News Column

NOBLE ENERGY INC - 10-Q - Management's Discussion and Analysis of Financial Condition and Results of Operations

July 24, 2014

Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide a narrative about our business from the perspective of our management. We use common industry terms, such as thousand barrels of oil equivalent per day (MBoe/d) and million cubic feet equivalent per day (MMcfe/d), to discuss production and sales volumes. Our MD&A is presented in the following major sections: Executive Overview ; Operating Outlook ; Results of Operations ; and Liquidity and Capital Resources .



The preceding consolidated financial statements, including the notes thereto, contain detailed information that should be read in conjunction with our MD&A.

EXECUTIVE OVERVIEW We are a worldwide explorer and producer of crude oil, natural gas and natural gas liquids. We aim to achieve sustainable growth in value and cash flow through exploration success and the development of a high-quality, diversified, portfolio of assets with investment flexibility between: onshore unconventional developments and offshore organic exploration leading to major development projects; US and international development projects; and production mix among crude oil, natural gas, and NGLs. We currently focus our efforts in five core operating areas: the DJ Basin and Marcellus Shale (onshore US), deepwater Gulf of Mexico, offshore West Africa, and offshore Eastern Mediterranean, where we have strategic competitive advantage and which we believe generate superior returns. We also seek to enter potential new core areas, and we are currently conducting exploration activities in domestic and international locations such as Northeast Nevada, the Falkland Islands, Cameroon, and Cyprus. Our financial results for second quarter 2014 included: net income of $192 million as compared with $377 million for second



quarter 2013;

loss on commodity derivative instruments of $236 million (including $187

million non-cash portion of loss) as compared with a gain on commodity

derivative instruments of $161 million (including $159 million non-cash

portion of gain) for second quarter 2013;

asset impairment charges of $34 million, as compared with zero for second

quarter 2013;

diluted earnings per share of $0.52, as compared with $1.04 for second

quarter 2013;

cash flow provided by operating activities of $828 million, as compared

with $539 million for second quarter 2013; ending cash balance of $958 million, as compared with $1.1 billion at December 31, 2013;



capital spending, on a cash basis, of $1.2 billion for both the second

quarter 2013 and 2014;

gain of $35 million on China asset sale;

repayment of $200 million senior notes in April 2014;

total liquidity of $4.4 billion at June 30, 2014, as compared with $5.1 billion at December 31, 2013; and ratio of debt-to-book capital of 35% at June 30, 2014, as compared with 35% at December 31, 2013.



Our operating results for second quarter 2014 included: delivered record horizontal production of 112 MBoe/d from the DJ Basin and

Marcellus Shale, 56% higher than second quarter of last year;

increased wet gas type curves 10% for wells in the Majorsville area of the

Marcellus Shale;

announced plans to form a master limited partnership (MLP) with CONSOL for

our jointly owned midstream assets in the Marcellus Shale;

exploration discovery made at the Katmai prospect located in the deepwater

Gulf of Mexico;

acquired interest in 17 exploration lease blocks in the Atwater Valley

area of the Gulf of Mexico and spud initial prospect, Bright; increased Leviathan resource estimate as the result of additional information from the ongoing Leviathan appraisal program; signed two regional export Letters of Intent for natural gas sales to customers in Egypt; and



closed China asset sale, receiving $186 million in proceeds.

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Exploration Program Update We have numerous exploration opportunities remaining in our core areas and are also engaged in new venture activity in both our US and international locations. We were in the process of drilling and/or evaluating significant exploratory wells at June 30, 2014 ( See Item 1. Financial Statements - Note 8. Capitalized Exploratory Well Costs), and expect to continue an active exploratory drilling program in the future. A portion of our 2014 capital investment program is dedicated to exploration and associated appraisal activities, including leasehold acquisitions. However, we do not always encounter hydrocarbons through our drilling activities. In addition, we may find hydrocarbons but subsequently reach a decision, through additional analysis or appraisal drilling, that a development project is not economically or operationally viable. In the event we conclude that one of our exploratory wells did not encounter hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense. Additionally, we may not be able to conduct exploration activities prior to lease expirations. As a result, in a future period, dry hole cost and/or leasehold abandonment expense could be significant. See Operating Outlook - Potential for Future Asset Impairment, Dry Hole or Lease Abandonment Expense, below. Updates on significant exploration activities are as follows: Northeast Nevada We are currently analyzing results from our first exploratory vertical well and conducting a long term production test. We plan to drill additional exploratory wells later in 2014. Deepwater Gulf of Mexico During second quarter 2014, we acquired working interests in 17 deepwater exploration leases in the Gulf of Mexico. Each of the leases resides in the Atwater Valley protraction area. We acquired a 50% working interest in 13 leases and an average 26% working interest in four leases. As part of the transaction, we are participating with a 50% non-operated working interest in the Bright prospect, which is currently being drilled on Atwater Valley Block 362 in a water depth of approximately 5,600 feet. The initial exploratory well, targeting multiple reservoirs, is anticipated to be drilled to a total depth of 13,500 feet. In addition to the Bright prospect, there are multiple follow-on exploration opportunities that have been identified on these newly acquired leases. We are also currently drilling the Katmai exploratory well (Green Canyon Block 40, 50% operated working interest) in water depth of approximately 2,100 feet. We recently announced a commercial crude oil discovery at Katmai, and expect to reach a total depth of 28,300 feet during the third quarter of 2014. Offshore West Africa We are currently acquiring 3D seismic data across Blocks O and I, offshore Equatorial Guinea, and may potentially drill an exploratory well offshore Cameroon in the fourth quarter of 2014. Additionally, we are reprocessing 3D seismic data over our YoYo mining concession, offshore Cameroon. Offshore Eastern Mediterranean We are processing and evaluating recently acquired 3D seismic data over offshore Israel and Cyprus and continue to study locations for potential exploratory wells, with opportunities offshore in both Israel and Cyprus. Offshore Falkland Islands We continue to process and evaluate 3D seismic data over the northern and southern areas and prepare for our first operated exploratory well planned for 2015. Major Development Project Updates We continue to advance our major development projects, which we expect to deliver incremental production over the next several years. Updates on major development projects are as follows: Sanctioned Ongoing Development Projects A "sanctioned" development project is one for which a final investment decision has been made. DJ Basin (Onshore US) We continue to operate at a high level of horizontal drilling activity with continued growth from strong well performance, new wells brought online, and expanded natural gas and crude oil infrastructure. We have accelerated our extended reach lateral well program to approximately 30% of our wells to be drilled in 2014. During the quarter, we spud 80 horizontal wells, of which 27 were extended reach lateral wells, and 85 wells initiated production. Our 2014 drilling program includes over 90 extended reach lateral wells. Currently, 10 drilling rigs are active across the basin. Marcellus Shale (Onshore US) We continue to delineate the wet gas acreage, while our partner, CONSOL Energy, Inc. (CONSOL), continues to develop the dry gas acreage. During the quarter, we and our partner drilled 48 wells, and 35 wells initiated production. The joint venture is currently operating ten drilling rigs. 24



