News Column

APACHE CORP - 10-Q - MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

August 8, 2014

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 Report on Form 8-K dated July 17, 2014 for our 2013 fiscal year.



Strategic Overview

Over the last five years, Apache has greatly enlarged and enhanced its North American onshore resource base, which we believe is capable of driving our growth and performance over the next several years. During the last 18 months, we have further increased the focus on our North American Onshore business by divesting $10 billion of properties. In North America, we completed the sale of our Gulf of Mexico Shelf region assets, certain non-producing assets in the deepwater Gulf of Mexico, and non-strategic, primarily dry-gas, assets in Canada. Internationally, we sold a one-third noncontrolling interest in our Egypt operations and all of 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 in North American Onshore, we are evaluating our international assets and exploring multiple opportunities, including the potential separation of some or all of them through the capital markets. In addition, we have launched a share repurchase program. Since June 2013, we have repurchased a total of 26 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. Financial Highlights



Apache reported earnings for the quarter of $505 million, or $1.31 per

diluted common share, compared with $1.0 billion, or $2.54 per diluted

share, for the prior-year period.



First-half 2014 earnings totaled $741 million, or $1.89 per diluted common

share, compared with $1.7 billion, or $4.30 per diluted share, in the

comparable prior-year period. Earnings for first half of 2014 reflect an

after-tax loss of $517 million on discontinued operations in Argentina.

Net cash provided by operating activities (operating cash flows or cash flows) totaled $4.6 billion for the first half of 2014, driven by the strength of our North American drilling program.



Second Quarter Operational Developments

Average daily production in the second quarter of 2014 totaled 636 thousand barrels of oil equivalent (Mboe), a decrease of 111 Mboe from the comparative 2013 quarter. The prior-year quarter includes volumes from properties in the Gulf of Mexico Shelf and Canada that have since been divested.



North America

North American onshore liquids averaged 202,861 barrels per day, up 16

percent over the prior-year quarter.



North American onshore liquids production represented nearly 54 percent of

our worldwide liquids production and 32 percent of our overall production.

Permian region surpassed a significant milestone as production averaged



over 150,000 barrels of oil equivalent per day (boe/d) in the second

quarter of 2014, a nearly 200 percent increase since we launched the region just over four years ago. Permian region averaged 37 rigs during the quarter, resulting in a



production increase of 26 percent relative to the prior-year period.

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Gulf Coast region increased its acreage position to 200,000 net acres in

the East Texas Eagle Ford play and drilled 26 horizontal wells. Based on

strong well results to date, we plan on having 10 rigs running in the play

by year-end. In the Canyon Lime play within our Central region, we have had strong



early results. Our most recent well, the Bivins 94-1H, had a 30-day

initial production (IP) rate of 1,718 boe/d. We hold approximately 100,000

net acres in this emerging area and are planning to drill a total of six

wells this year as we further delineate the play.



Central region's Anadarko basin, however, experienced several challenges

over the last two quarters, and total wells drilled are 26 percent behind

plan. We are scaling back activity and reducing capital and rigs as we

retool the region to ensure proper investment decisions.



Canada region had positive drilling results in the first quarter, as we

ramped up activity in the Montney and Duvernay plays. We increased our

acreage position to 146,000 net acres in the Montney and 177,000 net acres

in the Duvernay, and we plan to spud 10 wells and 2 wells in the Duvernay

and Montney plays, respectively, by year-end.



We completed the sale of our Lucius and Heidelberg deepwater development

projects and 11 primary term deepwater exploration blocks in the Gulf of Mexico for $1.4 billion.



We completed the sale of non-strategic producing oil and gas assets in

Canada for $374 million.

International North Sea region drilled eight new wells, including a new well in the Beryl field that achieved a 30-day IP rate of 4,500 boe/d and a new Forties area well that achieved a 30-day IP rate of 5,100 boe/d.



Egypt region made two notable discoveries: the Herunefer-1X discovery

located in the Matruh Basin had tests in the Lower Safa and Upper Safa intervals that flowed at a combined rate of 49 million cubic feet of



natural gas per day (MMcf/d) and 7,700 barrels of condensate per day, and

the BAT-1X in the northern Shushan Basin, which tested at rates of 31 MMcf/d and 390 barrels of condensate per day.



