company is not obligated to acquire any specific number of shares and has not purchased any additional shares during 2017.
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ITEM 3. | DEFAULTS UPON SENIOR SECURITIES |
None
| |
ITEM 4. | MINE SAFETY DISCLOSURES |
None
None
ITEM 6. EXHIBITS
| | | | | | | | |
3.1 | – | |
3.2 | – | |
3.3 | – | |
*31.1 | – | |
*31.2 | – | |
**32.1 | – | |
*101 | – | The following financial statements from the Registrant's Quarterly Report on Form 10-Q for the quarter ended March 31, 2023, formatted in Inline XBRL: (i) Statement of Consolidated Operations, (ii) Statement of Consolidated Comprehensive Income (Loss), (iii) Statement of Consolidated Cash Flows, (iv) Consolidated Balance Sheet, (v) Statement of Consolidated Changes in Equity (Deficit) and Noncontrolling Interests and (vi) Notes to Consolidated Financial Statements, tagged as blocks of text and including detailed tags. |
*101.SCH | – | Inline XBRL Taxonomy Schema Document. |
*101.CAL | – | Inline XBRL Calculation Linkbase Document. |
*101.DEF | – | Inline XBRL Definition Linkbase Document. |
*101.LAB | – | Inline XBRL Label Linkbase Document. |
*101.PRE | – | Inline XBRL Presentation Linkbase Document. |
*104 | – | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). |
* Filed herewith
** Furnished herewith
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| | |
3.1 | – | |
3.2 | – | |
3.3 | – | |
*4.1 | – | |
*31.1 | – | |
*31.2 | – | |
*32.1 | – | |
*101.INS | – | XBRL Instance Document. |
*101.SCH | – | XBRL Taxonomy Schema Document. |
*101.CAL | – | XBRL Calculation Linkbase Document. |
*101.DEF | – | XBRL Definition Linkbase Document. |
*101.LAB | – | XBRL Label Linkbase Document. |
*101.PRE | – | XBRL Presentation Linkbase Document. |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
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| | | | | | | | | | |
| | | APACHE CORPORATION |
| | |
Dated: | November 2, 2017May 4, 2023 | | /s/ STEPHEN J. RINEY |
| | | Stephen J. Riney |
| | | Executive Vice President and Chief Financial Officer |
| | | (Principal Financial Officer) |
| | |
Dated: | November 2, 2017May 4, 2023 | | /s/ REBECCA A. HOYT |
| | | Rebecca A. Hoyt |
| | | Senior Vice President, Chief Accounting Officer, and Controller |
| | | (Principal Accounting Officer) |