News Column

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

April 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 producer of crude oil and natural gas. 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 exploratory activities in domestic and international locations such as Northeast Nevada, the Falkland Islands, Cameroon, and Cyprus. Our financial results for first quarter 2014 included: net income of $200 million as compared with $261 million for first quarter 2013; loss on commodity derivative instruments of $75 million (including $42



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

derivative instruments of $72 million (including $79 million non-cash

portion of loss) for first quarter 2013; asset impairment charges of $97 million, as compared with zero for first quarter 2013; diluted earnings per share of $0.55, as compared with $0.72 for first quarter 2013;



cash flow provided by operating activities of $929 million, as compared

with $705 million for first quarter 2013; ending cash balance of $1.4 billion, as compared with $1.1 billion at December 31, 2013;



capital spending, on a cash basis, of $1.2 billion, as compared with $806

million for first quarter 2013;

total liquidity of $4.9 billion at March 31, 2014, as compared with $5.1

billion at December 31, 2013; and

ratio of debt-to-book capital of 36% at March 31, 2014, as compared with

35% at December 31, 2013.

Our operating results for first quarter 2014 included: total sales volumes of 286 MBoe/d, as compared with 246 MBoe/d for the

first quarter of 2013;



delivered record horizontal production of 100 MBoe/d on average from the

DJ Basin and Marcellus Shale plays, up over 60% versus first quarter 2013; performed completion operations on initial vertical well in the Wilson



play of Northeast Nevada, successfully recovering oil from multiple

intervals;

apparent high bidder on 12 deepwater lease blocks in the central Gulf of

Mexico Lease Sale 231; signed first two regional export sales agreements for natural gas sales from Tamar and Leviathan to customers in Jordan and Palestine;



finalized agreement with the Israel Antitrust Authority; and

executed sales agreements to divest of our non-core Haynesville and Powder

River Basin assets onshore US.

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 March 31, 2014 ( See Item 1. Financial Statements - Note 8. Capitalized Exploratory Well Costs), and expect to continue an active exploratory drilling program in the future. 21



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A significant 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 evaluating drilling and completion results from our first exploratory vertical wells. We plan to begin flow testing the first well in second quarter 2014 and drill additional exploratory wells later in 2014. Deepwater Gulf of Mexico During first quarter 2014, we participated in the central Gulf of Mexico Lease Sale 231 and were apparent high bidder on 12 deepwater blocks, providing further opportunities to expand our exploration portfolio. In late March 2014, we spud the Katmai exploration well (Green Canyon Block 40, 50% operated working interest). Also during the quarter, the new Atwood Advantage drillship successfully mobilized to the Gulf of Mexico where it is undergoing readiness activities for our 2014 drilling plan. Offshore West Africa We plan to shoot 3D seismic tests across Blocks O and I, offshore Equatorial Guinea, during the second half of 2014, and 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 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. 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. During the quarter, we spud 54 standard length lateral wells and 13 extended reach lateral wells, and recently increased our 2014 drilling program to include 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 and progress the Allegheny County Airport areas. During the quarter, we and our partner drilled 36 wells, and 11 wells initiated production. The joint venture is currently operating nine drilling rigs. 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. 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. During first quarter 2014, using the Ensco 8501 drilling rig, we conducted well completion activities, and 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. 22



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Tamar Southwest (Offshore Israel) We anticipate first production in the second half of 2015 utilizing Tamar infrastructure as part of our expansion project to meet domestic demand. We also expect Tamar Southwest to provide flow rate assurance for the overall Tamar project. Unsanctioned Development Projects (As of March 31, 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. We plan to drill another Dantzler appraisal well later in the year. Leviathan (Offshore Israel) We continue to make progress towards sanctioning the first phase of Leviathan development. In February 2014, we signed a non-binding memorandum of understanding (MOU) regarding the sale of an interest in the Leviathan licenses to Woodside Petroleum (Woodside). All the existing Leviathan partners are participating as sellers of a 25% interest to Woodside. We agreed to convey a 9.66% working interest and will continue as upstream operator with a 30% working interest. We and our existing Leviathan partners continue to work with Woodside to close a definitive agreement. Following completion of the transaction, Woodside will become operator of any LNG development of the field. Total compensation to us is anticipated to include $525 million in cash payments as follows: an initial cash payment of $390 million payable at closing of the transaction, which is expected later in 2014; and