Our Balnaves project in Western Australia is expected to come online in

the third quarter.



Australia region's Coniston development project, originally scheduled for

first oil in the third quarter of 2014, is delayed until early 2015 as a

result of additional repairs identified during upgrades and capacity

expansion on the floating, production, storage, and offloading vessel required to bring our new wells online. 30



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Results of Operations

Oil and Gas Revenues

Oil and gas production revenues for the second quarter of 2014 totaled $3.7 billion, a $293 million decrease from the comparative 2013 quarter. The table below presents revenues by region and each region's percent contribution to revenues for 2014 and 2013. For the Quarter Ended June 30, For the Six Months Ended June 30, 2014 2013 2014 2013 $ % $ % $ % $ % Value Contribution Value Contribution Value Contribution Value Contribution ($ in millions) Total Oil Revenues: United States $ 1,145 39 % $ 1,390 44 % $ 2,237 39 % $ 2,659 42 % Canada 154 5 % 148 5 % 294 5 % 275 4 % North America 1,299 44 % 1,538 49 % 2,531 44 % 2,934 46 % Egypt (1) 885 30 % 796 26 % 1,731 30 % 1,708 27 % Australia 153 5 % 199 6 % 323 6 % 402 7 % North Sea 613 21 % 597 19 % 1,180 20 % 1,278 20 % International (1) 1,651 56 % 1,592 51 % 3,234 56 % 3,388 54 % Total(1)(2) $ 2,950 100 % $ 3,130 100 % $ 5,765 100 % $ 6,322 100 % Total Gas Revenues: United States $ 245 41 % $ 319 44 % $ 511 41 % $ 607 43 % Canada 122 21 % 166 23 % 270 22 % 318 23 % North America 367 62 % 485 67 % 781 63 % 925 66 % Egypt (1) 99 17 % 97 13 % 202 16 % 194 14 % Australia 84 14 % 92 13 % 170 14 % 186 13 % North Sea 39 7 % 47 7 % 82 7 % 97 7 % International (1) 222 38 % 236 33 % 454 37 % 477 34 % Total(1)(3) $ 589 100 % $ 721 100 % $ 1,235 100 % $ 1,402 100 % Natural Gas Liquids (NGL) Revenues: United States $ 139 82 % $ 127 85 % $ 286 81 % $ 247 83 % Canada 17 10 % 15 10 % 47 13 % 34 11 % North America 156 92 % 142 95 % 333 94 % 281 94 % Egypt (1) 5 3 % - 0 % 6 2 % - 0 % North Sea 8 5 % 8 5 % 16 4 % 17 6 % International (1) 13 8 % 8 5 % 22 6 % 17 6 % Total (1) $ 169 100 % $ 150 100 % $ 355 100 % $ 298 100 % Total Oil and Gas Revenues: United States $ 1,529 41 % $ 1,836 46 % $ 3,034 41 % $ 3,513 44 % Canada 293 8 % 329 8 % 611 9 % 627 8 % North America 1,822 49 % 2,165 54 % 3,645 50 % 4,140 52 % Egypt (1) 989 27 % 893 23 % 1,939 26 % 1,902 24 % Australia 237 6 % 291 7 % 493 7 % 588 7 % North Sea 660 18 % 652 16 % 1,278 17 % 1,392 17 % International (1) 1,886 51 % 1,836 46 % 3,710 50 % 3,882 48 % Total (1) $ 3,708 100 % $ 4,001 100 % $ 7,355 100 % $ 8,022 100 % Discontinued Operations - Argentina Oil Revenues $ - $ 67$ 45$ 130 Gas Revenues - 47 39 101 NGL Revenues - 4 3 12 Total $ - $ 118$ 87$ 243



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

quarter and six months ended June 30, 2014.

