SEC Form 10-K Filing Report

Company: NEWFIELD EXPLORATION CO /DE/
CIK: 912750
SIC Code: 1311
Filing Date: 2015-02-24 00:00:00
Market Capitalization: 4346042.440469742

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ITEM 1. BUSINESS

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ITEM 1A. RISK FACTORS
Item 1A. Risk Factors
There are many factors that may affect Newfield’s business and results of operations. Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. You should carefully consider, in addition to the other information contained in this report, the risks described below.
Oil, gas and NGL prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse impact on our business. Our revenues, profitability and future growth, as well as liquidity and ability to access additional sources of capital, depend substantially on prevailing prices for oil, gas and NGLs. Sustained lower prices will reduce the amount of oil, natural gas and NGLs that we can economically produce. Oil, natural gas and NGL prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital.
The markets for oil, gas and NGLs have historically been, and will likely remain, volatile. For example, record high U.S. crude oil production has contributed to global oil supply exceeding demand, which has caused crude oil prices to drop precipitously since September 2014. The price of crude oil (WTI) in January 2015 averaged approximately $47 per barrel, as compared to approximately $95 per barrel in January 2014. Natural gas prices also experienced significant volatility during 2014, as the NYMEX Henry Hub natural gas price ranged from a high of $6.15 per MMBtu (the highest price since December 2008) to a low of $2.89 per MMBtu (on the last trading day of the year).
The market prices for crude oil, natural gas and NGLs depend on factors beyond our control. Among the factors that can cause fluctuations are:
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the domestic and foreign supply of, and demand for, oil, natural gas and NGLs;
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world-wide economic conditions;
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the level and effect of trading in commodity futures markets, including commodity price speculators and others;
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political conditions in oil and gas producing regions;
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the actions taken by foreign oil and gas producing nations;
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the actions taken by the Organization of Petroleum Exporting Countries;
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the price and availability of, and demand for, alternative fuels;
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weather conditions and climate change;
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world-wide conservation measures;
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technological advances affecting energy consumption;
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the price and level of foreign imports;
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potential U.S. exports of oil and/or NGLs;
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the availability, proximity and capacity of transportation and processing facilities;
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the costs of exploring for, developing, producing, transporting and marketing oil, gas and NGLs; and
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the nature and extent of domestic and foreign governmental regulations and taxation, including environmental regulation.
While we cannot predict whether or for how long commodity prices will remain at this level or decline further, we have made adjustments in response to the current strong supply and soft demand, such as modifying our 2015 capital investment plan based on commodity prices, drilling success, and markets for our products. These adjustments are likely to influence our profitability and could adversely affect our business, financial condition and results of operations. In addition, our stock price in the market is influenced by oil and gas price movements.
Sustained material declines in crude oil, natural gas or NGL prices may have the following effects on our business:
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limit our access to sources of capital, such as equity and long-term debt;
•cause us to delay or postpone capital projects;
•cause us to lose certain leases because we fail to develop the leases prior to expiration;
•reduce reserves and the amount of products we can economically produce;
•reduce revenues, income and cash flows; or
•reduce the carrying value of our assets in our balance sheet through ceiling test impairments.
We have substantial capital requirements to fund our business plans that could be greater than cash flows from operations. Limited liquidity would likely negatively impact our ability to execute our business plan. We anticipate that our 2015 capital investment levels will approximate our cash flows from operations (inclusive of realized derivative contract gains and losses). We expect to use available capacity under our credit arrangements to fund any shortfall. Our ability to generate operating cash flows is subject to many risks and variables, such as the level of production from existing wells; prices of natural gas, oil and NGLs; our success in developing and producing new reserves and the other risk factors discussed herein. Actual levels of capital expenditures may vary significantly due to many factors including drilling results, commodity prices, industry conditions, the prices and availability of goods and services, the extent to which properties are acquired and the promulgation of new regulatory requirements. In addition, in the past, we often have increased our capital budget during the year as a result of acquisitions or successful drilling. We may have to reduce capital expenditures, and our ability to execute our business plans could be adversely affected, if:
•we are unable to access the capital markets at a time when we would like, or need, to raise capital;
•one or more of the lenders under our existing credit arrangements fails to honor its contractual obligation to lend to us;
•investors limit funding or refrain from funding fossil fuel companies;
•our customers or working interest owners default on their obligations to us; or
•we are unable to sell non-strategic assets at acceptable prices due to low commodity prices.
Actual quantities of oil, natural gas and NGL reserves and future cash flows from those reserves will most likely vary from our estimates. Estimating accumulations of oil, natural gas and NGLs is complex and inexact. The process relies on interpretations of geologic, geophysical, engineering and production data. The extent, quality and reliability of these data can vary. The process also requires a number of economic assumptions, such as oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, the effect of government regulation, taxes and availability of funds. The accuracy of a reserve estimate is a function of:
•the quality and quantity of available data;
•the interpretation of that data;
•the accuracy of various mandated economic assumptions and our expected development plan; and
•the judgment of the persons preparing the estimate.
The proved reserve information set forth in this report is based on our prepared estimates. Estimates prepared by others might differ materially from our estimates.
Actual quantities of oil, natural gas and NGL reserves, future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures and operating expenses will most likely vary from our estimates. In addition, the methodologies and evaluation techniques that we use, which include the use of multiple technologies, data sources and interpretation methods, may be different than those used by our competitors. Further, reserve estimates are subject to the evaluator’s criteria and judgment and show important variability, particularly in the early stages of development. Any significant variance could materially affect the quantities and net present value of our reserves. In addition, we may adjust estimates of reserves to reflect
production history, results of exploration and development activities, prevailing oil, natural gas and NGL prices and other factors, many of which are beyond our control. Our reserves also may be susceptible to drainage by operators on adjacent properties.
You should not assume that the present value of future net cash flows is the current market value of our proved reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on SEC 12-month average pricing, adjusted for market differentials and costs in effect at year-end discounted at 10%. Actual future prices and costs may be materially higher or lower than the prices and costs we used as of the date of an estimate. In addition, actual production rates for future periods may vary significantly from the rates assumed in the calculation.
To maintain and grow our production and cash flows, we must continue to develop existing reserves and locate or acquire new reserves. Through our drilling programs and the acquisition of properties, we strive to maintain and grow our production and cash flows. However, as we produce from our properties, our reserves decline. Unless we successfully replace the reserves that we produce, the decline in our reserves will eventually result in a decrease in gas and oil production and lower revenues and cash flows from operations. Future natural gas and oil production is, therefore, highly dependent on our success in efficiently finding, developing or acquiring additional reserves that are economically recoverable. We may be unable to find, develop or acquire additional reserves or production at an acceptable cost, if at all. In addition, these activities require substantial capital expenditures.
Lower oil and gas prices and other factors have resulted in ceiling test writedowns in the past and based upon current commodity prices, will result in future ceiling test writedowns or other impairments. We use the full cost method of accounting for our oil and gas producing activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and gas properties are capitalized into cost centers that are established on a country-by-country basis. The net capitalized costs of our oil and gas properties may not exceed the present value of estimated future net revenues from proved reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties. If net capitalized costs of our oil and gas properties exceed the cost center ceiling, we are subject to a ceiling test writedown to the extent of such excess. If required, a ceiling test writedown reduces earnings and stockholders' equity in the period of occurrence. We evaluate the ceiling test quarterly and had our last ceiling test writedown of approximately $1.5 billion ($948 million, after tax) at December 31, 2012. We did not have a ceiling test writedown in 2013 or 2014; however, due to the substantial decline of commodity prices during the fourth quarter of 2014, which has continued so far during the first quarter of 2015, we anticipate that we will have a ceiling test writedown during the first quarter of 2015. It is difficult to predict with reasonable certainty the amount of expected future impairments given the many factors impacting the ceiling test calculation including, but not limited to, future pricing, operating costs, upward or downward reserve revisions, reserve adds, and tax attributes. Subject to these numerous factors and inherent limitations, we believe that an impairment in the first quarter of 2015 could exceed $750 million. Once recorded, a ceiling test writedown is not reversible at a later date even if oil and gas prices increase.
The risk that we will be required to further writedown the carrying value of our oil and gas properties increases when oil and gas prices are low or volatile. In addition, writedowns may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase.
Drilling is a high-risk activity. In addition to the numerous operating risks described in more detail below, the drilling of wells involves the risk that no commercially productive oil or gas reservoirs will be encountered. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or gas is present or may be produced economically. In addition, we are often uncertain of the future cost or timing of drilling, completing and producing wells. Furthermore, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
•costs of, or shortages or delays in the availability of, drilling rigs, equipment and materials;
•decreases in oil and gas prices;
•adverse weather conditions and changes in weather patterns;
•unexpected drilling conditions;
•pressure or irregularities in formations;
•surface access restrictions;
•access to, and costs for, water needed in our waterflood project in the GMBU;
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the presence of underground sources of drinking water, previously unknown water or other extraction wells or endangered or threatened species;
•embedded oilfield drilling and service tools;
•equipment failures or accidents;
•lack of necessary services or qualified personnel;
•availability and timely issuance of required governmental permits and licenses;
•loss of title and other title-related issues;
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availability, costs and terms of contractual arrangements, such as leases, pipelines and related facilities to gather, process and compress, transport and market natural gas, crude oil and related commodities; and
•compliance with, or changes in, environmental, tax and other laws and regulations.
Future drilling activities may not be successful, and if unsuccessful, this could have an adverse effect on our future results of operations and financial condition.
The oil and gas business involves many operating risks that can cause substantial losses. Our oil and gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and gas, including the risk of:
•fires and explosions;
•blow-outs and cratering;
•uncontrollable or unknown flows of oil, gas or well fluids;
•formations with abnormal pressures;
•pipe or cement failures and casing collapses;
•pipeline or other facility ruptures and spills;
•equipment malfunctions or operator error;
•adverse weather conditions or natural disasters;
•discharges of toxic gases;
•buildup of naturally occurring radioactive materials;
•vandalism;
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environmental costs and liabilities due to our use, generation, handling and disposal of materials, including wastes, hydrocarbons and other chemicals; and
•environmental damages caused by previous owners of property we purchase and lease.
Some of these risks or hazards could materially and adversely affect our revenues and expenses by reducing or shutting in production from wells, loss of equipment or otherwise negatively impacting the projected economic performance of our prospects. If any of these risks occur, we could incur substantial losses as a result of:
•injury or loss of life;
•severe damage or destruction of property and equipment, and oil and gas reservoirs;
•pollution and other environmental damage;
•investigatory and clean-up responsibilities;
•regulatory investigation and penalties or lawsuits;
•limitation on or suspension of our operations; and
•repairs to resume operations.
Further, offshore operations are subject to a variety of additional operating risks, such as capsizing, collisions and damage or loss from typhoons or other adverse weather conditions. These conditions could cause substantial damage to facilities and interrupt production. Our China operations are dependent upon the availability, proximity and capacity of gathering systems and processing facilities that we do not own. Necessary infrastructures have been in the past, and may be in the future, temporarily unavailable due to adverse weather conditions or other reasons, or they may not be available to us in the future on acceptable terms or at all.
Failure or loss of equipment, as the result of equipment malfunctions, cyber-attacks or natural disasters, could result in property damages, personal injury, environmental pollution and other damages for which we could be liable. Catastrophic occurrences giving rise to litigation, such as a well blowout, explosion or fire at a location where our equipment and services are used, may result in substantial claims for damages. Ineffective containment of a drilling well blowout or pipeline rupture could result in extensive environmental pollution and substantial remediation expenses. If our production is interrupted significantly, our efforts at containment are ineffective or litigation arises as the result of a catastrophic occurrence, our cash flows, and in turn, our results of operations, could be materially and adversely affected.
In connection with our operations, we generally require our contractors, which include the contractor, its parent, subsidiaries and affiliate companies, its subcontractors, their agents, employees, directors and officers, to agree to indemnify us for injuries and deaths of their employees, contractors, subcontractors, agents and directors, and any property damage suffered by the contractors. There may be times, however, that we are required to indemnify our contractors for injuries and other losses resulting from the events described above, which indemnification claims could result in substantial losses to us.
While we maintain insurance against some potential losses or liabilities arising from our operations, our insurance does not protect us against all operational risks. The occurrence of any of the foregoing events and any costs or liabilities incurred as a result of such events, if uninsured or in excess of our insurance coverage or not indemnified, could reduce revenue and the funds available to us for our exploration, exploitation, development and production activities and could, in turn, have a material adverse effect on our business, financial condition and results of operations. See also “- We may not be insured against all of the operating risks to which our business is exposed.”
We are subject to complex laws and regulatory actions that can affect the cost, manner, feasibility or timing of doing business. Existing and potential regulatory actions could increase our costs and reduce our liquidity, delay our operations or otherwise alter the way we conduct our business. Exploration and development and the production and sale of oil, natural gas and NGLs are subject to extensive federal, state, provincial, tribal, local and international regulation. We may be required to make large expenditures to comply with environmental, habitat and other governmental regulations. Matters subject to regulation include the following, in addition to the other matters discussed under the caption “Regulation” in Items 1 and 2 of this report:
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the amounts, types and manner of substances and materials that may be released into the environment;
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response to unexpected releases into the environment;
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reports and permits concerning exploration, drilling, production and other operations;
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the placement and spacing of wells;
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cement and casing strength;
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unitization and pooling of properties;
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calculating royalties on oil and gas produced under federal and state leases; and
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taxation.
Under these laws, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs, natural resource risk mitigation, damages and other environmental or habitat damages. We also could be required to install and operate expensive pollution controls, engage in environmental risk management and derivative activities or limit or cease activities on lands located within wilderness, wetlands or other environmentally or politically sensitive areas. In addition, failure to comply with applicable laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties as well as the imposition of corrective action orders. Any such liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our financial condition, results of operations or cash flows.
Further, changes to existing environmental regulations or the adoption of new regulations may unfavorably impact us, the oil and gas industry generally, our suppliers or our customers. For example, governments around the world have become increasingly focused on regulating greenhouse gas (GHG) emissions and addressing the impacts of climate change in some manner. In the absence of dedicated federal legislation on climate change mitigation or adaptation, the U.S. Environmental Protection Agency (EPA) has promulgated several rulemakings to regulate, measure or monitor GHG emissions under the existing provisions of the Clean Air Act, or CAA. The EPA has adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States on an annual basis, as well as from certain onshore oil and natural gas production, processing, transmission, storage and distribution facilities on an annual basis. The new regulations could impact certain facilities in which we have interests (legal, equitable, operated or non-operated) by increasing regulatory risks and reporting requirements.
In December 2009, the EPA issued an “endangerment finding” under the CAA concluding that the current and projected concentrations of GHGs in the atmosphere from motor vehicles threaten the public health and welfare of current and future generations. The finding, once made, required the EPA to begin regulating GHG emissions from new cars and light trucks under the CAA. Indirectly, the EPA argued that it also triggered an EPA obligation to regulate GHG emissions under existing relevant air permitting programs for large stationary sources. On January 2, 2011, the EPA initiated Prevention of Significant Deterioration (PSD) permitting requirements for carbon dioxide and other GHGs from large and modified stationary sources. Permits limiting GHGs have been issued for a variety of new or modified facilities under the Clean Air Act PSD program. GHG emissions also trigger Title V operating permit requirements for new and existing sources that exceed certain established emission thresholds. Emission levels in excess of these thresholds can then trigger preconstruction permit requirements and application of best available control technology (BACT) or operation consistent with the lowest achievable emissions rate (LAER) as determined on a source-by-source basis.
In June 2014, the Supreme Court upheld most of the EPA’s GHG permitting requirements, allowing the agency to regulate the emission of GHGs from stationary sources already subject to the Clean Air Act’s prevention of significant deterioration (PSD) and Title V requirements. Certain of our equipment and installations may currently be subject to PSD and Title V requirements and hence, under the Supreme Court’s ruling, also be subject to the installation of controls to capture GHGs. For any equipment or installation so subject, we may have to incur increased compliance costs to capture GHGs.
The EPA took additional action under the Clean Air Act in June 2014. In accordance with the President of the United States' Climate Action Plan, on June 18, 2014, the EPA proposed rules to reduce carbon emissions from electric generating units. The proposal, commonly called the “Clean Power Plan,” requires states to develop plans to reduce carbon emissions from fossil fuel-fired generating units, commencing in 2020, with the reductions to be fully phased in by 2030. Under the proposal, each state would be given a different carbon reduction target, but the EPA expects that, in the aggregate, the overall proposal will reduce carbon emissions from electric generating units by 30% from 2005 levels.
As proposed, states are given great flexibility in meeting their emission reduction targets, and can generally choose to lower carbon emissions by replacing higher carbon generation, such as coal or natural gas, with lower carbon generation, such as efficient natural gas units, renewable or end-use energy efficiency. It is not possible at this time to predict what requirements might be adopted by the EPA in the final rule, expected in 2015, or how any such final rule would impact our business.
Recently, the President of the United States announced that the EPA would propose by mid-2015, a new series of regulations to reduce methane emissions from the oil and gas industry by 2025 by about 40 to 45% from 2012 levels. These rules are in addition to a series of recent EPA oil and gas rules designed to curb volatile organic compound (VOC) emissions from natural gas wells and related equipment, such as storage vessels and glycol dehydrators.
If the U.S. Congress adopts market-based tax, energy or other mechanisms to regulate the carbon intensity of natural resources, or promote or require the reduction of GHG emissions from certain industrial sectors, such legislation, depending on design and scope, could increase the cost of oil and gas production and market demand. Some states, like California, have implemented state-wide GHG mitigation programs to reduce GHG emissions through a mixture of regulatory programs,
including a low carbon fuel standard and cap-and-trade market applicable to, among others, electric utilities and transportation fuels.
Further, the U.S. Congress has previously proposed legislation that would directly impact our industry. In response to the 2010 Macondo incident in the Gulf of Mexico, the U.S. Congress considered a number of legislative proposals relating to the upstream oil and gas industry both onshore and offshore that could result in significant additional laws or regulations governing our operations in the United States, including a proposal to raise or eliminate the cap on liability for oil spill cleanups under the Oil Pollution Act of 1990.
Some federal agencies are adopting new rules governing hydraulic fracturing on leased federal or tribal trust lands. Meanwhile, states, tribes and municipalities across the country have issued moratoria banning hydraulic fracturing. While we cannot predict how these rules will impact our business, they will likely increase costs or otherwise limit where we may conduct exploration and production activities.
In December 2014, the Council on Environmental Quality issued draft guidance on consideration of climate change in project reviews under the National Environmental Policy Act (NEPA). We do not know whether and when this guidance may become final, nor can we predict its likely impact on our business. It is possible, however, that closer consideration of climate change may require BLM or other federal agencies to require enhanced environmental protections, at increased costs to operations like ours, at hydraulic fracturing sites across the country.