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Due to an increase in Henry Hub natural gas prices, our funding of certain drilling and completion costs under the CONSOL Carried Cost Obligation commenced as of March 1, 2014. See Liquidity and Capital Resources - Contractual Obligations below. In June 2014, we and our joint venture partner, CONSOL, submitted a confidential draft Registration Statement on Form S-1 to the U.S. Securities and Exchange Commission relating to a proposed master limited partnership (MLP). The MLP will own, operate, and develop our jointly-owned natural gas midstream assets in the Marcellus Shale. Gunflint (Deepwater Gulf of Mexico) In 2013, we sanctioned the development plan for the 2008 Gunflint crude oil discovery, utilizing a subsea tieback to an existing host facility, and are targeting first production in 2016. Big Bend (Deepwater Gulf of Mexico) The 2012 Big Bend crude oil discovery is located in the Rio Grande area of the deepwater Gulf of Mexico. In October 2013, we sanctioned a development plan, utilizing a subsea tieback to a third party host facility. First production is targeted for late 2015. Tamar Expansion (Offshore Israel) The Tamar compression project, which is expected to increase capacity by 200 MMcf/d at the Ashdod onshore terminal, is progressing, and we expect operational start-up in the second half of 2015. We are continuing to work with the Israeli government to obtain regulatory approval of our development plan for the Tamar Southwest discovery, which is intended to utilize current Tamar infrastructure. Continuing delays in securing regulatory approvals have placed the project at risk of delay. We have petitioned the Israeli courts to expedite the needed approvals. Timely development of Tamar Southwest is important to provide future flow rate assurance for our overall Tamar project. In May 2014, we announced that we had entered into a non-binding Letter of Intent (LOI) for the supply of natural gas from the Tamar field to existing natural gas liquefaction (LNG) facilities in Egypt. Unsanctioned Development Projects (As of June 30, 2014) Dantzler (Deepwater Gulf of Mexico) The 2013 Dantzler crude oil discovery is located in the Rio Grande area of the deepwater Gulf of Mexico and is a co-development opportunity with Big Bend. During the second quarter, we spud the first Dantzler appraisal well (45% operated working interest) and expect drilling results during the third quarter of 2014. Leviathan (Offshore Israel) In the first half of 2014, we made significant progress on the development of the Leviathan field, following approval of Israel's natural gas export policy, an agreement with Israel's Anti-trust Authority, and receipt of the Development and Production Leases for Leviathan. In May 2014, we announced that the existing Leviathan partners terminated the non-binding memorandum of understanding regarding the sale of interest in the Leviathan licenses to Woodside Petroleum. The initial phase of the Leviathan project is designed to provide significant quantities of natural gas to Israel and regional markets. In June 2014, we announced that we had entered into a non-binding LOI for the supply of natural gas from the Leviathan field to existing LNG facilities in Egypt. We are currently considering various project finance options for Leviathan. Sanctioning of the initial phase of development at Leviathan is targeted by the end of 2014 or early 2015, with first production from the field currently planned for the end of 2017 or early 2018. See also Update on Israel's Natural Gas Economy, below. Cyprus Project (Offshore Cyprus) We are planning additional appraisal activities, including interpretation of seismic data and spudding another well to further determine the ultimate recoverable resources on Block 12 and optimize field development planning. In addition, our application for renewal of the production sharing contract for two additional years was approved in May 2014. Diega and Carla (Offshore Equatorial Guinea) We are currently evaluating regional development scenarios for Diega and Carla and targeting to sanction a Diega development project in 2015.



See Item 1. Financial Statements - Note 8. Capitalized Exploratory Well Costs for additional information on costs incurred related to these projects.

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Non-Core Divestiture Program We have continued our non-core asset divestiture program with the sale of our China assets on June 30, 2014. Sales of certain smaller onshore US property packages were completed during the first six months of 2014 or are expected to be completed this year. Divestitures of non-core properties allow us to allocate capital and human resources to high-value and high-growth areas. See Item 1. Financial Statements - Note 3. Divestitures and Operating Outlook - Potential for Future Asset Impairment, Dry Hole or Lease Abandonment Expense, below. We are currently winding up local business activities in countries of former operations. At this time, we do not believe that any of the activities associated with these areas will have a material effect on our financial position, results of operations or cash flows. Update on Israel's Natural Gas Economy Israel Antitrust Authority During 2014, we and our partners reached an agreement with the Israeli government on various antitrust matters. As a result of the agreement, we will divest two natural gas discoveries. We have initiated an active program to locate a buyer and other actions required to complete the plan to sell the assets. The assets are reported within assets held for sale in our consolidated balance sheet at June 30, 2014. The agreement also granted the rights, to us and our partners, to jointly market natural gas from the Leviathan field. As a result, we plan to further our domestic natural gas marketing activities. The agreement is subject to final approval by the Israeli government. On March 26, 2014, the Israel Ministry of Finance (Ministry) issued a memorandum indicating its intent to amend the Petroleum Profits Law in light of the Israeli government's 2013 decision to permit the export of natural gas from Israel. The purpose of the proposed amendments is mainly to regulate the method of taxing petroleum export transactions, and, in particular, exports of natural gas. As a part of the Ministry's draft recommendation, several methodologies could be used to establish the transfer price for natural gas sales, depending on various circumstances. We are currently evaluating the recommendation and proposed amendments. The recent Israel-Gaza conflict has resulted in loss of life and destruction of property. See our Annual Report on Form 10-K for the year ended December 31, 2013 - Item 1A. Risk Factors - Our operations may be adversely affected by violent acts such as from civil disturbances, terrorist acts, regime changes, cross-border violence, war, piracy, or other conflicts that may occur in regions that encompass our operations. Update on Hydraulic Fracturing Potential Rulemaking Although hydraulic fracturing is regulated primarily at the state level, governments and agencies at all levels from federal to municipal are conducting studies and considering regulations, and some have proposed rules. A measure to ban hydraulic fracturing was on the ballot in the City of Loveland in northern Colorado in June of 2014. Industry worked with the community to defeat that initiative. Also during 2014, we have been actively campaigning against statewide ballot initiatives that would unreasonably restrict or limit crude oil and natural gas development in Colorado. There are currently two remaining initiatives that have survived titling and Supreme Court review and are in a position to collect sufficient signatures to be placed on the November 2014 ballot. These are: an initiative to amend the state constitution to establish an environmental bill of rights; and



an initiative to amend the state constitution to impose a 2000-foot

statewide drilling setback from occupied structures, unless a waiver is obtained from the landowner. Petitioners have until August 4, 2014 to gather 86,105 verified signatures and we will work with the State of Colorado to ensure any signatures submitted on these initiatives are properly verified. The ultimate passage and implementation of one or both of these initiatives could have a negative impact on our business. In particular, a statewide drilling setback will likely delay or otherwise limit our drilling and development activities in certain parts of the DJ Basin. This could result in a reduction in our proved reserves and negatively impact our results of operations, cash flows, and stock price. In Nevada, state regulators are in the process of promulgating rules to govern hydraulic fracturing and new crude oil and natural gas development. We have actively participated in that process and do not believe it will have a material impact on our activities. We will continue to monitor new and proposed legislation and regulations to assess the potential impact on our operations. Concurrently, we are engaged in extensive public education and outreach efforts with the goal of engaging and educating the general public about the energy, economic and environmental benefits of safe and responsible crude oil and natural gas development. 26