a second cash payment of $135 million which is due when a final investment

decision is made in relation to an LNG or FLNG development program or as

regional export contracts are executed in excess of a threshold volume

amount, whichever occurs earlier.

In addition, the MOU provides for Woodside to share a portion of certain of their future revenues, subject to caps, if specified events were to occur, including: reaching a certain level of natural gas export, an increase in ultimate recoverable resources (as defined), or a commercial crude oil discovery and subsequent development. The MOU includes the agreed-upon commercial terms of the farm-out transaction. The transaction remains subject to the execution of definitive agreements between the parties, as well as necessary and customary regulatory approvals. In March 2014, the Israeli government converted the Leviathan licenses to Production and Development Leases (Leases). The Leases provide for, among other things: 30-year terms, from February14, 2014 until February 13, 2044;



the right to develop the project giving priority to the domestic natural

gas market and requiring a connection to the domestic natural gas transmission system prior to export; and



targeted milestones for development, subject to timing of regulatory and

permitting requirements, natural gas sales agreements and financing.

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 exploration or appraisal well to further determine the ultimate recoverable resources on Block 12 and optimize field development planning. In addition, we have filed an application for renewal of the production sharing contract for two additional years. Diega and Carla (Offshore Equatorial Guinea) We are currently evaluating regional development scenarios and targeting to sanction a Diega development project in 2014, with first production targeted for early 2017. See Item 1. Financial Statements - Note 8. Capitalized Exploratory Well Costs for additional information on costs incurred related to these projects. Non-Core Divestiture Program Our non-core asset divestiture program is winding down with certain smaller onshore US property packages sold during first quarter 2014 or expected to be sold this year. We are also in the process of negotiating a sale of our China assets. Divestitures of non-core properties allow us to allocate capital and employee 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 Argentina, Ecuador, and certain North Sea jurisdictions. 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. 23



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Update on Israel's Natural Gas Economy Israel Antitrust Authority We and our partners recently 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 March 31, 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 to regulate the method of taxing petroleum export transactions, and, in particular, exports of natural gas. As a part of the Ministry's final 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. 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. In 2013, several communities in Colorado passed ballot measures supporting restrictions or bans on the practice of hydraulic fracturing within their boundaries. The large majority of our DJ Basin acreage is not located in these municipalities and, therefore, we do not expect our operations to be impacted by these specific developments. In advance of the upcoming November 2014 state-wide elections, three general types of ballot initiatives have now emerged in Colorado. They can be characterized as: initiatives relating to local government control;



initiatives relating to mandatory statewide drilling setbacks; and

initiatives relating to constitutional duties to protect the environment.

Should these, or other, Colorado ballot initiatives succeed in regulating, limiting or banning hydraulic fracturing or other facets of oil and gas exploration, development or operations, our business could be impacted resulting in delay or inability to develop certain oil and gas reserves, reducing our long-term reserves, production and cash flow growth, and have a potential negative impact on our stock price. In Nevada, the State Assembly recently adopted legislation that requires the development of a program to regulate the use of hydraulic fracturing in Nevada. State regulators are in the process of proposing rules and holding public hearings. We will continue to monitor new and proposed legislation and regulations to assess the potential impact on our operations. We are currently evaluating the possible impact any proposed rules, such as those described above, could have on our business. Any additional federal, state or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could result in substantial incremental operating, capital and compliance costs as well as delay our ability to develop oil and gas reserves. 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 oil and natural gas development. 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 EPA'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 24



