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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

~~Number of shares of registrant’s common stock outstanding as of October 31, 2014 376,482,179~~

These 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). They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for the interim periods, on a basis consistent with the annual audited financial statements. 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) have been 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’s ~~Current~~Annual Report on Form ~~8-K dated July 17, 2014~~10-K for the fiscal year ended December 31, ~~2013,~~2014, which contains a summary of the Company’s significant accounting policies and other disclosures.

The Company’s financial statements for prior periods include reclassifications that were made to conform to the current-period presentation. In March 2014, Apache completed the sale of all of its operations in Argentina. Results of operations and cash flows for Argentina operations are reflected as discontinued operations in the Company’s financial statements for all periods presented. For more information regarding this divestiture, please refer to Note 2–Acquisitions and Divestitures.

As of ~~September 30, 2014,~~March 31, 2015, Apache’s significant accounting policies are consistent with those discussed in Note 1—Summary of Significant Accounting Policies to the consolidated financial statements contained in Apache’s ~~Current~~Annual Report on Form ~~8-K dated July 17, 2014~~10-K for the fiscal year ended December 31, ~~2013, other than the change in income taxes noted below and in Note 7—Income Taxes.~~2014.

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates with regard to these financial statements include the fair value determination of acquired assets and liabilities and assets held for sale, the estimate of proved oil and gas reserves and related present value estimates of future net cash flows therefrom, assessing asset retirement obligations, and the estimate of income taxes. Actual results could differ from those estimates.

The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. As of September 30, 2014, the Company had $545 million of proceeds from the sale of deepwater Gulf of Mexico properties held by a qualified intermediary and available for use in a like-kind exchange under Section 1031 of the U.S. Internal Revenue Code. As of the date of this filing, the Company has utilized or plans to utilize $471 million of the cash held by the qualified intermediary in the acquisition of like-kind property, and as such, this amount is classified as long-term restricted cash on Apache’s consolidated balance sheet as of September 30, 2014. The remaining $74 million of restricted cash was returned to Apache in October and, as such, is classified as short-term restricted cash on Apache’s consolidated balance sheet as of September 30, 2014. For more information regarding the sale of the deepwater Gulf of Mexico properties, please refer to Note 2—Acquisitions and Divestitures.

The Company follows the full-cost method of accounting for its oil and gas property. Under this method of accounting, all costs incurred for both successful and unsuccessful exploration and development activities, including salaries, benefits and other internal costs directly identified with these activities, and oil and gas property acquisitions are capitalized. The net book value of oil and gas properties, less related deferred income taxes, may not exceed a calculated “ceiling.” The ceiling limitation is the estimated after-tax future net cash flows from proved oil and gas reserves, discounted at 10 percent per annum and adjusted for designated cash flow hedges. Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements. For a discussion of the calculation of estimated future net cash flows, please refer to Note 14—Supplemental Oil and Gas Disclosures to the consolidated financial statements contained in Apache’s Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

Any excess of the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as “Additional depreciation, depletion and amortization” (DD&A) in the accompanying statement of consolidated operations. Such limitations are imposed separately on a country-by-country basis and are tested quarterly. For a discussion of the calculation of estimated future net cash flows, please refer to Note 14—Supplemental Oil and Gas Disclosures to the consolidated financial statements contained in Apache’s Current Report on Form 8-K dated July 17, 2014 for the fiscal year ended December 31, 2013.

In the ~~third~~first quarter of ~~2014,~~2015, the Company recorded ~~$1.5~~$5.2 billion ($~~996 million~~3.4 billion net of tax), $1.4 billion ($1.0 billion net of tax), and ~~$17~~$632 million ($7316 million net of tax) in non-cash write-downs of the carrying value of the Company’s U.S., Canada, and North Sea proved oil and gas properties, respectively. ~~In the second quarter of 2014, the Company recorded a $203 million ($77 million net of tax) non-cash write-down of the carrying value of the Company’s North Sea proved oil and gas properties.~~

Apache records deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in the financial statements and tax returns. The Company routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and gas prices) and changing tax laws.6

Apache is required to assess whether the undistributed earnings of its foreign subsidiaries will be permanently reinvested. In the third quarter of 2014, Apache evaluated its permanent reinvestment position and determined that undistributed earnings from certain subsidiaries located in Apache’s Australia, Egypt, and North Sea regions will no longer be permanently reinvested. As a result of this change in position, Apache recorded a U.S. deferred income tax liability of $814 million on the undistributed earnings of subsidiaries located in these regions. Undistributed earnings of Apache’s Canadian subsidiaries remain permanently reinvested. Apache does not record U.S. deferred income taxes on foreign subsidiaries that are deemed to be permanently reinvested. When such earnings are no longer deemed permanently reinvested, Apache will recognize the appropriate U.S. current or deferred income tax liabilities. In addition, the Company recorded $249 million of U.S. deferred income tax expense on foreign earnings that were distributed to the U.S. in the third quarter of 2014.

InOn April ~~2014,~~7, 2015, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) ~~No. 2014-08—Presentation~~2015-03, which simplifies the presentation of debt issuance costs. The new standard requires debt issuance costs to be presented as a direct deduction from the carrying value of the associated debt liability, whereas they are currently being presented as a component of “deferred charges and other” on the balance sheet. The new standard creates consistency in the way debt issuance costs and debt discounts are presented on the balance sheet and better aligns U.S. GAAP with International Financial ~~Statements (Topic 205) and Property, Plant, and Equipment (Topic 360):~~ Reporting ~~Discontinued Operations and Disclosures of Disposals of Components of an Entity.~~Standards (IFRS). ASU ~~2014-08 modifies the criteria for disposals to qualify as discontinued operations and expands related disclosures. The guidance~~2015-03 is effective for annual and interim reporting periods beginning after December 15, ~~2014. Adoption~~2015. The Company will apply the change retrospectively and does not expect the adoption of this amendment ~~will not~~to have a material ~~effect~~impact on ~~our~~its consolidated financial ~~position or results of operations.~~statements.

In May 2014, the FASB and the International Accounting Standards Board (IASB) issued a joint revenue recognition standard, ASU 2014-09. The new standard removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers, and increases disclosure requirements. The guidance requires companies to recognize revenue to depict the transfer of goods or services to customers in amounts that reflect the consideration to which the company expects to be entitled in exchange for those goods or services. ASU 2014-09 is effective for annual and interim periods beginning after December 15, ~~2016.~~2016, pending a one-year deferral currently under consideration. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Company is currently evaluating the level of effort needed to implement the standard, the impact of adopting this standard on its consolidated financial statements, and whether to use the full retrospective approach or the modified retrospective approach.

In August 2014, the FASB issued ASU No. 2014-15, which requires management of public and private companies to evaluate whether there are conditions and events that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the financial statements are issued (or available to be issued when applicable) and, if so, to disclose that fact. Management will be required to make this evaluation for both annual and interim reporting periods, if applicable. ASU No. 2014-15 is effective for annual periods ending after December 15, 2016 and interim periods within annual periods beginning after December 15, 2016. The Company does not expect the adoption of this amendment to have a material impact on its consolidated financial statements.

In April 2015, Apache completed the previously disclosed sale of its interest in two LNG projects, Wheatstone LNG in Australia and Kitimat LNG in Canada, along with the associated upstream oil and gas assets, to Woodside Petroleum Limited (Woodside). Total proceeds for the sale were $3.7 billion, which includes reimbursement of Apache’s net expenditure in the Wheatstone and Kitimat LNG projects, changes in working capital and other contractual adjustments between the effective date, July 1, 2014, and closing.

As a result of the sale of these projects, the LNG facilities on Apache’s consolidated balance sheet and Apache’s investment in Pacific Trail Pipelines Limited Partnership qualify as held for sale as of March 31, 2015. A summary of the associated assets and liabilities classified as held for sale on our consolidated balance sheet as of March 31, 2015, and December 31, 2014, is detailed below:

In connection with classifying these assets to held for sale, a separate impairment analysis was performed for each long-lived asset within the disposal group. The analysis was based on the estimated fair value of the assets in the disposal group, which was equivalent to the allocated purchase price associated with the transaction. The transaction’s purchase price was allocated based on the fair value of each asset in the disposal group. Each asset’s fair value was determined using a combination of the income approach, specifically discounted cash flows, and the cost approach. The income approach considered management views on current operating measures as well as assumptions pertaining to market forces in the oil and gas industry, such as future production, future commodity prices, and costs. These assumptions were applied to develop future cash flow projections that were then discounted to estimate fair value, using a discount rate believed to be consistent with those used by principal market participants. The cost approach reflects the amount that would be required currently to replace the service capacity of an asset (often referred to as current replacement cost) and is typically used to measure the fair value of tangible assets that are used in combination with other assets. Apache has classified these non-recurring fair value measurements as Level 3 in the fair value hierarchy.

In the fourth quarter of 2014, Apache recognized an impairment loss on held for sale assets totaling $1.0 billion ($753 million net of tax). As the sale and purchase agreements provide for Apache’s net expenditures incurred in connection with these projects subsequent to the effective date to be reimbursed by Woodside, the Company has recorded no further loss during the first quarter of 2015.

The upstream oil and natural gas properties associated with this sale are not presented as held for sale pursuant to the rules governing full-cost accounting for oil and gas properties. Approximately $1.4 billion and $500 million of the sale proceeds have been allocated to the Australia and Canada upstream assets, respectively. Proceeds from the disposition of oil and gas properties are accounted for as a reduction to capitalized costs unless a significant portion (greater than 25 percent) of the Company’s reserve quantities in a particular country are sold, in which case a gain or loss is recognized in income. Upon closing the transaction in the second quarter of 2015, a loss of approximately $900 million ($600 million net of tax) will be recognized for the sale of the Australian upstream assets that represented approximately 50 percent of the region’s total reserves. Reserves divested in Canada were not a significant portion of the region total.

On April 8, 2015, Apache Corporation announced an agreement to sell its Australian subsidiary Apache Energy Limited (AEL) to a consortium of private equity funds managed by Macquarie Capital Group Limited and Brookfield Asset Management Inc. for cash consideration of $2.1 billion. The Company estimates a loss of approximately $1 billion upon closing the transaction. The ultimate amount of loss will be determined by date of completion, impact of customary post-closing adjustments and finalization of various estimates. The transaction is expected to close mid-year 2015 and is subject to necessary government and regulatory approvals. The effective date of the sale is October 1, 2014.

Upon closing, Apache will have exited essentially all of the Company’s Australian operations. The associated results of operations for Australia and the loss on disposals will be classified as discontinued operations for all periods presented in subsequent SEC filings.

During the first quarter of 2015, Apache completed $92 million of leasehold acquisitions primarily in our North America onshore regions.

In December 2014, Apache completed the sale of certain Anadarko basin and non-core southern Louisiana oil and gas assets for approximately $1.3 billion in two separate transactions. In the Anadarko basin, Apache sold approximately 115,000 net acres in Wheeler County, Texas, and western Oklahoma. In southern Louisiana, Apache sold its working interest in approximately 90,000 net acres. The effective date of both of these transactions was October 1, 2014.

On June 30, 2014, Apache completed the sale of non-operated interests in the Lucius and Heidelberg development projects and 11 ~~primary term~~primary-term deepwater exploration blocks in the Gulf of Mexico for $1.4 billion. The effective date of the transaction was May 1, 2014. ~~Apache’s net book value of oil and gas properties was reduced by $850 million of proved property costs and $518 million of unproved property costs as a result of the transaction.~~

On April 30, 2014, Apache completed the sale of ~~primarily dry~~producing oil and gas ~~producing hydrocarbon~~ assets in the Deep Basin area of western Alberta and British Columbia, Canada, for $374 million. ~~The assets comprise~~Apache sold primarily dry-gas producing properties comprising 328,400 net acres in the Ojay, Noel, and Wapiti areas. In the Wapiti area, Apache retained 100 percent of its working interest in horizons below the Cretaceous, ~~in the Wapiti area,~~ including rights to the liquids-rich Montney and other deeper horizons. The effective date of the transaction was January 1, 2014.

On March 12, 2014, Apache’s subsidiaries completed the sale of all of the Company’s operations in Argentina to YPF Sociedad Anónima for cash consideration of $800 million ~~(subject to customary closing adjustments)~~ plus the assumption of $52 million of bank debt as of June 30, 2013. The results of operations during 2014 related to Argentina have been classified as discontinued operations in ~~all periods presented in~~ this Quarterly Report on Form 10-Q. ~~The carrying amounts of the major classes of assets and liabilities associated with the disposition were as follows:~~

Sales and other operating revenues and the loss from discontinued operations related to the Argentina disposition were as follows:

~~On November 14, 2013,~~During the first quarter of 2014, Apache completed the sale of a one-third minority participation in its Egypt oil and gas business to a subsidiary of Sinopec International Petroleum Exploration and Production Corporation (Sinopec). Apache received cash consideration of $2.95 billion after customary closing adjustments. Apache continues to operate its Egypt upstream oil and gas business. Apache recorded

$1.9 billion of the proceeds as a noncontrolling interest, which is reflected as a separate component of equity in the Company’s consolidated balance sheet. This represents one-third of Apache’s net book value of its Egypt holdings at the time of the transaction. The remaining proceeds were recorded as additional paid-in capital. Included in “Net income including noncontrolling interest” for the quarter ended September 30, 2014, is net income attributable to Sinopec’s interest totaling $89 million. For the first nine months of 2014, net income attributable to Sinopec’s interest totaled $295$44 million of ~~which the Company has distributed $124 million to Sinopec.~~

On September 30, 2013, Apache completed the sale of its Gulf of Mexico Shelf operations and properties to Fieldwood Energy LLC (Fieldwood), an affiliate of Riverstone Holdings. Under the terms of the agreement, Apache received cash consideration of $3.7 billion, and Fieldwood assumed $1.5 billion of discounted asset abandonment liabilities. Additionally, Apache retained 50 percent of its ownership interestleasehold acquisitions primarily in ~~all exploration blocks and in horizons below production in developed blocks.~~

In February 2013, Apache completed a transaction with Chevron Canada Limited (Chevron Canada) under which each company became a 50-percent owner of the Kitimat LNG plant, the Pacific Trail Pipelines Limited Partnership (PTP), and 644,000 gross undeveloped acres in the Horn River and Liard basins. Chevron Canada will operate the LNG plant and pipeline while Apache Canada will continue to operate the upstream assets. Apache’s net proceeds from the transaction were $396 million after post-closing adjustments, and no gain or loss was recorded.our North America onshore regions.

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, including swaps and options, to manage fluctuations in cash flows resulting from changes in commodity prices.

The use of derivative instruments exposes the Company to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. 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, 2014, 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.

The Company executes commodity derivative transactions under master agreements that have netting provisions that provide for offsetting payables against receivables. In general, if a party to a derivative transaction incurs a material deterioration in its credit ratings, as defined in the applicable agreement, the other party has the right to demand the posting of collateral, demand a transfer, or terminate the arrangement. The Company’s net derivative asset position at September 30, 2014, represents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in a net asset position. The Company has not provided any collateral to any of its counterparties as of September 30, 2014.

~~As of September 30, 2014, Apache had the following commodity derivative positions:~~

Apache has currently elected not to designate any of its qualifying natural gas and oil derivatives as cash flow hedges. Changes in the fair value of these derivatives for the current period are recorded in the Company’s statement of consolidated operations.

Apache’s commodity derivative instruments consist of variable-to-fixed price commodity swaps. 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, utilizing commodity futures price strips for the underlying commodities provided by a reputable third party.

~~The following table presents the Company’s derivative assets and liabilities measured at fair value on a recurring basis:~~

~~Derivative Assets and Liabilities Recorded in the Consolidated Balance Sheet~~

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:

~~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:~~

Unrealized gains and losses for derivative activity recorded in the statement of consolidated operations is reflected in the statement of consolidated cash flows as a component of “Other” in “Adjustments to reconcile net income to net cash provided by operating activities.”

A reconciliation of the components of accumulated other comprehensive loss in the statement of consolidated changes in equity related to Apache’s cash flow hedges is presented in the table below. The Company has no derivatives designated as cash flow hedges as of September 30, 2014.

The following table describes changes to the Company’s asset retirement obligation (ARO) liability for the ~~nine-month~~three-month period ended ~~September 30, 2014:~~March 31, 2015:

The following table presents the carrying amounts and estimated fair values of the Company’s outstanding debt:

The Company’s debt is recorded at the carrying amount, net of unamortized discount, on its consolidated balance sheet. The carrying amount of the Company’s commercial paper, committed bank facilities and uncommitted ~~credit facilities~~bank lines, and overdraft 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).