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Regulations

On February 23, 2014, the Colorado Air Quality Control Commission (Commission) adopted a number of revisions to its oil and gas industry regulations. The revisions include the full adoption of US Environmental Protection Agency's Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and Distribution (also known as NSPS Quad O) with corresponding complementary control measures. The control measures set forth requirements for identifying and repairing leaks, undertaking record keeping, and submitting reports. The revisions also include the first ever regulation of methane emissions from the industry. In collaboration with the Environmental Defense Fund and other oil and gas operators, we provided testimony and evidence to the Commission in support of the adopted revisions. The adopted revised regulations were published in the Colorado Register on March 25, 2014, Volume 37, No. 6, and are effective as of April 14, 2014. Copies of these regulations are available at http://www.sos.state.co.us/CCR. We do not currently believe costs incurred to implement these regulations will be material to our earnings or cash flows. Sales Volumes The execution of our strategy has delivered a diversified production growth most recently due to our Tamar natural gas field and Alen condensate project coming online in 2013 along with accelerated activity in onshore US unconventional developments. On a BOE basis, total sales volumes were 11% higher for the second quarter of 2014 as compared with the second quarter of 2013, and our mix of sales volumes was 46% global liquids, 27% international natural gas, and 27% US natural gas. See Results of Operations - Revenues, below. Commodity Price Changes Average realized natural gas prices increased 5% in the US and 13% in Israel for second quarter of 2014 as compared with the second quarter of 2013. Average realized crude oil prices increased 5% in the US and 7% in Equatorial Guinea for the second quarter of 2014 as compared with the second quarter of 2013. Recently Issued Accounting Standards See Item 1. Financial Statements - Note 2. Basis of Presentation. OPERATING OUTLOOK 2014 Production Our expected crude oil, natural gas and NGL production for 2014 may be impacted by several factors including: changes to drilling plans in the DJ Basin and the Marcellus Shale;



Israeli demand for electricity, which affects demand for natural gas as

fuel for power generation and industrial market growth, and which is impacted by unseasonable weather;



potential downtime at key assets including: Galapagos and Swordfish,

deepwater Gulf of Mexico; Tamar, offshore Israel; and Aseng and Alen, offshore Equatorial Guinea; natural field decline in the deepwater Gulf of Mexico and the Alba and Aseng fields offshore Equatorial Guinea; and potential weather-related volume curtailments due to hurricanes in the deepwater Gulf of Mexico which can shut-in or reduce production. 2014 Capital Investment Program Total capital expenditures are estimated at $4.8 to $5.0 billion for 2014. We expect to invest approximately 70% of the program in onshore US development and approximately 30% of the program in global deepwater activities. The 2014 capital investment program is estimated to exceed operating cash flows and is expected to be funded from cash flows from operations, cash on hand, and borrowings under our unsecured revolving credit facility (Credit Facility) and/or other financing. Funding may also be provided by proceeds from divestment of non-core assets or farm-out of working interests in exploration prospects. See Liquidity and Capital Resources - Financing Activities. We will continue to evaluate the level of capital spending and remain flexible throughout the year. For further discussion, see Executive Overview - Update on Hydraulic Fracturing, above, regarding potential legislative or regulatory changes in the use of hydraulic fracturing, and Liquidity and Capital Resources - Contractual Obligations , below, regarding the CONSOL Carried Cost Obligation. Potential for Future Asset Impairment, Dry Hole or Lease Abandonment Expense Exploration Activities We have an active exploratory drilling program. In the event we conclude that an exploratory well did not encounter hydrocarbons or that a discovery is not economically or operationally viable, the associated capitalized exploratory well costs would be charged to expense. For example, in the Falkland Islands we are processing recently acquired seismic data. We will conduct seismic interpretation and basin modeling during the remainder of 2014 in order to determine our future drilling program. Integration of seismic information with the results of the Scotia exploratory well will allow us to assess the economic viability of this prospect. If we were to determine, based on the results of seismic interpretation and/or 27



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additional drilling activities, that the Scotia prospect is not economically viable, the costs we have incurred (approximately $73 million to date) would be written off to dry hole expense. Additionally, we may not conduct exploration activities prior to lease expirations. For example, in the deepwater Gulf of Mexico, while we continue to mature our prospect portfolio, regulations have become more stringent due to the Deepwater Horizon incident in 2010. In some instances, specifically engineered blowout preventers, rigs, and completion equipment may be required for high pressure environments. Regulatory requirements or lack of readily available equipment could prevent us from engaging in future exploration activities during our current lease terms. One particular deepwater Gulf of Mexico lease, which we acquired under regulations in effect prior to the Deepwater Gulf of Mexico Moratorium, is set to expire on July 31, 2014. We have been working to mature this prospect by conducting various activities, including the licensing and processing of 3-D seismic data and interpretation of geophysical information, which have resulted in the identification of a potential hydrocarbon-bearing formation below 25,000 feet. We reviewed the criteria for a lease suspension of operations (SOO), which may be granted by regulatory authorities, and believe we satisfy each of the required conditions. We submitted an application for the SOO, evidencing satisfaction of the required conditions, on July 7, 2014. If an SOO is granted, we intend to continue processing of subsalt imaging and developing an exploration plan, targeting a 2017 exploratory well spud date. Although we believe we have satisfied the required conditions for the SOO, there is no certainty an extension will be obtained prior to the lease expiration. The lease had a net book value of approximately $41 million at June 30, 2014. If we are unable to obtain an extension, we must relinquish the lease, abandon our exploration plans, and write off the book value to exploration expense. Producing Properties Commodity prices remain volatile. A decline in future crude oil or natural gas prices could result in impairment charges. The cash flow model that we use to assess proved properties for impairment includes numerous assumptions, such as management's estimates of future oil and gas production along with operating and development costs, market outlook on forward commodity prices, and interest rates. All inputs to the cash flow model must be evaluated at each date of estimate. However, a decrease in forward crude oil or natural gas prices alone could result in an impairment. Occasionally, well mechanical problems arise, which can reduce production and potentially result in reductions in proved reserves estimates. For example, our South Raton development in the deepwater Gulf of Mexico has been shut-in due to mechanical issues. We have conducted remediation work; however, return to production has been delayed due to work being performed at the non-operated host facility. We expect to begin producing later in third quarter 2014. No impairment is currently indicated; however, we will monitor production and reserves when South Raton is brought back online and continue to assess the field for possible impairment. South Raton had a net book value of approximately $123 million at June 30, 2014. In addition, well decommissioning programs, especially in deepwater or remote locations, are often complex and expensive. It may be difficult to estimate timing of actual abandonment activities, which are subject to regulatory approval and the availability of rigs and services. It may be difficult to estimate costs as rigs and services become more expensive in periods of higher demand. Therefore, our ARO estimates may change, sometimes significantly, and could result in asset impairment. Divestments We are currently marketing certain non-core onshore US properties, including our assets in the Piceance Basin of western Colorado. If properties are reclassified as assets held for sale in the future, they will be valued at the lower of net book value or anticipated sales proceeds less costs to sell. Impairment expense would be recorded for any excess of net book value over anticipated sales proceeds less costs to sell. In addition, we would allocate a portion of goodwill to any non-core onshore US property held for sale that constitutes a business, which could potentially decrease any gain or increase any loss recorded on the sale. In addition, certain assets offshore Israel were classified as held for sale at June 30, 2014. No impairments are indicated at this time. However, failure to achieve acceptable sale terms or delays in closing sales of these properties could result in impairment and/or loss on sale. Potential Change in Pennsylvania Tax Structure The State of Pennsylvania has been addressing a potential budget deficit. As a result, Pennsylvania lawmakers have been considering various alternatives for generating additional revenues, including additional taxes on crude oil and natural gas production. Additional taxes could be in the form of a severance tax, which would be assessed on the value of the natural gas produced. A severance tax, if imposed, may or may not replace the current local impact fee, which is assessed on a per well basis at a rate determined primarily by the age of the well, under a law signed in 2012. We are currently unable to predict whether a severance tax will be imposed by the State of Pennsylvania. However, additional taxes on our crude oil, condensate or natural gas production could have a negative impact on our results of operations and cash flows. 28