These and other potential legislative proposals, along with any applicable legislation introduced and passed in Congress, could increase our costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business, negatively impacting our financial condition, results of operations and cash flows. See also “- The potential adoption of federal, state, tribal and local legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and gas wells.”
Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Additional costs or operating restrictions associated with legislation or regulations could have a material adverse effect on our operating results and cash flows, in addition to the demand for the natural gas and other hydrocarbon products that we produce.
The potential adoption of federal, state, tribal and local legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and gas wells. Hydraulic fracturing is an essential and common practice in the oil and gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. We routinely apply hydraulic fracturing techniques on almost all of our U.S. onshore oil and natural gas properties. Hydraulic fracturing involves using water, sand or other proppant materials, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore.
As explained in more detail below, the hydraulic fracturing process is typically regulated by state oil and natural gas agencies, although the EPA, the BLM and other federal regulatory agencies have taken steps to review or impose federal regulatory requirements. Certain states in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether. Certain municipalities have already banned hydraulic fracturing, and courts have upheld those moratoria in some instances. In the past several years, dozens of states have approved or considered additional legislative mandates or administrative rules on hydraulic fracturing.
For example, Texas adopted a law in June 2011 requiring disclosure to the Railroad Commission of Texas (RCT) and the public of certain information regarding the components used in the hydraulic-fracturing process, and the RCT promulgated rules regarding the same in December 2011. On September 11, 2012, the RCT approved new regulations relating to the commercial recycling of produced water and/or hydraulic-fracturing flowback fluid. In addition, in May 2013 the RCT adopted amendments to Statewide Rule 13 governing casing, cementing, well control and completion of oil and gas wells; these new construction requirements took effect on January 1, 2014.
In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. For example, on June 30, 2014, New York’s highest state court upheld local zoning ordinances that ban hydraulic fracturing within municipal limits.
In the event state, local or municipal legal restrictions are adopted in areas where we are currently conducting operations, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells. Depending on the areas in which they are adopted, such restrictions or prohibitions could have a material adverse effect on our business, prospects, results of operations, financial condition, and liquidity.
In addition, on July 3, 2014, major university and U.S. Geological Survey researchers published a study purporting to find a causal connection between the deep well injection of hydraulic fracturing wastewater and a sharp increase in seismic activity in Oklahoma since 2008. This study may trigger new legislation or regulations that would limit or ban the disposal of hydraulic fracturing wastewater in deep injection wells. If such new laws or rules are adopted, our operations may be curtailed while alternative treatment and disposal methods are developed and approved.
The EPA is also developing a proposed rule to amend the Effluent Limitations Guidelines for the Oil and Gas Extraction Category. The proposed rule is scheduled for publication in 2015. It is unclear what the proposed rule will require, but with potential future limits on deep well injection, these limits may become increasingly important, as extraction and production companies look to dispose of wastewater to publicly-owned treatment works or centralized waste treaters. If deep well injection is shut down or limited, and discharge to surface waters is impossible, we may face increased disposal costs.
In recent years, the federal government has increased its focus on the environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality has coordinated an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices involving the use of diesel fuel.
The EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel fuels under the Safe Drinking Water Act and in February 2014 issued permitting guidance for hydraulic fracturing activities using diesel.
Further, on May 19, 2014, the EPA published an Advance Notice of Proposed Rulemaking (ANPR) under the Toxic Substances Control Act, relating to the disclosure of chemical substances and mixtures used in oil and gas exploration and production. Depending on the precise disclosure requirements the EPA elects to impose, if any, we may be obliged to disclose valuable proprietary information, and failure to do so may subject us to penalties.
In addition, in May 2013, the Bureau of Land Management issued a proposed rule that would require the public disclosure of chemicals used in hydraulic fracturing operations, set requirements for well-bore integrity and establish flowback water standards for all hydraulic fracturing operations on federal public lands and American Indian Tribal lands. The proposed rule also required that an operator certify, in writing, that (a) the stimulation design complies with all federal, state, tribal and local regulations; (b) the stimulation was completed in accordance with the design approved by BLM and all applicable regulations; and (c) the well-bore integrity was maintained during the fracturing process and flowback water was properly stored, treated and disposed. Furthermore, a number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with draft results to be issued in 2015 for public comment and peer review.
In addition, the U.S. Department of Energy has conducted an investigation into practices to better protect the environment from drilling using hydraulic fracturing completion methods. In a November 18, 2011 report, the Shale Gas Subcommittee of the Secretary of Energy Advisory Board issued 20 recommendations to federal agencies, states and private entities that are intended to reduce the environmental impact and assure the safety of shale gas production. The U.S. Department of Energy continues to work with other federal agencies to identify best practices for shale gas production. Some of these may become enforceable statutory or regulatory requirements that would likely increase our compliance costs.
Given the heightened awareness regarding the use of hydraulic fracturing, it is possible that regulatory agencies or private parties may suggest that hydraulic fracturing has caused groundwater or surface water contamination, whether or not such allegations are accurate. For example, on December 8, 2011, the EPA released a preliminary report indicating that hydraulic fracturing is responsible for groundwater contamination in Pavillion, Wyoming, although the EPA’s draft report has been vigorously criticized as ignoring certain facts and utilizing incorrect data. In addition, the EPA alleged in an enforcement action against an operator in Texas that the operator contaminated local groundwater wells, although the RCT found after an evidentiary hearing that the operator was not responsible for the contamination. However, in 2013 the EPA deferred the Pavillion matter to state oversight and withdrew the emergency action order in Texas. Nevertheless, energy extraction, with a focus on onshore natural gas production, remains an EPA enforcement initiative. Thus, regulatory agencies or private parties
alleging groundwater contamination linked to hydraulic fracturing could trigger defense costs in administrative or civil litigation or proceedings to rebut the allegations.
Additionally, certain members of the Congress have called upon (a) the U.S. Government Accountability Office to investigate how hydraulic fracturing might adversely affect water resources, (b) the SEC to investigate the natural gas industry and any possible misleading of investors or the public regarding the economic feasibility of pursuing natural gas deposits in shales by means of hydraulic fracturing, and (c) the U.S. Energy Information Administration to provide a better understanding of that agency’s estimates regarding natural gas reserves, including reserves from shale formations, as well as uncertainties associated with those estimates. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the Safe Drinking Water Act or other regulatory mechanisms.
Further, on August 16, 2012, the EPA approved final regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA finalized rules under the New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants (NESHAPS) programs. The EPA regulations include NSPS standards for completions of hydraulically-fractured gas wells.
Since January 1, 2015, operators must capture the gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the regulations under NESHAPS include specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, gas processing plants and certain other equipment. EPA has revised this rule two times, in September 2013 and December 2014. We have and continue to evaluate the effect of these regulations, including the latest revisions, on our business. Compliance with such regulations could result in additional costs, including increased capital expenditures and operating costs, for us and our customers which may adversely impact our business.
Based on the foregoing, increased regulation and attention given to the hydraulic fracturing process from federal agencies, various states and local governments could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows.
We could be adversely affected by the credit risk of financial institutions. We have exposure to different counterparties, and we have entered into transactions with counterparties in the financial services industry, including commercial banks, investment banks, insurance companies, investment funds and other institutions. In the event of default of a counterparty, we would be exposed to credit risks. Deterioration in the credit markets may impact the credit ratings of our current and potential counterparties and affect their ability to fulfill their existing obligations to us and their willingness to enter into future transactions with us. We have exposure to financial institutions in the form of derivative contracts and insurance companies in the form of claims under our policies. In addition, if any lender under our credit facility is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our credit facility.
Our use of oil and natural gas price derivative contracts may limit future revenues from price increases and involves the risk that our counterparties may be unable to satisfy their obligations to us. As part of our risk management program, we generally use derivative contracts to protect a substantial, but varying, portion of our anticipated future oil and gas production for the next 24-36 months to reduce our exposure to fluctuations in oil and natural gas prices. As of December 31, 2014, we had no outstanding derivative contracts related to our NGL production. A significant portion of our crude oil derivative contracts include short puts. If market prices remain below our sold puts at contract settlement, we will receive the difference between our floors or swaps and the associated sold puts, effectively limiting the downside protection of these contracts. In the case of acquisitions, we may use derivative contracts to protect acquired production from commodity price volatility for a longer period. In addition, we may utilize basis contracts to hedge the differential between the relevant underlying commodity reference prices and those of our physical pricing points. While the use of derivative contracts may limit or reduce the downside risk of adverse price movements, their use also may limit future benefits from favorable price movements and expose us to the risk of financial loss in certain circumstances. Those circumstances include instances where our production is less than the volume subject to derivative contracts or there is a widening of price basis differentials between delivery points for our production and the delivery points assumed in the derivative transactions.
The use of derivative transactions also involves the risk that counterparties, which generally are financial institutions, will be unable to perform their financial and other obligations under such transactions. If any of our counterparties were to default on its obligations to us under the derivative contracts, enter receivership or seek bankruptcy or similar protection, that could
result in an economic loss to us and could have a material adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price changes. In addition, in poor economic environments and tight financial markets, the risk of a counterparty default is heightened, and it is possible that fewer counterparties will participate in future derivative transactions, which could result in greater concentration of our exposure to any one counterparty or a larger percentage of our future production being subject to commodity price changes.
Federal legislation regarding swaps could adversely affect the costs of, or our ability to enter into, those transactions. Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Act), which was passed by Congress and signed into law in July 2010, amends the Commodity Exchange Act (CEA) to establish a comprehensive new regulatory framework for over-the-counter derivatives, or swaps, and swaps market participants, such as Newfield. The Dodd-Frank Act requires certain swaps to be cleared through a derivatives clearing organization, unless an exception from mandatory clearing is available, and if the swap is subject to a clearing requirement, to be executed on a designated contract market or swap execution facility, and that market participants post margin for uncleared swaps. The CEA provides that non-financial entity end-users, such as Newfield, that enter into swaps to hedge or mitigate commercial risk may elect an exception from the mandatory clearing and exchange trading requirements. However, unless an exemption from the Dodd-Frank Act’s margin requirements is available, our derivative transactions could be subject to higher costs due to margin payments to swap counterparties. While we do not expect that we will be required to post margin for uncleared swaps, the Commodity Futures Trading Commission (CFTC) has not yet finalized the margin rules. Therefore, we are unable to determine the future costs on our derivative activities at this time.
Higher costs associated with the Dodd-Frank Act can create disincentives for end-users like Newfield to hedge their commercial risks, including market price fluctuations associated with anticipated production of oil and gas. The Dodd-Frank Act and related rules and regulations promulgated by CFTC could potentially increase the cost of Newfield’s risk management activities, which could adversely affect our available liquidity, materially alter the terms of our swap contracts, reduce the availability of swaps to hedge or mitigate risks we encounter, reduce our ability to monetize or restructure existing swap contracts, and increase our regulatory compliance costs related to our swap activities. In addition, if we reduce our use of swaps, our results of operations and cash flows may be adversely affected, including by becoming more volatile and less predictable, which also could adversely affect our ability to plan for and fund capital expenditures. It is also possible that the Dodd-Frank Act and related rules and regulations could affect prices for commodities that we purchase, use or sell, which, in turn, could adversely affect our liquidity or financial condition.
In December 2013, the CFTC re-proposed rules to amend the CEA to establish position limits for certain commodity futures and options contracts, and physical commodity swaps that are economically equivalent to such contracts, including on commodity derivative transactions in which we engage in beyond certain thresholds. If the CFTC position limit regulations are ultimately adopted substantially in the form proposed, they could result in additional compliance costs and alter our ability to effectively manage our commercial risks. Until the CFTC adopts final rules with respect to position limits and any exemptions for bona fide derivative transactions or off-setting positions from those limits, we will be unable to determine whether the CFTC’s proposed rules could result in additional derivative costs or adversely affect our ability to effectively manage our commercial risks.
Some of our undeveloped leasehold acreage is subject to leases that will expire unless production is established on the leases or units containing the leasehold acreage. Leases on oil and gas properties normally have a term of three to five years and will expire unless, prior to expiration of the lease term, production in paying quantities is established. If the leases expire and we are unable to renew them, we will lose the right to develop the related properties. The risk of the foregoing increases in periods of sustained low commodity prices due to the corresponding impact on our drilling plans and the likely decrease in what is considered economic production under the leases. Our drilling plans for these areas are subject to change based upon various factors, including commodity prices, drilling results, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.
Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation. In recent years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. federal income tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and natural gas exploration and production companies. These changes include, among other proposals:
•the repeal of the percentage depletion allowance for oil and gas properties;
•the elimination of current deductions for intangible drilling and development costs;
•the elimination of the deduction for certain U.S. production activities; and
•an extension of the amortization period for certain geological and geophysical expenditures.
These proposals were also included in the President of the United States' Proposed Fiscal Year 2014 Budget. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of such legislation or any other similar changes in U.S. Federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development. Any such changes could have an adverse effect on our financial position, results of operations and cash flows.
The marketability of our production is dependent upon transportation and processing facilities over which we may have no control. The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. We deliver oil and gas through gathering systems and pipelines that we do not own. The lack of available capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Although we have some contractual control over the transportation of our production through some firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions or mechanical or other reasons, or may not be available to us in the future at a price that is acceptable to us. New regulations on the transportation of crude oil by rail, like those issued via emergency orders by the U.S. Department of Transportation (DOT) in 2014, may increase our transportation costs. In addition, federal and state regulation of natural gas and oil production, processing and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, infrastructure or capacity constraints and general economic conditions could adversely affect our ability to produce, gather and transport natural gas. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could harm our business and, in turn, our financial condition, results of operations and cash flows.
We have risks associated with our China operations. Ownership of property interests and production operations in China are subject to the various risks inherent in international operations. These risks may include:
•currency restrictions and exchange rate fluctuations;
•
loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, war, piracy, acts of terrorism, insurrection, civil unrest and other political risks or other changes in government;
•
difficulties obtaining permits or governmental approvals as a foreign operator;
•increases in taxes and governmental royalties;
•
transparency issues in general and, more specifically, the U.S. Foreign Corrupt Practices Act and other anti-corruption compliance laws and issues;
•disruptions in international crude oil cargo shipping activities;
•physical, digital, internal and external security breaches;
•
forced renegotiation of, unilateral changes to, or termination of contracts with, governmental entities and quasi-governmental agencies;
•changes in laws and policies governing operations in China;
•our limited ability to influence or control the operation or future development of non-operated properties;
•the operator’s expertise or other labor problems;
•cultural differences;
•
difficulties enforcing our rights against a governmental entity because of the doctrine of sovereign immunity and foreign sovereignty over our China operations; and
•other uncertainties arising out of foreign government sovereignty over our China operations.
Our China operations also may be adversely affected by the laws and policies of the United States affecting foreign trade, taxation, investment and transparency issues. In addition, if a dispute arises with respect to our China operations, we may be subject to the exclusive jurisdiction of non-U.S. courts or may not be successful in subjecting non-U.S. persons to the jurisdiction of the courts of the United States. Realization of any of the factors listed above could materially and adversely affect our financial position, results of operations or cash flows.
Material differences between the estimated and actual timing of critical events may affect the completion of and commencement of production from our Pearl development project in China. Our Pearl facility in the South China Sea is a large, offshore development project. The completion of our drilling in this project may be delayed beyond our anticipated completion dates. Key factors that may affect the timing and outcome of this project include the following:
•project approvals by our joint-venture partner(s);
•timely issuance of permits and licenses by governmental agencies or legislative and other governmental approvals;
•weather conditions;
•availability of personnel;
•civil and political environment in China; and
•manufacturing and delivery schedules of critical equipment.
Delays and differences between estimated and actual timing of critical events may affect the forward-looking statements related to our Pearl development and could have a material adverse effect on our expected timing and amount of cash flows from China and international results of operations.
Competition for, or the loss of, our senior management or experienced technical personnel may negatively impact our operations or financial results. To a large extent, we depend on the services of our senior management and technical personnel and the loss of any key personnel could have a material adverse effect on our business, financial condition and operating results. Our continued drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain a seasoned management team and experienced explorationists, engineers, geologists and other professionals. Competition for these professionals remains strong. If we cannot retain our technical personnel or attract additional experienced technical personnel, our ability to compete could be harmed. We are likely to continue to experience increased costs to attract and retain these professionals.
Competition in the oil and gas industry is intense. We operate in a highly competitive environment for acquiring properties and marketing oil, natural gas and NGLs. Our competitors include multinational oil and gas companies, major oil and gas companies, independent oil and gas companies, individual producers, financial buyers as well as participants in other industries supplying energy and fuel to consumers. Many of our competitors have greater and more diverse resources than we do. In addition, high commodity prices and stiff competition for acquisitions have in the past, and may in the future, significantly increase the cost of available properties. We compete for the personnel and equipment required to explore, develop and operate properties. Our competitors also may have established long-term strategic positions and relationships in areas in which we may seek new entry. As a consequence, our competitors may be able to address these competitive factors more effectively than we can. If we are not successful in our competition for oil and gas reserves or in our marketing of production, our financial condition and results of operations may be adversely affected.
Shortages of oilfield equipment, services, supplies and qualified field personnel could adversely affect financial condition and results of operations. Historically, there have been shortages of drilling rigs and other oilfield equipment as demand for that equipment has increased along with the number of wells being drilled. The demand for qualified and experienced field personnel to drill wells and conduct field operations can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. These factors have caused significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment, services and raw materials. Similarly, lower crude oil and natural gas prices generally result in a decline in service costs due to reduced demand for drilling and completion services. If the current market changes, and commodity prices quickly recover, we may face shortages of field personnel, drilling rigs, or other equipment or supplies, which could delay or adversely affect our exploration and development operations and have a material adverse effect on our business, financial condition, results of operations or cash flows, or restrict operations.
Our ability to produce oil, natural gas and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner. Development activities require the use of water. For example, the hydraulic fracturing process that we employ to produce commercial quantities of natural gas and oil from many reservoirs requires the use and disposal of significant quantities of water in addition to the water we use to develop our waterflood in the GMBU. In certain regions, there may be insufficient local capacity to provide a source of water for drilling activities. In these cases, water must be obtained from other sources and transported to the drilling site, adding to the operating cost. Our inability to secure sufficient amounts of water, or to dispose of or recycle the water used in our operations, could adversely impact our operations in certain areas. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations, such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other materials associated with the exploration, development or production of natural gas and oil. In recent history, public concern surrounding increased seismicity has heightened focus on our industry's use of water in operations, which may cause increased costs, regulations or environmental initiatives impacting our use or disposal of water.