As of ~~September 30, 2014,~~March 31, 2015, the Company had unsecured committed revolving credit facilities totaling ~~$3.3~~$5.3 billion, of which $2.0 billion matures in December 2015, $1.0 billion matures in August 2016, and $2.3 billion matures in June ~~2018 pursuant to a one-year extension approved in May 2014 under the terms of the $2.3~~2018. Apache has $2.0 billion, ~~facilities. The facilities consist of a~~ $1.7 billion, ~~facility~~ and $1.0 billion ~~facility for the~~ U.S., facilities, a $300 million Australian facility, ~~for Australia,~~ and a $300 million ~~facility for Canada.~~Canadian facility. As of ~~September 30, 2014,~~March 31, 2015, aggregate available borrowing capacity under the Company’s credit facilities was ~~$2.1~~$2.7 billion. The Company’s committed ~~credit~~bank facilities are used to support Apache’s commercial paper program.

~~As of September 30, 2014, the Company had $20 million of~~ current debt outstanding ~~borrowed on uncommitted credit~~under commercial paper, committed bank facilities, and ~~overdraft lines, compared~~uncommitted bank lines. This amount was classified as current on Apache’s consolidated balance sheet based on an intent to repay the obligations with ~~$53 million as~~the proceeds from the LNG project divestitures. All current debt was repaid in April 2015 upon closing of ~~December 31, 2013.~~those divestitures.

In the third quarter of 2014, Apache evaluated its permanent reinvestment position and determined that undistributed earnings from certain foreign subsidiaries located in Apache’s Australia, Egypt, and North Sea regions will no longer be permanently reinvested. As a result of this change in position, the Company recorded $814 million of U.S. deferred income tax expense on undistributed earnings that were previously considered permanently reinvested. In addition, the Company recorded $249 million of U.S. deferred income tax expense on foreign earnings that were distributed to the U.S. in the third quarter of 2014.

The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the quarter in which they occur. Accordingly, in the ~~third~~first quarter of ~~2014,~~2015, the Company recorded ~~$814 million of U.S. deferred income tax expense on foreign earnings no longer deemed to be permanently reinvested as well as~~ the income tax effect of the ~~$1.5~~$7.2 billion ~~and $17 million~~ non-cash write-downs of its U.S., Canada, and North Sea proved oil and gas properties, respectively, offset by an increase in the Canadian valuation allowance, as discrete ~~items~~items.

On March 26, 2015, U.K. Finance Bill 2015 received Royal Assent. Under the enacted legislation, the corporate income tax rate on North Sea oil and gas profits was reduced from 62 percent to 50 percent effective January 1, 2015. As a result of the enacted legislation in the ~~third~~first quarter of ~~2014. In the second quarter of 2014,~~2015, the Company recorded a deferred tax benefit of $619 million related to the remeasurement of the Company’s December 31, 2014 U.K. deferred income tax impact of a $203 million non-cash write-down of its North Sea proved oil and gas properties as a discrete item. In the third quarter of 2013, the Company recorded the income tax impact of a $552 million non-cash write-down and a $75 million non-cash impairment on its U.S. and Kenyan oil and gas properties, respectively, as discrete items.liability.

Apache and its subsidiaries are subject to U.S. federal income tax as well as income or capital taxes in various state and foreign jurisdictions. The Company’s tax reserves are related to tax years that may be subject to examination by the relevant taxing authority. ~~In October 2014, the Internal Revenue Service concluded its audit of the 2011 and 2012 tax years.~~ The Company is under audit in various states and in most of the Company’s foreign jurisdictions as part of its normal course of business.

Apache is party to various legal actions arising in the ordinary course of business, including litigation and governmental and regulatory controls. As of ~~September 30, 2014,~~March 31, 2015, the Company has an accrued liability of approximately ~~$21~~$23 million for all legal contingencies that are deemed to be probable of occurring and can be reasonably estimated. Apache’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’s financial position, results of operations, or liquidity after consideration of recorded accruals. For material matters that Apache 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 see Note 8—Commitments and Contingencies to the consolidated financial statements contained in Apache’s ~~Current~~Annual Report on Form ~~8-K dated July 17, 2014~~10-K for the fiscal year ended December 31, ~~2013.~~2014.

The Asociación de Superficiarios de la Patagonia (ASSUPA) filed lawsuits against Company subsidiaries in Argentina courts relating to various environmental and remediation claims concerning certain geographic areas of Argentina, including in 2003 the Neuquén basin and in 2012 the Austral basin. In addition, effective December 1, 2011, Enargas, an autonomous entity that functions under the Argentine Ministry of Economy, created a tariff charge on all fuel gas used by oil and gas producers in field operations, which is likewise the subject of legal proceedings in Argentina.

On March 12, 2014, the Company and its subsidiaries completed the sale of all of the Company’s subsidiaries’ operations and properties in Argentina to YPF Sociedad Anonima (YPF). As part of that sale, YPF assumed responsibility for all of the past, present, and future litigation in Argentina involving Company subsidiaries, including the ASSUPA and Enargas matters, 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 (Pioneer) in an amount up to $67.5 million pursuant to the terms and conditions of stock purchase agreements entered in 2006 between Company subsidiaries and certain subsidiaries of Pioneer. No ~~other~~ material change in the status of ~~these~~the YPF Sociedad Anonima and Pioneer Natural Resources Company indemnities matters has occurred since the filing of Apache’s ~~Current~~Annual Report on Form ~~8-K dated July 17, 2014~~10-K for its ~~2013~~2014 fiscal year.

~~Numerous~~As more fully described in Apache’s Annual Report on Form 10-K for its 2014 fiscal year, numerous surface owners have filed claims or sent demand letters to various oil and gas companies, including Apache, claiming that, under either expressed or implied lease terms or Louisiana law, they are liable for damage measured by the cost of restoration of leased premises to their original condition as well as damages for contamination and cleanup.

In a case captioned~~Heloise, LLC, et al.~~State of Louisiana and the Cameron Parish School Board v. ~~BP America Production Company,~~Apache Corporation et al., ~~Case~~Docket No. ~~120113~~10-18672, in the 38^th Judicial District Court, ~~for the~~ Parish of ~~Lafourche, plaintiff landowners~~Cameron, State of Louisiana, plaintiffs allege that defendants’ oil and gas ~~operations~~exploration and production activities contaminated ~~their~~plaintiffs’ property, ~~primarily with chlorides.~~and claim an unspecified amount of damages. Apache, a defendant in the case, acquired its interest in the oil and gas operations on plaintiffs’ property from the former operator, Amoco Production Company, when the Company purchased the stock of Amoco’s subsidiary, MW Petroleum Corporation, in 1991. BP America Production Company (BP America), as Amoco’s successor in interest, and Apache dispute whether and to what extent they might owe each other indemnity in the case. Plaintiffs’ expert opined that the cost of remediating plaintiffs’ 825 acres exceeds $200 million. Prior to trial, Apache and BP America each settled with plaintiff. The amount paid by Apache in settlement is not material and does not have a material effect on the Company’s financial position, results of operations, or liquidity. Further, as part of the overall settlement, each of Apache and BP America released and waived its indemnity claim against the other arising out of this litigation. The lawsuit is concluded.

~~With respect to~~~~Board of Commissioners of the Southeast Louisiana Flood Protection Authority – East v. Tennessee Gas Pipeline Company et al.~~, Civil Action no. 13-5410, in the United States District Court for the Eastern District of Louisiana, the federal court has retained jurisdiction over the matter after denying plaintiff’s motion to remand on June 27, 2014. Further, the Louisiana state government has passed a new law (SB 469) clarifying that only entities authorized under the Coastal Zone Management Act may bring litigation to assert claims arising out of the permitted activities. Plaintiff is not one of those authorized entities. Thedefendant Davis Oil Company, and ~~other defendants seek dismissal of~~subsequently sold the interest to defendant Wagner Oil Company (Wagner). Apache claims indemnity from Wagner. The case ~~including pursuant~~is set for trial in November 2015. While an adverse judgment against Apache might be possible, Apache intends to ~~SB 469.~~vigorously oppose the claims.

No other material change in the status of these matters has occurred since the filing of Apache’s ~~Current~~Annual Report on Form ~~8-K dated July 17, 2014~~10-K for its ~~2013~~2014 fiscal year.

In 2008, Company subsidiaries reported a pipeline explosion that interrupted deliveries of natural gas in Australia to customers under various long-term contracts.

In The civil lawsuits concerning the ~~case captioned~~~~Alcoa~~pipeline explosion, all of ~~Australia Limited v. Apache Energy Limited, Apache Northwest Pty Ltd, Tap (Harriet) Pty Ltd, and Kufpec Australia Pty Ltd~~~~, Civ. 1481 of 2011,~~which were filed in the Supreme Court of Western Australia, have been resolved fully and dismissed on ~~June 20, 2012, the Supreme Court struck out Alcoa’s claim~~confidential terms, including for an exchange of consideration that the liquidated damages provisions under two long-term contracts are unenforceable as a penalty and also struck out Alcoa’s claim for damages for breach of statutory duty. On September 17, 2013, the Western Australia Court of Appeal dismissed the Company subsidiaries’ appeal concerning Alcoa’s remaining tort claim for economic loss. On October 15, 2013, the Company subsidiaries applied to the High Court of Australia for special leave to appeal. On April 11, 2014, the High Court refused special leave to appeal. However, on October 8, 2014, the High Court decided a separate case on point captioned~~Brookfield Multiplex Ltd v. Owners Corporation Strata Plan 61288 & Anor, [2014] HCA 36. The High Court’s holding in the~~~~Brookfield~~ case strongly favors the Company subsidiaries’ defenses to Alcoa’s remaining tort claim for economic loss. All of the Company subsidiaries’ defenses remain intact for further proceedings at the trial court level, including the defenses that were the subject of the special leave application and that have now been considered separately by the High Court in the~~Brookfield~~ ~~case. Further, in January 2014, an Alcoa affiliate pleaded guilty in~~~~United States of America v. Alcoa World Alumina LLC~~, Criminal No. 14-7, in the United States District Court for the Western District of Pennsylvania, to a charge under the Foreign Corrupt Practices Act (FCPA) anti-bribery provisions, 15 U.S.C. Section 78dd-2 and 18 U.S.C. Section 2. This matter overlaps with Alcoa’s claims against Company subsidiaries in that both cases concern alumina produced from Alcoa’s alumina refineries in Western Australia during the period of the gas supply disruption in 2008-2009. In the circumstances of the admitted, agreed, and stipulated facts set forth in the Alcoa affiliate’s Plea Agreement, which is a public document, Company subsidiaries will defend against Alcoa’s claims on the basis that Alcoa is barred by law from recovering economic losses.

In the week prior to expiration of the applicable six-year limitations period on June 3, 2014, the following civil lawsuits were filed in connection with the Varanus Island pipeline explosion (the Incident), and the amounts specified do not include plaintiffs’ alleged interest and costs:

~~With respect to the claims in which the plaintiffs have not specified an amount of alleged damages in their court filings, the exposure related to such claims~~ is not material ~~or,~~to Apache. The lawsuits are described in Apache’s Annual Report on Form 10-K dated February 27, 2015 for its 2014 fiscal year. On April 10, 2015, the court dismissed the lawsuits filed by plaintiffs Alcoa (Civ. 1481 of 2011), Barrick (Civ. 2656 of 2013), EDL LNG (Civ. 1751 of 2014), and Yara (Civ. 1742 of 2014). On April 9, 2015, plaintiffs Harvey (Civ. 1749 of 2014), Iluka (Civ. 1748 of 2014), Newmont (Civ. 1727 of 2014), and Wesfarmers (Civ. 1740 of 2014) discontinued their lawsuits, which were never served on the Apache defendants. All matters relating to the Australia gas pipeline force majeure are concluded.

In a second amended petition filed on February 27, 2015 in a case captionedApollo Exploration, LLC, Cogent Exploration, Ltd. Co. & SellmoCo, LLC v. Apache Corporation, Cause No. CV50538 in the ~~case~~385^th Judicial District Court, Midland County, Texas, plaintiffs allege damages in excess of~~Wesfarmers,not currently determinable but not expected~~ $1.1 billion relating to ~~be material. Insurance statistics maintained by~~certain purchase and sale agreements, mineral leases, and areas of mutual interest agreements concerning properties located in Hartley, Moore, Potter, and Oldham Counties, Texas. Apache believes the ~~Insurance Council of Australia show that the total insured loss resulting from the gas supply disruption was $230 million AUD.~~

The applicable six-year limitations period has expired. In six years none of the above-referenced plaintiffs presented a claim to Apache or its subsidiaries prior to filing suit and instead, each allowed the same plaintiff law firm to file suit in Western Australia at the latest possible moment. The Apache defendants do not believe that any of theplaintiffs’ claims ~~have~~lack merit and will vigorously pursue their defenses against such claims. The plaintiffs seek relief primarily in tort, in circumvention of their own positive arrangements regarding risk allocation and in contravention of the High Court’s decision in the~~Brookfield~~case. In respect of the pending claims filed prior to expiration of the limitations period, contractual liquidated damages under the long-term contracts with such provisions, and under which an Apache subsidiary is a gas supplier, would not be expected to exceed $20 million AUD exclusive of interest. This is a reduction from previous estimates. In addition, Company subsidiaries have received confirmation of liability insurance coverage from both the primary insurer and the excess insurers.

~~No other material change in the status of these matters has occurred since the filing of Apache’s Current Report on Form 8-K dated July 17, 2014 for its 2013 fiscal year.~~

~~On October 29, 2012, plaintiffs filed an amended complaint in~~~~Breton Energy, L.L.C. et al. v. Mariner Energy Resources, Inc., et al.~~, Case 4:11-cv-03561, in the United States District Court for the Southern District of Texas, Houston Division, seeking compensation from defendants for allegedly depriving plaintiffs of rights to hydrocarbons in a reservoir described by plaintiffs as a common reservoir in West Cameron Blocks 171 and 172 offshore Louisiana in the Gulf of Mexico. Plaintiffs assert claims for waste and drainage. On May 28, 2013, the United States District Court for the Southern District of Texas dismissed the plaintiffs’ claims and entered judgment in favor of the defendants. Plaintiffs appealed. On August 12, 2014, the United States Court of Appeals for the Fifth Circuit affirmed the District Court as to the claims for waste against all defendants except International Paper and also affirmed the District Court as to the claims for drainage against all defendants. The Company’s subsidiary, Mariner Energy Resources, Inc. (now known as Apache Shelf, Inc.), was dismissed from the case but is obligated to indemnify the remaining defendant, International Paper, against the sole remaining claim. Prior to trial, which was to commence on November 3, 2014, plaintiffs settled their remaining claim in an amount that is not material and does not have a material effect on the Company’s financial position, results of operations, or liquidity. The lawsuit is concluded.oppose them.

~~The~~There has been no material change with respect to the review of the books and records of the Company and its subsidiaries and related entities by the State of Delaware, Department of Finance, Division of Revenue (Unclaimed Property), ~~has notified numerous companies, including Apache Corporation, that the State intends to examine its books and records and those of its subsidiaries and related entities~~ to determine compliance with the Delaware Escheat ~~Laws. The review is ongoing, and no material change in the status of this matter has occurred~~Laws, since the filing of Apache’s ~~Current~~Annual Report on Form ~~8-K dated July 17, 2014~~10-K for its ~~2013~~2014 fiscal year.

~~On October 11, 2013, a~~In the lawsuit captionedPankaj Oswal v. Apache Corporation, No. WAD 389/2013, in the Federal Court of Australia, District of Western Australia, General Division, on the eve of a trial that was ~~filed in which~~to commence on February 9, 2015, plaintiff ~~asserts claims against~~decided to discontinue his claim. On March 18, 2015, the ~~Company under~~court entered an order dismissing the ~~Australian Trade Practices Act.~~case. The ~~case has been set for a preliminary hearing commencing December 8, 2014. The Company does not believe the~~ lawsuit ~~has merit and will vigorously defend against it. No other material change~~is concluded in the ~~status of this matter has occurred since the filing of Apache’s Current Report on Form 8-K dated July 17, 2014 for its 2013 fiscal year.~~Company’s favor.

In the ~~case~~cases captionedRadhika Oswal v. Australia and New Zealand Banking Group Limited(ANZ) et al., No. SCI 2011 4653 ~~in the Supreme Court of Victoria, plaintiff filed an application seeking to amend her statement of claim in order to add parties as defendants to the proceedings, including the Company~~ and ~~certain of its subsidiaries. Similarly, in a companion case captioned~~Pankaj Oswal v. Australia and New Zealand Banking Group Limited(ANZ) et al., No. SCI 2012 01995, in the Supreme Court of Victoria, ~~plaintiff also filed an application seeking to amend his statement~~the cross-vesting of ~~claim in order to add parties as defendants to the~~certain related proceedings ~~including~~(in which neither the Company and certain of its subsidiaries. This was the second attempt by the plaintiffs to amend their pleadings, with their first attempt having been unsuccessful. While reserving all rights, including all defenses to the plaintiffs’ proposed amended pleadings, the Company andnor its subsidiaries ~~did not object~~are parties) has caused the court to ~~the plaintiffs’ revised applications to amend their pleadings, which is a procedural matter. The court granted plaintiffs’ applications and entered a~~consider new scheduling order with respect to the filing of all amended pleadings. On July 23, 2014, the Apache defendants filed their responsive pleadings, which include substantial counterclaims against the Oswals by a Company subsidiary.orders. The Company and its subsidiaries ~~do not~~ believe the plaintiffs’ claims ~~have~~lack merit and will vigorously ~~defend against~~oppose them. ~~Trial is set to commence August 3, 2015.~~ No other material change in the status of ~~these matters~~this matter has occurred since the filing of Apache’s ~~Current~~Annual Report onForm ~~8-K dated July 17, 2014~~10-K for its ~~2013~~2014 fiscal year.