(2) Financial derivative hedging activities decreased oil revenues $1 million

and $2 million for the 2014 second quarter and six-month period,

respectively, and $18 million and $37 million for the 2013 second quarter

and six-month period, respectively. (3) Financial derivative hedging activities increased natural gas revenues $1



million and $2 million for the 2014 second quarter and six-month period,

respectively, and $7 million and $17 million for the 2013 second quarter and

six-month period, respectively. 31



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Production

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

For the Quarter Ended June 30, For the Six Months Ended June 30, Increase Increase 2014 2013 (Decrease) 2014 2013 (Decrease) Oil Volume - b/d United States 130,398 157,298 (17 %) 129,181 153,303 (16 %) Canada 17,981 18,573 (3 %) 17,786 17,878 (1 %) North America 148,379 175,871 (16 %) 146,967 171,181 (14 %) Egypt(1)(2) 88,643 88,002 1 % 88,370 89,649 (1 %) Australia 14,555 21,810 (33 %) 15,683 20,911 (25 %) North Sea 61,610 63,667 (3 %) 60,358 66,051 (9 %) International 164,808 173,479 (5 %) 164,411 176,611 (7 %) Total 313,187 349,350 (10 %) 311,378 347,792 (10 %) Natural Gas Volume - Mcf/d United States 596,970 860,661 (31 %) 594,840 857,195 (31 %) Canada 316,740 520,797 (39 %) 347,057 519,991 (33 %) North America 913,710 1,381,458 (34 %) 941,897 1,377,186 (32 %) Egypt(1)(2) 367,950 357,291 3 % 372,628 361,428 3 % Australia 210,470 212,022 (1 %) 213,116 213,202 0 % North Sea 54,848 48,411 13 % 49,986 51,704 (3 %) International 633,268 617,724 3 % 635,730 626,334 2 % Total 1,546,978 1,999,182 (23 %) 1,577,627 2,003,520 (21 %) NGL Volume - b/d United States 56,625 57,018 (1 %) 54,851 53,180 3 % Canada 5,921 6,686 (11 %) 6,840 6,675 2 % North America 62,546 63,704 0 % 61,691 59,855 3 % Egypt(1)(2) 884 - NM 560 - NM North Sea 1,367 1,201 14 % 1,230 1,346 (9 %) International 2,251 1,201 87 % 1,790 1,346 33 % Total 64,797 64,905 0 % 63,481 61,201 4 % BOE per day(3) United States 286,518 357,759 (20 %) 283,173 349,349 (19 %) Canada 76,692 112,059 (32 %) 82,469 111,218 (26 %) North America 363,210 469,818 (23 %) 365,642 460,567 (21 %) Egypt(2) 150,853 147,551 2 % 151,035 149,887 1 % Australia 49,633 57,147 (13 %) 51,203 56,444 (9 %) North Sea 72,118 72,936 (1 %) 69,918 76,015 (8 %) International 272,604 277,634 (2 %) 272,156 282,346 (4 %) Total 635,814 747,452 (15 %) 637,798 742,913 (8 %) Discontinued Operations - Argentina Oil (b/d) - 9,365 NM 3,424 9,331 NM Gas (Mcf/d) - 184,528 NM 70,286 186,383 NM NGL (b/d) - 2,239 NM 640 2,529 NM BOE/d - 42,359 NM 15,778 42,924 NM



(1) Gross oil, natural gas, and NGL production in Egypt for the second quarter

and six-month period of 2014 and 2013 were as follows: For the quarter ended June 30, For the six months ended June 30, 2014 2013 2014 2013 Oil (b/d) 197,069 193,341 197,839 196,242 Gas (Mcf/d) 907,752 901,181 914,558 907,871 NGL (b/d) 2,698 - 1,679 -



(2) Includes production volumes per day attributable to a noncontrolling

interest in Egypt for the second quarter and six-month period of 2014 of: For the six For the quarter months ended ended June 30, June 30, 2014 2014 Oil (b/d) 29,508 29,288 Gas (Mcf/d) 122,665 123,726 NGL (b/d) 295 187