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developments. On a BOE basis, total sales volumes were 16% higher for the first quarter of 2014 as compared with the first quarter of 2013, and our mix of sales volumes was 45% global liquids, 27% international natural gas, and 28% US natural gas. See Results of Operations - Revenues, below. Commodity Price Changes Average realized natural gas prices increased 45% in the US and 9% in Israel for first quarter 2014 as compared with the first quarter of 2013. Average realized crude oil prices remained relatively unchanged in the US, and decreased 5% for Equatorial Guinea. 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, non-core onshore US

areas, and the Alba and Aseng fields offshore Equatorial Guinea; and potential weather-related volume curtailments due to hurricanes in the deepwater Gulf of Mexico or flooding in the DJ Basin, Marcellus Shale and/or Rocky Mountain areas, which can shut-in or reduce production or result in the use of produced natural gas to fuel burners. 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 additional drilling activities, that the Scotia prospect is not economically viable, the costs we have incurred (approximately $72 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 based on regulations in effect prior to the Deepwater Gulf of Mexico Moratorium, is set to expire on July 31, 2014. We intend to request an extension of this lease; however, 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 March 31, 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. 25



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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 is currently shut-in due to mechanical issues. We are preparing for remediation work to commence in second quarter 2014 and expect return to production by 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 $121 million at March 31, 2014. In addition, well decommissioning programs, especially in deepwater or remote locations, are often complex and very 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 high demand. Therefore, our ARO estimates may change, sometimes significantly, and could result in asset impairment. For example, in the first quarter of 2014, the ARO estimate for one of our remaining non-operated North Sea fields changed significantly, resulting in asset impairment charges of $92 million. Divestments We are currently marketing certain non-core onshore US properties. 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. Goodwill write-offs result in an increase in our effective tax rate because goodwill is nondeductible for US federal income tax purposes. In addition, certain assets offshore Israel and offshore China are classified held for sale at March 31, 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. RESULTS OF OPERATIONS In the discussion below, the North Sea geographical segment is reflected as discontinued operations for the first three 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 first quarter 2014. See Item 1. Financial Statements - Note 2. Basis of Presentation,



Note 3. Divestitures, Note 4. Asset Impairments and Note 7. Fair Value Measurements and Disclosures. See also Discontinued Operations, below.

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Table of Contents Revenues Revenues were as follows: Increase/(Decrease) (millions) 2014 2013 from Prior Year Three Months Ended March 31, Oil, Gas and NGL Sales $ 1,327$ 1,083 23 % Income from Equity Method Investees 52 60 (13 )% Total $ 1,379$ 1,143 21 % Changes in revenues are discussed below. 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 March 31, 2014 United States 64 483 18 163 $ 97.02$ 4.81$ 44.50 Equatorial Guinea (2) 34 242 - 74 105.73 0.27 - Israel - 218 - 37 - 5.60 - Other International (3) 5 - - 5 104.28 - - Total Consolidated Operations 103 943 18 279 100.23 3.83 44.50 Equity Investees (4) 2 - 5 7 104.71 - 74.51 Total Continuing Operations 105 943 23 286 $ 100.30$ 3.83$ 51.54 Three Months Ended March 31, 2013 United States 63 409 16 146 $ 95.70$ 3.31$ 39.19 Equatorial Guinea (2) 27 246 - 68 111.79 0.27 - Israel - 111 - 19 - 5.15 - Other International (3) 4 - - 4 109.22 - - Total Consolidated Operations 94 766 16 237 100.90 2.60 39.19 Equity Investees (4) 2 - 6 8 108.63 - 74.19 Total Continuing Operations 96 766 22 245 $ 101.07$ 2.60$ 49.29



(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. (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 primarily includes China. (4) Volumes represent sales of condensate and LPG from the Alba plant in Equatorial Guinea. See Income from Equity Method Investees, below. 27



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An analysis of revenues from sales of crude oil, natural gas and NGLs is as follows: Sales Revenues Crude Oil & Natural (millions) Condensate Gas NGLs Total Three Months Ended March 31, 2013 $ 849 $ 179$ 55$ 1,083 Changes due to Increase in Sales Volumes 85 41 11 137 Increase (Decrease) in Sales Prices (6 ) 105 8 107