Concerning the action filed by Tap (Harriet) Pty Ltd (Tap) against Burrup Fertilisers Pty Ltd et al., Civ. 2329 of 2009, in the Supreme Court of Western Australia, the remaining parties have settled and the lawsuit has been discontinued by consent. The lawsuit is concluded.

As of ~~September 30, 2014,~~March 31, 2015, the Company had an undiscounted reserve for environmental remediation of approximately ~~$86~~$63 million. The Company is not aware of any environmental claims existing as of ~~September 30, 2014,~~March 31, 2015 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.

On May 25, 2011, a panel of the Bureau of Ocean Energy Management (BOEMRE, as it was then known) published a report dated May 23, 2011, and titled “OCS G-2580, Vermilion Block 380 Platform A, Incidents of Noncompliance.” The report concerned the BOEMRE’s investigation of a fire on the Vermilion 380 A platform located in the Gulf of Mexico. At the time of the incident, Mariner operated the platform. On December 27, 2011, the Bureau of Safety and Environmental Enforcement (BSEE, successor to BOEMRE) issued several Incidents of Non-Compliance, which may provide the basis for the assessment of civil penalties against Mariner. The Company’s subsidiary, Apache Deepwater LLC, which is the successor by merger to Mariner effective November 10, 2010, has been presented with a BSEE notice of proposed civil penalty assessment in an amount that is not material and that will not have a material effect on the Company’s financial position, results of operations, or liquidity.

No other material change in the status of these matters has occurred since the filing of Apache’s ~~Current~~Annual Report on Form ~~8-K dated July 17, 2014~~10-K for its ~~2013~~2014 fiscal year.

A reconciliation of the components of basic and diluted net income (loss) per common share for the quarters ended March 31, 2015 and ~~nine-month periods ended September 30,~~ 2014 ~~and 2013~~ is presented in the table below.

The diluted earnings per share calculation excludes options and restricted stock units that were anti-dilutive totaling ~~4.7~~9.1 million and ~~5.4~~5.8 million for the quarters ending ~~September 30,~~March 31, 2015 and 2014, ~~and 2013, respectively, and 5.5 million and 6.0 million for the nine months ended September 30, 2014 and 2013,~~ respectively. ~~For the quarter ended September 30, 2013, 4.8 million shares related to the assumed conversion of the Mandatory Convertible Preferred Stock were also anti-dilutive.~~

For the quarters ended ~~September 30,~~March 31, 2015 and 2014, ~~and 2013,~~ Apache paid ~~$95~~$94 million and ~~$78~~$79 million, respectively, in dividends on its common stock. ~~For the nine months ended September 30, 2014 and 2013, Apache paid $271 million and $223 million, respectively.~~

~~In the first nine months of 2013, the Company also paid $57 million in dividends on its Series D Preferred Stock, which was converted to common stock in August 2013.~~

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 held negotiated transactions. The Company initiated the buyback program on June 10, 2013, and through ~~September 30,~~December 31, 2014, ~~has~~had repurchased a total of ~~31.8~~32.2 million shares at an average price of ~~$88.90 per share. For the nine-month period ended September 30, 2014, the Company repurchased a total of 20.6 million shares at an average price of $88.92~~$88.96 per share. The Company has not purchased any additional shares during 2015, and is not obligated to acquire any specific number of shares.

Apache is engaged in a single line of business. Both domestically and internationally, the Company explores for, develops, and produces natural gas, crude oil and natural gas liquids. At ~~September 30, 2014,~~March 31, 2015, the Company had production in five countries: the United States, Canada, Egypt, Australia, and the United Kingdom (U.K.) North Sea. Apache also pursues exploration interests in other countries that may, over time, result in reportable discoveries and development opportunities. Financial information for each country is presented below:

In December 1999, Apache Finance Canada issued approximately $300 million of publicly-traded notes due in 2029. The notes are fully and unconditionally guaranteed by Apache. The following condensed consolidating financial statements are provided as an alternative to filing separate financial statements.

Apache Finance Canada is 100 percent owned by Apache Corporation. As such, these condensed consolidating financial statements should be read in conjunction with Apache’s consolidated financial statements and the notes thereto, of which this note is an integral part.

ITEM 2 – MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Apache Corporation, a Delaware corporation formed in 1954, is an independent energy company that explores for, develops and produces natural gas, crude oil, and natural gas liquids. The Company has exploration and production interests in five countries: the United States (U.S.), Canada, Egypt, Australia, and the United Kingdom (U.K.) North Sea. Apache also pursues exploration interests in other countries that may over time result in reportable discoveries and development opportunities.

This discussion relates to Apache Corporation and its consolidated subsidiaries and should be read in conjunction with our consolidated financial statements and accompanying notes included under Part I, Item 1, “Financial Statements” of this Quarterly Report on Form 10-Q, as well as our consolidated financial statements, accompanying notes and Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our ~~Current~~Annual Report on Form ~~8-K dated July 17, 2014~~10-K for our ~~2013~~2014 fiscal year.

The Company’s foundation for future growth is driven by our significant producing asset base and large undeveloped acreage positions. This allows for growth through sustainable lower-risk drilling opportunities, balanced by higher-risk, higher-reward exploration. We closely monitor drilling and acquisition cost trends in each of our core areas relative to product prices and, when appropriate, adjust our capital budgets accordingly and allocate funds to projects based on expected value. We do this through a disciplined and focused process that includes analyzing current economic conditions, projected rate of return on internally generated drilling inventories, and opportunities for tactical acquisitions or leasehold purchases that add substantial drilling prospects or, occasionally, provide access to new core areas that could enhance our portfolio.

Over the last five years, Apache has ~~greatly enlarged and enhanced~~increasingly focused on its North American onshore resource ~~base, which we~~base. Recent drilling successes and acquisitions of acreage positions across North America have built a robust drilling inventory for our Permian, Gulf Coast, and other onshore regions. We believe that this area is capable of driving our growth and performance over the next several years. As part of this strategy, we also conducted a company-wide review of our portfolio and our operations in an effort to best position Apache for the ~~foreseeable future. During~~long-term benefit of our shareholders. This review has resulted in several key divestitures during the last 18eighteen months ~~we have further increased~~including the ~~focus on~~recently completed sale of our ~~North American Onshore business by divesting $10 billion~~Kitimat and Wheatstone LNG projects and the announcement of ~~properties. In North America, we completed~~ the sale of substantially all of our ~~Gulf of Mexico Shelf region assets, certain non-producing~~operations in Australia, which is expected to close in mid-2015. The Company believes the resulting portfolio, which includes a significant onshore North America resource base coupled with Brent-linked, free cash flow generating assets in the ~~deepwater Gulf~~North Sea and Egypt, provides flexibility in capital allocation and a platform for sustainable growth in a volatile commodity price environment.

The decline in the prices of ~~Mexico,~~oil and ~~non-strategic, primarily dry-gas, assets~~natural gas at the end of 2014 and during the first quarter of 2015 was dramatic; however, we believe this environment will provide future growth opportunities for companies that have moved aggressively in ~~Canada. Internationally,~~response to the price drop. As we ~~sold a one-third noncontrolling interest in~~cannot predict the length or depth of this commodity price correction, or the timing and extent of any potential rebound, we moved quickly and decisively regarding certain matters within our ~~Egypt operations~~control: the timing and ~~all~~levels of capital spending and our ~~assets in Argentina. In addition, we intend to completely exit the Wheatstone and Kitimat LNG projects, and, in light of our expanding opportunity set~~cost structure. We are currently operating only 15 rigs onshore in North ~~American Onshore,~~America, but we are ~~evaluating~~prepared to ramp-up activity when we believe service costs are aligned with the current commodity price environment. We closely monitor commodity prices, service cost levels, regulatory impacts, and numerous other industry factors and routinely adjust our ~~international assets~~budgets in response to changing market conditions and ~~exploring multiple opportunities, including the potential separation of some or all of them through the capital markets.~~

In addition, in June 2013 we launched a share repurchase program. Through September 30, 2014, we have repurchased a total of 31.8 million of the 40 million shares authorized by our Board of Directors. Under the program, we are not obligated to acquire any specific number of shares.operating cash flow forecasts.

~~Net cash provided by operating activities (operating cash flows or cash flows) totaled $6.5 billion~~Results for the quarter ended March 31, 2015 include:

Average daily production in the first ~~nine months~~quarter of 2015 totaled 601 thousand barrels of oil equivalent (Mboe) compared to 640 Mboe from the comparative 2014 ~~driven by~~quarter, reflecting divestiture activity during the ~~strength~~prior year.

Liquids production for the quarter averaged 373 Mboe/d, with crude oil representing 85 percent of ~~our North American drilling program.~~total liquids production. Liquids production increased slightly from the prior-year quarter despite the significant divestiture activity during 2014.

Oil and gas production revenues totaled $1.8 billion, down 50 percent from $3.6 billion in the prior-year quarter, reflecting the significant decrease in realized commodity prices and lower production.

For the ~~third~~first quarter of ~~2014,~~2015, Apache reported a loss of ~~$1.3~~$4.7 billion, or ~~$3.50~~$12.34 per diluted common share, compared with earnings of ~~$300~~$236 million, or ~~$0.75~~$0.60 per diluted share, for the prior-year quarter. The loss for the ~~2014 third~~ quarter reflects after-tax write-downs of oil and gas properties in the U.S., Canada, and U.K. North Sea totaling $1.0 billion, a deferred tax charge on undistributed foreign earnings totaling $814 million, and a deferred tax charge on distributed foreign earnings of $249 million. These expenses were partially offset by an unrealized after-tax gain on commodity derivative mark-to-market changes of $202 million.$4.7 billion.

Results for the first nine months of 2014 reflected a loss of $589 million, or $1.52 per diluted common share, compared with earnings of $2.0 billion, or $5.06 per diluted share, in the comparable prior-year period. The loss for the 2014 nine-month period reflects after-tax write-downs of oil and gas properties in the U.S. and U.K. North Sea totaling $1.1 billion, third-quarter deferred tax adjustments noted above, and an after-tax loss of $517 million on discontinued operations in Argentina. These expenses were partially offset by an unrealized after-tax gain on commodity derivative mark-to-market changes of $220 million.

~~Third Quarter~~ Operational Developments

~~Average daily production in~~Our internally generated exploration and drilling opportunities provide the ~~third quarter~~foundation for our growth. Highlights of 2014 totaled 637 thousand barrels of oil equivalent (Mboe), a decrease of 105 Mboe from the comparative 2013 quarter. The prior-year quarter includes volumes from properties in the Gulf of Mexico Shelfour 2015 drilling successes and ~~Canada that have since been divested.~~other operational developments are discussed below.

North America

North ~~American~~America onshore ~~liquids averaged 211,402 barrels per day, up 12 percent over~~production of 307 Mboe/d in the ~~prior-year quarter.~~

~~North American onshore liquids production represented nearly 55~~first quarter of 2015 represents 51 percent of ~~our~~Apache’s total worldwide ~~liquids~~ production ~~and 33 percent of our overall production.~~for the period.

~~The~~Apache’s Permian Basin region ~~averaged 42 operated rigs during the quarter, drilling 195 gross wells, 144 net wells. Combined, drilling activity in the region resulted in a~~increased production ~~increase of 23~~6 percent relative to the ~~prior-year period.~~

~~The Central region averaged 31 operated~~first quarter of 2014 despite only operating an average of 15 rigs during the ~~quarter, drilling 70 gross wells, 46 net wells, in plays such as the Granite Wash, Marmaton and Cleveland. In the Canyon Lime play, the region averaged 2~~current period compared to 39 rigs in the ~~third~~first quarter ~~increasing~~of 2014. Apache plans to ~~5 by October.~~

~~Gulf Coast region averaged 10 operated rigs~~complete the wells drilled during 2015 in the ~~quarter, drilling 19 gross wells, 14 net wells. In the East Texas Eagle Ford play, the region brought on 6 new~~normal course of business and continues to work through completing prior-year wells in ~~the Reveille area~~backlog as service costs are reduced. The Permian represents almost a third of ~~Brazos County with an average 30-day initial~~Apache’s total liquids production ~~of 687 barrels of oil equivalent per day (boe/d).~~

~~The Canada region averaged 8 operated rigs, 2 at Kitimat, during the quarter, drilling 25 gross wells, 20 net wells. Apache spud initial wells at the Duvernay seven well pad and drilled~~for the first ~~well at the Montney two well pad.~~quarter of 2015.

International

In April 2015, Apache announced the agreement to sell its Australian subsidiary Apache Energy Limited to a consortium of private equity funds managed by Macquarie Capital Group Limited and Brookfield Asset Management Inc. for cash consideration of $2.1 billion. The transaction is expected to close mid-year 2015 and is subject to necessary government and regulatory approvals and customary post-closing adjustments. The effective date of the sale is October 1, 2014.

Also during April 2015, Apache completed the previously disclosed sale of its interest in two LNG projects, Wheatstone LNG in Australia ~~region averaged 2 rigs, drilling 5 gross~~and Kitimat LNG in Canada, along with the associated upstream oil and gas assets, to Woodside Petroleum Limited for total proceeds of approximately $3.7 billion, which includes reimbursement of Apache’s net expenditure in the Wheatstone and Kitimat LNG projects, changes in working capital and other contractual adjustments between the effective date, July 1, 2014, and closing.

During the first quarter of 2015, Apache reported strong appraisal- and development-drilling results from Egypt’s recent new oil fields, Berenice and Ptah, in the Western Desert. Three wells ~~2 net~~in the Berenice field are currently producing more than 9,500 barrels of oil per day (b/d). Up to four additional wells are planned during the ~~quarter. Production was up 12 percent over~~first phase of development in the Berenice field. In the Ptah field, the discovery well is currently producing 2,350 b/d. A second ~~quarter~~well started production in March 2015 at a rate of 2014 as a result of the successful commencement of production from the Balnaves Oil Development. In addition, during the quarter, the Company made a significant first oil discovery in Australia’s offshore Canning Basin at the Phoenix South-1 well which encountered oil in 4 discrete columns, the results of which are still being evaluated.

The North Sea region averaged 5 rigs, drilling 4 gross wells, 4 net wells. During the quarter, the region successfully completed the regular scheduled annual maintenance turnaround across all operated assets ahead of schedule and without incident.

~~The Egypt region averaged 27 rigs during the quarter, drilling 63 gross wells, 54 net wells.~~2,000 b/d.

3123

Results of Operations

Oil and Gas Revenues

Oil and gas production revenues for the ~~third~~first quarter of ~~2014~~2015 totaled ~~$3.5~~$1.8 billion, a ~~$820 million~~50 percent decrease from the comparative ~~2013~~2014 quarter. The table below presents revenues by region and each region’s percent contribution to revenues for the first quarter of 2015 and 2014, ~~and 2013.~~respectively.