(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 32



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Pricing

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

For the Quarter Ended June 30, For the Six Months Ended June 30, Increase Increase 2014 2013 (Decrease) 2014 2013 (Decrease) Average Oil Price - Per barrel United States $ 96.46$ 97.14 (1 %) $ 95.66$ 95.84 0 % Canada 94.66 87.38 8 % 91.47 84.97 8 % North America 96.24 96.11 0 % 95.15 94.70 0 % Egypt 109.74 99.36 10 % 108.24 105.25 3 % Australia 115.34 100.79 14 % 113.70 106.29 7 % North Sea 109.33 102.95 6 % 108.00 106.85 1 % International 110.08 100.86 9 % 108.67 105.97 3 % Total(1) 103.53 98.47 5 % 102.29 100.43 2 % Average Natural Gas Price - Per Mcf United States $ 4.51$ 4.07 11 % $ 4.75$ 3.92 21 % Canada 4.21 3.52 20 % 4.30 3.37 28 % North America 4.41 3.86 14 % 4.58 3.71 23 % Egypt 2.96 3.00 (1 %) 2.99 2.97 1 % Australia 4.40 4.70 (6 %) 4.41 4.82 (9 %) North Sea 7.75 10.86 (29 %) 9.07 10.41 (13 %) International 3.85 4.20 (8 %) 3.94 4.21 (6 %) Total(2) 4.18 3.97 5 % 4.33 3.87 12 % Average NGL Price - Per barrel United States $ 27.06$ 24.46 11 % $ 28.86$ 25.61 13 % Canada 31.67 24.60 29 % 37.56 28.35 32 % North America 27.50 24.48 12 % 29.83 25.92 15 % Egypt 57.67 - NM 59.05 - NM North Sea 61.81 70.39 (12 %) 69.77 70.81 (1 %) International 60.19 70.39 (14 %) 66.41 70.81 (6 %) Total 28.64 25.33 13 % 30.86 26.91 15 % Discontinued Operations - Argentina Oil price ($/Bbl) $ - $ 77.74 NM $ 72.70$ 76.56 (5 %) Gas price ($/Mcf) - 2.79 NM 3.04 2.99 2 % NGL price ($/Bbl) - 20.94 NM 24.57 26.12 (6 %)



(1) Reflects a per-barrel decrease of $0.03 from derivative hedging activities

for both the 2014 second quarter and six-month period and a decrease of

$0.54 and $0.57 from derivative hedging activities for the comparative 2013

second quarter and six-month period, respectively.

(2) Reflects a per-Mcf increase of $0.01 from derivative hedging activities for

both the 2014 second quarter and six-month period and an increase of $0.03

and $0.04 from derivative hedging activities for the comparative 2013 second

quarter and six-month period, respectively.

NM - Not meaningful

Second-Quarter 2014 compared to Second-Quarter 2013

Crude Oil Revenues Crude oil revenues for the second quarter of 2014 totaled $3.0 billion, a $180 million decrease from the comparative 2013 quarter. A 5 percent decrease in average daily production decreased second-quarter 2014 revenues by $341 million compared to the prior-year quarter, while 5 percent higher realized prices increased revenues by $161 million. Crude oil prices realized in the second quarter of 2014 averaged $103.53 per barrel, compared with $98.47 in the comparative prior-year quarter. Crude oil accounted for 80 percent of oil and gas production revenues and 49 percent of worldwide production in the second quarter of 2014. Worldwide production decreased 36 thousand barrels of oil per day (Mb/d) from the second quarter of 2013 to 313 Mb/d, primarily as a result of the divestiture of our Gulf of Mexico Shelf assets in the second half of 2013. Exclusive of production from these divested assets, oil production increased 11.5 Mb/d, primarily on drilling and recompletion activity in the U.S. Permian region, partially offset by production decreases in Australia and the North Sea. Australia's production decreased 7 Mb/d primarily on downtime for planned maintenance on the Ningaloo Vision FPSO. Production decreased 2 Mb/d in the North Sea primarily due to natural decline. 33 -------------------------------------------------------------------------------- Natural Gas Revenues Gas revenues for the second quarter of 2014 totaled $589 million, down 18 percent from the second quarter of 2013. A 23 percent decrease in average production reduced natural gas revenues by $172 million as compared to the prior-year quarter, while a 5 percent increase in average realized prices increased revenues by $40 million. Natural gas accounted for 16 percent of our oil and gas production revenues and 41 percent of our equivalent production. Worldwide natural gas production was 452 million cubic feet per day (MMcf/d) lower than the second quarter of 2013, primarily as a result of the divestiture of our Gulf of Mexico Shelf assets and certain Western Canadian assets in the second half of 2013. Exclusive of production from these divested assets, our worldwide gas production was essentially flat. NGL Revenues NGL revenues for the second quarter of 2014 totaled $169 million, up $19 million from the second quarter of 2013. Average NGL production remained flat compared to the prior-year quarter, while a 13 percent increase in average realized prices increased revenues by $19 million. NGLs accounted for nearly 5 percent of our oil and gas production revenues and 10 percent of our equivalent production during the second quarter of 2014. Worldwide production of NGLs decreased 108 b/d to 64.8 Mb/d in the second quarter of 2014, primarily as a result of the divestiture of our Gulf of Mexico Shelf assets and certain Western Canadian assets in the second half of 2013. Exclusive of production from these divested assets, our worldwide NGL production increased 8.5 Mb/d.