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RESULTS OF OPERATIONS In the discussion below, the North Sea geographical segment is reflected as discontinued operations for the first six months of 2013. During first quarter 2014, the remaining unsold North Sea assets were reclassified to held and used, and their operations are included in continuing operations for 2014. See also Discontinued Operations, below. Revenues Revenues were as follows: Increase/(Decrease) (millions) 2014 2013 from Prior Year Three Months Ended June 30, Oil, Gas and NGL Sales $ 1,338$ 1,112 20 % Income from Equity Method Investees 45 37 22 % Total $ 1,383$ 1,149 20 % Six Months Ended June 30, Oil, Gas and NGL Sales $ 2,665$ 2,196 21 % Income from Equity Method Investees 97 96 1 % Total $ 2,762$ 2,292 21 %



Changes in revenues are discussed below.

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Oil, Gas and NGL Sales Average daily sales volumes and average realized sales prices were as follows:

Sales Volumes



Average Realized Sales Prices

Crude Oil & Natural Crude Oil & Natural Condensate Gas NGLs Total Condensate Gas NGLs (MBbl/d) (MMcf/d) (MBbl/d) (MBoe/d) (1) (Per Bbl) (Per Mcf) (Per Bbl) Three Months Ended June 30, 2014 United States 65 469 22 166 $ 99.39$ 4.24$ 34.66 Equatorial Guinea (2) 34 248 - 75 108.08 0.27 - Israel - 218 - 37 - 5.57 - Other International (3) 5 - - 5 104.70 - - Total Consolidated Operations 104 935 22 283 102.53 3.50 34.66 Equity Investees (4) 2 - 6 7 108.31 - 64.86 Total Continuing Operations 106 935 28 290 $ 102.62$ 3.50$ 40.70 Three Months Ended June 30, 2013 United States 58 404 15 140 $ 94.29$ 4.04$ 30.05 Equatorial Guinea (2) 31 252 - 73 101.44 0.27 - Israel - 220 - 37 - 4.92 - Other International (3) 4 - - 4 97.92 - - Total Consolidated Operations 93 876 15 254 96.84 3.18 30.05 Equity Investees (4) 1 - 5 6 99.48 - 62.93 Total Continuing Operations 94 876 20 260 $ 96.87$ 3.18$ 38.48 Six Months Ended June 30, 2014 United States 65 476 20 165 $ 98.22$ 4.52$ 39.10 Equatorial Guinea (2) 34 245 - 74 106.92 0.27 - Israel - 218 - 37 - 5.59 - Other International (3) 5 - - 5 104.48 - - Total Consolidated Operations 104 939 20 281 101.39 3.66 39.10 Equity Investees (4) 2 - 6 7 106.50 - 69.70 Total Continuing Operations 106 939 26 288 $ 101.47$ 3.66$ 45.71 Six Months Ended June 30, 2013 United States 60 406 15 143 $ 95.02$ 3.68$ 34.63 Equatorial Guinea (2) 29 249 - 70 106.20 0.27 - Israel - 166 - 28 - 5.00 - Other International (3) 4 - - 4 103.66 - - Total Consolidated Operations 93 821 15 245 98.87 2.91 34.63 Equity Investees (4) 2 - 6 8 105.38 - 69.03 Total Continuing Operations 95 821 21 253 $ 98.98$ 2.91$ 44.02 (1) Natural gas is converted on the basis of six Mcf of gas per one barrel of



crude oil equivalent. This ratio reflects an energy content equivalency and

not a price or revenue equivalency. Given commodity price disparities, the

price for a barrel of crude oil equivalent for natural gas is significantly

less than the price for a barrel of crude oil. The price for a barrel of NGL

is also less than the price for a barrel of crude oil. 30



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(2) Natural gas from the Alba field in Equatorial Guinea is under contract for

$0.25 per MMBtu to a methanol plant, an LPG plant, an LNG plant and a power

generation plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting. (3) Other International includes primarily China. (4) Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea. See Income from Equity Method Investees, below. An analysis of revenues from sales of crude oil, natural gas and NGLs is as follows: Sales Revenues Natural (millions) Crude Oil & Condensate Gas NGLs Total Three Months Ended June 30, 2013 $ 817 $ 253$ 42$ 1,112 Changes due to Increase in Sales Volumes 100 17 19 136 Increase in Sales Prices 54 27 9 90 Three Months Ended June 30, 2014 $ 971 $ 297 $



70 $ 1,338

Six Months Ended June 30, 2013 $ 1,667 $ 432$ 97$ 2,196 Changes due to Increase in Sales Volumes 186 62 30 278 Increase in Sales Prices 46 128 17 191 Six Months Ended June 30, 2014 $ 1,899 $ 622 $



144 $ 2,665

Crude Oil and Condensate Sales - Revenues from crude oil and condensate sales increased during second quarter and first six months of 2014 as compared with 2013 due to the following: higher sales volumes in the DJ Basin attributable to our horizontal



drilling program;

additional sales volumes from the Alen condensate project, offshore

Equatorial Guinea, which began producing in late second quarter 2013 and averaged 11 MBoe/d during the first six months of 2014;



higher sales volumes from the deepwater Gulf of Mexico of approximately 2

MBoe/d for the second quarter of 2014 as compared with 2013; and

higher realized prices for crude and condensate, both in the DJ Basin and

offshore Equatorial Guinea;

partially offset by: negative volume impact of severe winter weather and downtime for facility

upgrades in the DJ Basin; and

lower sales volumes from the Aseng project, offshore Equatorial Guinea,

due to natural production declines.