	For the Quarter Ended September 30,										For the Nine Months Ended September 30,
	2014					2013					2014					2013					For the Quarter Ended March 31,
	$		%			$		%			$		%			$		%			2015					2014
	Value		Contribution			Value		Contribution			Value		Contribution			Value		Contribution			$ Value		% Contribution			$ Value		% Contribution
	($ in millions)																				($ in millions)
Total Oil Revenues:
United States	$	1,121		41	%	$	1,594		46	%	$	3,358		40	%	$	4,253		43	%	$	510		38	%	$	1,092		39	%
Canada		140		5	%		167		5	%		434		5	%		442		5	%		60		4	%		140		5	%

North America		1,261		46	%		1,761		51	%		3,792		45	%		4,695		48	%		570		42	%		1,232		44	%

Egypt⁽¹⁾		805		29	%		925		26	%		2,536		30	%		2,633		27	%		433		32	%		846		30	%
Australia		200		7	%		201		6	%		523		6	%		603		6	%		81		6	%		170		6	%
North Sea		487		18	%		581		17	%		1,667		19	%		1,859		19	%		278		20	%		567		20	%

International⁽¹⁾		1,492		54	%		1,707		49	%		4,726		55	%		5,095		52	%		792		58	%		1,583		56	%

Total⁽¹⁾⁽²⁾	$	2,753		100	%	$	3,468		100	%	$	8,518		100	%	$	9,790		100	%
Total⁽¹⁾																					$	1,362		100	%	$	2,815		100	%

Total Gas Revenues:
United States	$	210		39	%	$	286		44	%	$	721		41	%	$	894		44	%	$	103		27	%	$	266		41	%
Canada		112		21	%		139		22	%		382		21	%		457		22	%		67		17	%		148		23	%

North America		322		60	%		425		66	%		1,103		62	%		1,351		66	%		170		44	%		414		64	%

Egypt⁽¹⁾		101		19	%		97		15	%		303		17	%		291		14	%		96		25	%		103		16	%
Australia		87		16	%		78		12	%		257		15	%		264		13	%		87		22	%		86		13	%
North Sea		28		5	%		45		7	%		110		6	%		142		7	%		34		9	%		43		7	%

International⁽¹⁾		216		40	%		220		34	%		670		38	%		697		34	%		217		56	%		232		36	%

Total⁽¹⁾⁽³⁾	$	538		100	%	$	645		100	%	$	1,773		100	%	$	2,048		100	%
Total⁽¹⁾																					$	387		100	%	$	646		100	%

Natural Gas Liquids (NGL)
Revenues:
Total Natural Gas Liquids (NGL) Revenues:
United States	$	150		85	%	$	149		85	%	$	436		82	%	$	396		84	%	$	47		82	%	$	147		79	%
Canada		16		9	%		19		11	%		63		12	%		53		11	%		6		11	%		30		16	%

North America		166		94	%		168		96	%		499		94	%		449		95	%		53		93	%		177		95	%

Egypt⁽¹⁾		4		2	%		—		0	%		10		2	%		—		0	%		3		5	%		1		1	%
North Sea		7		4	%		7		4	%		23		4	%		24		5	%		1		2	%		8		4	%

International⁽¹⁾		11		6	%		7		4	%		33		6	%		24		5	%		4		7	%		9		5	%

Total⁽¹⁾	$	177		100	%	$	175		100	%	$	532		100	%	$	473		100	%	$	57		100	%	$	186		100	%

Total Oil and Gas Revenues:
United States	$	1,481		42	%	$	2,029		47	%	$	4,515		42	%	$	5,543		45	%	$	660		37	%	$	1,505		41	%
Canada		268		8	%		325		8	%		879		8	%		952		8	%		133		7	%		318		9	%

North America		1,749		50	%		2,354		55	%		5,394		50	%		6,495		53	%		793		44	%		1,823		50	%

Egypt⁽¹⁾		910		27	%		1,022		24	%		2,849		26	%		2,924		24	%		532		29	%		950		26	%
Australia		287		8	%		279		6	%		780		7	%		867		7	%		168		9	%		256		7	%
North Sea		522		15	%		633		15	%		1,800		17	%		2,025		16	%		313		18	%		618		17	%

International⁽¹⁾		1,719		50	%		1,934		45	%		5,429		50	%		5,816		47	%		1,013		56	%		1,824		50	%

Total⁽¹⁾	$	3,468		100	%	$	4,288		100	%	$	10,823		100	%	$	12,311		100	%	$	1,806		100	%	$	3,647		100	%

Discontinued Operations - Argentina
Oil Revenues	$	—				$	71				$	45				$	200
Gas Revenues		—					47					39					148
NGL Revenues		—					4					3					16
Discontinued Operations – Argentina
Oil Revenue																					$	—				$	45
Gas Revenue																						—					39
NGL Revenue																						—					3

Total	$	—				$	122				$	87				$	364				$	—				$	87

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

⁽¹⁾	~~Includes revenues attributable to a noncontrolling interest in Egypt for the quarter and nine months ended September 30, 2014.~~

⁽²⁾	~~Financial derivative hedging activities decreased oil revenues $2 million for the 2014 nine-month period, and $7 million and $44 million for the 2013 third quarter and nine-month period, respectively.~~

⁽³⁾	Financial derivative hedging activities increased natural gas revenues $2 million for the 2014 nine-month period, and $9 million and $26 million for the 2013 third quarter and nine-month period, respectively.

3224

Production

The table below presents ~~third-quarter~~first quarter 2015 and ~~year-to-date~~ 2014 ~~and 2013~~ production and the relative increase or decrease from the prior period.


	For the Quarter Ended September 30,							For the Nine Months Ended September 30,
					Increase							Increase			For the Quarter Ended March 31,
	2014		2013		(Decrease)			2014		2013		(Decrease)			2015		Increase (Decrease)			2014
Oil Volume – b/d
United States		133,613		163,690		(18	%)		130,675		156,803		(17	%)		126,639		(1	%)		127,951
Canada		17,672		18,573		(5	%)		17,748		18,112		(2	%)		16,875		(4	%)		17,589

North America		151,285		182,263		(17	%)		148,423		174,915		(15	%)		143,514		(1	%)		145,540

Egypt⁽¹⁾⁽²⁾		87,499		89,294		(2	%)		88,076		89,530		(2	%)		91,971		4	%		88,093
Australia		22,014		18,787		17	%		17,817		20,195		(12	%)		20,905		24	%		16,825
North Sea		55,247		57,861		(5	%)		58,636		63,291		(7	%)		61,699		4	%		59,092

International		164,760		165,942		(1	%)		164,529		173,016		(5	%)		174,575		6	%		164,010

Total		316,045		348,205		(9	%)		312,952		347,931		(10	%)		318,089		3	%		309,550

Natural Gas Volume – Mcf/d
United States		579,188		830,423		(30	%)		589,565		848,173		(30	%)		435,818		(26	%)		592,685
Canada		300,803		529,402		(43	%)		331,470		523,163		(37	%)		287,556		(24	%)		377,712

North America		879,991		1,359,825		(35	%)		921,035		1,371,336		(33	%)		723,374		(25	%)		970,397

Egypt⁽¹⁾⁽²⁾		377,838		350,504		8	%		374,384		357,747		5	%		363,989		(4	%)		377,357
Australia		201,386		212,141		(5	%)		209,163		212,845		(2	%)		230,691		7	%		215,792
North Sea		50,647		46,971		8	%		50,209		50,108		0	%		50,445		12	%		45,071

International		629,871		609,616		3	%		633,756		620,700		2	%		645,125		1	%		638,220

Total		1,509,862		1,969,441		(23	%)		1,554,791		1,992,036		(22	%)		1,368,499		(15	%)		1,608,617

NGL Volume – b/d
United States		61,712		57,510		7	%		57,163		54,639		5	%		47,221		(11	%)		53,058
Canada		5,381		7,012		(23	%)		6,349		6,788		(6	%)		5,853		(25	%)		7,769

North America		67,093		64,522		4	%		63,512		61,427		3	%		53,074		(13	%)		60,827

Egypt⁽¹⁾⁽²⁾		726		—		NM			616		—		NM			1,031		342	%		233
North Sea		1,294		1,097		18	%		1,251		1,263		(1	%)		886		(19	%)		1,091

International		2,020		1,097		84	%		1,867		1,263		48	%		1,917		45	%		1,324

Total		69,113		65,619		5	%		65,379		62,690		4	%		54,991		(12	%)		62,151

BOE per day⁽³⁾
United States		291,857		359,604		(19	%)		286,099		352,804		(19	%)		246,497		(12	%)		279,790
Canada		73,187		113,819		(36	%)		79,341		112,095		(29	%)		70,653		(20	%)		88,310

North America		365,044		473,423		(23	%)		365,440		464,899		(21	%)		317,150		(14	%)		368,100

Egypt⁽²⁾		151,198		147,711		2	%		151,090		149,154		1	%		153,667		2	%		151,219
Australia		55,578		54,144		3	%		52,677		55,669		(5	%)		59,353		12	%		52,790
North Sea		64,982		66,787		(3	%)		68,255		72,905		(6	%)		70,993		5	%		67,695

International		271,758		268,642		1	%		272,022		277,728		(2	%)		284,013		5	%		271,704

Total		636,802		742,065		(14	%)		637,462		742,627		(14	%)		601,163		(6	%)		639,804

Discontinued Operations – Argentina
Oil (b/d)		—		9,560		NM			2,269		9,408		NM			—					6,885
Gas (Mcf/d)		—		185,962		NM			46,599		186,241		NM			—					141,352
NGL (b/d)		—		1,713		NM			424		2,254		NM			—					1,287
BOE/d		—		42,266		NM			10,461		42,702		NM			—					31,731

⁽¹⁾	Gross oil, natural gas, and NGL production in Egypt for the ~~third~~first quarter of 2015 and ~~nine-month periods of~~ 2014 ~~and 2013~~ were as follows:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2014		2013		2014		2013		2015		2014
Oil (b/d)		195,165		193,869		196,938		195,442		197,785		198,619
Gas (Mcf/d)		891,392		915,965		906,751		910,599		861,933		921,440
NGL (b/d)		1,978		—		1,780		—		2,321		649

⁽²⁾	Includes net production volumes per day attributable to a noncontrolling interest in ~~Egypt for the third quarter and nine-month periods of 2014 of:~~Egypt:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	2014		2013		2014		2013		2015		2014
Oil (b/d)		29,201		—		29,259		—		30,671		29,066
Gas (Mcf/d)		127,020		—		124,836		—		121,408		124,799
NGL (b/d)		242		—		205		—		343		78

⁽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.

~~NM — Not meaningful~~

3325

Pricing

The table below presents ~~third-quarter~~first quarter 2015 and ~~year-to-date~~ 2014 ~~and 2013~~ pricing and the relative increase or decrease from the prior periods.

   For the Quarter Ended September 30, For the Nine Months Ended September 30,
   2014    2013    Increase
(Decrease) 2014    2013    Increase
(Decrease)
Average Oil Price—Per barrel

United States
   $ 91.26    $ 105.82    (14 %) $ 94.14    $ 99.35    (5 %)
Canada
   85.43    97.58    (12 %) 89.45    89.33    0 %
North America
   90.58    104.98    (14 %) 93.58    98.31    (5 %)
Egypt
   100.06    112.61    (11 %) 105.50    107.73    (2 %)
Australia
   98.82    116.21    (15 %) 107.50    109.40    (2 %)
North Sea
   95.80    109.33    (12 %) 104.13    107.61    (3 %)
International
   98.47    111.87    (12 %) 105.23    107.88    (2 %)
Total⁽¹⁾
   94.69    108.27    (13 %) 99.71    103.07    (3 %)
Average Natural Gas Price—Per Mcf

United States
   $ 3.94    $ 3.75    5 % $ 4.48    $ 3.86    16 %
Canada
   4.04    2.87    41 % 4.22    3.20    32 %
North America
   3.97    3.41    16 % 4.39    3.61    22 %
Egypt
   2.91    3.01    (3 %) 2.96    2.98    (1 %)
Australia
   4.70    3.98    18 % 4.51    4.54    (1 %)
North Sea
   6.10    10.29    (41 %) 8.06    10.37    (22 %)
International
   3.74    3.91    (4 %) 3.88    4.11    (6 %)
Total⁽²⁾
   3.88    3.56    9 % 4.18    3.77    11 %
Average NGL Price—Per barrel

United States
   $ 26.39    $ 28.25    (7 %) $ 27.96    $ 26.55    5 %
Canada
   33.50    28.77    16 % 36.40    28.49    28 %
North America
   26.96    28.30    (5 %) 28.81    26.76    8 %
Egypt
   52.80    —      NM    56.57    —      NM
North Sea
   59.47    69.77    (15 %) 66.18    70.51    (6 %)
International
   57.07    69.77    (18 %) 63.01    70.51    (11 %)
Total
   27.84    29.00    (4 %) 29.78    27.64    8 %
Discontinued Operations—Argentina

Oil price ($/Bbl)
   $ —      $ 79.77    NM    $ 72.70    $ 77.66    (6 %)
Gas price ($/Mcf)
   —      2.76    NM    3.04    2.91    4 %
NGL price ($/Bbl)
   —      22.19    NM    24.57    25.11    (2 %)

⁽¹⁾	Reflects a per-barrel decrease of $0.02 from derivative hedging activities for the 2014 nine-month period, and a decrease of $0.22 and $0.45 from derivative hedging activities for the comparative 2013 third quarter and nine-month period, respectively.

⁽²⁾	~~Reflects a per-Mcf increase of $0.05 and $0.04 from derivative hedging activities for the comparative 2013 third quarter and nine-month period, respectively.~~

~~NM — Not meaningful~~

~~Third-Quarter 2014 compared to Third-Quarter 2013~~


	For the Quarter Ended March 31,
	2015		Increase (Decrease)			2014
Average Oil Price — Per barrel
United States	$	44.73		(53	%)	$	94.84
Canada		39.76		(55	%)		88.19
North America		44.14		(53	%)		94.03
Egypt		52.29		(51	%)		106.70
Australia		43.17		(62	%)		112.26
North Sea		49.95		(53	%)		106.60
International		50.37		(53	%)		107.24
Total		47.56		(53	%)		101.03

Average Natural Gas Price — Per Mcf
United States	$	2.63		(47	%)	$	4.98
Canada		2.58		(41	%)		4.38
North America		2.61		(45	%)		4.75
Egypt		2.92		(3	%)		3.02
Australia		4.19		(5	%)		4.42
North Sea		7.40		(31	%)		10.69
International		3.73		(7	%)		4.03
Total		3.14		(30	%)		4.46

Average NGL Price — Per barrel
United States	$	11.00		(64	%)	$	30.81
Canada		11.09		(74	%)		42.09
North America		11.01		(66	%)		32.25
Egypt		36.29		(44	%)		64.34
North Sea		24.74		(69	%)		79.84
International		30.95		(60	%)		77.11
Total		11.71		(65	%)		33.20

Discontinued Operations — Argentina
Oil price ($/Bbl)	$	—				$	72.70
Gas price ($/Mcf)		—					3.04
NGL price ($/Bbl)		—					24.57

Crude Oil Revenues

Crude oil revenues for the ~~third~~first quarter of ~~2014~~2015 totaled ~~$2.8~~$1.4 billion, a ~~$715 million~~$1.5 billion decrease from the comparative ~~2013~~2014 quarter. ~~A 9 percent~~The $1.5 billion decrease ~~in average daily production decreased third-quarter 2014 revenues by $280 million compared to the prior-year quarter, while 13 percent~~was a result of substantially lower realized prices, ~~decreased~~slightly offset by higher production volumes which increased revenues by ~~$435~~$37 million. ~~Crude oil prices realized in the third quarter of 2014 averaged $94.69 per barrel, compared with $108.27 in the comparative prior-year quarter.~~ Crude oil accounted for 7975 percent of oil and gas production revenues and 5053 percent of worldwide production in the ~~third~~first quarter of ~~2014.~~2015.

Worldwide production ~~decreased 32~~increased 8.5 thousand barrels of oil per day (Mb/d) from the ~~third~~first quarter of ~~2013~~2014 to ~~316~~318.1 Mb/d in the first quarter of 2015, primarily ~~as a result of the divestiture of~~from our ~~Gulf of Mexico Shelf assets on September 30, 2013. Exclusive of~~international operations and drilling activity in North American onshore regions offsetting recent divestitures. Excluding production from ~~these~~North American assets divested ~~assets,~~between the periods, worldwide oil production increased 1323.8 Mb/~~d, primarily on drilling and recompletion activity in the U.S. Permian region, partially offset by production decreases in Canada, Egypt and the North Sea.~~d.

Natural Gas Revenues~~Gas~~

Natural gas revenues for the ~~third~~first quarter of ~~2014~~2015 totaled ~~$538~~$387 million, down ~~17 percent~~$259 million from the ~~third~~first quarter of ~~2013.~~2014. A 2330 percent decrease in average ~~production reduced natural gas~~realized prices decreased revenues by ~~$164~~$191 million as compared to the prior-year quarter, while a 915 percent ~~increase~~decrease in average ~~realized prices increased~~production further reduced natural gas revenues by ~~$57~~$68 million. Natural gas accounted for 1621 percent of our oil and gas production revenues and 4038 percent of our equivalent ~~production.~~

~~Worldwide natural gas~~ production ~~was 460 million cubic feet per day (MMcf/d) lower than~~during the ~~third~~first quarter of ~~2013,~~2015.

Worldwide production for the first quarter of 2015 decreased 240 MMcf/d from the comparative 2014 quarter, primarily as a result of divestitures made during 2014 and lower levels of drilling activity in the ~~divestiture of our Gulf of Mexico Shelf assets on September 30, 2013 and certain Western Canadian assets over the last 12 months. Exclusive of~~recent low commodity price environment. Excluding production from ~~these~~North American assets divested ~~assets, our worldwide~~between the periods, gas production ~~was essentially flat.~~increased 36 MMcf/d.

NGL Revenues

NGL revenues for the ~~third~~first quarter of ~~2014~~2015 totaled ~~$177~~$57 million, ~~up $2~~down $129 million from the ~~third~~first quarter of ~~2013.~~2014. A ~~5 percent increase in average NGL production increased NGL revenues by $9 million compared to the prior-year quarter, while a 4~~65 percent decrease in average realized prices decreased revenues by $7$121 million compared to the prior-year quarter, while a 12 percent decrease in average production further decreased NGL revenues by $8 million. NGLs accounted for ~~approximately 5~~3 percent of our oil and gas production revenues and ~~10 percent of our equivalent production during the third quarter of 2014.~~

Worldwide production of NGLs increased 3.5 Mb/d to 69.1 Mb/d in the third quarter of 2014, primarily from increased drilling activity in the Permian region offset by the divestiture of our Gulf of Mexico Shelf assets on September 30, 2013. Exclusive of production from these divested assets, our worldwide NGL production increased 8.7 Mb/d.