We may not be insured against all of the operating risks to which our business is exposed. Our operations are subject to all of the risks normally incident to the exploration for and the production of oil and gas, such as well blowouts, explosions, oil spills, releases of gas or well fluids, fires, pollution and adverse weather conditions, which could result in substantial losses to us. See also “- The oil and gas business involves many operating risks that can cause substantial losses.” Exploration and production activities are also subject to risk from political developments such as terrorist acts, piracy, civil disturbances, war, expropriation or nationalization of assets, which can cause loss of or damage to our property. We maintain insurance against many, but not all, potential losses or liabilities arising from our operations in accordance with what we believe are customary industry practices and in amounts and at costs that we believe to be prudent and commercially practicable. Our insurance includes deductibles that must be met prior to recovery, as well as sub-limits and/or self-insurance. Additionally, our insurance is subject to exclusions and limitations. Our insurance does not cover every potential risk associated with our operations, including the potential loss of significant revenues. We can provide no assurance that our insurance coverage will adequately protect us against liability from all potential consequences, damages and losses.
We currently have insurance policies covering our onshore and offshore operations that include coverage for general liability, excess liability, physical damage to our oil and gas properties, operational control of wells, oil pollution, third-party liability, workers’ compensation and employers’ liability and other coverages. Consistent with insurance coverage generally available to the industry, our insurance policies provide limited coverage for losses or liabilities relating to pollution and other environmental issues, with broader coverage for sudden and accidental occurrences. For example, we maintain operators extra expense coverage provided by third-party insurers for obligations, expenses or claims that we may incur from a sudden incident that results in negative environmental effects, including obligations, expenses or claims related to seepage and pollution, cleanup and containment, evacuation expenses and control of the well (subject to policy terms and conditions). In the specific event of a well blowout or out-of-control well resulting in negative environmental effects, such operators extra expense coverage would be our primary source of coverage, with the general liability and excess liability coverage referenced above also providing certain coverage.
In the event we make a claim under our insurance policies, we will be subject to the credit risk of the insurers. Volatility and disruption in the financial and credit markets may adversely affect the credit quality of our insurers and impact their ability to pay claims.
Further, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. Some forms of insurance may become unavailable in the future or unavailable on terms that we believe are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to maintain minimal or no insurance coverage. If we incur substantial liability from a significant event and the damages are not covered by insurance or are in excess of policy limits, then we would have lower revenues and funds available to us for our operations, that could, in turn, have a material adverse effect on our business, financial condition and results of operations.
We may be subject to risks in connection with acquisitions and divestitures. As part of our business strategy, we have made and will likely continue to make acquisitions of properties and to divest non-strategic assets. Suitable acquisition properties or suitable buyers of our non-strategic assets may not be available on terms and conditions we find acceptable.
Acquisitions pose substantial risks to our business, financial condition and results of operations. These risks include that the acquired properties may not produce revenues, reserves, earnings or cash flows at anticipated levels. Also, the integration of properties we acquire could be difficult. In pursuing acquisitions, we compete with other companies, many of which have
greater financial and other resources to acquire properties. The successful acquisition of producing properties requires an assessment of several factors, including:
•recoverable reserves;
•exploration potential;
•future oil and gas prices and their appropriate differentials;
•operating costs and production taxes; and
•potential environmental and other liabilities.
These assessments are complex and the accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.
In addition, our divestitures may pose residual risks to the Company, such as divestitures where we retain certain liabilities or we have legal successor liability due to the bankruptcy or dissolution of the purchaser. Uneconomic or unsuccessful acquisitions and divestitures may divert management’s attention and financial resources away from our existing operations, which could have a material adverse effect on our financial condition.
We depend on computer and telecommunications systems, and failures in our systems or cyber security attacks could significantly disrupt our business operations. The oil and gas industry has become increasingly dependent upon digital technologies to conduct day-to-day operations including certain exploration, development and production activities. We have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with our business. In addition, we have developed proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. We depend on digital technology to estimate quantities of oil, natural gas and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Our business partners, including vendors, service providers, purchasers of our production and financial institutions, are also dependent on digital technology. It is possible we could incur interruptions from cyber security attacks, computer viruses or malware. We believe that we have positive relations with our related vendors and maintain adequate anti-virus and malware software and controls; however, any cyber incidents or interruptions to our arrangements with third parties to our computing and communications infrastructure or our information systems could lead to data corruption, communication interruption, unauthorized release, gathering, monitoring, misuse or destruction of proprietary or other information, or otherwise significantly disrupt our business operations. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.
We are exposed to counterparty credit risk as a result of our receivables. We are exposed to risk of financial loss from trade, joint venture, joint interest billing, and other receivables. We sell our crude oil, natural gas and NGLs to a variety of purchasers. Some of our purchasers and non-operating partners may experience credit downgrades or liquidity problems and may not be able to meet their financial obligations to us. Nonperformance by a trade creditor or non-operating partner could result in financial losses.
Hurricanes, typhoons, tornadoes, earthquakes and other natural disasters could have a material adverse effect on our business, financial condition, results of operations and cash flow. Hurricanes, typhoons, tornadoes, earthquakes and other natural disasters can potentially destroy thousands of business structures and homes and, if occurring in the Gulf Coast region of the United States, could disrupt the supply chain for oil and gas products. Disruptions in supply could have a material adverse effect on our business, financial condition, results of operations and cash flow. Damages and higher prices caused by hurricanes, typhoons, tornadoes, earthquakes and other natural disasters could also have an adverse effect on our financial condition due to the impact on the financial condition of our customers.
A downgrade in our credit rating could negatively impact our cost of and ability to access capital. We receive debt ratings from the major credit rating agencies in the United States. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales, and near-term and long-term production growth opportunities. Liquidity, asset quality, cost structure, product mix, and commodity pricing levels are also considered by the rating agencies. A ratings downgrade could
adversely impact our ability to access debt markets in the future, increase the cost of future debt, and potentially require us to post letters of credit or other forms of collateral for certain obligations.
Our level of indebtedness and the restrictive covenants in the agreements governing our indebtedness and other financial obligations may reduce our operating flexibility. As of December 31, 2014, we had total indebtedness of $2.9 billion, including $0.4 billion in borrowings under our revolving credit facility and money market lines of credit. The indenture governing our outstanding notes and the agreements governing our other indebtedness and financial obligations contain, and any indenture that will govern other debt securities issued by us may contain, various covenants that limit our ability and the ability of specified subsidiaries of ours to, among other things:
•incur additional indebtedness;
•purchase or redeem our outstanding equity interests or subordinated debt;
•make specified investments;
•create liens;
•sell assets;
•engage in specified transactions with affiliates;
•engage in sale-leaseback transactions; and
•
effect a merger or consolidation with or into other companies or a sale of all or substantially all of our properties or assets.
These restrictions and our level of indebtedness could limit our ability to:
•obtain future financing;
•make needed capital expenditures;
•plan for, or react to, changes in our business and the industry in which we operate;
•compete with similar companies that have less debt;
•withstand a future downturn in our business or the economy in general; or
•conduct operations or otherwise take advantage of business opportunities that may arise.
Some of the agreements governing our indebtedness and other financial obligations also require the maintenance of specified financial ratios and the satisfaction of other financial conditions. Our ability to meet those financial ratios and conditions, and to comply with other covenants and restrictions in our financing agreements, can be affected by unexpected downturns in business operations beyond our control, such as a volatile energy commodity cost environment or an economic downturn. Accordingly, we may be unable to meet these obligations. This failure could impair our operating capacity and cash flows and could restrict our ability to incur debt or to make cash distributions, even if sufficient funds were available.
Our breach of any of these covenants could result in a default under the terms of the relevant indebtedness, which could cause such indebtedness or other financial obligations to become immediately due and payable. If the lenders accelerate the repayment of borrowings or other amounts owed, we may not have sufficient assets to repay our indebtedness or other financial obligations, including our outstanding notes and any future debt securities. If we are unable to satisfy our obligations with cash on hand, we could attempt to refinance such debt, or repay such debt with the proceeds from a sale of assets or a public offering of securities. Factors that will affect our ability to successfully complete a public offering, refinance our debt or conduct an asset sale include financial market conditions and our market value and operating performance at the time of such offering or other financing. We cannot assure that we will be able to generate sufficient cash flow to pay the interest on our debt, to meet our lease obligations, or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt or obligations.
Our certificate of incorporation, bylaws, some of our arrangements with employees and Delaware law contain provisions that could discourage an acquisition or change of control of our Company. Our certificate of incorporation and
bylaws contain provisions that may make it more difficult to affect a change of control of our Company, to acquire us or to replace incumbent management. In addition, our change of control severance plan and agreements and our omnibus stock plans contain provisions that provide for severance payments and accelerated vesting of benefits, including accelerated vesting of restricted stock, restricted stock units and stock options, upon a change of control. Section 203 of the Delaware General Corporation Law also imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. These provisions could discourage or prevent a change of control, even if it may be beneficial to our stockholders, or could reduce the price our stockholders receive in an acquisition of our Company.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
Not applicable.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
Between February and December 2013, we voluntarily self-disclosed to the U.S. Environmental Protection Agency (EPA) certain potential federal air quality violations at our facilities located on state lands and on the Uintah and Ouray Indian Reservation in the Uinta Basin of northeast Utah. The self-disclosures were made after a voluntary internal environmental audit under the EPA's Self-Disclosure and Audit Policy. The potential violations related primarily to certain stationary internal combustion engines that are subject to certain air quality performance standards under 40 C.F.R. Part 60, Subpart JJJJ. The engines were installed as a result of our efforts to replace older, higher-emitting engines with new, lower-emitting engines. Subpart JJJJ requires us to conduct certain emission performance tests within a defined time period. We did not conduct all of the requisite tests on the new engines in a timely fashion and have now negotiated a settlement and resolution with the EPA by entering in to a Combined Complaint and Consent Agreement and Compliance Order on Consent. Those settlement documents require us to pay a monetary penalty of $246,000 and conduct testing for numerous engines. The settlement documentation was finalized on October 20, 2014 and the penalty was paid timely on November 7, 2014. The required performance testing is ongoing and we anticipate that work to be completed in a timely manner, consistent with the requirements of the settlement. The violations did not contain any allegations of environmental spills, releases or pollution above permitted levels. We do not expect this matter to have a material adverse effect on our financial position, cash flows or results of operations.
In early 2012, through a voluntary environmental audit, we discovered potential violations of section 404 of the Clean Water Act relating to possible unpermitted discharges of fill materials into certain wetlands and drainages in the Uinta Basin. The potential violations were discovered on certain Newfield locations and several locations acquired in 2011. In June 2012, we self-disclosed these potential violations to the U.S. Army Corps of Engineers (Corps), in accordance with the EPA’s Audit Policy and an interagency memorandum of understanding with the Corps. The Corps initially indicated to us that it would not pursue penalty charges, but instead would work with us to restore the unpermitted discharges and acquire the appropriate after-the-fact permits. The EPA later inquired with the Corps, and was informed about the potential violations. Thereafter, the EPA initiated an administrative enforcement action against Newfield. The EPA has evaluated the discharges and our proposed restoration and mitigation, and a negotiated settlement has been finalized. On November 13, 2014, Newfield entered into an Administrative Order on Consent and a Combined Complaint and Consent Agreement to settle the matter. The EPA executed both agreements on December 17, 2014. The EPA published the notice of the Combined Complaint and Consent Agreement on December 17, 2014, for a 40-day comment period. No comments were received by the EPA. The settlement terms involved payment of a $175,000 penalty, restoration of much of the unpermitted discharges and off-site mitigation. The EPA issued the Final Order together with the fully executed Combined Complaint and Consent Agreement on January 27, 2015. The penalty will be paid before February 27, 2015 and the remediation and mitigation work will begin in 2015. We do not expect this administrative settlement to have a material adverse effect on our financial position, cash flows or results of operations.
We have been named as a defendant in a number of lawsuits and are involved in various other disputes, all arising in the ordinary course of our business, such as (a) claims from royalty owners for disputed royalty payments, (b) commercial disputes, (c) personal injury claims and (d) property damage claims. Although the outcome of these lawsuits and disputes cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, cash flows or results of operations. In addition, from time to time we receive notices of violation from governmental and regulatory authorities in areas in which we operate related to alleged violations of environmental statutes or rules and regulations promulgated thereunder. We cannot predict with certainty whether these notices of violation will result in fines or penalties, or if such fines or penalties are imposed, that they would individually or in the aggregate exceed $100,000. If any fines or penalties are in fact imposed that are greater than $100,000, then we will disclose such fact in our subsequent filings.

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ITEM 4. RESERVED
Item 4.
Mine Safety Disclosures
Not applicable.
Executive Officers of the Registrant
The following table sets forth the names, ages (as of February 20, 2015) and positions held by our executive officers. Our executive officers serve at the discretion of our Board of Directors.
Lee K. Boothby was named Chairman of the Board of Directors in May 2010, Chief Executive Officer in May 2009 and President in February 2009. Prior to this, he was Senior Vice President - Acquisitions and Business Development. From 2002 to 2007, he was Vice President - Mid-Continent. From 1999 to 2001, Mr. Boothby was Vice President and Managing Director - Newfield Exploration Australia Ltd. and managed operations in the Timor Sea (divested in 2003) from Perth, Australia. Prior to joining Newfield in 1999, Mr. Boothby worked for Cockrell Oil Corporation, British Gas and Tenneco Oil Company. He serves as a board member for America’s Natural Gas Alliance and the American Exploration and Production Council. He is a member of the Louisiana State University Craft & Hawkins Department of Petroleum Engineering Advisory Committee, the Society of Petroleum Engineers, the Independent Petroleum Association of America and the Rice University Jones Graduate School of Business Council of Overseers. He holds a degree in Petroleum Engineering from Louisiana State University and a Master of Business Administration from Rice University.
Lawrence S. Massaro was promoted to Executive Vice President and Chief Financial Officer in November 2013. Mr. Massaro joined Newfield in March 2011 and served as Vice President - Corporate Development until November 2013. In this position, he led the Company's business development, strategic planning and product marketing efforts. Prior to joining Newfield, Mr. Massaro served as Managing Director at JP Morgan in its oil and gas investment banking group beginning in 2005 and was Vice President, Corporate Strategy and Business Development while at Amerada Hess Corporation from 1995 to 2005. He also held various senior petroleum engineering positions at both PG&E Resources from 1992 to 1994 and at British Petroleum from 1985 to 1991. Mr. Massaro holds a degree in Petroleum Engineering from Texas A&M University and a Master of Business Administration from Southern Methodist University.
Gary D. Packer was promoted to the position of Executive Vice President and Chief Operating Officer in May 2009. Prior thereto, he was promoted from Gulf of Mexico General Manager to Vice President - Rocky Mountains in November 2004. Mr. Packer joined the Company in 1995. Prior to joining Newfield, Mr. Packer worked for Amerada Hess Corporation in both the Rocky Mountains and Gulf of Mexico divisions. Prior to these roles, he worked for Tenneco Oil Company. In December 2014, Mr. Packer joined the board of directors of Bennu Oil & Gas, LLC, a private oil and gas company operating offshore in the Gulf of Mexico. He serves as a board member for the Independent Petroleum Association of America (IPAA). He holds a degree in Petroleum and Natural Gas Engineering from Penn State University.
George T. Dunn was promoted to Senior Vice President - Development in September 2012, previously serving as Vice President - Mid-Continent beginning in October 2007. He managed our onshore Gulf Coast operations from 2001 to October 2007, and was promoted from General Manager to Vice President in November 2004. Before managing our Gulf Coast operations, Mr. Dunn was the General Manager of our Western Gulf of Mexico division. Prior to joining Newfield in 1992, Mr. Dunn was employed by Meridian Oil Company and Tenneco Oil Company. He holds a degree in Petroleum Engineering from the Colorado School of Mines.
John H. Jasek was promoted to Senior Vice President - Operations in October of 2014, after serving as Vice President - Onshore Gulf Coast since February 2011. Prior to that, Mr. Jasek served as Vice President - Gulf of Mexico from December 2008 until February 2011 and as Vice President - Gulf Coast from October 2007 until December 2008 while also serving as the manager of our onshore Gulf Coast operations. He previously managed our Gulf of Mexico operations from March 2005 until October 2007, and was promoted from General Manager to Vice President in November 2006. Prior to March 2005, he was a Petroleum Engineer in the Western Gulf of Mexico. Before joining Newfield, Mr. Jasek worked for Anadarko Petroleum Corporation and Amoco Production Company. He has a degree in Petroleum Engineering from Texas A&M University.
Stephen C. Campbell was promoted to Vice President - Investor Relations in December 2005, after serving as Newfield’s Manager - Investor Relations since 1999. Prior to joining Newfield, Mr. Campbell was the Investor Relations Manager at Anadarko Petroleum Corporation from 1993 to 1999 and the Assistant Vice President of Marketing & Communications at United Way, Texas Gulf Coast from 1990 to 1993. He is a member of the National Investor Relations Institute. He holds a Bachelor of Science degree in Journalism from Texas A&M University.
George W. Fairchild, Jr. was promoted to Chief Accounting Officer and Assistant Corporate Secretary in November 2013. Mr. Fairchild joined Newfield in August of 2012 as Controller and Assistant Corporate Secretary and has served as the Company’s Principal Accounting Officer since joining the Company. Prior to joining Newfield, Mr. Fairchild served as Controller for Sheridan Production Company LLC, a privately-held oil and gas company, beginning in 2009 and was Vice President and Controller of Davis Petroleum Corporation, also a privately-held oil and gas company, from 2006 to 2009. Prior thereto, Mr. Fairchild was with Burlington Resources Inc., a publicly-held oil and gas company, serving as Senior Manager - Accounting Policy & Research from 2001 to 2006 and Manager - Internal Audit from 2000 to 2001. Before joining Burlington Resources Inc., he was with PricewaterhouseCoopers LLP from 1993 to 2000. Mr. Fairchild served in the U.S. Air Force from 1986 to 1990. He holds a Bachelor of Business Administration in Accounting from the University of Texas at Austin and is a Certified Public Accountant in the state of Texas.
John D. Marziotti was promoted to General Counsel in August 2007 and was named Corporate Secretary in May 2008. Prior to joining Newfield in 2003, Mr. Marziotti was a partner at the law firm of Strasburger & Price, LLP in their Houston office. He received his Juris Doctor degree from Southern Methodist University and a Bachelor of Arts degree from the College of Charleston and is a member of the State Bar of Texas, the Houston Bar Association, the Association of Corporate Counsel, Texas General Counsel Forum and is a Board Leadership Fellow with the National Association of Corporate Directors.
Valerie A. Mitchell was promoted to Vice President - Mid-Continent effective February 9, 2015, after serving as Vice President - Corporate Development beginning in June of 2014. From 2011 to June 2014, she served as General Manager of our Mid-Continent business unit. Prior to that, Ms. Mitchell served in a number of leadership roles since joining Newfield in July 2004, including business development manager for our onshore Gulf Coast region and asset lead and asset manager from 2009 to 2011. Ms. Mitchell began her career as a reservoir engineer with Shell Oil in 1996 and thereafter worked in various technical and management positions at Coastal and El Paso. She has served in leadership positions for several industry organizations including the Oklahoma Independent Producers Association and the Society of Petroleum Engineers. She holds a Bachelor of Science in Chemical Engineering from the University of Missouri-Columbia.