Natural Gas Sales - Revenues from natural gas sales increased during the second quarter and first six months of 2014 as compared with 2013 due to the following: increases in total consolidated average realized prices of 10% primarily due to increased demand from cooler weather and higher-than-expected inventory withdrawals in the US; and



higher sales volumes in the Marcellus Shale of 231 MMcf/d for second

quarter 2014 and 218 MMcf/d for the first six months of 2014, as compared

with 108 MMcf/d and 104 MMcf/d, respectively for 2013, primarily

attributable to our horizontal drilling program and continued ramp-up of

activity;



partially offset by: lower sales volumes due to non-core onshore US properties divested during

2013 and first six months of 2014; and

lower sales volumes due to natural field decline from the Mari-B, Noa and

Pinnacles fields, offshore Israel.

NGL Sales - The majority of our US NGL production is currently from the DJ Basin. Additional NGL production from the Marcellus Shale added 2 MBbl/d during second quarter and first six months of 2014 as compared with 2013, primarily due to increased production from the wet gas acreage. NGL sales in the DJ Basin increased by 5 MBbl/d during the second quarter of 2014 as compared with 2013, and recent sales of our non-core onshore US properties have slightly reduced sales volumes as compared with second quarter 2013. Additionally, sales prices have increased 13% for the first six months of 2014, compared to the first six months of 2013. Income from Equity Method Investees We have a 45% interest in Atlantic Methanol Production Company, LLC, which owns and operates a methanol plant and related facilities, and a 28% interest in Alba Plant LLC, which owns and operates a liquefied petroleum gas processing plant. Both plants are located onshore on Bioko Island in Equatorial Guinea. 31



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Equity method investments are included in other noncurrent assets in our consolidated balance sheets, and our share of earnings is reported as income from equity method investees in our consolidated statements of operations. Within our consolidated statements of cash flows, our share of dividends is reported within cash flows from operating activities and our share of investments is reported within cash flows from investing activities.

Operating Costs and Expenses Operating costs and expenses were as follows: Increase (millions) 2014 2013 from Prior Year Three Months Ended June 30, Production Expense $ 248$ 210 18 % Exploration Expense 59 90 (34 )% Depreciation, Depletion and Amortization 413 368 12 % General and Administrative 127 104 22 % Gain on Divestitures (44 ) 4 N/M Asset Impairments 34 - - % Other Operating (Income) Expense, Net 17 12 42 % Total $ 854$ 788 8 % Six Months Ended June 30, Production Expense $ 481$ 398 21 % Exploration Expense 133 151 (12 )% Depreciation, Depletion and Amortization 837 734 14 % General and Administrative 266 216 23 % Gain on Divestitures (42 ) (12 ) N/M Asset Impairments 131 - - % Other Operating (Income) Expense, Net 23 20 N/M Total $ 1,829$ 1,507 21 % N/M - Amount is not meaningful. Changes in operating costs and expenses are discussed below. 32



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Production Expense Components of production expense were as follows:

Total per United Other Int'l, (millions, except unit rate) BOE (1) Total States Equatorial Guinea Israel Corporate (2) Three Months Ended June 30, 2014 Lease Operating Expense (3) $ 5.99$ 154$ 88 $ 36 $ 14 $ 16 Production and Ad Valorem Taxes 2.06 53 45 - - 8 Transportation and Gathering Expense 1.60 41 40 - - 1 Total Production Expense $ 9.65$ 248$ 173 $ 36 $ 14 $ 25 Three Months Ended June 30, 2013 Lease Operating Expense (3) $ 6.04$ 140$ 90 $ 27 $ 19 $ 4 Production and Ad Valorem Taxes 1.87 43 35 - - 8 Transportation and Gathering Expense 1.17 27 27 - - - Total Production Expense $ 9.08$ 210$ 152 $ 27 $ 19 $ 12 Six Months Ended June 30, 2014 Lease Operating Expense (3) $ 5.89$ 299$ 176 $ 67 $ 26 $ 30 Production and Ad Valorem Taxes 2.01 102 85 - - 17 Transportation and Gathering Expense 1.57 80 78 - - 2 Total Production Expense $ 9.47$ 481$ 339 $ 67 $ 26 $ 49 Six Months Ended June 30, 2013 Lease Operating Expense (3) $ 5.78$ 257$ 179 $ 47 $ 20 $ 11 Production and Ad Valorem Taxes 1.94 86 69 - - 17 Transportation and Gathering Expense 1.24 55 54 - - 1 Total Production Expense $ 8.96$ 398$ 302 $ 47 $ 20 $ 29



(1) Consolidated unit rates exclude sales volumes and expenses attributable to

equity method investees. (2) Other International includes primarily China.



(3) Lease operating expense includes oil and gas operating costs (labor, fuel,

repairs, replacements, saltwater disposal and other related lifting costs)

and workover expense.

For the second quarter and first six months of 2014, total production expense increased as compared with 2013 due to the following: increased lease operating expense in the DJ Basin and Marcellus Shale due

to increased development activity and higher production;

increased lease operating expense offshore Equatorial Guinea primarily due

to the start up of the Alen field in the second half of 2013; increased lease operating expense offshore Israel primarily due to the start up of the Tamar field, which began producing at the end of first quarter 2013;



increased production and ad valorem taxes in the DJ Basin and Marcellus

Shale due to higher production volumes and higher average prices; and increased transportation and gathering expense in the DJ Basin and



Marcellus Shale due to higher production volumes from ongoing development

activities; partially offset by: decreased lease operating expense from sales of non-core onshore US properties in 2013; and decreased lease operating expense from natural field decline from the Mari-B field, offshore Israel. 33



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Exploration Expense Components of exploration expense were as follows:

Eastern United West Mediter- Other Int'l, (millions) Total States Africa (1) ranean (2) Corporate (3) Three Months Ended June 30, 2014 Dry Hole Cost $ - $ - $ - $ - $ - Seismic 9 8 - 1 - Staff Expense 33 10 2 3 18 Other 17 17 - - - Total Exploration Expense $ 59$ 35 $ 2 $ 4 $ 18 Three Months Ended June 30, 2013 Dry Hole Cost $ 23$ 15 $ 8 $ - $ - Seismic 25 7 2 6 10 Staff Expense 30 5 3 - 22 Other 12 12 - - -



Total Exploration Expense $ 90$ 39 $ 13 $ 6 $ 32

Six Months Ended June 30, 2014 Dry Hole Cost $ 2$ 2 $ - $ - $ - Seismic 32 15 - 2 15 Staff Expense 68 18 4 5 41 Other 31 31 - - - Total Exploration Expense $ 133$ 66 $ 4 $ 7 $ 56 Six Months Ended June 30, 2013 Dry Hole Cost $ 23$ 15 $ 8 $ - $ - Seismic 50 13 2 6 29 Staff Expense 58 12 4 2 40 Other 20 21 - - (1 ) Total Exploration Expense $ 151$ 61 $ 14 $ 8 $ 68 (1) West Africa includes Equatorial Guinea, Cameroon, and Sierra Leone. (2) Eastern Mediterranean includes Israel and Cyprus. (3) Other International includes the Falkland Islands and Nicaragua.