~~Year-to-Date 2014 compared to Year-to-Date 2013~~

~~Crude Oil Revenues~~ Crude oil revenues for the first nine months of 2014 totaled $8.5 billion, $1.3 billion lower than the comparative 2013 period, the result of a 10 percent decrease in worldwide production and a 3 percent decrease in average realized prices. Crude oil accounted for 79 percent of oil and gas production revenues and 49 percent of worldwide production for the first nine months of 2014. Lower production volumes reduced revenue by $952 million compared to the first nine months of 2013, and lower realized prices reduced revenues by $320 million. Crude oil prices realized in the first nine months of 2014 averaged $99.71 per barrel, compared with $103.07 in the comparative prior-year period.

Worldwide production declined 35 Mb/d to 313 Mb/d in the first nine months of this year from the same period last year, primarily as a result of the divestiture of our Gulf of Mexico Shelf assets on September 30, 2013. Exclusive of production from these divested assets, worldwide production increased 10 Mb/d, primarily a result of drilling and recompletion activity in our Permian region.

~~Natural Gas Revenues~~Gas revenues for the first nine months of 2014 totaled $1.8 billion, down 13 percent from the comparative 2013 period. A 22 percent decline in average production reduced natural gas revenues by $499 million, partially offset by an 11 percent increase in average realized prices that added $224 million to revenues. Natural gas accounted for 16 percent of our oil and gas production revenues and 41 percent of our equivalent production, compared to 17 percent and 45 percent, respectively, for the 2013 period.

Our worldwide natural gas production was 437 MMcf/d lower than the first nine months of 2013 as a result of the divestiture of our Gulf of Mexico Shelf assets on September 30, 2013 and certain Western Canadian assets over the last 12 months. Exclusive of production from these divested assets, worldwide production was essentially flat.

~~NGL Revenues~~NGL revenues for the first nine months of 2014 totaled $532 million, up $59 million from the comparative 2013 period. A 4 percent increase in average production increased NGL revenues by $22 million as compared to the prior-year period, and an 8 percent increase in average realized prices increased revenues by $37 million. NGLs accounted for nearly 5 percent of our oil and gas production revenues and 109 percent of our equivalent production during the first ~~nine months~~quarter of ~~2014.~~2015.

Worldwide production of NGLs ~~increased 2.7~~decreased 7.2 Mb/d to ~~65.4~~55.0 Mb/d in the first ~~nine months~~quarter of 2015, primarily as a result of divestitures made during 2014 ~~primarily from~~and lower levels of drilling ~~and recompletion~~ activity in the ~~Central and Permian regions. Exclusive of~~recent low commodity price environment. Excluding production from North American assets divested ~~assets, our worldwide~~between the periods, NGL production increased ~~9.4~~5.0 Mb/d.

Operating Expenses

The table below presents a comparison of our expenses on an absolute dollar basis and a boe basis. Our 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 but exclude discontinued operations in Argentina.


	For the Quarter Ended September 30,								For the Nine Months Ended September 30,								For the Quarter Ended March 31,
	2014		2013		2014		2013		2014		2013		2014		2013		2015		2014		2015		2014
	(In millions)				(Per boe)				(In millions)				(Per boe)				(In millions)				(Per boe)
Depreciation, depletion, and amortization:
Depreciation, depletion and amortization:
Oil and gas property and equipment
Recurring	$	1,173	$	1,272	$	20.03	$	18.63	$	3,437	$	3,740	$	19.75	$	18.45	$	1,089	$	1,109	$	20.13	$	19.26
Additional		1,562		627		26.65		9.18		1,765		627		10.14		3.09		7,220		—		133.44		—
Other assets		100		96		1.72		1.41		296		290		1.70		1.43		98		97		1.81		1.68
Asset retirement obligation accretion		46		65		0.78		0.95		135		192		0.78		0.95		44		44		0.82		0.77
Lease operating costs		652		772		11.13		11.31		1,862		2,275		10.70		11.22		538		597		9.94		10.37
Gathering and transportation costs		67		81		1.16		1.19		203		231		1.16		1.13		56		70		1.02		1.19
Taxes other than income		170		176		2.90		2.56		532		574		3.06		2.83		84		181		1.54		3.15
General and administrative expense		112		120		1.91		1.78		309		359		1.78		1.77		79		103		1.46		1.79
Acquisition, divestiture, and separation costs		34		—		0.58		—		66		—		0.38		—		54		18		1.00		0.31
Financing costs, net		41		50		0.69		0.74		103		157		0.59		0.78		46		27		0.86		0.48

Total	$	3,957	$	3,259	$	67.55	$	47.75	$	8,708	$	8,445	$	50.04	$	41.65	$	9,308	$	2,246	$	172.02	$	39.00

Recurring Depreciation, Depletion and Amortization (DD&A)The following table details the changes in ~~recurring~~ DD&A of oil and gas properties between the ~~third quarter~~first quarters of 2015 and ~~nine-month periods of 2014 and 2013:~~2014:


	For the Quarter Ended September 30,			For the Nine Months Ended September 30,			For the Quarter Ended March 31,
	(In millions)			(In millions)			(In millions)
2013 DD&A	$	1,272		$	3,740
2014 DD&A							$	1,109
Volume change		(157	)		(487	)		(46	)
DD&A rate change		58			184
DD&A Rate change								26

2014 DD&A	$	1,173		$	3,437
2015 DD&A							$	1,089

~~Oil and gas property recurring DD&A~~Recurring full-cost depletion expense ~~of $1.2 billion in the third quarter of 2014~~ decreased ~~$99~~$20 million compared to the prior-year quarter on an absolute dollar basis: ~~$157~~$46 million from lower volumes, partially offset by ~~$58 million~~an increase ~~on rate. Oil and gas property recurring DD&A expense~~ of ~~$3.4 billion in the first nine months of 2014 decreased $303 million compared to the prior-year period on an absolute dollar basis: $487~~$26 million from ~~lower volumes offset by $184 million increase on rate. The Company’s oil and gas property recurring DD&A~~a higher average cost rate per boe. Our full-cost depletion rate increased ~~$1.40 and $1.30~~$0.87 to $20.13 per boe reflecting increased cost for exploration and development activity over the ~~third quarter and first nine months of 2014, respectively, compared to the prior-year periods.~~past several years.

Additional DD&AUnder the ~~full-cost~~full cost method of accounting, the Company is required to review the carrying value of its proved oil and gas properties each quarter on a country-by-country basis. Under these rules, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas reserves, net of related tax effects and discounted 10 percent per annum. Estimated future net cash flows are calculated using end-of-period costs and an unweighted arithmetic average of commodity prices in effect on the first day of each of the previous 12 months, held flat for the life of the production, except where prices are defined by contractual arrangements. ~~Any excess of~~

During the net book value of proved oil and gas properties, less related deferred income taxes, over the ceiling is charged to expense and reflected as “Additional DD&A” in the statement of consolidated operations.

~~In the third~~first quarter of ~~2014, the Company~~2015, we recorded ~~$1.5~~$5.2 billion ($~~996 million~~3.4 billion net of tax), $1.4 billion ($1.0 billion net of tax), and ~~$17~~$632 million ($7316 million net of tax) in non-cash ~~write-down~~write-downs of the carrying value of the Company’s U.S., Canada, and North Sea proved oil and gas properties, respectively. InIf commodity prices do not recover significantly from the ~~second quarter of 2014,~~current prices, the Company ~~recorded a $203 million ($77 million net of tax) non-cash write-down~~expects further write-downs of the carrying value of ~~the Company’s North Sea proved~~its oil and gas ~~properties.~~properties, which may be material to the Company’s consolidated financial statements, throughout the remainder of 2015.

Lease Operating Expenses (LOE)LOE decreased ~~$120~~$59 million, or 1610 percent, ~~for the quarter, and $413 million, or 18 percent, for the nine-month period,~~ on an absolute dollar basis, for the quarter ended March 31, 2015, relative to the comparable ~~periods~~period of ~~2013.~~2014. On a per unit basis, LOE decreased 4 percent to $9.94 per boe for the first quarter of 2015, as compared to the same prior-year period. The following table identifies changes in Apache’s LOE rate between the ~~third quarters~~first quarter of 2015 and ~~nine-month periods of 2014 and 2013.~~2014.


For the Quarter Ended September 30,				For the Nine Months Ended September 30,
	Per boe				Per boe			Per boe
2013 LOE	$	11.31		2013 LOE	$	11.22
First-Quarter 2014 LOE								$	10.37
Divestitures⁽¹⁾									0.35
Equipment rental									0.20
Saltwater disposal									0.10
Workover costs									(0.16	)
Labor and overhead costs		0.42		Labor and overhead costs		0.18			(0.16	)
Saltwater disposal		0.12		Saltwater disposal		0.09
Materials		0.07		Materials		0.07
Divestitures⁽¹⁾		(0.75	)	Repairs and maintenance		0.07
Power and fuel costs									(0.32	)
FX impact									(0.45	)
Other		0.30		Transportation		0.05			0.24
Other increased production		(0.34	)	Equipment rental		0.04			(0.23	)
				Workovers		0.04
First-Quarter 2015 LOE								$	9.94
				Divestitures⁽¹⁾		(1.16	)
				Other		0.36
				Other increased production		(0.26	)

2014 LOE	$	11.13		2014 LOE	$	10.70

⁽¹⁾	Per-unit impact of divestitures is shown net of associated production.

Gathering and TransportationGathering and transportation costs totaled ~~$67 million and $203~~$56 million in the ~~third~~first quarter ~~and first nine months~~ of ~~2014, respectively,~~2015, down $14 million ~~and $28 million~~ from the ~~third~~first quarter of 2014 on lower North American production. On a per-unit basis, gathering and transportation costs of $1.02 for the first ~~nine months~~quarter of ~~2013, respectively.~~2015 were down 14 percent from the prior-year quarter. The following table presents gathering and transportation costs paid by Apache directly to third-party carriers for each of the periods presented:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,				For the Quarter Ended March 31,
	2014		2013		2014		2013		2015		2014
	(In millions)								(In millions)
Canada	$	29	$	38	$	93	$	118	$	26	$	34
U.S.		24		23		69		67		16		22
Egypt		10		11		31		31		10		10
North Sea		4		9		10		15		4		4

Total Gathering and transportation	$	67	$	81	$	203	$	231	$	56	$	70

Taxes other than IncomeTaxes other than income totaled ~~$170 million and $532~~$84 million for the ~~third~~first quarter ~~and the first nine months~~ of ~~2014, respectively,~~2015, a decrease of $6$97 million ~~and $42 million, respectively,~~ from the comparative prior-year ~~periods.~~period. The following table presents a comparison of these expenses:


	For the Quarter Ended September 30,				For the Nine Months Ended September 30,				For the Quarter Ended March 31,
	2014		2013		2014		2013		2015		2014
	(In millions)								(In millions)
Australia PRRT and U.K. PRT	$	61	$	66	$	215	$	273	$	24	$	63
Severance taxes		75		71		199		185		30		73
Ad valorem taxes		26		29		89		88		24		40
Other		8		10		29		28		6		5

Total Taxes other than income	$	170	$	176	$	532	$	574	$	84	$	181

Australia Petroleum Resource Rent Tax (PRRT) ~~expense~~ is a levy assessed on the sale of hydrocarbons derived from specific developmental areas in Australia. We incurred a $45 million charge in the third quarter of 2014. Prior periods reflect no PRRT expense as sales subject to PRRT were fully offset by credits derived from exploration and development expenditures. The North Sea Petroleum Revenue Tax (PRT) is assessed on qualifying fields in the U.K. North Sea. For the first quarter of 2015, Australian PRRT and U.K. PRT ~~for the third quarter of 2014 was~~were $39 million lower than the ~~2013 period based on lower revenues. Severance tax expense increased $4 million as a result of higher U.S. onshore production.~~

~~U.K. PRT for the first nine months of~~ 2014 ~~was lower when compared to the 2013~~ period based on a decrease in ~~production revenue. For~~revenues from qualifying fields during the first ~~nine months of 2014, higher sales volumes increased severance taxes by $14~~quarter. Severance tax expense and ad valorem tax expense decreased $43 million ~~as compared to the first nine months of 2013.~~and $16 million, respectively, on lower production and oil and gas prices.

General and Administrative Expenses General and administrative expenses (G&A) for the ~~third~~first quarter of ~~2014~~2015 decreased $8$24 million from the ~~third quarter of 2013 on an absolute basis and increased $0.13 per boe on a per-unit basis. For the first nine months of 2014 G&A decreased $50 million on an absolute basis from the~~ comparable ~~2013 period and increased $0.01 per boe on a per-unit basis. Expense for the nine-month~~ 2014 period ~~includes~~on lower incentive and stock-based compensation costs following a ~~$25 million benefit from nonrecurring third party cost reimbursements.~~headcount reduction in January 2015, as well as other lower corporate costs and foreign exchange benefits.

Acquisition, Divestiture, and Separation Costs~~During the third quarter of 2014, the Company recognized $34 million in acquisition,~~Acquisition, divestiture, and separation costs for the first quarter of 2015 totaled $54 million, a $36 million increase as compared to the prior-year quarter, primarily driven by separation payments and other costs related to ~~acquisition~~an overall headcount reduction of approximately 5 percent, as well as the retirement of our former Chairman and ~~divestiture activity. For~~Chief Executive Officer during the ~~nine-month 2014 period, the Company recognized $66 million in acquisition,~~quarter. Acquisition, divestiture, and separation ~~costs.~~costs for the period also include costs related to recent divestiture and leasehold acquisition activity.

Financing Costs, NetFinancing costs incurred during the period comprised the following:


	For the Quarter Ended September 30,						For the Nine Months Ended September 30,						For the Quarter Ended March 31,
	2014			2013			2014			2013			2015			2014
	(In millions)												(In millions)
Interest expense	$	126		$	142		$	374		$	429		$	128		$	124
Amortization of deferred loan costs		2			2			5			6			2			2
Capitalized interest		(85	)		(91	)		(270	)		(268	)		(80	)		(95	)
Interest income		(2	)		(3	)		(6	)		(10	)		(4	)		(4	)

Financing costs, net	$	41		$	50		$	103		$	157		$	46		$	27

Net financing costs ~~were down $9 million and $54~~increased $19 million in the ~~third~~first quarter ~~and first nine months~~ of ~~2014, respectively,~~2015 compared to the same ~~2013 periods. The $16~~2014 period primarily from a $15 million decrease in capitalized interest as a result of divestitures made throughout 2014 and ~~$55~~a $4 million ~~decreases~~increase in interest expense ~~in the third quarter and first nine months of 2014, respectively, were a result of lower average debt balances.~~during 2015.

Provision for Income TaxesIn the third quarter of 2014, Apache evaluated its permanent reinvestment position and determined that undistributed earnings from certain foreign subsidiaries located in Apache’s Australia, Egypt, and North Sea regions will no longer be permanently reinvested. As a result of this change in position, the Company recorded $814 million of U.S. deferred income tax expense on the undistributed earnings that were previously considered permanently reinvested. In addition, the Company recorded $249 million of U.S. deferred income tax expense on foreign earnings that were distributed to the U.S. in the third quarter of 2014.

On March 26, 2015, U.K. Finance Bill 2015 received Royal Assent. Under the enacted legislation, the corporate income tax rate on North Sea oil and gas profits was reduced from 62 percent to 50 percent effective January 1, 2015. As a result of the enacted legislation in the ~~third~~first quarter of ~~2014,~~2015, the Company recorded ~~$814~~a discrete deferred tax benefit of $619 million related to the remeasurement of ~~U.S.~~the Company’s December 31, 2014 U.K. deferred income tax ~~expense on foreign earnings no longer deemed to be permanently reinvested as well as the~~liability.

The 2015 first-quarter income tax ~~effect~~benefit was $2.9 billion, representing an effective income tax rate of 38 percent for the ~~$1.5~~quarter compared to 40 percent during the 2014 period. The 2015 effective rates reflect the tax benefit from the $7.2 billion ~~and $17 million~~ non-cash write-downs of ~~its~~our U.S., Canada, and North Sea proved oil and gas properties, ~~respectively, as discrete items~~the tax benefit related to the change in ~~the third quarter of 2014. In the second quarter of 2014, the Company recorded the~~U.K. income tax ~~impact of a $203 million non-cash write-down of its North Sea proved oil~~rate from 62 percent to 50 percent, and ~~gas properties as a discrete item. In~~ the ~~third quarter of 2013,~~Canadian valuation allowance. The 2014 effective rate reflects the ~~Company recorded the income~~Canadian valuation allowance and deferred tax ~~impact of a $552 million non-cash write-down and a $75 million non-cash impairment on its U.S. and Kenyan oil and gas properties, respectively, as discrete items.~~expense related to mark-to-market commodity derivatives. Excluding these items, the first-quarter 2015 and ~~certain other tax adjustments, the third quarter~~ 2014 ~~and 2013~~effective rates would have been ~~44 percent~~28 and 41 percent, respectively.