Matthew R. Vezza was promoted to Vice President - Rocky Mountains in June of 2014. Mr. Vezza joined Newfield in August 2012 as General Manager of our Rocky Mountains business unit after 16 years with Marathon Oil Company. Mr. Vezza began his career at Marathon in 1996 as a production engineer and then moved through the organization in various technical and managerial roles in Oklahoma, Texas, Louisiana, Colorado and Wyoming. While at Marathon, Mr. Vezza's last position, from August 2009 to August 2012, was serving as Asset Manager - Wyoming. Mr. Vezza is a member of the Society of Petroleum Engineers and holds a Bachelor of Science in Petroleum and Natural Gas Engineering from Penn State University.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market for Common Stock
Our common stock is listed on the New York Stock Exchange (NYSE) under the symbol “NFX.” The following table sets forth, for each of the periods indicated, the high and low reported sales price of our common stock on the NYSE.
On February 20, 2015, the last reported sales price of our common stock on the NYSE was $32.09. As of that date, there were approximately 1,526 holders of our common stock.
Dividends
We have not paid any cash dividends on our common stock and do not intend to do so in the foreseeable future. We intend to retain earnings for the future operation and development of our business. Any future cash dividends to holders of our common stock would depend on future earnings, capital requirements, our financial condition and other factors determined by our Board of Directors. The covenants contained in our credit facility and in the indentures governing our 6⅞% Senior Subordinated Notes due 2020, our 5¾% Senior Notes due 2022 and our 5⅝% Senior Notes due 2024 could restrict our ability to pay cash dividends. See “Contractual Obligations” under Item 7 of this report and Note 9, “Debt,” to our consolidated financial statements in Item 8 of this report.
Issuer Purchases of Equity Securities
The following table sets forth certain information with respect to repurchases of our common stock during the three months ended December 31, 2014.
_________________
(1)
All of the shares repurchased were surrendered by employees to pay tax withholding upon the vesting of restricted stock awards and restricted stock units. These repurchases were not part of a publicly announced program to repurchase shares of our common stock.
Stockholder Return Performance Presentation
The performance presentation below is being furnished pursuant to applicable rules of the SEC. As required by these rules, the performance graph was prepared based upon the following assumptions:
•
$100 was invested in our common stock, the S&P 500 Index, the Philadelphia Oil/Exploration & Production Index (EPX) and our peer group on December 31, 2009 at the closing price on such date;
•
investment in our peer group was weighted based on the stock market capitalization of each individual company within the peer group at the beginning of the period; and
•
dividends were reinvested on the relevant payment dates.
For 2015, we refreshed our peer group to better reflect our focus on U.S. domestic resource plays.
New Peer Group. Our new peer group consists of Cimarex Energy Co., Continental Resources Inc., EP Energy Corp., QEP Resources Inc., SandRidge Energy Inc., SM Energy Company and Whiting Petroleum Corporation.
Prior Peer Group. Our prior peer group consisted of Bill Barrett Corp., Carrizo Oil & Gas Inc., EP Energy Corp., Halcon Resources Corp., QEP Resources Inc., Rosetta Resources Inc., SandRidge Energy Inc. and SM Energy Company.
Comparison of Five-Year Cumulative Total Return

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. Selected Financial Data
SELECTED FIVE-YEAR FINANCIAL DATA
The following table shows selected consolidated financial data derived from our consolidated financial statements set forth in Item 8 of this report. The data should be read in conjunction with Items 1 and 2, “Business and Properties,” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of this report.
_________________
(1) Continuing operations only (excludes Malaysia).

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Overview
We are an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids. Our principal areas of operation include the Mid-Continent, Rocky Mountains and onshore Gulf Coast regions of the United States. Internationally, we have offshore oil developments in China.
To maintain and grow our production and cash flows, we must continue to develop existing proved reserves and locate or acquire new oil and natural gas reserves to replace those reserves being produced. Our revenues, profitability and future growth depend substantially on prevailing prices for oil, natural gas and NGLs and on our ability to find, develop and acquire oil and natural gas reserves that are economically recoverable. Prices for oil, natural gas and NGLs fluctuate widely and affect:
•the amount of cash flows available for capital expenditures;
•our ability to borrow and raise additional capital; and
•the quantity of oil, natural gas and NGLs that we can economically produce.
Crude oil and natural gas prices decreased significantly during the fourth quarter of 2014 and have remained low into the first quarter of 2015. Nevertheless, we had many operational, financial and strategic successes in 2014. As a result, we believe we are better positioned to face the challenges of 2015.
Significant 2014 highlights include:
•
domestic production increased 20% over 2013 to 46.4 MMBOE, excluding approximately 8.5 Bcf of natural gas produced and consumed in operations;
•
domestic liquids production up 38% over 2013;
•
best in class well in each region: Uinta, Anadarko and Williston Basins;
•
net acres in the Anadarko Basin increased to nearly 300,000;
•
our Pearl development in China achieved first oil and commenced production in the fourth quarter;
•
income from operations increased $125 million over 2013 to $575 million;
•
lease operating expense for continuing operations, on a per BOE basis, decreased 5% year-over-year;
•
general and administrative expense for continuing operations, on a per BOE basis, decreased 15% year-over-year;
•
net derivative asset of $613 million recognized, $423 million of which is current;
•
sold our Granite Wash assets for $588 million and used proceeds from the sale to redeem our 2018 Senior Subordinated Notes of $600 million;
•
sold our Malaysia business for $898 million and used the proceeds from the sale to fund 2014 capital expenditures;
•
reduced debt and strengthened our balance sheet through divestitures; and
•
released inaugural Corporate Responsibility Report.
Building on the results of 2014, we have adapted our 2015 business plan to focus on the following goals in response to this period of dramatic oil and natural gas price declines:
•
maintain and prioritize liquidity preservation over reserve and production growth;
•
match capital investments with cash flows from operations;
•
allocate the majority of capital to the Anadarko Basin of Oklahoma;
•
implement a plan to reduce gross general and administrative expenses by 10% to 15%; and
•
implement a plan to reduce domestic per unit lease operating costs by approximately 5 to 15%.
While we expect to achieve savings from cost reductions during 2015, given the lower oil and natural gas price environment as compared to 2014, our revenues and operating income are expected to be lower in 2015 as compared to 2014.
Discontinued Operations
During the second quarter of 2013, our businesses in Malaysia and China met the criteria to be classified as held for sale and reported as discontinued operations. In February 2014, Newfield International Holdings Inc., a wholly-owned subsidiary of the Company, closed the sale of our Malaysia business to SapuraKencana Petroleum Berhad, a Malaysian public company, for $898 million. See Note 1, “Organization and Summary of Significant Accounting Policies,” and Note 3, “Discontinued Operations,” to our consolidated financial statements in Item 8 of this report for additional information regarding the sale of our Malaysia business. During 2014, we continued to market our China business with bids due December 2014. Due to the precipitous decline in oil prices in the fourth quarter, we were unable to sell our China business at an acceptable price and determined it was in the Company's best interest to retain the cash flow from the China business. Accordingly, we reclassified this business as continuing operations for all periods presented.
Results of Continuing Operations
Our continuing operations consist of exploration, development and production activities in the United States and China. The production and average realized prices tables below include our Gulf of Mexico operations for 2012. In the 2012 discussion below, we excluded revenue of $116 million and production of 2,369 MBOE related to our Gulf of Mexico assets that were fully divested in the fourth quarter of 2012 in order to provide a more comparable analysis of our continuing operations.
Domestic Revenues. Revenues from domestic operations of $2.2 billion for the year ended December 31, 2014 were 26% higher than 2013. The increase was primarily due to a 38% year-over-year increase in our liquids production. Increased oil production generated approximately 81% of the total revenue increase due to production increases in our Mid-Continent, onshore Gulf Coast and Rocky Mountains regions of 51%, 26% and 26%, respectively. The increase related to higher oil production was partially offset by lower oil prices, which reduced the overall oil volume and price impact to 58% of the total revenue growth. Increased NGL production in the Mid-Continent, onshore Gulf Coast and Rocky Mountains regions of 67%, 44% and 35%, respectively, during the year ended December 31, 2014 generated approximately 20% of the total revenue increase. Approximately 18% of the total revenue increase was due to higher natural gas prices received during the year ended December 31, 2014 compared to the year ended December 31, 2013.
Revenues from domestic operations of $1.8 billion for the year ended December 31, 2013 were 32% higher than 2012. The increase was primarily due to higher liquids production and commodity prices in 2013. Our liquids production increased 43% year-over-year. As expected, our natural gas production declined as we continued to focus capital investments on higher-margin liquids production. Approximately 58% of the revenue increase in 2013 was attributable to increases in oil production in our Mid-Continent, onshore Gulf Coast and Rocky Mountains regions of 47%, 59% and 18%, respectively. Higher realized oil prices also increased revenues along with this favorable volume variance. Additionally, revenues increased 21% due to year-over-year NGL production increases in the Mid-Continent, onshore Gulf Coast and Rocky Mountains regions of 180%, 59% and 23%, respectively, partially offset by lower NGL prices. While natural gas production declined 14% in 2013, a 29% increase in the realized price during the period more than offset the negative production impact on revenue.
China Revenues. Our China revenues are recorded when oil is lifted and sold, not when it is produced into floating storage facilities. As a result, the timing of liftings may impact period-to-period results.
Revenues from China of $39 million for the year ended December 31, 2014 were 43% lower than 2013. The decrease was primarily due to the temporary shut-in of production in Bohai Bay by the operator during the second and third quarters of 2014 for scheduled repair and maintenance activities, along with a 24% decrease in oil price during 2014. Revenues from China of $69 million for the year ended December 31, 2013 were 20% lower than 2012. The decrease was primarily due to 18% lower production and slightly lower commodity prices.
The following table reflects our production from continuing operations and average realized commodity prices:
_________________
(1)
Excludes natural gas produced and consumed in operations of 8.5 Bcf in 2014, 8.1 Bcf in 2013 and 7.8 Bcf in 2012.
(2)
Represents our net share of volumes sold regardless of when produced.
(3)
We had no outstanding derivative contracts related to our NGL production or our production associated with our international operations. Had we included the realized effects of derivative contracts, the domestic average realized prices would have been as follows:
Domestic Production. For the year ended December 31, 2014, production from domestic operations increased 20% primarily due to increased liquids production. Our total 2014 domestic liquids production increased 38% over the prior year due to the success of our liquids-focused drilling programs. Almost 60% of the increase in total liquids was attributable to higher margin crude oil. Natural gas production increased 2% due to associated gas production generated by our liquids-focused drilling programs.
For the year ended December 31, 2013, production from domestic operations increased 7% over the prior year. Crude oil and NGL production increased 43% in 2013 but was partially offset by decreases in natural gas production across our domestic regions. The decrease in natural gas production was due to natural decline as a result of reduced investment in natural gas wells. More than half of the increase in total liquids in 2013 was attributable to higher margin crude oil.
China Production/Liftings. For the year ended December 31, 2014, production from China decreased 25% compared to the same period in 2013 primarily due to the temporary shut-in of production in Bohai Bay by the operator between May and
August 2014 for scheduled repairs and maintenance activities. Production resumed in August 2014; however, we had not accumulated sufficient quantities to schedule a lifting during the remainder of the year. Liftings from Bohai Bay are expected to resume in the first quarter of 2015. The decrease in liftings from Bohai Bay was partially offset by the first lifting from our Pearl development in December 2014. Our Pearl development achieved first oil in the fourth quarter of 2014 after the repaired LF-7 topside facilities were installed in August 2014.
For the year ended December 31, 2013, production from China decreased 18% compared to the same period in 2012 due to natural production decline combined with no wells drilled in the last nine months of the year.
Operating Expenses.
Year ended December 31, 2014 compared to December 31, 2013
The following table presents information about operating expenses for our continuing operations:
Domestic Operations. For the year ended December 31, 2014, total operating expenses per BOE for domestic operations increased 2% as compared to the year ended December 31, 2013. The primary reasons for the change follow:
•
Lease operating expenses decreased 7% on a per BOE basis. Higher production volumes, coupled with flat year-over-year well repair costs in all areas, generated approximately 60% of the per BOE reduction. The remaining decrease relates primarily to successful water and compression cost management initiatives in our Williston Basin, Mid-Continent and onshore Gulf Coast areas.
•
Transportation and processing expense increased 6% on a per BOE basis primarily due to a 59% increase in NGL volumes processed during 2014.
•
Production and other taxes as a percent of revenue increased 1%. Approximately one-half of this increase is the result of higher tax incentives as well as an ad valorem tax true-up in 2013. The remaining increase, on a percent of revenue basis, is primarily due to the significant growth of our Williston Basin production, which is subject to a higher production tax rate. On a per BOE basis, the increase is driven by increased liquids production as a percent of total production, and the associated increase in average revenue per BOE produced from $45.91 for the year ended December 31, 2013 to $48.41 for the year ended December 31, 2014.
•
Total depreciation, depletion and amortization (DD&A) increased 28% primarily due to the 20% increase in production volumes in 2014 compared to 2013, combined with a 7% increase in the cost per unit of production. The increased cost per unit of production is primarily due to the transfer of approximately $760 million of unevaluated property costs into the full cost pool amortization base during the year. The majority of the costs were transferred in the fourth quarter in response to the significant decrease in oil and natural gas prices and the resulting impact on our future development plans.
•
General and administrative (G&A) expense on a per BOE basis decreased 16% primarily due to increased production in 2014 as compared to 2013. G&A expense was flat year-over-year as increased employee-related expenses in 2014 were offset by higher capitalization of direct internal costs. Employee-related expenses increased by $32 million for stock-based compensation, primarily due to our Stockholder Value Appreciation Program, which achieved three payout targets in 2014 compared to one in 2013 (see Note 11, "Stock-based Compensation," to our consolidated financial statements in Item 8 of this report). The increase in stock-based compensation expense was partially offset by a decrease of $13 million in labor-related costs associated primarily with the centralization of certain functions during the second half of 2013. For the year ended December 31, 2014, we capitalized $135 million ($2.90 per BOE) of direct internal costs as compared to $107 million ($2.77 per BOE) during the comparable period of 2013. This increase is primarily due to a higher portion of the costs associated with stock-based liability awards earned by employees who are directly involved with our exploration and development activities.
•
Other operating expense increased $12 million primarily due to equipment inventory value impairments and legal settlements during 2014 as compared to 2013.
China Operations. For the year ended December 31, 2014, total operating expenses per BOE for our China operations increased 11% compared to the year ended December 31, 2013. Results for 2014 include activity from Bohai Bay and our Pearl development, whereas 2013 results include only Bohai Bay.
LOE per barrel increased over 100% as a result of one-time production preparation costs associated with our Pearl development, a higher tariff on crude oil produced from our Pearl development and higher operating costs associated with deep water operations for Pearl. These increases were partially offset by a 37% decrease in production and other taxes per BOE, primarily due to the timing of liftings in China. Approximately 60% of our liftings in China were in the fourth quarter of 2014, which had significantly lower realized prices than 2013.
We expect that 2015 revenues and expenses in China will increase over 2014 as we execute our Pearl development plan. In January 2015, we completed one well, and we plan to drill 4 additional wells during the year. The Pearl development is expected to reach peak production by mid-2015.
Year ended December 31, 2013 compared to December 31, 2012
The following table presents information about our operating expenses for our continuing operations:
Domestic Operations. For the year ended December 31, 2013, total operating expenses for domestic operations increased 7% but were flat on a per BOE basis after adjusting for the 2012 ceiling test writedown and operating expenses of $102 million attributable to Gulf of Mexico assets that were fully divested in the fourth quarter of 2012. The components of significant period-to-period change for operating expenses excluding Gulf of Mexico related expenses related to 2012 are as follows:
•
Lease operating expense decreased 2% on a per BOE basis primarily due to lower well repair costs in our Williston Basin, Mid-Continent and onshore Gulf Coast areas.
•
Transportation and processing expense increased 22% on a per BOE basis primarily due to increased NGL volumes as a percent of total production resulting from our liquids-focused drilling program.
•
Production and other taxes were flat on an actual cost and per unit basis. However, on a percent of revenue basis, they fell approximately 1%. This rate reduction is primarily attributable to production tax credits received in the Mid-Continent, onshore Gulf Coast and Uinta basins plus an $8 million adjustment of ad valorem taxes in the Uinta Basin previously expensed in 2012 and prior years. Without the ad valorem tax adjustment in the Uinta Basin, production and other taxes on a percent of revenue basis would have decreased by less than a half of a percent.
•
General and administrative expense increased during 2013 primarily due to employee-related expenses associated with our Voluntary Severance Program and Stockholder Value Appreciation Program (see Note 11, "Stock-Based Compensation," to our consolidated financial statements in Item 8 of this report), partially offset by the cost savings generated by the centralization of several administrative functions. During 2013, we capitalized $107 million ($2.77 per BOE) of direct internal costs as compared to $95 million ($2.45 per BOE) during 2012.
•
In the fourth quarter of 2012, we recorded a ceiling test writedown of $1.5 billion due to a net decrease in the discounted value of our proved reserves. The primary reason for the change in value was negative price-related reserve revisions as a result of a 33% decrease in the natural gas SEC pricing.
•
Other expenses in 2012 of $15 million included a writedown of $8 million of subsea wellhead inventory that was not included in the sale of our Gulf of Mexico assets and contract termination costs of $6 million in consideration of other services.
China Operations. For the year ended December 31, 2013, total operating expenses for China operations decreased by $9 million compared to the same period in 2012. This overall decrease is consistent with the 18% decrease in production volumes in 2013 compared to 2012.
Interest Expense. The following table presents information about interest expense for each of the following years ended
December 31:
Gross interest expense decreased slightly in 2014 as compared to 2013, due to the redemption of our 7⅛% Senior Subordinated Notes due 2018 in October 2014. Gross interest expense remained flat in 2013 as compared to 2012 due to the restructuring of our senior notes in 2012. See Note 9, “Debt,” to our consolidated financial statements in Item 8 of this report.
Interest expense associated with oil and gas properties excluded from amortization is capitalized into oil and gas properties. The average balance of oil and gas properties excluded from amortization was consistent for the first three quarters of 2014 resulting in flat capitalized interest in 2014 as compared to 2013. We expect to see less capitalized interest in 2015 due to the reduction of oil and gas properties excluded from amortization at December 31, 2014. Capitalized interest decreased in 2013 as compared to 2012, due to a reduction in our average balance of oil and gas properties excluded from amortization.
Commodity Derivative Income (Expense). The fluctuations in commodity derivative income (expense) from period to period are due to the volatility of oil and natural gas prices and changes in our outstanding derivative contracts during these periods. Commodity derivative income for the year ended December 31, 2014 was $610 million, which was primarily comprised of unrealized gains of $649 million related to the change in value of derivative contracts due to changes in commodity prices, offset by $39 million of realized losses associated with derivative contract settlements. Commodity derivative expense for the year ended December 31, 2013 was $97 million, which was primarily comprised of unrealized losses of $157 million related to the change in value of derivative contracts due to changes in commodity prices, offset by $60 million of realized gains associated with derivative contract settlements. See Note 5, "Derivative Financial Instruments," and Note 8, "Fair Value Measurements," to our consolidated financial statements in Item 8 of this report.