Exploration expense for the second quarter and first six months of 2014 included: seismic expense related to 3D seismic testing in the DJ Basin and Falkland

Islands; and

staff expense associated with new ventures and corporate expenditures.

Exploration expense for the second quarter and first six months of 2013 included the following: dry hole cost related primarily to the deeper exploration objective of the



second Gunflint appraisal well, deepwater Gulf of Mexico, and the side

track portion of the Carla I-7 appraisal well, offshore Equatorial Guinea; other international seismic expense related to 3D seismic testing in the



Falkland Islands; and

staff expense associated with new ventures and corporate expenditures.

Depreciation, Depletion and Amortization DD&A expense was as follows:

Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 DD&A Expense (millions) (1) $ 413$ 368$ 837$ 734 Unit Rate per BOE (2) $ 16.07$ 15.93$ 16.49$ 16.53



(1) For DD&A expense by geographical area, see Item 1. Financial Statements -

Note 12. Segment Information.

(2) Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees. 34



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Total DD&A expense for the second quarter and first six months of 2014 increased as compared with 2013 due to the following: increase in the DJ Basin and the Marcellus Shale due to higher sales volumes associated with increased development activity;



increase in the deepwater Gulf of Mexico due to a new well producing at

Ticonderoga and the addition of the Neptune spar at Swordfish; and

increase offshore Equatorial Guinea primarily due to the start up of the

Alen field in the second half of 2013;

partially offset by: decrease due to sales of non-core onshore US properties in 2013; and



decrease offshore Israel related to the start up of the Tamar field at the

end of first quarter 2013 which has a lower DD&A rate.

The increase in the unit rate per BOE for the second quarter of 2014 as compared with 2013 was due primarily to the change in mix of production. Higher-cost production volumes in the deepwater Gulf of Mexico were offset by lower cost volumes produced at Tamar, offshore Israel, which replaced higher cost volumes produced from the Mari-B, Noa and Pinnacles fields. The unit rate per BOE remained flat for the first six months of 2014 as compared with 2013. General and Administrative Expense General and administrative expense (G&A) was as follows: Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 G&A Expense (millions) $ 127$ 104$ 266$ 216 Unit Rate per BOE (1) $ 4.93$ 4.48$ 5.24$ 4.86



(1) Consolidated unit rates exclude sales volumes and expenses attributable to

equity method investees.

G&A expense for the second quarter and first six months of 2014 increased as compared with 2013 primarily due to additional expenses relating to personnel and office space in support of our major development projects and increased exploration activities. For example, our total number of employees increased from 2,190 at December 31, 2012, to 2,527 at December 31, 2013 and to just over 2,600 at June 30, 2014. An increase in the number of participants in our 401(k) savings plan, as a result of the planned termination of the defined benefit pension plan, resulted in an increase in payroll burden. Asset Impairment Expense Asset impairment expense was as follows: Three Months Ended Six Months Ended June 30, June 30, (millions) 2014 2013 2014 2013 Asset Impairments $ 34 $ - $ 131 $ - See Item 1. Financial Statements - Note 2. Basis of Presentation, Note 4. Asset Impairments and Note 7. Fair Value Measurements and Disclosures. Other (Income) Expense Other (income) expense was as follows: Three Months Ended Six Months Ended June 30, June 30, (millions) 2014 2013 2014 2013



(Gain) Loss on Commodity Derivative Instruments $ 236$ (161 )$ 311$ (89 ) Interest, Net of Amount Capitalized

52 33 99 58 Other Non-Operating Expense, Net 8 3 13 12 Total $ 296$ (125 )$ 423$ (19 ) (Gain) Loss on Commodity Derivative Instruments (Gain) Loss on commodity derivative instruments is a result of mark-to-market accounting. Many factors impact a gain or loss on commodity derivative instruments including: increases and decreases in the commodity forward price curves compared to our executed hedging arrangements; increases in hedged future volumes; and the mix of hedge arrangements between NYMEX WTI, Dated Brent and NYMEX Henry Hub commodities.



See Item 1. Financial Statements - Note 5. Derivative Instruments and Hedging Activities and Note 7. Fair Value Measurements and Disclosures.

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Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows: Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 (millions, except unit rate) Interest Expense, Gross $ 78$ 68$ 159$ 135 Capitalized Interest (26 ) (35 ) (60 ) (77 ) Interest Expense, Net $ 52$ 33$ 99$ 58 Unit Rate per BOE (1) $ 2.01$ 1.44$ 1.95$ 1.31 (1) Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees. The increase in interest expense, gross, is due to the issuance of new senior debt in November 2013 and recent borrowings under our Credit Facility. The decrease in capitalized interest is primarily due to the completion of longer cycle time major projects, such as Alen, offshore West Africa, and Tamar, offshore Israel, and the current concentration of development activity onshore US, which has more rapid well construction time, partially offset by higher work in progress amounts related to major long-term projects in the deepwater Gulf of Mexico, offshore West Africa, and offshore Israel. Income Tax Provision See Item 1. Financial Statements - Note 11. Income Taxes for a discussion of the change in our effective tax rate for the second quarter and first six months of 2014 as compared with 2013. Discontinued Operations The North Sea geographical segment is reflected as discontinued operations for the first six months of 2013. During first quarter 2014, the remaining unsold North Sea assets were reclassified to held and used, and their operations are included in continuing operations for 2014. Summarized results of discontinued operations were as follows: Three Months Ended Six Months Ended June 30, June 30, 2013 2013 (millions) Oil and Gas Sales $ 12 $ 21 Expenses 7 17 Income Before Income Taxes 5 4 Income Tax Expense 3 10 Operating (Income) Loss, Net of Tax 2 (6 ) Gain on Sale, Net of Tax 17



55

Income From Discontinued Operations $ 19 $



49

Key Statistics: Daily Production Crude Oil & Condensate (MBbl/d) 1



1

Natural Gas (MMcf/d) 3



3

Average Realized Price Crude Oil & Condensate (Per Bbl) $ 103.21 $ 107.63 Natural Gas (Per Mcf) 11.40 10.63 Our long-term debt is recorded at the consolidated level and is not reflected by each component. Thus, we have not allocated interest expense to discontinued operations. See Item 1. Financial Statements - Note 3. Divestitures. 36