Capital Resources and Liquidity

Operating cash flows are the Company’s primary source of liquidity. We may also elect to utilize 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. As a majority of our capital investment activity is discretionary, we routinely adjust our capital budget on a quarterly basis in response to changing market conditions and operating cash flow forecasts.

Apache’s operating cash flows, both in the short-term and the long-term, are impacted by highly volatile oil and natural gas prices. Significant deterioration in commodity prices negatively impacts our revenues, earnings and cash flows, and potentially our liquidity if spending does not trend downward as well. Sales volumes and costs also impact cash flows; however, these historically have not been as volatile and have less impact than commodity prices 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 our drilling program and our ability to add reserves at reasonable costs.

We believe the liquidity and capital resource alternatives available to Apache, combined with ~~internally generated~~proactive measures to adjust our capital budget to reflect lower oil prices and anticipated operating cash flows, will be adequate to fund short-term and long-term operations, including our capital spending program, repayment of debt maturities, and any amount that may ultimately be paid in connection with commitments and contingencies.

For additional information, please see Part II, Item 1A, “Risk Factors” of this Quarterly Report on Form 10-Q and Part I, Items 1 and 2, “Business and Properties,” and Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for our ~~2013~~2014 fiscal year.

Sources and Uses of Cash

The following table presents the sources and uses of our cash and cash equivalents ~~and the sources of our restricted cash~~ for the periods presented.

   For the Nine Months Ended
September 30,
   2014 2013
   (In millions)
Sources of Cash and Cash Equivalents:

Net cash provided by continuing operating activities
   $ 6,446 $ 7,200
Proceeds from the sale of Argentina
   786 —
Net cash provided by Argentina operations
   2 —
Proceeds from sale of Deepwater Gulf of Mexico assets
   1,367 —
Proceeds from divestiture of Gulf of Mexico Shelf properties
   —   3,594
Proceeds from Kitimat LNG transaction, net
   —   396
Proceeds from sale of other oil and gas properties
   390 199
Net commercial paper and bank loan borrowings
   1,246 —
Other
   —   26


   10,237 11,415


Uses of Cash and Cash Equivalents:

Capital expenditures for exploration and development (E&D) activity
   $ 7,131    $ 7,186
Capital expenditures for gas gathering, transmission, and processing facilities
   1,035 852
Net cash used by Argentina operations
   —   5
Leasehold and property acquisitions
   655    313
Restricted cash from sale of Deepwater Gulf of Mexico assets
   545 —
Payments on fixed rate debt
   —   900
Net commercial paper and bank loan repayments
   —   539
Dividends
   271 280
Treasury stock activity, net
   1,830 249
Distributions to noncontrolling interest
   124 —
Other
   42 —


   11,633 10,324


Increase (decrease) in cash and cash equivalents
   $ (1,396 ) $ 1,091


Sources of Restricted Cash:

Short-term restricted cash from sale of Deepwater Gulf of Mexico assets
   74 —
Long-term restricted cash from sale of Deepwater Gulf of Mexico assets
   471 —


Increase in restricted cash
   $ 545 $ —


	For the Three Months Ended March 31,
	2015			2014
	(In millions)
Sources of Cash and Cash Equivalents:
Net cash provided by continuing operating activities	$	650		$	2,211
Commercial paper and bank loan borrowings, net		1,028			—
Net cash provided by Argentina discontinued operations		—			788
Other		15			9

		1,693			3,008

Uses of Cash and Cash Equivalents:
Capital expenditures⁽¹⁾	$	1,991		$	2,706
Leasehold and property acquisitions		92			44
Dividends paid		94			79
Treasury stock activity, net		—			484
Other		56			2

		2,233			3,315

Increase (decrease) in cash and cash equivalents	$	(540	)	$	(307	)

⁽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 Continuing Operating ActivitiesOperating cash flows are our 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, asset retirement obligation (ARO) accretion, and deferred income tax expense, which affect earnings but do not affect cash flows.

Net cash provided by continuing operating activities for the first ~~nine~~three months of ~~2014~~2015 totaled ~~$6.4 billion,~~$650 million, a decrease of ~~$754 million~~$1.6 billion from the first ~~nine~~three months of ~~2013.~~2014. The decrease is primarily ~~reflects~~a result of the ~~impact~~loss from operations from low oil prices and lower production during the first quarter of ~~2013 divestitures~~2015 and ~~comparative~~ changes in working ~~capital during the periods.~~capital.

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 Part I, Item 1, Financial Statements of this Quarterly Report on Form 10-Q.

~~Proceeds~~Commercial paper and bank loan borrowings During the first quarter of 2015, Apache’s net borrowings on committed bank facilities, uncommitted bank lines, and commercial paper totaled $1.0 billion. Outstanding debt under these programs totaled $2.6 billion as of March 31, 2015, and was classified as current on Apache’s consolidated balance sheet based on an intent to repay the obligations with proceeds from the ~~Sale~~LNG project divestitures. All current debt was repaid in April 2015 upon closing of ~~Argentina~~In March 2014, we completed the previously disclosed sale of our Argentina operations and properties to YPF Sociedad Anònima for cash consideration of $800 million (subject to customary closing adjustments) plus the assumption of $52 million of bank debts as of June those divestitures.

30 ~~2013. The results of operations related to Argentina have been classified as discontinued operations in all periods presented in this Quarterly Report on Form 10-Q.~~

Capital Expenditures~~During~~ Worldwide E&D expenditures for the first ~~nine~~three months of ~~2014, capital spending for E&D activities~~2015 totaled ~~$7.1~~$1.8 billion, compared to ~~$7.2~~$2.3 billion infor the ~~prior year period.~~first three months of 2014. Apache’s E&D capital spending was primarily focused on ~~our~~ North American onshore assets. With the focused reduction of drilling rigs and activity occurring during the first quarter of 2015, we expect capital expenditures to be significantly reduced for the remainder of the year. In the ~~Permian~~North America onshore region, ~~we averaged 42~~Apache operated an average of 32 drilling rigs during the ~~quarter. Our recent drilling successes in the Permian have led the region to increase the number~~first quarter of horizontal drilling rigs being utilized, and now two-thirds of our rigs are drilling horizontal wells that, given their nature, are more costly than vertical wells. In our Gulf Coast region, we are increasing activity on our Eagle Ford acreage in Texas and have nearly tripled E&D spending over the 2013 nine-month period.2015.

Apache also completed leasehold and property acquisitions totaling ~~$655~~$92 million and $44 million during the first ~~nine months~~quarters of 2015 and 2014, ~~compared with $313 million in the 2013 period.~~respectively. Our ~~2014~~2015 acquisition investments ~~focused~~continue to focus on adding new leasehold positions to our North American onshore portfolio.

Apache’s investment in gas gathering, transmission, and processing (GTP) facilities totaled ~~$1.0 billion~~$223 million during the first ~~nine months~~quarter of ~~2014~~2015 compared to ~~$852~~$344 million in the ~~prior year~~comparative prior-year period. ~~Apache’s 2014 GTP capital expenditures were primarily for the Wheatstone and Kitimat LNG facilities.~~

Dividends For the ~~nine-month~~three-month periods ended ~~September 30,~~March 31, 2015 and 2014, ~~and 2013,~~ the Company paid ~~$271~~$94 million and ~~$223~~$79 million, respectively, in dividends on its common stock. ~~In the first nine months of 2013, the Company also paid $57 million in dividends on its Series D Preferred Stock, which was converted to common stock in August 2013.~~

~~Shares Repurchased~~ 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 held negotiated transactions. The Company initiated the buyback program on June 10, 2013, and through September 30, 2014 has repurchased a total of 31.8 million shares at an average price of $88.90 per share. For the nine-month period ended September 30, 2014, the Company repurchased a total of 20.6 million shares at an average price of $88.92 per share. The Company is not obligated to acquire any specific number of shares.

~~Restricted Cash~~The Company classifies cash balances as restricted cash when cash is restricted as to withdrawal or usage. As of September 30, 2014, the Company had $545 million of proceeds from the sale of deepwater Gulf of Mexico properties held by a qualified intermediary and available for use in a like-kind exchange under Section 1031 of the U.S. Internal Revenue Code. As of the date of this filing, the Company has utilized or plans to utilize $471 million of the cash held by the qualified intermediary in the acquisition of like-kind property, and as such, this amount is classified as long-term restricted cash on Apache’s consolidated balance sheet as of September 30, 2014. The remaining $74 million of restricted cash was returned to Apache in October and, as such, is classified as short-term restricted cash on Apache’s consolidated balance sheet as of September 30, 2014. For more information regarding the sale of the deepwater Gulf of Mexico properties, please refer to Note 2—Acquisitions and Divestitures.

Liquidity

The following table presents a summary of our key financial indicators at the dates presented:


	September 30,			December 31,
	2014			2013			March 31, 2015			December 31, 2014
	(In millions of dollars, except as indicated)						(In millions of dollars, except as indicated)
Cash and cash equivalents	$	510		$	1,906		$	229		$	769
Short-term restricted cash		74			—
Total debt		10,922			9,725			12,273			11,245
Equity		32,986			35,393			23,405			28,137
Available committed borrowing capacity		2,072			3,300			2,702			3,730
Percent of total debt-to-capitalization		25	%		22	%		34	%		29	%

Cash and cash equivalents ~~The Company~~We had ~~$510~~$229 million in cash and cash equivalents as of ~~September 30, 2014,~~March 31, 2015, compared to ~~$1.9 billion~~$769 million at December 31, ~~2013. Approximately $487~~2014. At March 31, 2015, approximately $210 million of the cash was held by foreign subsidiaries. The cash held by foreign subsidiaries ~~may be~~is subject to additional U.S. income taxes if repatriated. ~~Almost all~~The majority of the cash ~~is denominated in U.S. dollars and, at times,~~ is invested in highly liquid, investment grade securities with maturities of three months or less at the time of purchase.

DebtAs of ~~September 30, 2014,~~March 31, 2015, outstanding debt, which consisted of notes, debentures, commercial paper, committed bank facilities, and uncommitted bank lines, totaled ~~$10.9~~$12.3 billion. ~~The Company had approximately $20 million~~Current debt of ~~current debt~~$2.6 billion was outstanding ~~borrowed on uncommitted credit facilities and overdraft lines~~ as of ~~September 30, 2014, compared with $53 million as of December~~March 31, ~~2013.~~2015.

Available committed borrowing capacity As of ~~September 30, 2014,~~March 31, 2015, the Company had unsecured committed revolving syndicated bank credit facilities totaling ~~$3.3~~$5.3 billion, of which $2.0 billion matures in December 2015, $1.0 billion matures in August 2016, and $2.3 billion matures in June ~~2018 pursuant to a one-year extension approved in May 2014 under the terms of the $2.3~~2018. Apache has $2.0 billion, ~~facilities. The facilities consist of a~~ $1.7 billion, ~~facility~~ and a $1.0 billion ~~facility in the~~ U.S., facilities, a $300 million Australian facility, ~~in Australia,~~ and a $300 million ~~facility in Canada.~~Canadian facility. As of ~~September 30, 2014,~~March 31, 2015, available borrowing capacity under the Company’s credit facilities was ~~$2.1~~$2.7 billion. The Company’s committed credit facilities are used to support Apache’s commercial paper program.

The Company has ~~available~~ a ~~$3.0~~$5.0 billion commercial paper program, which ~~generally enables~~allows Apache to borrow funds for up to 270 days at competitive interest rates. ~~The commercial paper program is fully supported by available borrowing capacity under the Company’s committed credit facilities.~~ As of ~~September 30, 2014,~~March 31, 2015, the Company had ~~$1.2~~$2.6 billion ofin current debt outstanding ~~commercial paper. There was no outstanding~~under commercial paper, committed bank facilities, and uncommitted bank lines. This amount was classified as current on Apache’s consolidated balance sheet based on an intent to repay the obligations with the proceeds from the LNG project divestitures. All current debt was repaid in April 2015 upon closing of ~~December 31, 2013.~~those divestitures.

The Company was in compliance with the terms of all credit facilities as of ~~September 30, 2014.~~March 31, 2015.

Percent of total debt-to-capitalizationThe Company’s debt-to-capitalization ratio at ~~September 30, 2014~~March 31, 2015 and December 31, ~~2013~~2014 was 2534 percent and 2229 percent, respectively.

4131

~~ITEM 3 –~~

~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

ITEM 3 – QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Risk

The Company’s revenues, earnings, cash flow, capital investments and, ultimately, future rate of growth are highly dependent on the prices we receive for our crude oil, natural gas and NGLs, which have historically been very volatile because of unpredictable events such as economic growth or retraction, weather, and political climate. Our average crude oil realizations decreased 53 percent to ~~$94.69~~$47.56 per barrel in the ~~third~~first quarter of ~~2014~~2015 from ~~$108.27~~$101.03 per barrel in the comparable period of ~~2013.~~2014. Our average natural gas price realizations ~~increased 9~~decreased 30 percent to ~~$3.88~~$3.14 per Mcf ~~in the third quarter of 2014~~ from ~~$3.56~~$4.46 per Mcf in the comparable period of ~~2013.~~2014.

We periodically enter into derivative positions on a portion of our 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. ~~For the third quarter~~Apache periodically uses futures contracts, swaps, and ~~first nine months of 2014, approximately 11 percent and 9 percent, respectively, of our natural gas production and approximately 40 percent of our crude oil production in each period was subject~~options to ~~financial derivatives.~~mitigate commodity price risk. Apache does not hold or issue derivative instruments for trading purposes.

~~On September 30, 2014, the Company~~ As of March 31, 2015, Apache had no open natural gas derivatives in an asset position with a fair value of $6 million. A 10 percent movement in natural gas prices would move the fair value by approximately $6 million. The Company also had open oil derivatives in an asset position with a fair value of $35 million. A 10 percent decrease in oil prices would increase the asset by approximately $107 million, while a 10 percent increase in prices would move the derivatives to a liability position of $71 million. These fair value changes assume volatility based on prevailing market parameters at September 30, 2014. See Note 3—Derivative Instruments and Hedging Activities of the Notes to Consolidated Financial Statements in Item 1 of this Form 10-Q for notional volumes and terms associated with the Company’scommodity derivative ~~contracts.~~positions.

Interest Rate Risk

The Company considers its interest rate risk exposure to be minimal as a result of fixing interest rates on approximately 8979 percent of the Company’s debt. At ~~September 30, 2014,~~March 31, 2015, total debt included ~~approximately $1.2~~$2.6 billion of floating-rate debt. As a result, Apache’s annual interest costs will fluctuate based on short-term interest rates on 11approximately 21 percent of our total debt outstanding at ~~September 30, 2014.~~March 31, 2015. The impact on cash flow of a 10 percent change in the floating interest rate based on debt balances at ~~September 30, 2014,~~March 31, 2015, would be approximately ~~$103,000~~$588,570 per quarter.

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. In Australia, oil production is sold under U.S. dollar contracts, and gas production is sold under a ~~combination~~mixture of ~~Australian~~fixed-price U.S. dollar and ~~U.S.~~Australian dollar ~~fixed-price~~ contracts. Approximately 40 percent of the costs incurred for Australian operations are paid in U.S. dollars. In Canada, oil and gas prices and costs, such as equipment rentals and services, are generally denominated in Canadian dollars but heavily influenced by U.S. markets. Our 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 Australian dollars, Canadian dollars, and 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 we re-measure our 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 $176 million would result from a~~ 10 percent strengthening or weakening ~~or strengthening, respectively, in~~of the Australian dollar, Canadian dollar, and British pound as of ~~September 30, 2014.~~March 31, 2015, would result in a foreign currency net loss or gain, respectively, of approximately $163 million.

4232

Forward-Looking Statements and Risk

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs, and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information that was used to prepare our estimate of proved reserves as of December 31, ~~2013,~~2014, and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “could,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “plan,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:

the market prices of oil, natural gas, NGLs and other products or services;

our commodity derivative and hedging arrangements;

~~the integration of acquisitions;~~

the supply and demand for oil, natural gas, NGLs, and other products or services;

production and reserve levels;

drilling risks;

economic and competitive conditions;

the availability of capital resources;

capital expenditure and other contractual obligations;

currency exchange rates;

weather conditions;

inflation rates;

the availability of goods and services;

legislative or regulatory changes;

the impact on our operations ~~from~~due to changes in the Egyptian government;

the integration of acquisitions;

terrorism or ~~cyber-attacks;~~cyber attacks;

occurrence of property acquisitions or divestitures;

the securities or capital markets and related risks such as general credit, liquidity, market, and interest-rate risks; and

other factors disclosed under Items 1 and 2—Business and Properties—Estimated Proved Reserves and Future Net Cash Flows, Item 1A—Risk Factors, ~~and elsewhere in our most recently filed Form 10-K,~~ Item 7—Management’s Discussion and Analysis of Financial Condition and Results of Operations, Item 7A—Quantitative and Qualitative Disclosures About Market Risk and elsewhere in our ~~Current~~most recently filed Annual Report on Form ~~8-K dated July 17, 2014,~~10-K, other risks and uncertainties in our ~~third-quarter 2014~~first-quarter 2015 earnings release, other factors disclosed under Part II, Item 1A—Risk Factors of this Quarterly Report on Form 10-Q, and other filings that we make with the Securities and Exchange Commission.