Three Months Ended March 31, 2014 $ 928 $ 325$ 74$ 1,327

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



drilling program; and

additional sales volumes of 12 MBoe/d from the Alen condensate project,

offshore Equatorial Guinea, which began producing in late second quarter

2013;



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

upgrades in the DJ Basin;

lower sales volumes from the Galapagos project, deepwater Gulf of Mexico,

and Aseng project, offshore Equatorial Guinea, due to natural production

declines; and

decreases in total consolidated average realized price related to sales

volumes offshore Equatorial Guinea, which are priced based on the global

Brent market.

Natural Gas Sales - Revenues from natural gas sales increased during the first quarter of 2014 as compared with 2013 due to the following: increases in total consolidated average realized prices of 47% primarily

due to increased demand from cooler weather and higher-than-expected inventory withdrawals in the US; higher sales volumes in the Marcellus Shale of 206 MMcf/d for first quarter 2014, as compared with 100 MMcf/d for first quarter of 2013,



primarily attributable to our horizontal drilling program and continued

ramp-up of activity; and additional sales volumes offshore Israel due to start up of the Tamar natural gas field, which began producing at the end of first quarter 2013;



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

2013 and first quarter 2014; and lower sales volumes due to natural field decline from the Mari B/Noa/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 first quarter 2014 as compared with 2013, primarily due to increased production from the wet gas acreage. NGL sales in the DJ Basin increased by 1 MBbl/d during the first 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 first quarter 2013. Additionally, sales prices have increased 14% for the first three months of 2014, compared to the first three 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. 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. 28



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Operating Costs and Expenses Operating costs and expenses were as follows: Increase (millions) 2014 2013 from Prior Year Three Months Ended March 31, Production Expense $ 232$ 187 24 % Exploration Expense 74 61 21 % Depreciation, Depletion and Amortization 425 366 16 % General and Administrative 140 112 25 % Asset Impairments 97 - - Other Operating (Income) Expense, Net 7 (8 ) N/M Total $ 975$ 718 36 %



N/M - Amount is not meaningful Changes in operating costs and expenses are discussed below. Production Expense Components of production expense were as follows:

Total per United Other Int'l, (millions, except unit rate) BOE (1) Total States



Equatorial GuineaIsrael Corporate Three Months Ended March 31, 2014 Lease Operating Expense (2) $ 5.79$ 145$ 88

$ 31 $ 12 $ 14 Production and Ad Valorem Taxes 1.96 49 40 - - 9 Transportation and Gathering Expense 1.52 38 37 - - 1 Total Production Expense $ 9.27$ 232$ 165 $ 31 $ 12 $ 24 Three Months Ended March 31, 2013 Lease Operating Expense (2) $ 5.49$ 117$ 89 $ 20 $ 1 $ 7 Production and Ad Valorem Taxes 2.02 43 34 - - 9 Transportation and Gathering Expense 1.30 27 27 - - - Total Production Expense $ 8.81$ 187$ 150 $ 20 $ 1 $ 16



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

equity method investees.

(2) 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 first quarter of 2014, total production expense increased as compared with 2013 due to the following: an increase in lease operating expense of approximately $10 million in the



DJ Basin due to workovers, labor charges and other cost allocations;

an increase in lease operating expense of $11 million offshore Equatorial

Guinea primarily due to the start up of the Alen field in the second half of 2013;



an increase in lease operating expense of $11 million offshore Israel

primarily due to the start up of the Tamar field, which began producing at

the end of first quarter 2013;

an increase in production and ad valorem taxes of approximately $7 million

in the DJ Basin due to higher production volumes and higher average prices; and



an increase in transportation and gathering expense of approximately $8

million in the Marcellus Shale due to increased production from ongoing

development activities;

partially offset by: a decrease in lease operating expense of approximately $2 million from sales of non-core US onshore properties in 2013; and



a decrease of approximately $6 million in the deepwater Gulf of Mexico

primarily due to lower throughput fees as we recently acquired the Neptune

spar to process our remaining Swordfish production. 29



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Exploration Expense Components of exploration expense were as follows:

Eastern West Mediter- Other Int'l, (millions) Total United States Africa (1) ranean (2) Corporate (3) Three Months Ended March 31, 2014 Dry Hole Cost $ 2 $ 3 $ - $ - $ (1 ) Seismic 23 7 - 1 15 Staff Expense 35 8 2 3 22 Other 14 14 - - - Total Exploration Expense $ 74 $ 32 $ 2 $ 4 $ 36 Three Months Ended March 31, 2013 Dry Hole Cost $ - $ - $ - $ - $ - Seismic 25 6 - - 19 Staff Expense 28 7 1 3 17 Other 8 9 - - (1 ) Total Exploration Expense $ 61 $ 22 $ 1 $ 3 $ 35 (1) West Africa includes Equatorial Guinea, Cameroon, and Sierra Leone. (2) Eastern Mediterranean includes Israel and Cyprus. (3) Other International includes various international new ventures such as Falkland Islands and Nicaragua.



Exploration expense for the first quarter of 2014 included: $12 million of seismic expense in the Falkland Islands; and

staff expense associated with new ventures and corporate expenditures.

Exploration expense for the first quarter of 2013 included the following: $17 million of 3D seismic 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 March 31, 2014 2013 DD&A Expense (millions) (1) $ 425$ 366 Unit Rate per BOE (2) $ 16.95$ 17.18



(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.

Total DD&A expense for the first quarter of 2014 increased as compared with 2013 due to the following: increases of $19 million in the DJ Basin and $14 million in the Marcellus



Shale due to higher sales volumes associated with increased development

activity; an increase of $9 million in the deepwater Gulf of Mexico due to a new well producing at Ticonderoga and the addition of the Neptune spar at Swordfish;



an increase of $22 million offshore Equatorial Guinea primarily due to the

start up of the Alen field in the second half of 2013; and

an increase of approximately $12 million related to the start up of the

Tamar field, offshore Israel, at the end of first quarter 2013;

partially offset by: a decrease of $7 million due to sales of non-core US onshore properties in

2013; and a decrease of approximately $27 million related to the Mari-B/Noa/Pinnacles fields due to natural field decline. The reduction in the unit rate per BOE for first quarter 2014 as compared with 2013 was due primarily to lower cost volumes produced at Tamar, offshore Israel, which replaced higher cost volumes produced from the Mari-B/Noa/Pinnacles fields. In addition, the effect of higher costs incurred in the DJ Basin and Marcellus Shale were offset by the effect of a higher volume of proved reserves being recorded at year-end 2013 as compared with year-end 2012. 30



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General and Administrative Expense General and administrative expense (G&A) was as follows: Three Months Ended March 31, 2014 2013 G&A Expense (millions) $ 140$ 112 Unit Rate per BOE (1) $ 5.57$ 5.28



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

equity method investees.

G&A expense for the first quarter of 2014 increased as compared with 2013 primarily due to additional expenses relating to personnel, office, and information technology costs in support of our major development projects and increased exploration activities. For example, our total number of employees increased 15%, from 2,190 at December 31, 2012, to 2,527 at December 31, 2013.