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LIQUIDITY AND CAPITAL RESOURCES Capital Structure/Financing Strategy In seeking to effectively fund and monetize our discovered hydrocarbons, we employ a capital structure and financing strategy designed to provide sufficient liquidity throughout the volatile commodity price cycle. Specifically, we strive to retain the ability to fund long cycle, multi-year, capital intensive development projects throughout a range of scenarios, while also funding a robust exploration program and maintaining capacity to capitalize on financially attractive periodic mergers and acquisitions activity. We endeavor to maintain an investment grade debt rating in service of these objectives, while delivering competitive returns and a growing dividend. We utilize a commodity price hedging program to reduce the impacts of commodity price volatility and enhance the predictability of cash flows along with a risk and insurance program to protect against disruption to our cash flows and the funding of our business. We strive to maintain a minimum liquidity level to address volatility and risk. Traditional sources of our liquidity are cash flows from operations, cash on hand, available borrowing capacity under our Credit Facility, and proceeds from sales of non-core properties. We may also access the capital markets to ensure adequate liquidity exists in the form of unutilized capacity under our Credit Facility or to refinance scheduled debt maturities. On April 15, 2014, we repaid $200 million of scheduled current maturities. See Item 1. Financial Statements - Note 6. Debt and Credit Facility, below. Expanded development in the DJ Basin and Marcellus Shale, investment in our recently sanctioned major development projects, and our planned exploration and appraisal drilling activities are estimated to result in near term capital expenditures exceeding cash flows from operating activities. The extent to which capital investment will exceed operating cash flows depends on our success in sanctioning future development projects, the results of our exploration activities, and new business opportunities as well as external factors such as commodity prices, among others. Our financial capacity, coupled with our diversified portfolio, provides us with flexibility in our investment decisions including execution of our major development projects and increased exploration activity. To support our investment program, we expect that higher production resulting from our core onshore US development programs combined with new production from Tamar, which began producing in late first quarter 2013, and Alen, which began producing in late second quarter 2013, will result in an increase in cash flows which will be available to meet a substantial portion of future capital commitments. Cash on hand at June 30, 2014 totaled $958 million, and includes both domestic and foreign cash. We consider repatriating foreign cash to increase our financial flexibility and fund our capital investment program to the extent such cash is not required to fund foreign investment projects and would not incur material US tax. During the first six months of 2014, we repatriated $519 million from our UK operations. We will not incur material US tax on these repatriations. We also evaluate potential strategic farm-out arrangements of our working interests in Israel, Cyprus, Cameroon, Nicaragua and the deepwater Gulf of Mexico for reimbursement of our capital spending in these areas. In addition, our current liquidity level and balance sheet, along with our ability to access the capital markets, provide flexibility. We believe that we are well-positioned to fund our long-term growth plans. We are currently evaluating potential development scenarios for our significant natural gas discoveries offshore Eastern Mediterranean, including Leviathan and Cyprus Block 12. The magnitude of these discoveries presents technical and financial challenges for us due to the large-scale development requirements. Potential development scenarios may include the construction of subsea pipeline, floating LNG, LNG terminals, FPSO or other options. Each of these development options would require a multi-billion dollar investment and require a number of years to complete. We are currently considering various project finance alternatives for Leviathan. Marcellus Shale Joint Venture Our joint venture arrangement with a subsidiary of CONSOL Energy, Inc. is structured in a manner to address partner alignment and financial affordability. Under the arrangement, we agreed to fund one-third of CONSOL's 50% working interest share of future drilling and completion costs up to a fixed amount. See Contractual Obligations, below. Pension Plan Termination We are in the process of terminating our defined benefit pension plan (pension plan). We expect to liquidate the associated pension obligation through lump-sum payments to participants or the purchase of annuities on their behalf. As of December 31, 2013, the latest actuarial measurement date for the pension plan, the accumulated benefit obligation totaled $315 million, and the fair value of plan assets was $265 million. At March 31, 2014, we reclassified the long-term portion of the net pension plan liability to current, as we expect final plan termination to occur by the end of first quarter 2015. We expect to make additional contributions to the plan during the period leading up to final termination and distribution to the extent necessary to fund these obligations. In addition, upon termination 37



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of the pension plan, all unamortized prior service cost and net actuarial loss remaining in AOCL will be charged to expense. This amount totaled approximately $98 million as of June 30, 2014. In coordination with the termination of the pension plan, we also amended our restoration plan to freeze the accrual of benefits effective December 31, 2013. Payments under the restoration plan will continue to be made in ordinary course without acceleration. Restoration plan participants who remain employed by us upon final liquidation and distribution of assets of the pension plan may elect to have the lump sum present value of their restoration plan benefits converted into an account balance under our nonqualified deferred compensation plan. Available Liquidity Information regarding cash and debt balances is as follows: June 30, December 31, 2014 2013 (millions, except percentages) Cash and Cash Equivalents $ 958 $



1,117

Amount Available to be Borrowed Under Credit Facility (1) 3,400

4,000 Total Liquidity $ 4,358$ 5,117 Total Debt (2) $ 5,237$ 4,843 Total Shareholders' Equity 9,554 9,184 Ratio of Debt-to-Book Capital (3) 35 % 35 % (1) See Credit Facility, below. (2) Total debt includes capital lease and other obligations and excludes unamortized debt discount.



(3) We define our ratio of debt-to-book capital as total debt (which includes

long-term debt excluding unamortized discount, the current portion of

long-term debt, and short-term borrowings) divided by the sum of total debt

plus shareholders' equity.

Cash and Cash Equivalents We had approximately $958 million in cash and cash equivalents at June 30, 2014, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $859 million of this cash is attributable to our foreign subsidiaries and a portion would be subject to US income taxes if repatriated. Credit Facility Our Credit Facility matures on October 3, 2018. The commitment is $4.0 billion through the maturity date of the Credit Facility. As of June 30, 2014, we had drawn $600 million under the Credit Facility to fund increased development activities. The weighted average interest rate on the borrowings was 1.41%. Borrowings under our Credit Facility subject us to interest rate risk. See Item 1. Financial Statements -Note 6. Debt and Item 3. Quantitative and Qualitative Disclosures . Commodity Derivative Instruments We use various derivative instruments in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations and ensure cash flow for future capital needs. Such instruments may include variable to fixed price commodity swaps, two-way collars, and/or three-way collars. Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties. We net settle by counterparty based on netting provisions within the master agreements. None of our counterparty agreements contain margin requirements. Commodity derivative instruments are recorded at fair value in our consolidated balance sheets, and changes in fair value are recorded in earnings in the period in which the change occurs. As of June 30, 2014, the fair value of our commodity derivative assets was $2 million and the fair value of our commodity derivative liabilities was $288 million (after consideration of netting provisions within our master agreements). See Item 1. Financial Statements -Note 7. Fair Value Measurements and Disclosures for a description of the methods we use to estimate the fair values of commodity derivative instruments and Credit Risk, below. Credit Risk We monitor the creditworthiness of our trade creditors, joint venture partners, hedging counterparties, and financial institutions on an ongoing basis. Some of these entities are not as creditworthy as we are and may experience credit downgrades or liquidity problems. Counterparty credit downgrades or liquidity problems could result in a delay in our receiving proceeds from commodity sales, reimbursement of joint venture costs, and potential delays in our major development projects. We are unable to predict sudden changes in a party's creditworthiness or ability to perform. Even if we do accurately predict such sudden changes, our ability to negate these risks may be limited and we could incur significant financial losses. In addition, nonoperating partners often must obtain financing for their share of capital cost for development projects. A partner's inability to obtain financing could result in a delay of our joint development projects. For example, our Eastern Mediterranean partners must obtain financing for their share of significant development expenditures at Leviathan, offshore Israel, which potentially includes an LNG project and/or major underwater pipeline. 38