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

Crude Oil Revenues Crude oil revenues for the first six months of 2014 totaled $5.8 billion, $557 million lower than the comparative 2013 period, the result of a 10 percent decrease in worldwide production partially offset by a 2 percent increase in average realized prices. Crude oil accounted for 78 percent of oil and gas production revenues and 49 percent of worldwide production for the first six months of 2014, and 79 percent of production revenues and 47 percent of worldwide production for the 2013 comparative period. Lower production volumes reduced revenue by $674 million compared to the first six months of 2013, while higher realized prices added $117 million to revenues. Crude oil prices realized in the first six months of 2014 averaged $102.29 per barrel, compared with $100.43 in the comparative prior-year period. Worldwide production declined 36 Mb/d to 311 Mb/d in the first six months of this year from the same period last year, primarily as a result of the divestiture of our Gulf of Mexico Shelf assets in the second half of 2013. Exclusive of production from these divested assets, worldwide production increased 8.9 Mb/d. Production increased 21 Mb/d in our Permian region on drilling and recompletion activity. Net production in the North Sea was 6 Mb/d lower on natural decline, and Australia production decreased 5 Mb/d as a result of downtime for planned maintenance. Natural Gas Revenues Gas revenues for the first six months of 2014 totaled $1.2 billion, down 12 percent from the comparative 2013 period. A 21 percent decline in average production reduced natural gas revenues by $333 million, offset by a 12 percent increase in average realized prices that added $166 million to revenues. Natural gas accounted for 17 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 425 MMcf/d lower than the first six months of 2013, as a result of the divestiture of our Gulf of Mexico Shelf assets and certain Western Canadian assets in the second half of 2013. Exclusive of production from these divested assets, worldwide production was essentially flat. NGL Revenues NGL revenues for the first six months of 2014 totaled $355 million, up $57 million from the comparative 2013 period. A 4 percent increase in average production increased NGL revenues by $13 million as compared to the prior-year period, while a 14 percent increase in average realized prices increased revenues by $44 million. NGLs accounted for nearly 5 percent of our oil and gas production revenues and 10 percent of our equivalent production during the first six months of 2014. Worldwide production of NGLs increased 2.3 Mb/d to 63.5 Mb/d in the first six months of 2014, primarily from drilling and recompletion activity in the Central and Permian regions. Exclusive of production from divested assets, our worldwide NGL production increased 9.7 Mb/d. 34



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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 June 30, For the Six Months Ended June 30, 2014 2013 2014 2013 2014 2013 2014 2013 (In millions) (Per boe) (In millions) (Per boe) Depreciation, depletion and amortization: Oil and gas property and equipment Recurring $ 1,155$ 1,258$ 19.96$ 18.49$ 2,264$ 2,468$ 19.61$ 18.35 Additional 203 - 3.51 - 203 - 1.76 - Other assets 99 92 1.71 1.34 196 194 1.69 1.44 Asset retirement obligation accretion 45 64 0.78 0.94 89 127 0.77 0.95 Lease operating costs 613 781 10.59 11.48 1,210 1,503 10.48 11.17 Gathering and transportation costs 66 77 1.16 1.15 136 150 1.19 1.12 Taxes other than income 181 170 3.12 2.51 362 399 3.14 2.97 General and administrative expense 94 126 1.63 1.85 199 238 1.72 1.77 Acquisition, divestiture, and separation costs 14 - 0.24 - 30 - 0.26 - Financing costs, net 35 52 0.60 0.76 62 107 0.54 0.79 Total $ 2,505$ 2,620$ 43.30$ 38.52$ 4,751$ 5,186$ 41.16$ 38.56