Taxes. The effective tax rates for continuing operations for the years ended December 31, 2014, 2013 and 2012 were 37%, 64% and 33%, respectively. Our effective tax rate for all periods was different than the federal statutory rate of 35% due to non-deductible expenses, state income taxes, the differences between international and U.S. federal statutory rates, and the impact of our China earnings being taxed both in the U.S and China. This double taxation is a byproduct of our federal net operating loss (NOL) position which limits our ability to utilize related foreign tax credits (FTC) until our remaining NOLs are
utilized. As a result of our earnings in China being taxed in both the U.S. and China, we expect our effective tax rate for future China earnings to be approximately 60%. We expect the U.S. portion of the rate to be a 35% tax rate, all of which is expected to be deferred taxes.
Our effective tax rate for our domestic operations generally approximates 37%. For the year ended 2014, our effective tax rate was 37% for continuing operations as the majority of our income from continuing operations resulted from our domestic business, which was only taxable in the U.S. As a result of our December 2012 decision to repatriate earnings from our international operations, we experienced fluctuation in our effective tax rates in 2013 and 2012 due to these earnings being taxed both in the U.S. and the local countries. Please see the discussion and tables in Note 10, “Income Taxes,” to our consolidated financial statements in Item 8 of this report.
Estimates of future taxable income can be significantly affected by changes in oil and natural gas prices; the timing, amount and location of future production; operating expenses; and capital costs.
Results of Discontinued Operations - Malaysia
Revenues and Liftings. Our Malaysia revenues were primarily from the sale of crude oil. Substantially all of the crude oil from our offshore Malaysia operations was produced into FPSOs and "lifted" and sold periodically as barge quantities were accumulated. Revenues were recorded when oil was lifted and sold, not when it was produced into FPSOs or onshore storage terminals. As a result, timing of liftings impacted period-to-period results. In February 2014, we closed the sale of our Malaysia business. See Note 1, “Organization and Summary of Significant Accounting Policies” and Note 3, “Discontinued Operations,” to our consolidated financial statements appearing in Item 8 of this report for additional information regarding the sale.
For the year ended December 31, 2014, revenues from discontinued operations of $90 million were 89% lower than 2013, due to the sale of our Malaysia business in February 2014. Revenues of $823 million for 2013 were 18% lower than 2012, primarily due to fewer liftings of crude oil. The average realized price per BOE remained essentially flat during 2012, 2013 and 2014 through the close date of the sale. Our 2013 total liftings decreased 18% as compared to 2012. Approximately 65% of the decrease in liftings was due to natural decline. The remainder of the decrease was due to the timing of liftings and the terms of the production sharing contracts (PSCs) in Malaysia, which reduced entitled production as we reached certain cost recovery milestones.
The following table reflects our production and average realized commodity prices from discontinued operations for each of the following years ended December 31:
________________
(1)
Represents our net share of volumes sold regardless of when produced.
Operating Expenses. The following tables present information about our operating expenses for our discontinued operations.
Year ended December 31, 2014 compared to December 31, 2013
Our total operating expenses for discontinued operations for 2014 decreased $583 million compared to the same period of 2013 as a result of the sale of our Malaysia business in February 2014.
Year ended December 31, 2013 compared to December 31, 2012
Our operating expenses for discontinued operations for 2013, stated on a per BOE basis, increased 29% over 2012. The components of the period-to-period change are as follows:
•
LOE per BOE increased 41% ($4.50 per BOE) due to increased service costs related to offshore support operations in Malaysia and mostly-fixed fees associated with producing into onshore storage terminals in Malaysia combined with fewer liftings.
•
Production and other taxes per BOE increased 29% due to the terms of the PSCs in Malaysia, which increased production tax rates subsequent to reaching certain cost recovery milestones.
•
DD&A expense decreased 2% due to an 18% decrease in liftings during 2013 as compared to 2012, partially offset by an increase in the average DD&A rate. Our DD&A rate per BOE increased 19% in 2013 compared to 2012 due primarily to upward revisions of asset retirement costs in 2013 for Malaysia and the costs of unsuccessful wells in offshore Malaysia being included in costs subject to amortization in the second quarter of 2013 without a related increase in reserves.
•
G&A expense increased approximately $11 million ($1.56 per BOE) primarily due to increased employee-related costs and other costs associated with our decision to sell our Malaysia business.
Liquidity and Capital Resources
The following discussion is inclusive of both our continuing and discontinued operations, unless otherwise noted.
We must find new and develop existing reserves to maintain and grow our production and cash flows. We accomplish this through drilling programs and property acquisitions, which require substantial capital expenditures. Sustained lower prices for oil, natural gas and NGLs will reduce the amount of oil and gas that we can economically produce and will affect the amount of cash flow available for capital expenditures. Sustained lower commodity prices may also impact our ability to borrow and raise additional capital, as further described below.
We establish a capital budget at the beginning of each calendar year and review it during the course of the year. Our capital budgets (excluding acquisitions) are created based upon our estimate of internally generated sources of cash, as well as the available borrowing capacity of our revolving credit facility and money market lines of credit.
During the fourth quarter of 2014 and continuing into the first quarter of 2015, crude oil prices declined significantly primarily due to global supply and demand imbalances. Given the future uncertainty regarding the timing and magnitude of an eventual recovery of crude oil prices, we have reduced our planned capital spending for 2015 to more closely match our expected cash flows and have decided to optimize long-term liquidity preservation over short-term reserve and production growth. We expect our 2015 budget will be financed through our cash flows from operations (inclusive of realized derivative contract gains and losses) and borrowings under our credit facility, as needed. Approximately 82% of our expected 2015 domestic oil and gas sales (excluding NGLs) supporting the current 2015 capital budget are partially protected against oil and gas price volatility using derivative contracts. For further discussion of our derivative activities, see Note 5, "Derivative Financial Instruments," to our consolidated financial statements in Item 8 of this report. Our 2015 capital budget, excluding estimated capitalized interest and direct internal costs of approximately $120 million, is expected to be approximately $1.2 billion.
At December 31, 2014, the values of our U.S. and China cost center ceilings were calculated based upon SEC pricing of $4.35 per MMBtu for natural gas and $94.98 per barrel for oil. Using these prices, our ceilings for the U.S. and China exceeded the net capitalized costs of oil and gas properties by approximately $400 million and $150 million, respectively, net of tax, and as such, no ceiling test writedown was required. Holding all other factors constant, it is likely that we will experience a ceiling test writedown in the U.S. and China in the first quarter of 2015. It is difficult to predict with reasonable certainty the amount of expected future impairments given the many factors impacting the ceiling test calculation including, but not limited to, future pricing, operating costs, upward or downward reserve revisions, reserve adds, and tax attributes. Subject to these numerous factors and inherent limitations, we believe that an impairment in the first quarter of 2015 could exceed $750 million. Once recorded, a ceiling test writedown is not reversible at a later date even if oil and gas prices increase.
Actual capital expenditure levels may vary significantly due to many factors, including drilling results; oil, natural gas and NGL prices; industry conditions; the prices and availability of goods and services; and the extent to which properties are acquired or non-strategic assets are sold. We continue to screen for attractive acquisition opportunities; however, the timing and size of acquisitions are unpredictable. We believe we have the operational flexibility to react quickly with our capital expenditures to changes in circumstances or fluctuations in our cash flows.
We continuously monitor our liquidity needs, coordinate our capital expenditure program with our expected cash flows and projected debt-repayment schedule, and evaluate our available alternative sources of liquidity, including accessing debt and equity capital markets in light of current and expected economic conditions. We believe that our liquidity position and ability to generate cash flows from our operations will be adequate to fund 2015 operations and continue to meet our other obligations.
Credit Arrangements and Other Financing Activities. We maintain a revolving credit facility of $1.4 billion that matures in June 2018, as well as money market lines of credit of $195 million. At December 31, 2014, we had $345 million of LIBOR based loans outstanding against our revolving credit facility and $101 million outstanding against our money market lines of credit. In October 2014, we completed the redemption of our $600 million aggregate principal of 7⅛% Senior Subordinated Notes due 2018. The transaction included a premium payment of approximately $14 million. At December 31, 2014, we had no scheduled maturities of senior or senior subordinated notes until 2020. For a more detailed description of the terms of our credit arrangements and senior and senior subordinated notes, please see Note 9, “Debt,” to our consolidated financial statements in Item 8 of this report.
Our credit facility has restrictive financial covenants that include the maintenance of a ratio of total debt to book capitalization not to exceed 0.6 to 1.0 and maintenance of a ratio of earnings before gain or loss on the disposition of assets, interest expense, income taxes and certain noncash items to interest expense of at least 3.0 to 1.0. At December 31, 2014, we were in compliance with all of our debt covenants. We entered this challenging commodity price environment with strong debt covenant-related financial ratios and do not foresee this changing in 2015. For a more detailed description of the terms of our credit arrangements, please see Note 9, “Debt ,” to our consolidated financial statements in Item 8 of this report.
As of February 20, 2015, we had outstanding borrowings of $610 million and available borrowing capacity of approximately $790 million under our revolving credit facility. In addition, we had outstanding borrowings under our money market lines of credit of $85 million.
Working Capital. Our working capital balance fluctuates as a result of the timing and amount of borrowings or repayments under our credit arrangements, changes in the fair value of our outstanding commodity derivative instruments as well as the timing of receiving reimbursement of amounts paid by us for the benefit of joint venture partners. Without the effects of commodity derivative instruments, we typically have a working capital deficit or a relatively small amount of positive working capital.
At December 31, 2014 and 2013, we had negative working capital of $161 million and $389 million, respectively. The changes in our working capital from 2013 to 2014 are primarily a result of a $485 million increase in the fair value of our current net derivative asset during 2014 combined with working capital reductions associated with the sale of our Malaysia business (February 2014) and our Granite Wash assets (September 2014). The remaining change is due to the timing of the collection of receivables; the timing of crude oil liftings in our China operations; drilling activities; payments made by us to vendors and other operators; and the timing and amount of advances received from our joint operations.
Cash Flows from Operations. Our primary source of capital and liquidity are cash flows from operations, which are primarily affected by the sale of oil, natural gas and NGLs, as well as commodity prices, net of the effects of settled derivative contracts, as well as changes in working capital.
Our net cash flows from operations were approximately $1.4 billion in 2014 (includes $3 million of cash flows from our Malaysia discontinued operations), $1.4 billion in 2013 and $1.1 billion in 2012. Despite selling our Malaysia business, which provided approximately $249 million of our 2013 cash flows from operations, our 2014 cash flows from operations were relatively flat compared to 2013. This is a result of increased domestic production, strong pricing during the first nine months of the year and a $0.42 per BOE decrease in domestic operating expenses (excluding non-cash DD&A expense) during the year.
Cash Flows from Investing Activities. Net cash used in investing activities for 2014 was $660 million compared to $2.1 billion for 2013. The decrease in net cash used in 2014 investing activities is primarily due to net proceeds of $809 million received from the sale of our Malaysia business and proceeds of approximately $620 million from the sale of our Granite Wash and other assets. Our investment levels in our oil and gas properties were relatively consistent during 2014 and 2013 as we executed our plan in a stable commodity price environment into third quarter 2014. Due to the dramatic commodity price decline in fourth quarter 2014, we expect a significant decrease in our investments during 2015.
Cash Flows from Financing Activities. Net cash used in financing activities for 2014 was $808 million compared to net cash provided by financing activities of $620 million for 2013. During 2014, we reduced our outstanding borrowings under our revolving credit facility and money market lines of credit by $203 million and redeemed our $600 million aggregate principal of 7⅛% Senior Subordinated Notes due 2018 using the proceeds from the sale of our Granite Wash assets.
Capital Expenditures. Our capital investments for continuing operations for 2014 increased 5% compared to 2013, due to accelerating the development of our domestic assets during 2014. The table below summarizes our capital investments.
Contractual Obligations
The table below summarizes our significant contractual obligations due by year as of December 31, 2014.
_________________
(1)
Excludes assets and liabilities associated with our derivative contracts. For a discussion regarding our derivative contracts, see Note 5, "Derivative Financial Instruments," to our consolidated financial statements in Item 8 of this report, which is incorporated herein by reference.
(2)
Includes agreements for office space, drilling rigs and other equipment, as well as certain service contracts. The majority of these obligations are related to contracts for office space and drilling rigs and are included at the gross contractual value. Due to our various working interests where the drilling rig contracts will be utilized, it is not feasible to estimate a net contractual obligation. Net payments under these contracts are accounted for as capital additions to our oil and gas properties and could be significantly less than the gross obligation disclosed.
We have various oil and gas production volume delivery commitments that are related to our domestic operations. Given the recent decline in oil and natural gas prices and the related impact on our 2015 planned capital investments as well as the potential impact on development plans in future years, we could fail to deliver the minimum production required under these commitments. In the event that we are unable to meet our crude oil volume delivery commitments, we would incur deficiency fees ranging from $1.83 to $6.50 per barrel. See Items 1 and 2, “Business and Properties” for a description of our production and proved reserves. As of December 31, 2014, our delivery commitments through 2025 were as follows:
_________________
(1)
Our oil delivery commitments include commitments with Salt Lake City, Utah refiners. Our delivery commitments are for approximately 18,000 barrels of oil per day through 2020 and an additional 20,000 barrels of oil per day expected to start in 2016 and continuing through 2025. The 20,000 barrel per day delivery commitment represents approximately 7,300 MBbls of our committed oil volumes for each of the years 2016 through 2025. The timing may change due to timing of the refinery expansion completion. These commitments relate to our Uinta Basin production.
Commitments under Joint Operating Agreements. Most of our properties are operated through joint ventures under joint operating or similar agreements. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and
in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a “working interest” basis. The joint operating agreement provides remedies to the operator if a non-operator does not satisfy its share of the contractual obligations. Occasionally, the operator is permitted by the joint operating agreement to enter into lease obligations and other contractual commitments that are then passed on to the non-operating joint interest owners as lease operating expenses, frequently without any identification as to the long-term nature of any commitments underlying such expenses.
Oil and Gas Derivatives
We use derivative contracts to manage the variability in cash flows caused by commodity price fluctuations associated with our anticipated future oil and gas production for the next 24 to 36 months. As of December 31, 2014, we had no outstanding derivative contracts related to our NGL production or on production associated with our discontinued operations. We do not use derivative instruments for trading purposes.
For a further discussion of our derivative activities, see "Critical Accounting Policies and Estimates - Commodity Derivative Activities" below and "Oil, Natural Gas and NGL Prices" in

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risk from changes in oil, natural gas and NGL prices, interest rates and foreign currency exchange rates as discussed below.
Oil, Natural Gas and NGL Prices
Our decision on the quantity and price at which we choose to enter into derivative contracts is based in part on our view of current and future market conditions. While the use of derivative contracts can limit or reduce the downside risk of adverse price movements, their use also may limit future benefits from favorable price movements. In addition, the use of derivative contracts may involve basis risk. All of our derivative transactions have been carried out in the over-the-counter market. The use of derivative contracts also involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. At December 31, 2014, ten of our 16 counterparties accounted for approximately 85% of our contracted volumes with no single counterparty accounting for more than 15%. Of our expected 2015 crude oil production, 87% is protected against price volatility through the use of derivative contracts. Almost 90% of our crude oil derivative structures include short puts. Short puts effectively limit our downward price protection below the weighted average of our short puts of $71.83 per barrel. If the market price remains below $71.83 per barrel, we receive the market price for our associated production plus the difference between our short puts and the associated floors or fixed-price swaps, which average $18.19 per barrel. We do not have any natural gas derivative contracts that include short puts. For a further discussion of our derivative activities, see the information under the captions “Oil and Gas Derivatives” and “Critical Accounting Policies and Estimates” in Item 7 of this report and the discussion and tables in Note 5, “Derivative Financial Instruments,” to our consolidated financial statements in

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED FINANCIAL STATEMENTS
AND SUPPLEMENTARY INFORMATION
Page
Management’s Report on Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheet as of December 31, 2014 and 2013
Consolidated Statement of Operations for each of the three years in the period ended December 31, 2014
Consolidated Statement of Comprehensive Income for each of the three years in the period ended December 31, 2014
Consolidated Statement of Cash Flows for each of the three years in the period ended December 31, 2014
Consolidated Statement of Stockholders’ Equity for each of the three years in the period ended December 31, 2014
Notes to Consolidated Financial Statements
Supplementary Financial Information - Supplementary Oil and Gas Disclosures - Unaudited
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Our Company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles. Under the supervision and with the participation of our Company’s management, including the Chief Executive Officer and the Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Our internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on our evaluation under the framework in Internal Control - Integrated Framework (2013), the management of our Company concluded that our internal control over financial reporting was effective as of December 31, 2014.
The effectiveness of our internal control over financial reporting as of December 31, 2014 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report that follows.
Lee K. Boothby
Lawrence S. Massaro
President and Chief Executive Officer
Executive Vice President and Chief Financial Officer
The Woodlands, Texas
February 24, 2015
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Newfield Exploration Company:
In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of comprehensive income, of stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of Newfield Exploration Company and its subsidiaries at December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Houston, Texas
February 24, 2015
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(In millions, except share data)
The accompanying notes to consolidated financial statements are an integral part of this statement.
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF OPERATIONS
(In millions, except per share data)
The accompanying notes to consolidated financial statements are an integral part of this statement.
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(In millions)
The accompanying notes to consolidated financial statements are an integral part of this statement.
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
The accompanying notes to consolidated financial statements are an integral part of this statement.
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
(In millions)
The accompanying notes to consolidated financial statements are an integral part of this statement.
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1.
Organization and Summary of Significant Accounting Policies:
Organization and Principles of Consolidation
We are an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids (NGLs). Our principal domestic areas of operation include the Mid-Continent, the Rocky Mountains and the onshore Gulf Coast regions of the United States. In addition, we have offshore oil developments in China.
Our consolidated financial statements include the accounts of Newfield Exploration Company, a Delaware corporation, and its subsidiaries. We proportionately consolidate our interests in oil and natural gas exploration and production ventures and partnerships in accordance with industry practice. All significant intercompany balances and transactions have been eliminated. Unless otherwise specified or the context otherwise requires, all references in these notes to “Newfield,” “we,” “us,” “our” or the “Company” are to Newfield Exploration Company and its subsidiaries.