Asset Impairment Expense Asset impairment expense was as follows:

Three Months Ended March 31, (millions) 2014 2013 Asset Impairments $ 97 $ - Asset impairment expense related primarily to one of our remaining non-operated North Sea fields. 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 March 31, (millions) 2014 2013 Loss on Commodity Derivative Instruments $ 75$ 72 Interest, Net of Amount Capitalized 47 25 Other Non-Operating (Income) Expense, Net 5 10 Total $ 127$ 107 Loss on Commodity Derivative Instruments 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 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 HH commodities. See Item 1. Financial Statements - Note 5. Derivative Instruments and Hedging Activities and Note



7. Fair Value Measurements and Disclosures. Interest Expense and Capitalized Interest Interest expense and capitalized interest were as follows:

Three Months Ended March 31, 2014 2013 (millions, except unit rate) Interest Expense, Gross $ 81$ 67 Capitalized Interest (34 ) (42 ) Interest Expense, Net $ 47$ 25 Unit Rate per BOE (1) $ 1.89$ 1.19 (1) Consolidated unit rates exclude sales volumes and expenses attributable to equity method investees. The increase in interest expense, gross, is due to an increase in new senior debt issued in November 2013 and recent borrowings under the Credit Facility. 31



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The decrease in capitalized interest is primarily due to the completion of major projects, such as Alen, offshore West Africa, and Tamar, offshore Israel, 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 first quarter of 2014 as compared with 2013. Discontinued Operations Summarized results of discontinued operations were as follows: Three Months Ended March 31, 2013 (millions) Oil and Gas Sales $ 10 Expenses 11 Income Before Income Taxes (1 ) Income Tax Expense 7 Operating Loss, Net of Tax (8 ) Gain on Sale, Net of Tax 37 Income From Discontinued Operations $ 29 Key Statistics: Daily Production Crude Oil & Condensate (MBbl/d) 1 Natural Gas (MMcf/d) 3



Average Realized Price Crude Oil & Condensate (Per Bbl) $ 113.97 Natural Gas (Per Mcf)

10.03 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. 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 32



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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 March 31, 2014 totaled $1.4 billion, 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 we would not incur additional US tax. During first quarter 2014, we repatriated $62 million from our UK operations. During April 2014, we repatriated an additional $110 million from our UK operations. We incurred no residual 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 and our Leviathan partners have announced a potential strategic partner for Leviathan, Woodside, who could provide midstream expertise as well as LNG project execution, marketplace expertise and financial capacity. 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. We expect to liquidate the associated pension obligation through lump-sum payments to participants. In addition, we amended our restoration plan effective December 31, 2013 to freeze the accrual of benefits under the plan in coordination with the termination of our defined benefit pension plan so that no additional benefits will accrue under the restoration plan after December 31, 2013. Benefits accrued under the restoration plan as of that date will be frozen, and payments under the restoration plan will continue to be made in ordinary course without acceleration of payment. Participants in the restoration plan who remain employed by us upon final liquidation and distribution of assets of the defined benefit 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. As of December 31, 2013, the latest actuarial measurement date for the plans, the accumulated benefit obligations for the defined benefit pension and restoration plans totaled approximately $394 million, and the fair value of plan assets was $265 million, leaving approximately $129 million unfunded. At March 31, 2014, we reclassified the long-term portion of the net pension plan liability ($50 million) 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 plans during the period leading up to final termination and distribution to the extent necessary to fund these obligations. In addition, upon pension and restoration plan termination, all unamortized prior service cost and net actuarial loss remaining in AOCL will be charged to expense. These amounts totaled approximately $101 million for the pension plan and $38 million for the restoration plan at March 31, 2014. 33



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Table of Contents Available Liquidity Information regarding cash and debt balances is as follows: March 31, December 31, 2014 2013 (millions, except percentages) Cash and Cash Equivalents $ 1,354$ 1,117 Amount Available to be Borrowed Under Credit Facility (1) 3,550 4,000 Total Liquidity $ 4,904$ 5,117 Total Debt (2) $ 5,285$ 4,843 Total Shareholders' Equity 9,361 9,184 Ratio of Debt-to-Book Capital (3) 36 % 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 $1.4 billion in cash and cash equivalents at March 31, 2014, primarily denominated in US dollars and invested in money market funds and short-term deposits with major financial institutions. Approximately $1.0 billion 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 March 31, 2014, we had drawn $450 million under the Credit Facility at an interest rate of 1.43%. 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 March 31, 2014, the fair value of our commodity derivative assets was $11 million and the fair value of our commodity derivative liabilities was $111 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. We are considering assisting our current Leviathan partners, under certain conditions, to obtain appropriate financing for their share of development costs. 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. 34