Recurring Depreciation, Depletion and Amortization (DD&A) The following table details the changes in recurring DD&A of oil and gas properties between the second quarters and six-month periods of 2014 and 2013:

For the Quarter For the Six Months Ended Ended June 30, June 30, (In millions) (In millions) 2013 DD&A $ 1,258 $ 2,468 Volume change (164 ) (329 ) DD&A rate change 61 125 2014 DD&A $ 1,155 $ 2,264 Oil and gas property recurring DD&A expense of $1.2 billion in the second quarter of 2014 decreased $103 million compared to the prior-year quarter on an absolute dollar basis: $164 million from lower volumes offset by $61 million increase on rate. Oil and gas property recurring DD&A expense of $2.3 billion in the first six months of 2014 decreased $204 million compared to the prior-year period on an absolute dollar basis: $329 million from lower volumes offset by $125 million increase on rate. The Company's oil and gas property recurring DD&A rate increased $1.47 and $1.26 per boe for the second quarter and first six months of 2014, respectively, compared to the prior-year periods. Additional DD&A Under the 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 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 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. 35 -------------------------------------------------------------------------------- Lease Operating Expenses (LOE) LOE decreased $168 million, or 22 percent, for the quarter, and $293 million, or 19 percent, for the six month period, on an absolute dollar basis relative to the comparable periods of 2013. On a per unit basis, LOE decreased 7 percent to $10.59 per boe for the second quarter of 2014, as compared to the same prior-year period, and decreased 6 percent to $10.48 per boe for the first six months of 2014, as compared to the prior-year six-month period. The following table identifies changes in Apache's LOE rate between the second quarters and six-month periods of 2014 and 2013. For the Quarter Ended June 30, For the Six Months Ended June 30, Per boe Per boe 2013 LOE $ 11.48 2013 LOE $ 11.17 Transportation 0.13 Transportation 0.14 Materials 0.13 Materials 0.12 Saltwater disposal 0.09 Labor and overhead costs 0.10 Divestitures(1) (1.28 ) Saltwater disposal 0.07 Power and fuel (0.20 ) Divestitures(1) (1.64 ) Other 0.29 Other 0.36 Other increased production (0.05 ) Other decreased production 0.16 2014 LOE $ 10.59 2014 LOE $ 10.48 (1) Per-unit impact of divestitures is shown net of associated production. Gathering and Transportation Gathering and transportation costs totaled $66 million and $136 million in the second quarter and first six months of 2014, respectively, down $11 million and $14 million from the second quarter and first six months of 2013, respectively. 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 For the Six Months Ended June 30, June 30, 2014 2013 2014 2013 (In millions) Canada $ 30$ 40 $ 64 $ 80 U.S. 23 23 45 44 Egypt 11 11 21 20 North Sea 2 3 6 6



Total Gathering and transportation $ 66$ 77

$ 136$ 150

Taxes other than Income Taxes other than income totaled $181 million and $362 million for the second quarter and the first six months of 2014, respectively, an increase of $11 million and a decrease of $37 million, respectively, from the comparative prior-year periods. The following table presents a comparison of these expenses: For the Quarter Ended For the Six Months Ended June 30, June 30, 2014 2013 2014 2013 (In millions) U.K. PRT $ 91$ 72$ 154$ 207 Severance taxes 52 63 125 114 Ad valorem taxes 22 26 62 59 Other 16 9 21 19 Total Taxes other than income $ 181$ 170



$ 362$ 399

The North Sea Petroleum Revenue Tax (PRT) is assessed on qualifying fields in the U.K. North Sea. U.K. PRT for the second quarter of 2014 was $19 million higher than the 2013 period based on an increase in revenues as a result of higher production on qualifying fields. Severance tax expense decreased $11 million as a result of marketing cost recoveries.