Discontinued Operations
Our businesses in Malaysia and China were classified as held for sale in the second quarter of 2013. As of December 31, 2014, our China business is no longer held for sale, as we concluded the marketing process and were unable to sell at an acceptable price given the significant decrease in oil prices in the fourth quarter of 2014. Therefore, our China business is included in continuing operations for all periods in these financial statements. The results of our Malaysia operations are reflected separately as discontinued operations in the consolidated statement of operations on a line immediately after "Income (loss) from continuing operations." See Note 3, "Discontinued Operations," for additional disclosures, as well as information regarding the sale of our Malaysia business, which closed in February 2014. These financial statements and notes are inclusive of our Malaysia operations unless otherwise noted.
Risks and Uncertainties
As an independent oil and natural gas producer, our revenue, profitability and future rate of growth are substantially dependent on prevailing prices for oil, natural gas and NGLs. Historically, the energy markets have been very volatile, and there can be no assurance that commodity prices will not be subject to wide fluctuations in the future. A substantial or extended decline in commodity prices could have a material adverse effect on our financial position, results of operations, cash flows, access to capital and on the quantities of oil, natural gas and NGL reserves that we can economically produce. It is possible for any of these effects to occur in the near term, given the recent decline in commodity pricing.
Use of Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities; disclosure of contingent assets and liabilities at the date of the financial statements; the reported amounts of revenues and expenses during the reporting period; and the quantities and values of proved oil, natural gas and NGL reserves used in calculating depletion and assessing impairment of our oil and gas properties. Actual results could differ significantly from these estimates. Our most significant estimates are associated with the quantities of proved oil, natural gas and NGL reserves, the timing and amount of transfers of our unevaluated properties into our amortizable full cost pool and the fair value of both our derivative positions and our stock-based compensation liability awards.
Reclassifications
Certain reclassifications have been made to prior years’ reported amounts in order to conform to the current year presentation. These reclassifications did not impact our net income (loss), stockholders’ equity or cash flows.
Revenue Recognition
Substantially all of our oil, natural gas and NGLs are sold at market-based prices to a variety of purchasers under short-term contracts (less than 12 months). We also have long-term contracts in the Uinta Basin at market-based prices, less a variable differential that becomes fixed below certain market price thresholds. We record revenue when we deliver our production to the
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
customer and collectability is reasonably assured. Revenues from the production of oil, natural gas and NGLs on properties in which we have joint ownership are recorded under the sales method. Under the sales method, the Company and other joint owners may sell more or less than their entitled share of production. Should the Company’s excess sales exceed our share of estimated remaining recoverable reserves, a liability is recorded. Differences between sales and our entitled share of production are not significant.
Foreign Currency
The functional currency for our foreign operations is the U.S. dollar. Gains and losses incurred on transactions in a currency other than a country’s functional currency are recorded under the caption “Other income (expense) - Other, net” on our consolidated statement of operations.
Cash and Cash Equivalents
Cash and cash equivalents include highly liquid investments with a maturity of three months or less when acquired and are stated at cost, which approximates fair value. We invest cash in excess of near-term capital and operating requirements in U.S. Treasury Notes, Eurodollar time deposits and money market funds, which are classified as cash and cash equivalents on our consolidated balance sheet.
Restricted Cash and Deferred Liabilities
Restricted cash and the associated deferred liability on our consolidated balance sheet at December 31, 2013 represent a deposit received in the fourth quarter of 2013 related to the sale of our Malaysia business. Amounts were contractually restricted until the transaction closed in February 2014. See Note 3, "Discontinued Operations," for further discussion about the close of the sale of the Malaysia business.
Investments
Investments consist of debt and equity securities, a majority of which are classified as “available-for-sale” and stated at fair value. Accordingly, unrealized gains and losses and the related deferred income tax effects are excluded from earnings and reported in other comprehensive income within our consolidated statement of stockholders' equity. Realized gains or losses are computed based on specific identification of the securities sold. We regularly assess our investments for impairment and consider any impairment to be other than temporary if we intend to sell the security, it is more likely than not that we will be required to sell the security or we do not expect to recover our cost of the security.
Allowance for Doubtful Accounts
We routinely assess material trade and other receivables to determine their collectability. Many of our receivables are from joint interest owners of properties we operate. Thus, we may have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Generally, our oil and gas receivables are collected within 45 to 60 days of production. We accrue a reserve on a receivable when, based on the judgment of management, it is probable that a receivable will not be collected and the amount of the reserve may be reasonably estimated.
Inventories
Inventories primarily consist of tubular goods and well equipment held for use in our oil and natural gas operations and oil produced but not sold in our international operations. Tubular goods and well equipment inventories are carried at the lower of cost or market. During 2014, we wrote down obsolete inventory across all three of our domestic regions. At December 31, 2012, we wrote down subsea wellhead inventory that was not included in the sale of our Gulf of Mexico assets. The writedowns of $9 million in 2014 and $8 million in 2012 are included in “Operating expenses - Other” on our consolidated statement of operations.
Substantially all of the crude oil from our offshore operations in China is produced into floating storage facilities and “lifted” and sold periodically as barge quantities are accumulated. At December 31, 2014 and 2013, the crude oil inventory from our China operations consisted of approximately 240,000 and 23,000 barrels of crude oil valued at cost of approximately
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
$8 million and $1 million, respectively, and is included under the caption "Inventories" on our consolidated balance sheet. Cost for purposes of the carrying value of oil inventory is the sum of related production costs and depletion expense. See Note 3, "Discontinued Operations" for details on our Malaysia crude oil inventory.
Oil and Gas Properties
We use the full cost method of accounting for our oil and gas producing activities. Under this method, all costs incurred in the acquisition, exploration and development of oil and gas properties, including salaries, benefits, interest and other internal costs directly attributable to these activities, are capitalized into cost centers that are established on a country-by-country basis. We capitalized approximately $199 million, $198 million and $191 million of interest and direct internal costs in 2014, 2013 and 2012, respectively.
Proceeds from the sale of oil and gas properties are applied to reduce the costs in the applicable cost center unless the reduction would significantly alter the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized. During the first quarter of 2014, we sold our Malaysia business, which constituted the entire full cost pool for Malaysia. See Note 3, "Discontinued Operations," for further discussion.
Capitalized costs and estimated future development costs are amortized using a unit-of-production method based on proved reserves associated with the applicable cost center. For each cost center, the net capitalized costs of oil and gas properties are limited to the lower of the unamortized cost or the cost center ceiling. A particular cost center ceiling is equal to the sum of:
•
the present value (10% per annum discount rate) of estimated future net revenues from proved reserves using oil, natural gas and NGL reserve estimation requirements, which require use of the unweighted average first-day-of-the-month commodity prices for the prior 12 months (SEC pricing), adjusted for market differentials, applicable to our reserves (including the effects of derivative contracts that are designated for hedge accounting, if any); plus
•
the costs of properties not included in the costs being amortized, if any; less
•
related income tax effects.
If net capitalized costs of oil and gas properties exceed the cost center ceiling, we are subject to a ceiling test writedown to the extent of such excess. If required, a ceiling test writedown reduces earnings and stockholders’ equity in the period of occurrence and, holding other factors constant, results in lower depreciation, depletion and amortization expense in future periods.
The risk that we will be required to writedown the carrying value of our oil and gas properties increases when oil, natural gas and NGL prices decrease significantly for a prolonged period of time or if we have substantial downward revisions in our estimated proved reserves. At December 31, 2014, the ceiling value of our reserves was calculated based upon SEC pricing of $4.35 per MMBtu for natural gas and $94.98 per barrel for oil. Using these prices, our ceilings for the U.S. and China exceeded the net capitalized costs of oil and gas properties by approximately $400 million and $150 million, respectively, net of tax, and as such, no ceiling test writedown was required.
The continued decline of SEC pricing for oil and natural gas reserves since December 31, 2014 will likely result in a ceiling test writedown in the first quarter of 2015.
At December 31, 2013, the ceiling value of our reserves was calculated based upon SEC pricing of $3.67 per MMBtu for natural gas and $96.82 per barrel for oil. Using these prices, the cost center ceilings with respect to our domestic and China full cost pools exceeded the net capitalized costs. As such, no ceiling test writedowns were required at December 31, 2013.
At December 31, 2012, the ceiling value of our reserves was calculated based upon SEC pricing of $2.76 per MMBtu for natural gas and $94.84 per barrel for oil. Using these prices, the unamortized net capitalized costs of our domestic oil and gas properties exceeded the ceiling amount by approximately $1.5 billion ($948 million, after tax). No ceiling test writedown was required for the China full cost pool at December 31, 2012.
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
See Note 4, “Oil and Gas Assets,” for a detailed discussion regarding our oil and gas asset acquisitions and sales transactions during 2014, 2013 and 2012.
Other Property and Equipment
Furniture, fixtures and equipment are recorded at cost and are depreciated using the straight-line method over their estimated useful lives, which range from three to seven years. Gathering systems and equipment are recorded at cost and depreciated using the straight-line method over their estimated useful lives of 25 years.
Accounting for Asset Retirement Obligations
If a reasonable estimate of the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells can be made, we record a liability (an asset retirement obligation or ARO) on our consolidated balance sheet and capitalize the present value of the asset retirement cost in oil and gas properties in the period in which the ARO is incurred. Settlements include payments made to satisfy the AROs, as well as transfer of the AROs to purchasers of our divested properties.
In general, the amount of an ARO and the costs capitalized will equal the estimated future costs to satisfy the abandonment obligation assuming normal operation of the asset, using current prices that are escalated by an assumed inflation factor up to the estimated settlement date, which is then discounted back to the date that the abandonment obligation was incurred using an assumed cost of funds for our Company. After recording these amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds, and the original capitalized costs are depreciated on a unit-of-production basis within the related full cost pool. Both the accretion and the depreciation are included in depreciation, depletion and amortization expense on our consolidated statement of operations.
The change in our ARO for continuing operations for each of the three years ended December 31, is set forth below:
_________________
(1)
For the year ended December 31, 2014, additions include $28 million for our Pearl development in offshore China and $30 million for abandonment obligations in our domestic business.
(2)
For the year ended December 31, 2014, settlements include $10 million related to the sale of our Granite Wash assets. For the year ended December 31, 2012, settlements include $28 million related to the sale of our Gulf of Mexico assets. See Note 4, “Oil and Gas Assets.”
Contingencies
We are subject to legal proceedings, claims, liabilities and environmental matters that arise in the ordinary course of business. We accrue for losses when such losses are considered probable and the amounts can be reasonably estimated. See Note 13, “Commitments and Contingencies,” for a more detailed discussion regarding our contingencies.
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Environmental Matters
Environmental costs that relate to current operations are expensed as incurred. Remediation costs that relate to an existing condition caused by past operations are accrued when it is probable that those costs will be incurred and can be reasonably estimated based upon evaluations of currently available facts related to each site.
Income Taxes
We use the liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are determined by applying tax regulations existing at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in our financial statements. A valuation allowance is established to reduce deferred tax assets if it is more likely than not that the related tax benefits will not be realized.
As of December 31, 2014, we did not have a liability for uncertain tax positions, and as such, we did not accrue related interest or penalties. The tax years 2011-2014 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.
Stock-Based Compensation
We apply a fair value-based method of accounting for stock-based compensation which requires recognition in the financial statements of the cost of services received in exchange for awards of equity instruments based on the grant date fair value of those awards. For equity awards, compensation expense is based on the fair value on the grant or modification date and is recognized in our financial statements over the vesting period. We utilize the Black-Scholes option-pricing model to measure the fair value of stock options and a Monte Carlo lattice-based model for our performance and market-based restricted stock and restricted stock units. We also have cash-settled restricted stock units as well as a Stockholder Value Appreciation Program that are accounted for under the liability method which requires us to recognize the fair value of each award based on the underlying share price at the end of each period. See Note 11, “Stock-Based Compensation,” for a full discussion of our stock-based compensation.
Concentration of Credit Risk
We operate a substantial portion of our oil and gas properties. As the operator of a property, we make full payment for costs associated with the property and seek reimbursement from the other working interest owners in the property for their share of those costs. Our joint interest owners consist primarily of independent oil and gas producers. If the oil and gas exploration and production industry in general was adversely affected, the ability of our joint interest partners to reimburse us could be adversely affected.
The purchasers of our oil, gas and NGL production consist primarily of independent marketers, major oil and gas companies, refiners and gas pipeline companies. We perform credit evaluations of the purchasers of our production and monitor their financial condition on an ongoing basis. Based on our evaluations and monitoring, we obtain cash escrows, letters of credit or parental guarantees from some purchasers.
All of our derivative transactions have been carried out in the over-the-counter market and are not typically subject to margin-deposit requirements. The use of derivative transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. The counterparties for all of our derivative transactions have an “investment grade” credit rating. We monitor the credit ratings of our hedging counterparties on an ongoing basis. Although we have entered into derivative contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the derivative contracts or seek bankruptcy protection, it could have a material adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price changes. In addition, in poor economic environments and tight financial markets, the risk of a counterparty default is heightened and fewer counterparties may participate in hedging transactions, which could result in greater concentration of our exposure to any one counterparty or a larger percentage of our future production being subject to commodity price changes. At December 31, 2014, ten of our 16 counterparties accounted for approximately 85% of our contracted volumes, with no single counterparty accounting for more than 15%. Approximately 40% of our volumes subject to derivative instruments are with lenders under our credit facility. Our credit facility, senior notes, senior subordinated notes
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
and substantially all of our derivative instruments contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations.
Major Customers
Tesoro Corporation and Sunoco Logistics Partners Operations GP LLC accounted for 12% and 10%, respectively, of our total revenues in 2014. During 2013, Sunoco Logistics Partners Operations GP LLC, Royal Dutch Shell plc and Tesoro Corporation accounted for 13%, 12%, and 11%, respectively, of our total revenues. During 2012, sales of our oil and gas production to Royal Dutch Shell plc, Tesoro Corporation and Big West Oil LLC accounted for 14%, 14% and 10%, respectively, of our total revenues. We believe that the loss of any of our major customers would not have a material adverse effect on us because alternative purchasers are available.
Derivative Financial Instruments
Our derivative instruments are recorded on the consolidated balance sheet at fair value as either an asset or a liability with changes in fair value recognized currently in earnings. While we utilize our derivative instruments to manage the price risk attributable to our expected oil and gas production, we have elected not to designate our derivative instruments as accounting hedges under the accounting guidance.
The related cash flow impact of our derivative activities are reflected as cash flows from operating activities unless they are determined to have a significant financing element at inception, in which case they are classified within financing activities. See Note 5, “Derivative Financial Instruments,” for a more detailed discussion of our derivative activities.
Offsetting Assets and Liabilities
Our derivative financial instruments are subject to master netting arrangements and are reflected on our consolidated balance sheet accordingly. See Note 5, "Derivative Financial Instruments," for details regarding the gross amounts, as well as the impact of our netting arrangements on our net derivative position. We only offset assets and liabilities in relation to our derivative financial instruments.
Accumulated Other Comprehensive Income
At December 31, 2012, accumulated other comprehensive income (“AOCI”) included unrealized losses related to auction rate securities that were deemed to be temporary as the Company had the intent and ability to hold the securities to maturity. As of December 31, 2013, the Company changed its intention and considered plans to sell the securities. As a result, the losses previously accumulated in AOCI related to these securities were transferred and recognized in the consolidated statement of operations for the year ended December 31, 2013. During the first quarter of 2014, all auction rate securities were sold for $39 million. The change in AOCI for the indicated periods is set forth below:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
New Accounting Requirements
In August 2014, the FASB issued guidance regarding disclosures of uncertainties about an entity's ability to continue as a going concern. The guidance applies prospectively to all entities, requiring management to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity's ability to continue as a going concern and disclose certain information when substantial doubt is raised. The guidance is effective for interim and annual periods beginning on or after December 15, 2016. We do not expect this guidance to impact our Company.
In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The guidance may be applied retrospectively or using a modified retrospective approach to adjust retained earnings. The guidance is effective for interim and annual periods beginning on or after December 15, 2016. We are currently evaluating the impact of this guidance on our financial statements.
In April 2014, the FASB issued guidance regarding the reporting of discontinued operations. The guidance applies prospectively to new disposals and new classifications of disposal groups as held for sale after the effective date. The guidance is effective for interim and annual periods beginning on or after December 15, 2014. We do not expect this guidance to impact our Company.
2.
Earnings Per Share:
Basic earnings per share (EPS) is calculated by dividing net income, less any applicable adjustments, (the numerator) by the weighted-average number of shares of common stock (excluding unvested restricted stock and restricted stock units) outstanding during the period (the denominator). Diluted EPS incorporates the dilutive impact of outstanding stock options and unvested restricted stock and restricted stock units (using the treasury stock method). Under the treasury stock method, the amount the employee must pay for exercising stock options, the amount of unrecognized compensation expense related to unvested stock-based compensation grants and the amount of excess tax benefits that would be recorded when the award becomes deductible are assumed to be used to repurchase shares. See Note 11, “Stock-Based Compensation.”
The following is the calculation of basic and diluted weighted-average shares outstanding and EPS for the indicated years:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
_________________
(1)
Excludes 1.1 million and 4.0 million shares of unvested restricted stock or restricted stock units and stock options for the years ended December 31, 2014 and 2013, respectively, because including the effect would have been anti-dilutive.
(2)
The effect of unvested restricted stock or restricted stock units and stock options has not been included in the calculation of shares outstanding for diluted EPS for the year ended December 31, 2012, as their effect would have been anti-dilutive. Had we recognized income from continuing operations for that year, incremental shares attributable to the assumed vesting of unvested restricted stock and restricted stock units and the assumed exercise of outstanding stock options would have increased diluted weighted-averages shares outstanding by 0.7 million shares for the year ended December 31, 2012.
(3)
The numerator includes an adjustment of $20 million related to the repurchase of preferred shares of a now wholly-owned subsidiary, which reduces net income (loss) for purposes of earnings per share for the year ended December 31, 2013. The subsidiary is part of our continuing operations. See Note 16, "Related Party Transaction," for additional information.
3. Discontinued Operations:
In 2013, we met the criteria to classify our Malaysia business as held-for-sale and discontinued operations. In February 2014, Newfield International Holdings Inc., a wholly-owned subsidiary of the Company, closed the sale of our Malaysia business to SapuraKencana Petroleum Berhad (SapuraKencana), a Malaysian public company, for $898 million. As a result of
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
the sale, we recorded a gain in the first quarter of 2014 of approximately $388 million ($252 million, after tax). As of the date of this report, the final post-close settlement is pending due to a dispute with the purchaser that arose subsequent to closing and could possibly go to arbitration. In the fourth quarter of 2014, we recorded an allowance against a receivable from SapuraKencana and reduced the previously recognized gain by $15 million ($10 million, after tax) due to uncertainty associated with collectability.
Results of Discontinued Operations
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(1) Certain payments to foreign governments made on our behalf that are part of the revenue process are recorded as a reduction of the related oil and gas revenues.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Income Taxes
Historically, our effective tax rate in Malaysia was approximately 38%. As a result of our December 2012 decision to repatriate earnings from our international operations, we experienced higher international effective tax rates due to these earnings being taxed both in the U.S. and the local country. For the year ended 2014, our effective tax rate in Malaysia was 37% as the majority of our income from discontinued operations resulted from the gain on the sale of our Malaysia business, which was only taxable in the U.S. The effective tax rate for our discontinued operations for the years ended 2013 and 2012 was 58% and 168%, respectively, due to our international earnings being taxed both in the U.S and the local country.