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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 March 31, 2014, NYMEX Henry Hub natural gas price curve and current development plans, we forecast funding approximately $235 million in 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: Three Months Ended March 31, 2014 2013



(millions)

Total Cash Provided By (Used in) Operating Activities $ 929$ 705 Investing Activities (1,078 ) (748 ) Financing Activities 386 (39 )



Increase (Decrease) in Cash and Cash Equivalents $ 237$ (82 )

Operating Activities Net cash provided by operating activities for the first three months of 2014 increased as compared with 2013. Higher natural gas sales prices and an increase in crude oil and natural gas sales volumes were offset by slightly lower crude oil sales prices and increases in production expenses and general and administrative expense. Working capital changes contributed $126 million of positive operating cash flow in first quarter 2014 as compared with a negative impact of $9 million in first quarter 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 $352 million during the first three months of 2014 as compared with 2013, primarily due to increased major project development activity in our core areas. We also invested $12 million in CONE Gathering LLC (CONE), discussed below, during the first three months of 2014. We received $92 million proceeds from non-core asset divestitures first quarter 2014, as compared with $76 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 three months of 2014, funds were provided by cash proceeds from, and tax benefits related to the exercise of stock options ($16 million) and net cash proceeds from our Credit Facility ($450 million). We used cash to pay dividends on our common stock ($50 million), make principal payments related to capital lease obligations ($15 million) and repurchase shares of our common stock ($15 million). In comparison, during the first three months of 2013, funds were provided by cash proceeds from, and tax benefits related to, the exercise of stock options ($31 million). We also used cash to pay dividends on our common stock ($44 million), make principal payments related to the Aseng FPSO capital lease obligation ($12 million) and repurchase shares of our common stock ($14 million).



See Item 1. Financial Statements - Consolidated Statements of Cash Flows .

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Investing Activities Acquisition, Capital and Exploration Expenditures Information for investing activities (on an accrual basis) is as follows: Three Months Ended March 31, 2014 2013 (millions) Acquisition, Capital and Exploration Expenditures Unproved Property Acquisition (1) $ 55$ 37 Exploration 90 188 Development (2) 747 630 Corporate and Other 47 35 Total $ 939$ 890 Other Investment in Equity Method Investee (3) $ 12 $



20

Increase in Capital Lease Obligations 5 -



(1) Unproved property acquisition cost for 2014 includes $20 million in the DJ

Basin and $35 million in the Marcellus Shale. Unproved property acquisition

cost for 2013 includes $27 million in the DJ Basin and $9 million in the Marcellus Shale.



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

of $45 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 March 31, 2014, we had $450 million outstanding under the Credit Facility, leaving almost $3.6 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 $4.5 billion at March 31, 2014. The weighted average interest rate on fixed-rate debt was 4.88%, with maturities ranging from April 2014 to August 2097. On April 15, 2014, we repaid $200 million of matured fixed rate debt. Dividends We paid total cash dividends of 14 cents per share of our common stock during the first three months of 2014 and 12.5 cents per share during the first three months of 2013 (as adjusted for the 2-for-1 stock split during the second quarter of 2013). On April 21, 2014, the Board of Directors increased the quarterly cash dividend to 18 cents per common share, which will be paid May 19, 2014 to shareholders of record on May 5, 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 $10 million during the first three months of 2014 and $22 million during the first three 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 247,674 shares with a value of $15 million during the first three months of 2014 and 245,660 shares with a value of $14 million during the first three months of 2013. Item 3. Quantitative and Qualitative Disclosures About Market Risk Commodity Price Risk Derivative Instruments Held for Non-Trading Purposes We are exposed to market risk in the normal course of business operations, and the volatility of crude oil and natural gas prices continues to impact the oil and gas industry. Due to the volatility of crude oil and natural gas prices, we continue to use derivative instruments as a means of managing our exposure to price changes. 36