All subsequent written and oral forward-looking statements attributable to the Company, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.

4333

~~ITEM 4 –~~

~~CONTROLS AND PROCEDURES~~

ITEM 4 – CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

~~G. Steven Farris,~~John J. Christmann, the Company’s ~~Chairman of the Board,~~ Chief Executive Officer and President, in his capacity as principal executive officer, and ~~P. Anthony Lannie,~~Stephen J. Riney, the Company’s Executive Vice President and Chief Financial Officer, in his capacity as principal financial officer, evaluated the effectiveness of our disclosure controls and procedures as of ~~September 30, 2014,~~March 31, 2015, 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 information we are required to disclose under applicable laws and regulations is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

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

Changes in Internal Control over Financial Reporting

There was no change in our internal controls over financial reporting during the period covered by this Quarterly Report on Form 10-Q that materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II—OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

Please refer to both ~~Note 8—Commitments and Contingencies~~Part I, Item 3 of the ~~notes to the consolidated financial statements~~Company’s Annual Report on Form 10-K for the fiscal year ended December 31, ~~2013 contained in Apache’s Current Report on Form 8-K dated July 17,~~ 2014, and Note 8—7—Commitments and Contingencies of the notes to the consolidated financial statements set forth in Part I, Item 1 of this Quarterly Report on Form 10-Q, for a description of material legal proceedings.

ITEM 1A.

RISK FACTORS

Please refer to both Part I, Item 1A—Risk Factors of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, ~~2013,~~2014, and as noted above in Part I, Item 3—Quantitative and Qualitative Disclosures About Market Risk of this Quarterly Report on Form 10-Q.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

~~The following table presents information on~~Apache’s Board of Directors has authorized the purchase of up to 40 million shares of the Company’s common ~~stock~~stock. Shares may be purchased either in the open market or through privately held negotiated transactions. The Company initiated the buyback program on June 10, 2013, and through December 31, 2014, had repurchased ~~by the~~a total of 32.2 million shares at an average price of $88.96 per share. The Company has not purchased any additional shares during ~~the quarter ended September 30, 2014:~~2015, and is not obligated to acquire any specific number of shares.

Issuer Purchases of Equity Securities

Period
   Total Number
of Shares
Purchased    Average Price
Paid per Share    Total Number of
Shares Purchased
as Part of Publicly
Announced Plans
or Programs⁽¹⁾    Maximum Number
of Shares that May
Yet Be Purchased
Under the Plans or
Programs⁽¹⁾
July 1 to July 31, 2014
   —      $ —      —      13,922,662
August 1 to August 31, 2014
   2,504,119    99.68    2,504,119    11,418,543
September 1 to September 30, 2014
   3,239,674    97.93    3,239,674    8,178,869





Total
   5,743,793    $ 98.69

⁽¹⁾

On May 9, 2013, the Company announced that its Board of Directors authorized the repurchase of up to 30 million shares of the Company’s common stock. Additionally, on May 15, 2014, the Company announced that the Board of Directors had authorized the repurchase of an additional 10 million shares, supplementing the May 2013 authorization. The Company may buy shares from time to time on the open market, in privately negotiated transactions, or a combination of both. The timing and amounts of any repurchases will be at the discretion of Apache’s management and will depend on a variety of factors, including the stock price, corporate and regulatory requirements, and other market and economic conditions. Repurchased shares will be available for general corporate purposes.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4.

MINE SAFETY DISCLOSURES

None

ITEM 5.

OTHER INFORMATION

None

ITEM 6.

EXHIBITS

      3.1 –    Restated Certificate of Incorporation of Registrant, dated September 19, 2013, as filed with the Secretary of State of Delaware on September 19, 2013 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed September 20, 2013, SEC File No. 001-4300).
      3.2 –    Bylaws of Registrant, as amended May 16, 2013 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed May 17, 2013, SEC File No. 001-4300).
  *10.1 –    2014 Employee Release and Settlement Agreement, by and between Registrant and Thomas P. Chambers, effective as of August 31, 2014.
  *10.2 –    Amendment of Stock Option Grants (2007 and 2011 Omnibus Equity Compensation Plans) by and between Registrant and Thomas P. Chambers, effective as of August 31, 2014.
  *10.3 –    Amendment of Restricted Stock Unit Awards (2007 and 2011 Omnibus Equity Compensation Plans) by and between Registrant and Thomas P. Chambers, effective as of August 31, 2014.
  *10.4 –    Employee Resignation Agreement by and between Registrant and Alfonso Leon, effective as of October 13, 2014.
  *10.5 –    Amendment of Stock Option Grants (2007 and 2011 Omnibus Equity Compensation Plans) by and between Registrant and Alfonso Leon, effective as of October 9, 2014.
  *10.6 –    Amendment of Restricted Stock Unit Awards (2007 and 2011 Omnibus Equity Compensation Plans), effective October 9, 2014, between Registrant and Alfonso Leon.
  *31.1 –    Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.
  *31.2 –    Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.
  *32.1 –    Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.
*101.INS –    XBRL Instance Document.
*101.SCH –    XBRL Taxonomy Schema Document.
*101.CAL –    XBRL Calculation Linkbase Document.
*101.LAB –    XBRL Label Linkbase Document.
*101.PRE –    XBRL Presentation Linkbase Document.
*101.DEF –    XBRL Definition Linkbase Document.

*	~~Filed herewith~~



3.1	–	Restated Certificate of Incorporation of Registrant, dated September 19, 2013, as filed with the Secretary of State of Delaware on September 19, 2013 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed September 20, 2013, SEC File No. 001 -4300).

3.2	–	Bylaws of Registrant, as amended February 19, 2015 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed February 23, 2015, SEC File No. 001-4300).

*10.1	–	Form of 2015 Performance Share Program Award Notice and Agreement.

*10.2	–	2015 Long Term Cash Performance Program Award Notice and Agreement between Registrant and Stephen J. Riney, dated April 8, 2015.

10.3	–	Retirement Agreement, dated January 19, 2015, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.39 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2014, SEC File No. 001-4300).

10.4	–	Amendment of Stock Option Grants (2011 Omnibus Equity Compensation Plan), dated January 20, 2015, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.63 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2014, SEC File No. 001-4300).

10.5	–	Amendment of Restricted Stock Unit Awards (2007 and 2011 Omnibus Equity Compensation Plans), dated January 20, 2015, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.64 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2014, SEC File No. 001-4300).

10.6	–	Amendment of 2014 Performance Program (Business Performance) Award (2011 Omnibus Compensation Plan), dated January 20, 2015, between Registrant and G. Steven Farris (incorporated by reference to Exhibit 10.65 to Registrant’s Annual Report on Form 10-K for the year ended December 31, 2014, SEC File No. 001-4300).

*10.7	–	Restricted Stock Unit Award Agreement between Registrant and John J. Christmann, dated February 18, 2015.

*31.1	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.

*31.2	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.

*32.1	–	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.

*101.INS	–	XBRL Instance Document.

*101.SCH	–	XBRL Taxonomy Schema Document.

*101.CAL	–	XBRL Calculation Linkbase Document.

*101.LAB	–	XBRL Label Linkbase Document.

*101.PRE	–	XBRL Presentation Linkbase Document.

*101.DEF	–	XBRLDefinition Linkbase Document.

* Filed herewith

4535

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.


		APACHE CORPORATION

Dated: ~~November 6, 2014~~May 7, 2015		/s/ ~~P. ANTHONY LANNIE~~STEPHEN J. RINEY
	~~P. Anthony Lannie~~	Stephen J. Riney
		Executive Vice President and Chief Financial Officer (Principal Financial Officer)

Dated: ~~November 6, 2014~~May 7, 2015		/s/ REBECCA A. HOYT
		Rebecca A. Hoyt
		Senior Vice President, Chief Accounting Officer, and Controller (Principal Accounting Officer)

4636


	For the Nine Months Ended September 30,						For The Quarter Ended March 31,
	2014			2013			2015			2014
	(In millions)						(In millions)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) including noncontrolling interest	$	(294	)	$	2,058		$	(4,636	)	$	334
Adjustments to reconcile net income to net cash provided by operating activities:
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss from discontinued operations		517			192			—			517
Depreciation, depletion, and amortization		5,498			4,657			8,407			1,206
Asset retirement obligation accretion		135			192			44			44
Provision for deferred income taxes		930			229
Provision for (benefit from) deferred income taxes								(2,898	)		162
Other		(263	)		190			(17	)		(41	)
Changes in operating assets and liabilities:
Receivables		572			(49	)		257			389
Inventories		78			(41	)		48			85
Drilling advances		(84	)		123			(85	)		37
Deferred charges and other		(244	)		(205	)		(102	)		(74	)
Accounts payable		(303	)		183			(199	)		(170	)
Accrued expenses		(117	)		(369	)		(199	)		(286	)
Deferred credits and noncurrent liabilities		21			40			30			8

NET CASH PROVIDED BY CONTINUING OPERATING ACTIVITIES		6,446			7,200			650			2,211
NET CASH PROVIDED BY DISCONTINUED OPERATIONS		82			158			—			82

NET CASH PROVIDED BY OPERATING ACTIVITIES		6,528			7,358			650			2,293
CASH FLOWS FROM INVESTING ACTIVITIES:
Additions to oil and gas property		(7,131	)		(7,186	)		(1,768	)		(2,318	)
Leasehold and property acquisitions								(92	)		(44	)
Additions to gas gathering, transmission, and processing facilities		(1,035	)		(852	)		(223	)		(344	)
Proceeds from divestiture of Gulf of Mexico Shelf properties		—			3,594
Proceeds from sale of Deepwater Gulf of Mexico assets		1,367			—
Restricted cash related to divestitures		(545	)		—
Proceeds from Kitimat LNG transaction, net		—			396
Proceeds from sale of other oil and gas properties		390			199
Leasehold and property acquisitions		(655	)		(313	)
Other, net		(80	)		(12	)		(35	)		9

NET CASH USED IN CONTINUING INVESTING ACTIVITIES		(7,689	)		(4,174	)		(2,118	)		(2,697	)
NET CASH PROVIDED BY (USED IN) DISCONTINUED OPERATIONS		748			(160	)
NET CASH PROVIDED BY DISCONTINUED OPERATIONS								—			748

NET CASH USED IN INVESTING ACTIVITIES		(6,941	)		(4,334	)		(2,118	)		(1,949	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Commercial paper and bank credit facilities, net		1,246			(539	)		1,028			(2	)
Payments on fixed rate debt		—			(900	)
Distributions to noncontrolling interest		(124	)		—			(21	)		—
Dividends paid		(271	)		(280	)		(94	)		(79	)
Treasury stock activity, net		(1,830	)		(249	)		—			(484	)
Other		38			38			15			—

NET CASH USED IN CONTINUING FINANCING ACTIVITIES		(941	)		(1,930	)
NET CASH PROVIDED BY (USED IN) CONTINUING FINANCING ACTIVITIES								928			(565	)
NET CASH USED IN DISCONTINUED OPERATIONS		(42	)		(3	)		—			(42	)

NET CASH USED IN FINANCING ACTIVITIES		(983	)		(1,933	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(1,396	)		1,091
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES								928			(607	)
NET DECREASE IN CASH AND CASH EQUIVALENTS								(540	)		(263	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR		1,906			160			769			1,906

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	510		$	1,251		$	229		$	1,643

SUPPLEMENTARY CASH FLOW DATA:
Interest paid, net of capitalized interest	$	143		$	185		$	89		$	70
Income taxes paid, net of refunds		1,134			1,344			142			491


	September 30,			December 31,
	2014			2013			March 31, 2015			December 31, 2014
	(In millions)						(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	510		$	1,906		$	229		$	769
Short-term restricted cash		74			—
Receivables, net of allowance		2,287			2,952			1,767			2,024
Inventories		713			891			666			708
Drilling advances		434			371			468			388
Assets held for sale								1,804			1,628
Deferred tax asset								769			769
Prepaid assets and other		408			246			203			129

		4,426			6,366			5,906			6,415

PROPERTY AND EQUIPMENT:
Oil and gas, on the basis of full-cost accounting:
Proved properties		86,963			83,390			91,634			89,852
Unproved properties and properties under development, not being amortized		7,928			8,363			6,753			7,014
Gathering, transmission and processing facilities		7,874			6,995			5,472			5,440
Other		1,107			1,071			1,161			1,152

		103,872			99,819			105,020			103,458
Less: Accumulated depreciation, depletion, and amortization		(50,837	)		(47,398	)
Less: Accumulated depreciation, depletion and amortization								(63,790	)		(55,382	)

		53,035			52,421			41,230			48,076

OTHER ASSETS:
Long-term restricted cash		471			—
Goodwill		1,369			1,369			87			87
Deferred charges and other		1,689			1,481			1,427			1,374

	$	60,990		$	61,637		$	48,650		$	55,952

LIABILITIES AND SHAREHOLDERS’ EQUITY
CURRENT LIABILITIES:
Accounts payable	$	1,316		$	1,616		$	1,010		$	1,210
Current debt		20			53			2,598			—
Current asset retirement obligation		177			121			47			37
Derivative instruments		—			299
Other current liabilities		2,794			2,611			1,838			2,417

		4,307			4,700			5,493			3,664

LONG-TERM DEBT		10,902			9,672			9,675			11,245

DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES:
Income taxes		9,298			8,364			6,611			9,499
Asset retirement obligation		3,096			3,101			3,094			3,048
Other		401			407			372			359

		12,795			11,872			10,077			12,906

COMMITMENTS AND CONTINGENCIES (Note 8)
COMMITMENTS AND CONTINGENCIES (Note 7)
EQUITY:
Common stock, $0.625 par, 860,000,000 shares authorized, 409,671,364 and 408,041,088 shares issued, respectively		256			255
Common stock, $0.625 par, 860,000,000 shares authorized, 410,110,362 and 409,706,347 shares issued, respectively								256			256
Paid-in capital		12,379			12,251			12,456			12,438
Retained earnings		21,156			22,032			11,504			16,249
Treasury stock, at cost, 32,853,183 and 12,268,180 shares, respectively		(2,857	)		(1,027	)
Treasury stock, at cost, 33,192,567 and 33,201,455 shares, respectively								(2,889	)		(2,890	)
Accumulated other comprehensive loss		(116	)		(115	)		(116	)		(116	)

APACHE SHAREHOLDERS’ EQUITY		30,818			33,396			21,211			25,937
Noncontrolling interest		2,168			1,997			2,194			2,200

TOTAL EQUITY		32,986			35,393			23,405			28,137

	$	60,990		$	61,637		$	48,650		$	55,952


			Fixed-Price Swaps
Production					MMBtu		Weighted Average
Period	Commodity	Settlement Index	Mbbls		(in 000’s)		Fixed Price
2014	Crude Oil	NYMEX WTI		5,750		—	$	90.83
2014	Crude Oil	Dated Brent		5,750		—		100.05
2014	Natural Gas	Various⁽¹⁾		—		16,235		4.37


	(In millions)			(In millions)
Asset retirement obligation at December 31, 2013	$	3,222
Asset retirement obligation at December 31, 2014				$	3,085
Liabilities incurred		86			41
Liabilities divested		(91	)
Liabilities settled		(79	)		(58	)
Accretion expense		135			44
Revisions in estimated liabilities					29

Asset retirement obligation at September 30, 2014		3,273
Asset retirement obligation at March 31, 2015					3,141
Less current portion		(177	)		(47	)

Asset retirement obligation, long-term	$	3,096		$	3,094


Number of shares of registrant’s common stock outstanding as of April 30, 2015			377,094,714


	For the Quarter Ended September 30,						For the Nine Months Ended September 30,						For The Quarter Ended March 31,
	2014			2013			2014			2013			2015			2014
	(In millions, except per common share data)												(In millions, except per share data)
REVENUES AND OTHER:
Oil and gas production revenues
Oil and gas production revenues:
Oil revenues	$	2,753		$	3,468		$	8,518		$	9,790		$	1,362		$	2,815
Gas revenues		538			645			1,773			2,048			387			646
Natural gas liquids revenues		177			175			532			473			57			186

		3,468			4,288			10,823			12,311			1,806			3,647
Derivative instrument gains (losses), net		273			(422	)		79			(275	)
Other		(1	)		34			(3	)		78			12			28