Assets and Liabilities in the Consolidated Balance Sheet Attributable to Discontinued Operations
Inventories
At December 31, 2013, the crude oil inventory from our Malaysia operations consisted of approximately 1.1 million barrels of crude oil valued at cost of $89 million and is included in the "Inventories" line item in the preceding table and in our consolidated balance sheet. Cost for purposes of the carrying value of oil inventory is the sum of production costs and depletion expense.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Oil and Gas Properties
At December 31, 2013, we performed a fair value assessment of our discontinued operations, noting no indication of impairment based on the carrying value.
During 2012, when our Malaysia business was reported as continuing operations, we performed a ceiling test for the full cost pool. The ceiling value of our reserves was calculated based upon SEC pricing of $2.76 per MMBtu for natural gas and $94.84 per barrel for oil. Using these prices, the cost center ceiling with respect to our Malaysia full cost pool exceeded the net capitalized costs of the respective cost center at December 31, 2012 and as such, no ceiling test writedown was required.
The change in our ARO for our discontinued operations for each of the three years ended December 31, is set forth below:
________________
(1) Obligations reduced as a result of the sale of our Malaysia business in February 2014.
4.
Oil and Gas Assets:
Property and Equipment
Property and equipment consisted of the following at December 31:
Oil and gas properties not subject to amortization represent investments in unproved properties and major development projects in which we own an interest. These unproved property costs include unevaluated leasehold acreage, geological and geophysical data costs associated with leasehold or drilling interests, costs associated with wells in progress at year-end and capitalized internal costs. We exclude these costs on a country-by-country basis until proved reserves are found or until it is determined that the costs are impaired. Unproved property costs are grouped by major prospect area where individual property
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
costs are not significant and are assessed individually when individual costs are significant. Costs associated with wells in progress are transferred to the amortization base upon the determination of whether proved reserves can be assigned to the properties, which is generally based on drilling results. All other costs excluded from the amortization base are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the amortization base or a charge is made against earnings for international operations if a reserve base has not yet been established.
During the fourth quarter of 2014, crude oil and natural gas prices declined to price levels that are likely to change our future development plans in certain operating areas of our domestic business. Accordingly, we transferred approximately $760 million of costs that were previously withheld from the full cost pool into the full cost pool amortization base.
Oil and gas properties not subject to amortization as of December 31, 2014, consisted of the following:
Granite Wash Asset Sale
In September 2014, we closed on the sale of our Granite Wash assets, located primarily in Texas, for approximately $588 million, subject to customary post-closing purchase price adjustments. The sale of our Granite Wash assets did not significantly alter the relationship between capitalized costs and proved reserves, and as such, all proceeds were recorded as adjustments to our domestic full cost pool with no gain or loss recognized. These consolidated financial statements include the results of our Granite Wash operations through the date of sale.
Gulf of Mexico Asset Sale
In October 2012, we closed the sale of our remaining assets in the Gulf of Mexico to W&T Offshore, Inc. for approximately $208 million, subject to customary post-closing adjustments. The sale of our remaining assets in the Gulf of Mexico did not significantly alter the relationship between capitalized costs and proved reserves, and as such, all proceeds were recorded as adjustments to our domestic full cost pool with no gain or loss recognized. These consolidated financial statements include the results of our Gulf of Mexico operations through the date of sale.
Other Asset Acquisitions and Sales
During 2014, 2013 and 2012, we acquired various other oil and gas properties for approximately $33 million, $72 million and $9 million, respectively, and sold certain other oil and gas properties for proceeds of approximately $69 million, $36 million and $422 million, respectively. The cash flows and results of operations for the assets included in a sale are included in our consolidated financial statements up to the date of sale. All of the proceeds associated with our asset sales were recorded as adjustments to our domestic full cost pool.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
5.
Derivative Financial Instruments:
Commodity Derivative Instruments
We utilize the following derivative strategies, which consist of either a single derivative instrument or a combination of instruments, to manage the variability in cash flows associated with the forecasted sale of our domestic oil and natural gas production.
•
Fixed-price swaps. With respect to a swap position, the counterparty is required to make a payment to us if the settlement price for any settlement period is less than the swap strike price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap strike price.
•
Collars (combination of purchased put options (floor) and sold call options (ceiling)). For a collar position, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor strike price while we are required to make payment to the counterparty if the settlement price for any settlement period is above the ceiling strike price. Neither party is required to make a payment to the other party if the settlement price for any settlement period is equal to or greater than the floor strike price and equal to or less than the ceiling strike price.
•
Fixed-price swaps with sold puts. A swap with a sold put position consists of a standard swap position plus a put sold by us with a strike price below the associated fixed-price swap. This structure enables us to increase the fixed-price swap with the value received through the sale of the put. If the settlement price for any settlement period falls equal to or below the put strike price, then we will only receive the difference between the swap price and the put strike price. If the settlement price is greater than the put strike price, the result is the same as it would have been with a standard swap only.
•
Collars with sold puts. A collar with a sold put position consists of a standard collar position plus a put sold by us with a strike price below the floor strike price of the collar. This structure enables us to improve the collar strike prices with the value received through the sale of the additional put. If the settlement price for any settlement period falls equal to or below the additional put strike price, then we will receive the difference between the floor strike price and the additional put strike price. If the settlement price is greater than the additional put strike price, the result is the same as it would have been with a standard collar only.
•
Swaptions. A swaption is an option to exercise a swap where the buyer (counterparty) of the swaption purchases the right from the seller (Newfield), but not the obligation, to enter into a fixed-price swap with the seller on a predetermined date (expiration date). The swap price is a fixed price determined at the time of the swaption contract. If the swaption is exercised, the contract will become a swap treated consistent with our other fixed-price swaps.
While the use of these derivative instruments may limit or partially reduce the downside risk of adverse commodity price movements, their use also may limit future income from favorable commodity price movements. For discussion of the accounting policies associated with our derivative financial instruments (including the offsetting of derivative assets and liabilities), see Note 1, "Organization and Summary of Significant Accounting Policies."
Our oil and gas derivative contracts are settled based upon reported prices on the NYMEX. The estimated fair value of these contracts is based upon various factors, including closing exchange prices on the NYMEX, over-the-counter quotations, estimated volatility, non-performance risk adjustments using credit default swaps, interest rates and time to maturity. The calculation of the fair value of options requires the use of an option-pricing model. See Note 8, “Fair Value Measurements.”
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
At December 31, 2014, we had outstanding derivative positions as set forth in the tables below.
Natural Gas
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(1)
During the fourth quarter of 2014, we sold natural gas swaption contracts that, if exercised on their expiration date in the second quarter of 2015, would protect 14,640 MMMBtus of calendar-year 2016 production from future commodity price volatility. These contracts give the counterparties the option to enter into swap contracts with us at $4.10/MMBtu for calendar-year 2016.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Crude Oil
_________________
(1)
If the market prices remain below our sold puts at contract settlement, we will receive the market price plus the following associated with our production:
•
the difference between our floors and our sold puts for collars with sold puts; or
•
the difference between our swaps and our sold puts for fixed-price swaps with sold puts.
(2)
During the third quarter of 2014, we sold crude oil swaption contracts that, if exercised on their expiration date in the first quarter of 2015, would protect 732 MBbls of calendar-year 2016 production from future commodity price volatility. These contracts give the counterparties the option to enter into swap contracts with us at $91.00/Bbl for calendar-year 2016.
Additional Disclosures about Derivative Instruments
We had derivative financial instruments recorded in our consolidated balance sheet as assets (liabilities) at their respective estimated fair value, as set forth below.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The amount of gain (loss) recognized in “Commodity derivative income (expense)” in our consolidated statement of operations related to our derivative financial instruments follows:
6. Accounts Receivable:
Accounts receivable consisted of the following at December 31:
Reserve for doubtful accounts at December 31, 2014 includes an allowance for $15 million related to discontinued operations. See Note 3, "Discontinued Operations."
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
7. Accrued Liabilities:
Accrued liabilities consisted of the following at December 31:
8.
Fair Value Measurements:
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The authoritative guidance requires disclosure of the framework for measuring fair value and requires that fair value measurements be classified and disclosed in one of the following categories:
Level 1:
Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2:
Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity fixed-price swaps and certain investments.
Level 3:
Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). Level 3 instruments primarily include derivative instruments, such as commodity options (i.e., price collars, sold puts or swaptions) and other financial investments.
•
Our valuation models for derivative contracts are primarily industry-standard models (i.e., Black-Scholes) that consider various inputs including: (a) forward prices for commodities, (b) time value, (c) volatility factors, (d) counterparty credit risk and (e) current market and contractual prices for the underlying instruments.
•
Our valuation model for the Stockholder Value Appreciation Program (SVAP) is a Monte Carlo simulation that is based on a probability model and considers various inputs including: (a) the measurement date stock price, (b) time value and (c) historical and implied volatility. See Note 11, “Stock-Based Compensation,” for a description of the SVAP.
Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Recurring Fair Value Measurements
The following table summarizes the valuation of our assets and liabilities that are measured at fair value on a recurring basis.
The determination of the fair values above incorporates various factors, which include not only the impact of our non-performance risk on our liabilities but also the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), if any. We utilize credit default swap values to assess the impact of non-performance risk when evaluating both our liabilities to and receivables from counterparties.
As of December 31, 2013, we held $39 million of auction rate securities, which were classified as a Level 3 fair value measurement. During the first quarter of 2014, all auction rate securities were sold for $39 million.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Level 3 Fair Value Measurements
The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the indicated periods.
________
(1)
During the second quarter of 2014, we transferred $3 million of derivative option contracts out of the Level 3 hierarchy. The transfer was a result of our Level 3 swaptions being exercised by the counterparties as swaps on May 30, 2014.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Qualitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements
Investments. As of December 31, 2013, we held $39 million of auction rate securities maturing beginning in 2033 that were classified as a Level 3 fair value measurement. This amount reflected an other than temporary decrease in the fair value of these investments since the time of purchase of $6 million ($4 million net of tax) recorded in 2013 under the caption "Other income (expense) - Other, net" on our consolidated statement of operations as a result of our 2013 decision to liquidate our auction rate investments. During the first quarter of 2014, all auction rate securities were sold for $39 million.
Derivatives. Our valuation models for Level 3 derivative option contracts are primarily industry-standard models that consider various factors, including certain significant unobservable inputs such as (a) volatility factors and (b) counterparty credit risk. The calculation of the fair value of our option contracts requires the use of an option-pricing model. The estimated future prices are compared to the strike prices fixed by our derivative contracts, and the resulting estimated future cash inflows or outflows over the contractual life are discounted to calculate the fair value. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts, regional price differences and interest rates. Significant increases (decreases) in the quoted forward prices for commodities generally lead to corresponding decreases (increases) in the fair value measurement of our oil and gas derivative contracts. Significant changes in the volatility factors utilized in our option-pricing model can cause significant changes in the fair value measurement of our oil and gas derivative contracts. See Note 5, "Derivative Financial Instruments," for additional discussion of our derivative instruments.
The determination of the fair values of derivative instruments incorporates various factors that include not only the impact of our non-performance risk on our liabilities but also the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests). Historically, we have not experienced significant changes in the fair value of our derivative contracts resulting from changes in counterparty credit risk as the counterparties for all of our derivative transactions have an “investment grade” credit rating.
Stock-Based Compensation. The calculation of the fair value of the SVAP liability requires the use of a probability-based Monte Carlo simulation, which includes unobservable inputs. The simulation predicts multiple scenarios of future stock returns over the performance period, which are discounted to calculate the fair value. The fair value is recognized over a service period derived from the simulation. Future stock returns and discounting variables are sensitive to market volatility. Significant increases (decreases) in the volatility factors utilized in our option-pricing model can cause significant increases (decreases) in the fair value measurement of the SVAP liability.
Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Fair Value of Debt
The estimated fair value of our notes, based on quoted prices in active markets (Level 1) as of December 31, was as follows:
Any amounts outstanding under our revolving credit facility and money market lines of credit are at variable rates as of the indicated dates and are stated at cost, which approximates fair value. Please see Note 9, "Debt."
9.
Debt:
At December 31, our debt consisted of the following:
_________________
(1)
Because we have the ability and intent to use our available credit facility capacity to repay borrowings under our money market lines of credit as of the indicated dates, amounts outstanding under these obligations, if any, are classified as long-term.
Credit Arrangements
We have a revolving credit facility that matures in June 2018 and provides borrowing capacity of $1.4 billion. As of December 31, 2014, the largest individual loan commitment by any lender was 14% of total commitments.
Loans under the credit facility bear interest, at our option, equal to (a) a rate per annum equal to the higher of the prime rate announced from time to time by JPMorgan Chase Bank, N.A. or the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 50 basis points, plus a margin that is based on a grid of our debt rating (75 basis points per annum at December 31, 2014) or (b) the London Interbank Offered Rate, plus a margin that is based on a grid of our debt rating (175 basis points per annum at December 31, 2014).
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Under our credit facility, we pay commitment fees on available but undrawn amounts based on a grid of our debt rating (30 basis points per annum at December 31, 2014). We incurred aggregate commitment fees under our credit facility of approximately $4 million, $3 million and $3 million for each of the years ended December 31, 2014, 2013 and 2012, respectively, which are recorded in “Interest expense” on our consolidated statement of operations.
Our credit facility has restrictive financial covenants that include the maintenance of a ratio of total debt to book capitalization not to exceed 0.6 to 1.0 and maintenance of a ratio of earnings before gain or loss on the disposition of assets, interest expense, income taxes and noncash items (such as depreciation, depletion and amortization expense, unrealized gains and losses on commodity derivatives, ceiling test writedowns and goodwill impairments) to interest expense of at least 3.0 to 1.0. At December 31, 2014, we were in compliance with all of our debt covenants.
As of December 31, 2014, we had no letters of credit outstanding under our credit facility. Letters of credit are subject to a fronting fee of 20 basis points and annual fees based on a grid of our debt rating (175 basis points at December 31, 2014).
Subject to compliance with the restrictive covenants in our credit facility, at December 31, 2014, we also had a total of $94 million of additional, available borrowing capacity under money market lines of credit with various financial institutions, the availability of which is at the discretion of the financial institutions.
The credit facility includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; inaccuracy of representations and warranties in any material respect; a change of control; or certain other material adverse changes in our business. Our senior notes and senior subordinated notes also contain standard events of default. If any of the foregoing defaults were to occur, our lenders under the credit facility could terminate future lending commitments, and our lenders under both the credit facility and our notes could declare the outstanding borrowings due and payable. In addition, our credit facility, senior notes, senior subordinated notes and substantially all of our derivative arrangements contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations. See Note 1, " Organization and Principles of Consolidation - Concentration of Credit Risk," for additional details.
Senior Notes
In June 2012, we issued $1 billion of 5⅝% Senior Notes due 2024 and received proceeds of $990 million (net of offering costs). These notes were issued at par to yield 5⅝%. We used a portion of the net proceeds to repay borrowings outstanding under our credit facility and money market lines of credit as well as redeem our 6⅝% Senior Subordinated Notes due 2016.
Interest on our senior notes is payable semi-annually. The notes are unsecured and unsubordinated obligations and rank equally with all of our other existing and future unsecured and unsubordinated obligations. We may redeem some or all of our senior notes at any time before their maturity at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. The indentures governing our senior notes contain covenants that may limit our ability to, among other things, incur debt secured by liens; enter into sale/leaseback transactions; and enter into merger or consolidation transactions.
The indentures also provide that if any of our subsidiaries guarantee any of our indebtedness at any time in the future, then we will cause our senior notes to be equally and ratably guaranteed by that subsidiary. At December 31, 2014, we were in compliance with all of our debt covenants.
Senior Subordinated Notes
In October 2014, we redeemed our $600 million aggregate principal amount of 7⅛% Senior Subordinated Notes due 2018. In connection with the redemption, we paid a premium of $14 million. The premium was recorded under the caption "Other income (expense) - Other, net" on our consolidated statement of operations. In addition, unamortized offering costs of approximately $3 million were charged to interest expense as a result of the repayment.
We may redeem some or all of our 6⅞% Senior Subordinated Notes due 2020 at any time on or after February 1, 2015 at a redemption price stated in the indenture governing the notes. Interest on our senior subordinated notes is payable semi-annually. The notes are unsecured senior subordinated obligations that rank junior in right of payment to all of our present and future senior indebtedness.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The indenture governing our senior subordinated notes may limit our ability under certain circumstances to, among other things:
•
incur additional debt;
•
make restricted payments; and
•
engage in mergers; consolidations; and sales and other dispositions of assets.
At December 31, 2014, we were in compliance with all of our debt covenants.
10.
Income Taxes:
For the years ended December 31, income (loss) from continuing operations before income taxes consisted of the following:
For the years ended December 31, the total provision (benefit) for income taxes for continuing operations consisted of the following:
The provision (benefit) for income taxes for continuing operations for the indicated years was different than the amount computed using the federal statutory rate (35%) for the following reasons:
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
In fourth quarter 2012, we made a decision to repatriate earnings from our international operations. By doing so we made an election to have our China business be treated as a disregarded entity for U.S. federal income tax purposes, which resulted in earnings and profits of our international business in China being taxed both in the United States and China. Due to our NOL carryforward position, we do not expect to be able to utilize related foreign tax credits (FTC) before they expire and accordingly recorded a full valuation allowance against these credits. These FTCs are utilized in the alternative minimum tax (AMT) system to reduce current cash taxes. The result is a high effective tax rate in periods where our book income in China is high relative to our domestic book income. These effective tax rate fluctuations are magnified when net income approaches zero.
At December 31, the components of our deferred tax asset (liability) were as follows:
As of December 31, 2014 and 2013, we had gross net operating loss (NOL) carryforwards of approximately $0.5 billion and $1.0 billion for federal income tax and $1.6 billion and $1.7 billion for state income tax purposes, respectively, which may be used in future years to offset taxable income. NOL carryforwards of $155 million are subject to annual limitations due to stock ownership changes. We currently estimate that we will not be able to utilize $64 million of our various gross state NOLs because we do not have sufficient estimated future taxable income in the appropriate jurisdictions. To the extent not utilized, the federal NOL carryforwards will begin to expire during the years 2019 through 2033.
As of December 31, 2013, we had gross NOL carryforwards for international income tax purposes of approximately $17 million. In the fourth quarter of 2014, we wrote off the deferred tax asset and related valuation allowance since we have ceased operating in these jurisdictions and it is remote that the NOL carryforwards will be realized in the future.
As of December 31, 2014 and 2013, we had foreign tax credits of approximately $547 million and $535 million, respectively, which will expire during the years 2022 through 2024.