36 -------------------------------------------------------------------------------- U.K. PRT for the first six months of 2014 was $53 million lower when compared to the 2013 period based on a decrease in production revenue. For the first half of 2014, higher drilling activity increased severance taxes by $11 million as compared to the first six months of 2013. General and Administrative Expenses General and administrative expenses (G&A) for the second quarter of 2014 decreased $32 million from the second quarter of 2013 on an absolute basis and $0.22 per boe on a per-unit basis. For the first six months of 2014 G&A decreased $39 million on an absolute basis from the comparable 2013 period and decreased $0.05 per boe on a per-unit basis. Expense for the three- and six-month 2014 periods includes a $25 million benefit from nonrecurring third party cost reimbursements. Acquisition, Divestiture, and Separation Costs During the second quarter of 2014, the Company recognized $14 million in acquisition, divestiture, and separation costs related to our recent divestiture activity. For the six-month 2014 period, the Company recognized $30 million in acquisition, divestiture, and separation costs. Financing Costs, Net Financing costs incurred during the period comprised the following: For the Quarter Ended For the Six Months Ended June 30, June 30, 2014 2013 2014 2013 (In millions) Interest expense $ 124$ 141$ 248$ 287 Amortization of deferred loan costs 1 2 3 4 Capitalized interest (90 ) (88 ) (185 ) (178 ) Interest income - (3 ) (4 ) (6 ) Financing costs, net $ 35$ 52$ 62$ 107 Net financing costs were down $17 million and $45 million in the second quarter and first six months of 2014, respectively, compared to the same 2013 periods. The $17 million and $39 million decreases in interest expense in the second quarter and first six months of 2014, respectively, were a result of lower average debt balances. Provision for Income Taxes The Company estimates its annual effective income tax rate in recording its quarterly provision for income taxes in the various jurisdictions in which the Company operates. Statutory tax rate changes and other significant or unusual items are recognized as discrete items in the quarter in which they occur. Accordingly, the Company recorded the 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 second quarter of 2014. The 2014 second-quarter provision for income taxes was $366 million, representing an effective income tax rate of 37 percent for the quarter, unchanged from the 2013 period. The 2014 second-quarter effective rate reflects the impact of a $203 million non-cash write-down in the North Sea. The effective rate for both quarters also reflects a valuation allowance in Canada, foreign currency fluctuations on deferred taxes, and deferred tax expense related to mark-to-market commodity derivatives. Excluding these items, the second-quarter 2014 and 2013 effective rates would have been 40 percent and 41 percent, respectively. The 2014 first six-months provision for income taxes was $944 million, representing an effective income tax rate of 39 percent for the period compared to 40 percent during the 2013 period. The 2014 effective rate reflects the impact of a $203 million non-cash write-down in the North Sea. The effective rate for both quarters also reflects a valuation allowance in Canada, foreign currency fluctuations on deferred taxes, and deferred tax expense related to mark-to-market commodity derivatives. Excluding these items, the 2014 and 2013 effective rates would have been 40 percent and 42 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 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. 37

-------------------------------------------------------------------------------- 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 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 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 fiscal year.



Sources and Uses of Cash and Restricted Cash

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

For the Six Months Ended June 30, 2014 2013 (In millions) Sources of Cash and Cash Equivalents: Net cash provided by continuing operating activities $ 4,550$ 5,276 Proceeds from the sale of Argentina 786 - Net cash provided by Argentina operations 2 2 Net commercial paper and bank loan borrowings - 945 Proceeds from Kitimat LNG transaction, net - 405 Proceeds from sale of other oil and gas properties 381 - Other 2 17 5,721 6,645



Uses of Cash and Cash Equivalents: Capital expenditures for exploration and development (E&D) activity

$ 4,871



$ 5,050 Capital expenditures for gas gathering, transmission, and processing facilities

721 491 Acquisitions 5 148 Payments on fixed rate debt - 500 Net commercial paper and bank loan repayments 1 - Dividends 176 183 Treasury stock activity, net 1,263 249 Distributions to noncontrolling interest 66 - 7,103 6,621



Increase (decrease) in cash and cash equivalents $ (1,382 )

$ 24

Sources of Restricted Cash: Short-term restricted cash from sale of Deepwater Gulf of Mexico assets 778 - Long-term restricted cash from sale of Deepwater Gulf of Mexico assets 589 - Increase in restricted cash $ 1,367 $ - Net Cash Provided by Continuing Operating Activities Operating 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 six months of 2014 totaled $4.6 billion, a decrease of $726 million from the first six months of 2013. The decrease primarily reflects the impact of 2013 divestitures and comparative changes in working capital during the periods. 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. 38 -------------------------------------------------------------------------------- Proceeds from the Sale of Argentina InMarch 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 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 the first six months of 2014, capital spending for E&D activities totaled $4.9 billion compared to $5.0 billion in the prior year period. Apache's E&D capital spending was primarily focused on our North American onshore assets. In the Permian region we averaged 37 operated drilling rigs during the quarter. Our recent drilling successes in the Permian has led the region to increase the number of horizontal drilling rigs being utilized, and now almost 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 doubled E&D spending over the prior-year period.