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Credit enhancements have been obtained from some parties in the form of parental guarantees, letters of credit or credit insurance; however, not all of our counterparty credit is protected through guarantees or credit support. Nonperformance by a trade creditor, joint venture partner, hedging counterparty or financial institution could result in significant financial losses. Contractual Obligations CONSOL Carried Cost Obligation The CONSOL Carried Cost Obligation represents our agreement to fund up to approximately $2.1 billion of CONSOL's future drilling and completion costs. The CONSOL Carried Cost Obligation is expected to extend over a multi-year period and is capped at $400 million in each calendar year. The obligation is suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any three consecutive month period and remain suspended until average Henry Hub natural gas prices are above $4.00 per MMBtu for three consecutive months. The carry terms ensure economic alignment with our partner in periods of low natural gas prices. Due to past low natural gas prices, the CONSOL Carried Cost Obligation was suspended from the end of 2011 to February 28, 2014. Due to recent increases in Henry Hub natural gas prices, we began funding a portion of CONSOL's working interest share of certain drilling and completion costs as of March 1, 2014. Based on the June 30, 2014, NYMEX Henry Hub natural gas price curve and current development plans, we forecast we will incur approximately $240 million under the CONSOL Carried Cost Obligation for 2014. The carry will be suspended again if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu in any future three consecutive month period. Marcellus Shale Firm Transportation Agreements In February 2014, we signed Precedent Agreements for Firm Transportation to move 150,000 MMBtu per day of our Marcellus Shale natural gas production to Gulf Coast markets. Our financial commitment is approximately $765 million, undiscounted, over a 15-year period, beginning in 2017. Cash Flows Cash flow information is as follows: Six Months Ended June 30, 2014 2013



(millions)

Total Cash Provided By (Used in) Operating Activities $ 1,757$ 1,244 Investing Activities (2,215 ) (1,835 ) Financing Activities 299 (90 )



Decrease in Cash and Cash Equivalents $ (159 )$ (681 )

Operating Activities Net cash provided by operating activities for the first six months of 2014 increased as compared with 2013. Higher crude oil and natural gas sales prices and an increase in crude oil and natural gas sales volumes were offset by increases in production expenses and general and administrative expense. Working capital changes contributed $105 million of positive operating cash flow in the first six months of 2014 as compared with a negative impact of $168 million in the first six months of 2013. Investing Activities Our investing activities include capital spending on a cash basis for oil and gas properties and investments in unconsolidated subsidiaries accounted for by the equity method. These investing activities may be offset by proceeds from property sales or dispositions, including farm-in arrangements, which may result in reimbursement for capital spending that had occurred in prior periods. Capital spending for property, plant and equipment increased by $392 million during the first six months of 2014 as compared with 2013, primarily due to increased major project development activity in our core areas. We also invested $40 million in CONE Gathering LLC (CONE), discussed below, during the first six months of 2014. We received $146 million in proceeds from non-core asset divestitures during the first six months of 2014, as compared with $114 million during the same period in 2013. Financing Activities Our financing activities include the issuance or repurchase of our common stock, payment of cash dividends on our common stock, the borrowing of cash and the repayment of borrowings. During the first six months of 2014, funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($58 million) and net cash proceeds from our Credit Facility ($600 million). We used cash to pay dividends on our common stock ($116 million), to repay Senior Notes that were due April 15, 2014 ($200 million), make principal payments related to capital lease obligations ($28 million) and repurchase shares of our common stock ($15 million). In comparison, during the first six months of 2013, funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($43 million). We also used cash to pay dividends on our common stock ($96 million), make 39



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principal payments related to the Aseng FPSO capital lease obligation ($23 million) and repurchase shares of our common stock ($14 million).

See Item 1. Financial Statements - Consolidated Statements of Cash Flows . Investing Activities Acquisition, Capital and Exploration Expenditures Information for investing activities (on an accrual basis) is as follows: Three Months Ended Six Months Ended June 30, June 30, 2014 2013 2014 2013 (millions) Acquisition, Capital and Exploration Expenditures Unproved Property Acquisition (1) $ 74$ 97$ 129$ 134 Exploration 138 197 228 385 Development (2) 989 749 1,736 1,374 Corporate and Other 43 89 90 124 Total $ 1,244$ 1,132$ 2,183$ 2,017 Other



Investment in Equity Method Investee (3) $ 28$ 3$ 40$ 23 Increase in Capital Lease Obligations

16 31 21 36



(1) Unproved property acquisition cost for 2014 includes $37 million in the DJ

Basin, $75 million in the Marcellus Shale, and $16 million in the deepwater

Gulf of Mexico. Unproved property acquisition cost for 2013 includes $73

million in the DJ Basin, $47 million in the Marcellus Shale, and $12 million

in the deepwater Gulf of Mexico.

(2) Development expenditures for 2014 include drilling rig mobilization charges

of $55 million, a portion of which will be billed to partners in future

periods as the rig is utilized.

(3) Investment in equity method investees represents funding of our investment

in CONE which owns and operates the natural gas gathering infrastructure

associated with our Marcellus Shale joint venture.

Total expenditures increased in 2014 as compared with 2013 due to accelerated activity in the DJ Basin and Marcellus Shale. Financing Activities Long-Term Debt Our principal source of liquidity is our Credit Facility that matures October 3, 2018. At June 30, 2014, $600 million was outstanding under the Credit Facility, leaving $3.4 billion available for use. We expect to use the Credit Facility to fund our capital investment program, and may periodically borrow amounts for working capital purposes. See Item 1 Financial Statements - Note 6. Debt. Our outstanding fixed-rate debt (excluding capital lease and other obligations) totaled approximately $4.3 billion at June 30, 2014. The weighted average interest rate on fixed-rate debt was 6.09%, with maturities ranging from March 2019 to August 2097. On April 15, 2014, we repaid $200 million of matured fixed rate debt. Dividends We paid total cash dividends of 32 cents per share of our common stock during the first six months of 2014 and 27 cents per share during the first six months of 2013 (as adjusted for the 2-for-1 stock split during the second quarter of 2013). On July 22, 2014, the Board of Directors declared a quarterly cash dividend of 18 cents per common share, which will be paid August 18, 2014 to shareholders of record on August 4, 2014. The amount of future dividends will be determined on a quarterly basis at the discretion of our Board of Directors and will depend on earnings, financial condition, capital requirements and other factors. Exercise of Stock Options We received cash proceeds from the exercise of stock options of $41 million during the first six months of 2014 and $31 million during the first six months of 2013. Common Stock Repurchases We receive shares of common stock from employees for the payment of withholding taxes due on the vesting of restricted shares issued under stock-based compensation plans. We received 250,013 shares with a value of $15 million during the first six months of 2014 and 247,985 shares with a value of $14 million during the first six months of 2013. 40



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