		3,740			3,900			10,899			12,114			1,818			3,675

OPERATING EXPENSES:
Depreciation, depletion, and amortization:
Oil and gas property and equipment
Recurring		1,173			1,272			3,437			3,740			1,089			1,109
Additional		1,562			627			1,765			627			7,220			—
Other assets		100			96			296			290			98			97
Asset retirement obligation accretion		46			65			135			192			44			44
Lease operating expenses		652			772			1,862			2,275			538			597
Gathering and transportation		67			81			203			231			56			70
Taxes other than income		170			176			532			574			84			181
General and administrative		112			120			309			359			79			103
Acquisition, divestiture, and separation costs		34			—			66			—			54			18
Financing costs, net		41			50			103			157			46			27

		3,957			3,259			8,708			8,445			9,308			2,246

NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(217	)		641			2,191			3,669			(7,490	)		1,429
Current income tax provision		297			409			1,038			1,190			44			416
Deferred income tax provision (benefit)		727			(203	)		930			229			(2,898	)		162

NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST		(1,241	)		435			223			2,250			(4,636	)		851
Net loss from discontinued operations, net of tax		—			(129	)		(517	)		(192	)
Net income (loss) from discontinued operations, net of tax														—			(517	)

NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST		(1,241	)		306			(294	)		2,058			(4,636	)		334
Preferred stock dividends		—			6			—			44
Net income attributable to noncontrolling interest		89			—			295			—			15			98

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(1,330	)	$	300		$	(589	)	$	2,014		$	(4,651	)	$	236

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS:
Net income (loss) from continuing operations attributable to common shareholders	$	(1,330	)	$	429		$	(72	)	$	2,206		$	(4,651	)	$	753
Net loss from discontinued operations		—			(129	)		(517	)		(192	)
Net income (loss) from discontinued operations														—			(517	)

Net income (loss) attributable to common shareholders	$	(1,330	)	$	300		$	(589	)	$	2,014		$	(4,651	)	$	236

NET INCOME (LOSS) PER COMMON SHARE:
BASIC NET INCOME (LOSS) PER COMMON SHARE:
Basic net income (loss) from continuing operations per share	$	(3.50	)	$	1.08		$	(0.19	)	$	5.59		$	(12.34	)	$	1.92
Basic net loss from discontinued operations per share		—			(0.33	)		(1.33	)		(0.48	)
Basic net income (loss) from discontinued operations per share														—			(1.32	)

Basic net income (loss) per share	$	(3.50	)	$	0.75		$	(1.52	)	$	5.11		$	(12.34	)	$	0.60

DILUTED NET INCOME (LOSS) PER COMMON SHARE:
Diluted net income (loss) from continuing operations per share	$	(3.50	)	$	1.07		$	(0.19	)	$	5.53		$	(12.34	)	$	1.90
Diluted net loss from discontinued operations per share		—			(0.32	)		(1.33	)		(0.47	)
Diluted net income (loss) from discontinued operations per share														—			(1.30	)

Diluted net income (loss) per share	$	(3.50	)	$	0.75		$	(1.52	)	$	5.06		$	(12.34	)	$	0.60

WEIGHTED-AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic		381			399			387			394			377			394
Diluted		381			401			387			407			377			396
DIVIDENDS DECLARED PER COMMON SHARE	$	0.25		$	0.20		$	0.75		$	0.60		$	0.25		$	0.25


	Series D Preferred Stock			Common Stock		Paid-In Capital			Retained Earnings			Treasury Stock			Accumulated Other Comprehensive Loss			APACHE SHAREHOLDERS’ EQUITY			Non Controlling Interest			TOTAL EQUITY
	(In millions)
BALANCE AT DECEMBER 31, 2012	$	1,227		$	245	$	9,859		$	20,161		$	(30	)	$	(131	)	$	31,331		$	—		$	31,331
Net income		—			—		—			2,058			—			—			2,058			—			2,058
Commodity hedges, net of tax		—			—		—			—			—			8			8			—			8
Dividends:
Preferred		—			—		—			(44	)		—			—			(44	)		—			(44	)
Common ($0.60 per share)		—			—		—			(237	)		—			—			(237	)		—			(237	)
Common shares issued		—			9		1,218			—			—			—			1,227			—			1,227
Common stock activity, net		—			1		(12	)		—			—			—			(11	)		—			(11	)
Treasury stock activity, net		—			—		(1	)		—			(250	)		—			(251	)		—			(251	)
Conversion of Series D preferred stock		(1,227	)		—		—			—			—			—			(1,227	)		—			(1,227	)
Compensation expense		—			—		135			—			—			—			135			—			135
Other		—			—		(8	)		—			—			—			(8	)		—			(8	)

BALANCE AT SEPTEMBER 30, 2013	$	—		$	255	$	11,191		$	21,938		$	(280	)	$	(123	)	$	32,981		$	—		$	32,981

BALANCE AT DECEMBER 31, 2013	$	—		$	255	$	12,251		$	22,032		$	(1,027	)	$	(115	)	$	33,396		$	1,997		$	35,393
Net income (loss)		—			—		—			(589	)		—			—			(589	)		295			(294	)
Distributions to noncontrolling interest		—			—		—			—			—			—			—			(124	)		(124	)
Commodity hedges, net of tax		—			—		—			—			—			(1	)		(1	)		—			(1	)
Dividends:
Common ($0.75 per share)		—			—		—			(287	)		—			—			(287	)		—			(287	)
Common stock activity, net		—			1		(12	)		—			—			—			(11	)		—			(11	)
Treasury stock activity, net		—			—		(1	)		—			(1,830	)		—			(1,831	)		—			(1,831	)
Compensation expense		—			—		145			—			—			—			145			—			145
Other		—			—		(4	)		—			—			—			(4	)		—			(4	)

BALANCE AT SEPTEMBER 30, 2014	$	—		$	256	$	12,379		$	21,156		$	(2,857	)	$	(116	)	$	30,818		$	2,168		$	32,986


	March 31, 2015						December 31, 2014
	Canada		Australia		Total		Canada		Australia		Total
	(In millions)
ASSETS
Current assets	$	15	$	—	$	15	$	30	$	—	$	30
GTP assets		229		1,459		1,688		200		1,297		1,497
Other long-term assets		101		—		101		101		—		101

Assets held for sale⁽¹⁾	$	345	$	1,459	$	1,804	$	331	$	1,297	$	1,628

LIABILITIES
Current liabilities	$	1	$	—	$	1	$	12	$	—	$	12
Other long-term liabilities		6		—		6		7		—		7

Liabilities held for sale⁽¹⁾	$	7	$	—	$	7	$	19	$	—	$	19


	Fair Value Measurements Using
	Quoted
	Price in		Significant		Significant
	Active		Other		Unobservable		Total
	Markets		Inputs		Inputs		Fair					Carrying
	(Level 1)		(Level 2)		(Level 3)		Value		Netting⁽¹⁾			Amount
	(In millions)
September 30, 2014
Assets:
Commodity Derivative Instruments	$	—	$	41	$	—	$	41	$	—		$	41
Liabilities:
Commodity Derivative Instruments		—		—		—		—		—			—
December 31, 2013
Assets:
Commodity Derivative Instruments	$	—	$	3	$	—	$	3	$	(2	)	$	1
Liabilities:
Commodity Derivative Instruments		—		301		—		301		(2	)		299


		For the Quarter Ended						For the Nine Months Ended
	Gain (Loss) on Derivatives	September 30,						September 30,
	Recognized in Income	2014			2013			2014			2013
		(In millions)
Gain (loss) on cash flow hedges reclassified from accumulated other comprehensive loss	Oil and Gas Production Revenues	$	—		$	2		$	—		$	(18	)
Loss for ineffectiveness on cash flow hedges	Revenues and other: Other	$	—		$	(1	)	$	—		$	(1	)
Derivatives not designated as cash flow hedges:
Realized loss		$	(41	)	$	(91	)	$	(262	)	$	(138	)
Unrealized gain (loss)			314			(331	)		341			(137	)

Gain (loss) on derivatives not designated as cash flow hedges	Derivative instrument gains (losses), net	$	273		$	(422	)	$	79		$	(275	)


	United											Other						United States			Canada			Egypt ⁽¹⁾		Australia			North Sea			Other International		Total
	States			Canada		Egypt⁽²⁾		Australia		North Sea		International			Total			(In millions)
	(In millions)
For the Quarter Ended September 30, 2014
For the Quarter Ended March 31, 2015
Oil and Gas Production Revenues	$	1,481		$	268	$	910	$	287	$	522	$	—		$	3,468		$	660		$	133		$	532	$	168		$	313		$	—	$	1,806

Operating Income (Loss)⁽¹⁾	$	(988	)	$	11	$	481	$	70	$	124	$	—		$	(302	)
Operating Income (Loss)⁽²⁾																		$	(5,320	)	$	(1,430	)	$	102	$	(12	)	$	(663	)	$	—	$	(7,323	)

Other Income (Expense):
Derivative instrument gains (losses), net																273
Other																(1	)																		12
General and administrative																(112	)																		(79	)
Acquisition, divestiture, and separation costs																(34	)																		(54	)
Financing costs, net																(41	)																		(46	)
Net Loss From Continuing Operations

Loss Before Income Taxes															$	(217	)
Before Income Taxes																																		$	(7,490	)

For the Nine Months Ended September 30, 2014
Total Assets																		$	21,577		$	5,288		$	7,247	$	9,044		$	5,376		$	118	$	48,650

For the Quarter Ended March 31, 2014
Oil and Gas Production Revenues	$	4,515		$	879	$	2,849	$	780	$	1,800	$	—		$	10,823		$	1,505		$	318		$	950	$	256		$	618		$	—	$	3,647

Operating Income⁽¹⁾	$	354		$	131	$	1,601	$	239	$	268	$	—		$	2,593
Operating Income⁽²⁾																		$	663		$	71		$	536	$	96		$	183		$	—	$	1,549

Other Income (Expense):
Derivative instrument gains (losses), net																79
Other																(3	)																		28
General and administrative																(309	)																		(103	)
Acquisition, divestiture, and separation costs																(66	)																		(18	)
Financing costs, net																(103	)																		(27	)
Net Income From Continuing Operations

Income Before Income Taxes															$	2,191
Before Income Taxes																																		$	1,429

Total Assets	$	30,613		$	7,100	$	7,246	$	9,148	$	6,824	$	59		$	60,990		$	30,618		$	7,102		$	7,350	$	8,403		$	7,599		$	49	$	61,121

For the Quarter Ended September 30, 2013
Oil and Gas Production Revenues⁽³⁾	$	2,029		$	325	$	1,022	$	279	$	633	$	—		$	4,288

Operating Income (Loss)⁽¹⁾⁽³⁾	$	310		$	4	$	658	$	117	$	186	$	(76	)	$	1,199

Other Income (Expense):
Derivative instrument gains (losses), net																(422	)
Other																34
General and administrative																(120	)
Financing costs, net																(50	)

Income Before Income Taxes⁽³⁾															$	641

For the Nine Months Ended September 30, 2013
Oil and Gas Production Revenues⁽³⁾	$	5,543		$	952	$	2,924	$	867	$	2,025	$	—		$	12,311

Operating Income (Loss)⁽¹⁾⁽³⁾	$	1,607		$	17	$	1,827	$	373	$	634	$	(76	)	$	4,382

Other Income (Expense):
Derivative instrument gains (losses), net																(275	)
Other																78
General and administrative																(359	)
Financing costs, net																(157	)

Income Before Income Taxes⁽³⁾															$	3,669

Total Assets⁽³⁾	$	29,503		$	7,083	$	7,142	$	7,567	$	7,292	$	54		$	58,641


																					All Other
																		Apache			Subsidiaries
															Apache			Finance			of Apache			Reclassifications
	Apache Corporation			Apache Finance Canada		All Other Subsidiaries of Apache Corporation			Reclassifications & Eliminations			Consolidated			Corporation			Canada			Corporation			& Eliminations		Consolidated
	(In millions)														(In millions)
REVENUES AND OTHER:
Oil and gas production revenues	$	882		$	—	$	2,586		$	—		$	3,468		$	365		$	—		$	1,441		$	—	$	1,806
Equity in net income (loss) of affiliates		491			5		1			(497	)		—			(1,085	)		(654	)		1			1,738		—
Derivative instrument gains (losses), net		320			—		(47	)		—			273
Other		(34	)		14		17			2			(1	)		(40	)		14			38			—		12

		1,659			19		2,557			(495	)		3,740			(760	)		(640	)		1,480			1,738		1,818

OPERATING EXPENSES:
Depreciation, depletion, and amortization		1,914			—		921			—			2,835
Depreciation, depletion and amortization																5,499			—			2,908			—		8,407
Asset retirement obligation accretion		8			—		38			—			46			4			—			40			—		44
Lease operating expenses		137			—		515			—			652			124			—			414			—		538
Gathering and transportation		15			—		52			—			67			9			—			47			—		56
Taxes other than income		67			—		103			—			170			34			—			50			—		84
General and administrative		89			—		21			2			112			64			—			15			—		79
Acquisition, divestiture, and separation costs		34			—		—			—			34			54			—			—			—		54
Financing costs, net		45			11		(15	)		—			41			52			10			(16	)		—		46

		2,309			11		1,635			2			3,957			5,840			10			3,458			—		9,308

NET INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES		(650	)		8		922			(497	)		(217	)		(6,600	)		(650	)		(1,978	)		1,738		(7,490	)
Provision (benefit) for income taxes		678			2		344			—			1,024			(1,949	)		3			(908	)		—		(2,854	)

NET INCOME (LOSS) FROM CONTINUING OPERATIONS INCLUDING NONCONTROLLING INTEREST		(1,328	)		6		578			(497	)		(1,241	)		(4,651	)		(653	)		(1,070	)		1,738		(4,636	)
Net loss from discontinued operations, net of tax		—			—		—			—			—
Net income (loss) from discontinued operations, net of tax																—			—			—			—		—

NET INCOME (LOSS) INCLUDING NONCONTROLLING INTEREST		(1,328	)		6		578			(497	)		(1,241	)		(4,651	)		(653	)		(1,070	)		1,738		(4,636	)
Net income attributable to noncontrolling interest		—			—		89			—			89			—			—			15			—		15

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK	$	(1,328	)	$	6	$	489		$	(497	)	$	(1,330	)	$	(4,651	)	$	(653	)	$	(1,085	)	$	1,738	$	(4,651	)

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK⁽¹⁾	$	(1,328	)	$	6	$	489		$	(497	)	$	(1,330	)	$	(4,651	)	$	(653	)	$	(1,085	)	$	1,738	$	(4,651	)


Issuer Purchases of Equity Securities
Period	Total Number of Shares Purchased		Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs⁽¹⁾		Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs⁽¹⁾
July 1 to July 31, 2014		—	$	—		—		13,922,662
August 1 to August 31, 2014		2,504,119		99.68		2,504,119		11,418,543
September 1 to September 30, 2014		3,239,674		97.93		3,239,674		8,178,869

Total		5,743,793	$	98.69


3.1	–	Restated Certificate of Incorporation of Registrant, dated September 19, 2013, as filed with the Secretary of State of Delaware on September 19, 2013 (incorporated by reference to Exhibit 3.2 to Registrant’s Current Report on Form 8-K filed September 20, 2013, SEC File No. 001-4300).

3.2	–	Bylaws of Registrant, as amended May 16, 2013 (incorporated by reference to Exhibit 3.1 to Registrant’s Current Report on Form 8-K filed May 17, 2013, SEC File No. 001-4300).

*10.1	–	2014 Employee Release and Settlement Agreement, by and between Registrant and Thomas P. Chambers, effective as of August 31, 2014.

*10.2	–	Amendment of Stock Option Grants (2007 and 2011 Omnibus Equity Compensation Plans) by and between Registrant and Thomas P. Chambers, effective as of August 31, 2014.

*10.3	–	Amendment of Restricted Stock Unit Awards (2007 and 2011 Omnibus Equity Compensation Plans) by and between Registrant and Thomas P. Chambers, effective as of August 31, 2014.

*10.4	–	Employee Resignation Agreement by and between Registrant and Alfonso Leon, effective as of October 13, 2014.

*10.5	–	Amendment of Stock Option Grants (2007 and 2011 Omnibus Equity Compensation Plans) by and between Registrant and Alfonso Leon, effective as of October 9, 2014.

*10.6	–	Amendment of Restricted Stock Unit Awards (2007 and 2011 Omnibus Equity Compensation Plans), effective October 9, 2014, between Registrant and Alfonso Leon.

*31.1	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Executive Officer.

*31.2	–	Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange Act) by Principal Financial Officer.

*32.1	–	Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by Principal Executive Officer and Principal Financial Officer.

*101.INS	–	XBRL Instance Document.

*101.SCH	–	XBRL Taxonomy Schema Document.

*101.CAL	–	XBRL Calculation Linkbase Document.

*101.LAB	–	XBRL Label Linkbase Document.

*101.PRE	–	XBRL Presentation Linkbase Document.

*101.DEF	–	XBRL Definition Linkbase Document.

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