Apache's investment in gas gathering, transmission, and processing facilities totaled $721 million during the first six months of 2014 compared to $491 million in the prior year period. Apache's 2014 capital expenditures were primarily for the Wheatstone and Kitimat LNG facilities.

For the year, we have invested a total of $894 million for E&D and facility costs in the Wheatstone and Kitimat LNG projects. We recently announced our intentions to completely exit both of these projects.

Dividends For the six-month periods ended June 30, 2014 and 2013, the Company paid $176 million and $145 million, respectively, in dividends on its common stock. In the first six months of 2013, the Company also paid $38 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 has since repurchased a total of 26.1 million shares at an average price of $86.75. For the six-months period ended June 30, 2014, the Company repurchased a total of 14.9 million shares at an average price of $85.14. 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 June 30, 2014, the Company had approximately $1.4 billion of proceeds from the sale of our 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. The Company has the option to use these funds for the acquisition of properties or receive the funds in cash after a short-term contractual period. As of the date of this filing, the Company expects to close on the acquisition of like-kind properties for $589 million, and as such, the balance is classified as long-term restricted cash on Apache's consolidated balance sheet as of June 30, 2014. The remaining proceeds of $778 million are classified as short-term restricted cash as of June 30, 2014. Should the Company elect to use additional funds for a like-kind exchange, the balance will be reclassified to long-term restricted cash until the funds are expended.



Liquidity

The following table presents a summary of our key financial indicators at the dates presented: June 30, December 31, 2014 2013 (In millions of



dollars, except as indicated)

Cash and cash equivalents $ 524 $ 1,906 Short-term restricted cash 778 - Total debt 9,675 9,725 Equity 34,892 35,393 Available committed borrowing capacity 3,300 3,300 Percent of total debt-to-capitalization 22 % 22 % Cash and cash equivalents The Company had $524 million in cash and cash equivalents as of June 30, 2014, compared to $1.9 billion at December 31, 2013. Approximately $512 million of the cash was held by foreign subsidiaries. The cash held by foreign subsidiaries may be subject to additional U.S. income taxes if repatriated. Almost all 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. 39 -------------------------------------------------------------------------------- Short-term restricted cash The Company has approximately $778 million classified as short-term restricted cash as of June 30, 2014. The Company has the option to use these funds for the acquisition of properties or receive the funds in cash after a short-term contractual period. Should the Company elect to use these funds for a like-kind exchange, the balance will be reclassified to long-term restricted cash until the funds are expended. Debt As of June 30, 2014, outstanding debt, which consisted of notes, debentures, and uncommitted bank lines, totaled $9.7 billion. The Company had approximately $1 million of current debt outstanding borrowed on uncommitted credit facilities and overdraft lines as of June 30, 2014, compared with $53 million as of December 31, 2013. Available committed borrowing capacity As of June 30, 2014, the Company had unsecured committed revolving syndicated bank credit facilities totaling $3.3 billion, of which $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 billion facilities. The facilities consist of a $1.7 billion facility and a $1.0 billion facility in the U.S., a $300 million facility in Australia, and a $300 million facility in Canada. As of June 30, 2014, available borrowing capacity under the Company's credit facilities was $3.3 billion. The Company's committed credit facilities are used to support Apache's commercial paper program. The Company has available a $3.0 billion commercial paper program, which generally enables 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. At June 30, 2014 and December 31, 2013, the Company had no outstanding commercial paper.



The Company was in compliance with the terms of all credit facilities as of June 30, 2014.

Percent of total debt-to-capitalization The Company's debt-to-capitalization ratio at June 30, 2014 and December 31, 2013 was 22 percent.

40



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