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At March 31, 2014, we had entered into variable to fixed price commodity swaps and three-way collars related to crude oil and natural gas sales. Changes in fair value of commodity derivative instruments are reported in earnings in the period in which they occur. Our open commodity derivative instruments were in a net liability position with a fair value of $100 million. Based on the March 31, 2014 published commodity futures price curves for the underlying commodities, a hypothetical price increase of $1.00 per Bbl for crude oil would increase the fair value of our net commodity derivative liability by approximately $38 million. A hypothetical price increase of $0.10 per MMBtu for natural gas would increase the fair value of our net commodity derivative liability by approximately $10 million. Our derivative instruments are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net cash settled at the time of election. See Item 1. Financial Statements - Note 5. Derivative Instruments and Hedging Activities. Interest Rate Risk Changes in interest rates affect the amount of interest we pay on borrowings under our Credit Facility and the amount of interest we earn on our short-term investments. At March 31, 2014, we had approximately $4.9 billion (excluding capital lease and other obligations) of long-term debt outstanding. Of this amount, $4.5 billion was fixed-rate debt with a weighted average interest rate of 4.88%. Although near term changes in interest rates may affect the fair value of our fixed-rate debt, they do not expose us to the risk of earnings or cash flow loss. The remainder of our long-term debt, $450 million at March 31, 2014, was variable-rate debt. Variable-rate debt exposes us to the risk of earnings or cash flow loss due to increases in market interest rates. We estimate that a hypothetical 25 basis point change in the floating interest rates applicable to the March 31, 2014 balance of our variable-rate debt would result in a change in annual interest expense of approximately $1 million. We are also exposed to interest rate risk related to our interest-bearing cash and cash equivalents balances. As of March 31, 2014, our cash and cash equivalents totaled approximately $1.4 billion, approximately 52% of which was invested in money market funds and short-term investments with major financial institutions. A hypothetical 25 basis point change in the floating interest rates applicable to the amount invested as of March 31, 2014 would result in a change in annual interest income of approximately $2 million. Foreign Currency Risk The US dollar is considered the functional currency for each of our international operations. Substantially all of our international crude oil, natural gas and NGL production is sold pursuant to US dollar denominated contracts. Transactions, such as operating costs and administrative expenses that are paid in a foreign currency, are remeasured into US dollars and recorded in the financial statements at prevailing currency exchange rates. Certain monetary assets and liabilities, such as taxes payable in foreign tax jurisdictions, are settled in the foreign local currency. A reduction in the value of the US dollar against currencies of other countries in which we have material operations could result in the use of additional cash to settle operating, administrative, and tax liabilities. Net transaction gains and losses were de minimis for the first quarters of both 2014 and 2013. We currently have no foreign currency derivative instruments outstanding. However, we may enter into foreign currency derivative instruments (such as forward contracts, costless collars or swap agreements) in the future if we determine that it is necessary to invest in such instruments in order to mitigate our foreign currency exchange risk. Disclosure Regarding Forward-Looking Statements This quarterly report on Form 10-Q contains forward-looking statements within the meaning of the federal securities laws. Forward-looking statements give our current expectations or forecasts of future events. These forward-looking statements include, among others, the following: our growth strategies;



our ability to successfully and economically explore for and develop crude

oil and natural gas resources;

anticipated trends in our business;

our future results of operations;

our liquidity and ability to finance our exploration and development

activities;

market conditions in the oil and gas industry;

our ability to make and integrate acquisitions;

the impact of governmental fiscal terms and/or regulation, such as those

involving the protection of the environment or marketing of production, as

well as other regulations; and

access to resources. 37



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Forward-looking statements are typically identified by use of terms such as "may," "will," "expect," "believe," "anticipate," "estimate," "intend," and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon our current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 2013, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements. Our Annual Report on Form 10-K for the year ended December 31, 2013 is available on our website at www.nobleenergyinc.com.


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