Utilization of deferred tax assets is dependent upon generating sufficient future taxable income in the appropriate jurisdictions within the carryforward period. Estimates of future taxable income can be significantly affected by changes in oil, gas and NGL prices; estimates of the timing and amount of future production; and estimates of future operating and capital costs. Therefore, no certainty exists that we will be able to fully utilize our existing deferred tax assets.
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
The change in our deferred tax asset valuation allowance is as follows at December 31:
As the result of the divestiture of the Malaysia operations in 2014, all of the deferred tax asset and related valuation allowance were transferred to the buyer. In the fourth quarter of 2014, we wrote off the other international deferred tax assets and related valuation allowances since we have ceased operating in these jurisdictions and it is remote that the NOL carryforwards will be realized in the future. In fourth quarter of 2014, 2013 and 2012, we recorded valuation allowances related to insufficient estimated future domestic taxable income to fully utilize foreign tax credits before they expire of $12 million, $114 million, and $421 million, respectively. The foreign tax credit deferred tax asset is fully offset by a valuation allowance. In 2014, we released $1 million of state valuation allowances due to utilization of the related state NOLs.
11.
Stock-Based Compensation:
For the years ended December 31, our stock-based compensation expense consisted of the following:
As of December 31, 2014, we had approximately $70 million of total unrecognized stock-based compensation expense related to unvested stock-based compensation awards. The full amount is expected to be recognized within four years.
Equity Awards
Equity awards consist of service-based and performance- or market-based restricted stock units, stock options and stock purchase options under the Employee Stock Purchase Plan.
Stock-based compensation classified as equity awards to employees and non-employee directors are currently granted under the 2011 Omnibus Stock Plan (2011 Plan). The fair value of grants is determined utilizing the Black-Scholes option-pricing model for stock options and a Monte Carlo lattice-based model for our performance- and market-based restricted stock and restricted stock units. Compensation expense for equity awards is expected to be recognized on a straight-line basis over the applicable remaining vesting periods.
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Shares available for grant under our 2011 Plan are reduced by 1.87 times the number of shares of restricted stock or restricted stock units awarded under the plan and are reduced by 1 times the number of shares subject to stock options awarded under the plan. At December 31, 2014, we had approximately (1) 2.3 million additional shares available for issuance pursuant to our existing plan if all future awards under our 2011 Plan are stock options, or (2) 1.2 million additional shares available for issuance pursuant to our existing plan if all future awards under our 2011 Plan are restricted stock or restricted stock units. Thus far, the majority of the awards under our 2011 Plan have been granted as restricted stock unit awards.
Restricted Stock. At December 31, 2014, our employees held approximately 1.9 million shares of non-vested restricted stock and restricted stock units. These shares primarily vest over three to five years and vesting is dependent upon the employee’s continued service with our Company. In addition, at December 31, 2014, our employees held approximately 0.9 million shares of restricted stock subject to performance-based vesting criteria (all of which are currently considered market-based restricted stock under authoritative accounting guidance). To the extent we have treasury shares available, we utilize treasury shares when restricted stock is issued or restricted stock units vest.
The following table provides information about restricted stock and restricted stock unit activity.
The total fair value of restricted stock and restricted stock units that vested during the years ended December 31, 2014, 2013 and 2012 was $43 million, $47 million and $44 million, respectively.
Stock Options. Options generally expire ten years from the date of grant and become exercisable at the rate of 20% per year. The exercise price of options cannot be less than the fair market value per share of our common stock on the date of grant. We issue new shares of stock when stock options are exercised.
The excess tax benefit realized from stock options exercised is recognized as a credit to additional paid-in capital and is calculated as the amount by which the tax deduction we receive exceeds the deferred tax asset associated with recorded stock-based compensation expense. We did not realize an excess tax benefit from stock-based compensation for 2014, 2013 or 2012 because we did not have sufficient taxable income to fully realize the deduction. At December 31, 2014, we had unrecognized net operating losses of $99 million related to stock-based compensation.
The following table below provides information about stock option activity.
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
_________________
(1)
The intrinsic value of a stock option is the amount by which the market value of our common stock at the indicated date, or at the time of exercise, exceeds the exercise price of the option.
On December 31, 2014, the last reported sales price of our common stock on the New York Stock Exchange was $27.12 per share.
The following table summarizes information about stock options outstanding and exercisable at December 31, 2014:
Employee Stock Purchase Plan. In May 2010, our stockholders approved the Newfield Exploration Company 2010 Employee Stock Purchase Plan with one million shares of our common stock available for issuance. Pursuant to our employee stock purchase plan, for each six-month period beginning on January 1 or July 1 during the term of the plan, each eligible employee has the opportunity to purchase our common stock for a purchase price equal to 85% of the lesser of the fair market value of our common stock on the first or last day of the period. Each employee may purchase up to $25,000 in common stock per calendar year. Employees of our foreign subsidiaries are not eligible to participate in the plan.
During 2014, options to purchase 168,394 shares of our common stock were issued under our employee stock purchase plan. The weighted-average fair value of each option was $7.91 per share. The fair value of the options granted was determined using the Black-Scholes option valuation method assuming no dividends, a risk-free weighted-average interest rate of 0.07%, an expected life of six months and weighted-average volatility of 32.05%. At December 31, 2014, approximately 356,000 shares of our common stock remained available for issuance under the current plan.
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
During 2013, options to purchase 178,733 shares of our common stock were issued under our employee stock purchase plan. The weighted-average fair value of each option was $6.59 per share. The fair value of the options granted was determined using the Black-Scholes option valuation method assuming no dividends, a risk-free weighted-average interest rate of 0.10%, an expected life of six months and weighted-average volatility of 39.45%.
During 2012, options to purchase 165,722 shares of our common stock were issued under our employee stock purchase plan. The weighted-average fair value of each option was $9.86 per share. The fair value of the options granted was determined using the Black-Scholes option valuation method assuming no dividends, a risk-free weighted-average interest rate of 0.10%, an expected life of six months and weighted-average volatility of 49.43%.
Liability Awards
Liability awards consist of performance awards that are settled in cash instead of shares as discussed below.
Stockholder Value Appreciation Program. In September 2013, the Compensation and Management Development Committee of the Board approved the SVAP to be administered under the 2011 Plan. The SVAP pays substantially all full-time domestic, nonexecutive employees a cash payment based on a percentage of salary upon each incremental $5 increase in our 30 -calendar day average share price. Each price threshold can be reached only once during the term of the program. The SVAP's performance period lasts through December 31, 2015. Each price trigger that is reached results in an approximately $13 million payment.
The first price threshold that triggered a payment under the SVAP was $27.50 during the fourth quarter of 2013. The second and third price thresholds for the SVAP were $32.50 and $37.50, respectively, which were reached during the second quarter of 2014. The fourth price threshold for the SVAP of $42.50 was reached in July 2014.
Based on the valuation of the SVAP as of December 31, 2014, the fair value was $4 million, of which $3 million has been accrued. The total expected cost was determined using a Monte Carlo simulation assuming no dividends, a risk-free weighted-average interest rate of 0.27%, a plan term of one year and an average of implied and historical stock price volatility of 47%. An additional $1 million is expected to be recognized over the remaining service period of the plan. Future changes in our stock price could cause the total cost of the plan to be significantly different than our estimates as of December 31, 2014.
Cash-Settled Restricted Stock Units. We also have granted cash-settled restricted stock units to employees that vest over three years. As of December 31, 2014, we accrued $12 million for future cash settlement upon vesting of awards. The value of the awards, and the associated stock-based compensation expense, is based on the Company's stock price at the end of each period. During the year ended December 31, 2014, we granted approximately 759,000 cash-settled restricted stock units to employees. During the year ended December 31, 2014, approximately 587,000 cash-settled restricted stock units vested and settled for approximately $19 million. During the year ended December 31, 2013, approximately 85,000 cash-settled restricted units vested and settled for approximately $2 million. As of December 31, 2014, we had approximately 1.2 million cash-settled restricted stock units outstanding and related unrecognized stock-based compensation expense of approximately $18 million.
12.
Employee Benefit Plans:
Post-Retirement Medical Plan
We sponsor a post-retirement medical plan that covers all retired employees until they reach age 65. At December 31, 2014, both our accumulated benefit obligation and our accrued benefit costs were $16 million. Our net periodic benefit cost was approximately $2 million for each of the years ended December 31, 2014, 2013 and 2012.
The expected future benefit payments under our post-retirement medical plan for the next ten years include $5 million for the five-year period 2015 through 2019 and $7 million for the five-year period 2020 through 2024.
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
Annual Cash Incentive Compensation Plan
During 2010, our Board of Directors, with the recommendation of the Compensation & Management Development Committee, approved a new annual cash incentive compensation plan for all employees (the 2011 Annual Incentive Plan). Under the 2011 Annual Incentive Plan, the Compensation & Management Development Committee determines the annual award pool for all employees based upon a number of factors including the Company’s performance against stated performance goals and in comparison with peer companies in our industry. All employees are eligible if employed on October 1 and December 31 of the performance period. Beginning with the year ended December 31, 2010, our annual cash incentive compensation is paid in a single payment to employees during the first quarter after the end of the performance period.
Total incentive compensation expense under the 2011 Annual Incentive Plan for the years ended December 31, 2014, 2013 and 2012 was $45 million, $40 million and $41 million, respectively.
401(k) and Deferred Compensation Plans
We sponsor a 401(k) profit sharing plan under Section 401(k) of the Internal Revenue Code. This plan covers all of our employees, excluding those of our foreign subsidiaries. We match $1.00 for each $1.00 of employee deferral, with our contribution not to exceed 8% of an employee’s salary, subject to limitations imposed by the IRS. We also sponsor a highly compensated employee deferred compensation plan. This non-qualified plan allows an eligible employee to defer a portion of his or her salary or bonus on an annual basis. We match $1.00 for each $1.00 of employee deferral, with our contribution not to exceed 8% of an employee’s salary, subject to limitations imposed by the plan. Our contribution with respect to each participant in the deferred compensation plan is reduced by the amount of contribution made by us to our 401(k) plan for that participant. Our combined contributions to these two plans was $10 million for each of the years ended December 31, 2014, 2013 and 2012.
13.
Commitments and Contingencies:
We have various commitments from continuing operations for firm transportation, operating lease agreements for office space and other agreements. As of December 31, 2014, future minimum payments under these non-cancelable agreements are as follows:
Firm transportation is comprised of various agreements with third parties for oil and gas gathering and transportation. Rent expense with respect to our lease commitments for office space for the years ended December 31, 2014, 2013 and 2012 was $20 million, $19 million and $17 million, respectively. Our other agreements are primarily other equipment leases. Payments under our drilling-related contracts are accounted for as capital additions to our oil and gas properties.
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
We have various oil and gas production volume delivery commitments that are related to our domestic operations. As of December 31, 2014, our delivery commitments through 2025 were as follows:
_________________
(1)
Our oil delivery commitments include commitments with Salt Lake City, Utah refiners. Our delivery commitments are for approximately 18,000 barrels of oil per day through 2020 and an additional 20,000 barrels of oil per day expected to start in 2016 and continuing through 2025. The 20,000 barrel per day delivery commitment represents approximately 7,300 MBbls of our committed oil volumes for each of the years 2016 through 2025. The timing may change due to timing of the refinery expansion completion. These commitments relate to our Uinta Basin production.
Given the recent decline in oil and natural gas prices and the related impact on our 2015 planned capital investments as well as the potential impact on development plans in future years, we could fail to deliver the minimum production required under these commitments. In the event that we are unable to meet our crude oil volume delivery commitments, we would incur deficiency fees ranging from $1.83 to $6.50 per barrel.
Litigation
We have been named as a defendant in a number of lawsuits and are involved in various other disputes, all arising in the ordinary course of our business, such as (a) claims from royalty owners for disputed royalty payments, (b) commercial disputes, (c) personal injury claims and (d) property damage claims. Although the outcome of these lawsuits and disputes cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, cash flows or results of operations.
During the fourth quarter 2012, we settled a lawsuit where the Company was the plaintiff and recorded a gain of $13 million in “Other income (expense) - Other, net” on our consolidated statement of operations.
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
14.
Segment Information
While we only have operations in the oil and gas exploration and production industry, we are organizationally structured along geographic operating segments. Our current operating segments are the United States and China. Prior to classifying our Malaysia business as held for sale and discontinued operations, we reported a business segment for Malaysia. The accounting policies of each of our operating segments are the same as those described in Note 1, “Organization and Summary of Significant Accounting Policies.”
The following tables provide the geographic operating segment information for our continuing operations for the years ended December 31, 2014, 2013 and 2012. Income tax allocations have been determined based on statutory rates in the applicable geographic segment. In order to reflect the double taxation of our earnings and profits in China, we have applied the statutory rates for China and the U.S. to determine our income tax allocation for our China operations in the following three tables.
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
_________________
(1)
Excludes total assets from our discontinued operations of $916 million.
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
_________________
(1)
Excludes total assets from our discontinued operations of $866 million.
15.
Supplemental Cash Flows Information:
The following table presents information about supplemental cash flows for each of the years in the three-year period ended December 31:
16.
Related Party Transaction:
Kevin M. Robinson, our former Vice President - Asia through February 10, 2014, and Susan G. Riggs, our current Treasurer, were minority owners of Huffco International L.L.C. (Huffco). In May 1997, before Mr. Robinson and Ms. Riggs
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
joined the Company, we acquired from Huffco an entity now known as Newfield China, LDC, the owner of a 12% interest in a three-field unit located in Bohai Bay, offshore China. Huffco retained preferred shares of Newfield China that provided for dividend payments. During the third quarter of 2013, we purchased the outstanding preferred shares of Newfield China from Huffco for approximately $20 million, which was recorded as a charge against retained earnings.
17. Subsequent Events:
As a result of decreasing commodity pricing and projected lower capital spending for 2015, the Company executed a reduction in force during the first quarter of 2015, which reduced approximately 15% of the total headcount. We incurred severance and related costs as a result of these workforce reductions totaling approximately $10 million, which will be reflected in our first quarter 2015 financial statements.
18.
Quarterly Results of Operations (Unaudited):
The results of operations by quarter for the indicated periods are as follows:
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)
_________________
(1)
Oil, gas and NGL revenues and Income (loss) from operations are specific to our continuing operations.
(2)
During the quarter ended March 31, 2014, we sold our Malaysia business and recorded a gain of approximately $388 million ($252 million, after tax). During the fourth quarter, we reduced the previously recognized gain by $15 million ($10 million, after tax) due to recording an allowance against a receivable. See Note 3, "Discontinued Operations," for additional information.
(3)
The sum of the individual quarterly earnings (loss) per share may not agree with year-to-date earnings (loss) per share as each quarterly computation is based on the income or loss for that quarter and the weighted-average number of shares outstanding during that quarter.
(4)
Basic and diluted earnings per share includes an adjustment of $20 million related to the repurchase of preferred shares of a now wholly-owned subsidiary. See Note 2, "Earnings Per Share" for additional detail.
NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES - UNAUDITED
Results of Operations for Oil and Gas Producing Activities
The following tables present the results of our oil and gas producing activities for the years ending December 31:
NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES - UNAUDITED - (Continued)
Costs Incurred
The following tables present costs incurred for oil and gas property acquisitions, exploration and development for the respective years:
_________________
(1)
Includes $56 million, $121 million and $9 million for 2014, 2013 and 2012, respectively, of asset retirement costs.
(2)
Other items impacting the capitalized costs of our oil and gas properties which are not included in total costs incurred are as follows:
NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES - UNAUDITED - (Continued)
Capitalized Costs
Capitalized costs for our oil and gas producing activities consisted of the following at the end of each of the years in the two-year period ended December 31, 2014:
Reserves
Users of this information should be aware that the process of estimating quantities of proved and proved developed oil and gas reserves is very complex, requiring significant subjective decisions in the evaluation of all available geological, engineering and economic data for each reservoir. The data for a given reservoir also may change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions to existing reserve estimates may occur from time to time.
Reserves Estimates. All reserve information in this report is based on estimates prepared by our petroleum engineering staff and is the responsibility of management. The preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data input into our reserves forecasting and economics evaluation software, as well as multi-discipline management reviews. The technical employee responsible for overseeing the preparation of the reserves estimates has a Bachelor of Science in Petroleum Engineering, with more than 30 years of experience (including over 20 years of experience in reserve estimation).
Our reserves estimates are made using available geological and reservoir data as well as production performance data. These estimates, made by our petroleum engineering staff, are reviewed annually with management and revised, either upward or downward, as warranted by additional data. The data reviewed includes, among other things, seismic data, well logs, production tests, reservoir pressures, and individual well and field performance data. The data incorporated into our interpretations includes structure and isopach maps, individual well and field performance and other engineering and geological work products such as material balance calculations and reservoir simulation to arrive at conclusions about individual well and field projections. Additionally, offset performance data, operating expenses, capital costs and product prices factor into estimating quantities of reserves. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental regulations, as well as changes in the expected recovery rates associated with development drilling. Sustained decreases in prices, for example, may cause a reduction in some reserves due to reaching economic limits sooner.
Reserves Activity Overview. The following is a discussion of our proved reserves and reserve additions and revisions.
NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES - UNAUDITED - (Continued)
Our proved crude oil and condensate reserves at year-end 2014 were 301 million barrels compared to 270 million barrels and 237 million barrels at year-end 2013 and 2012, respectively. Our proved NGL reserves at year-end 2014 were 76 million barrels compared to 68 million barrels and 37 million barrels at year-end 2013 and 2012, respectively. Our proved natural gas reserves at year-end 2014 were 1.6 Tcf compared to 1.6 Tcf and 1.8 Tcf year-end 2013 and 2012, respectively. Liquids comprised about 58%, 55% and 48% of our proved reserves at year-end 2014, 2013 and 2012, respectively.
Reserve Additions and Revisions. During 2014, our proved reserves increased 132 MMBOE as a result of additions (extensions, discoveries, improved recovery and purchases of reserves in place) and revisions of previous estimates. We expect the majority of future reserve growth to be associated with infill drilling, extensions of current fields and new discoveries, as well as improved recovery operations and purchases of proved properties. The success of these operations will directly impact reserve additions or revisions in the future.
Additions. We added 72 MMBOE of proved reserves through discoveries, extensions and other additions, and 9 MMBOE through purchases. Drilling additions related to our domestic resource plays constituted 99% of our additions. Of the drilling additions, 52 MMBOE were proved undeveloped additions and 54 million barrels were liquids reserves.
Revisions. Total proved reserve revisions in 2014 were a positive 51 MMBOE or 8% of the beginning of year proved reserves. They included a positive 3 MMBOE price revision which was primarily related to our onshore natural gas plays. In mature plays, dominated by infill drilling and where reserve growth cannot be classified as an extension or discovery, the change in reserves is captured as a revision. In 2014, our revisions associated with the development of existing fields were a positive 77 MMBOE. The remaining 29 MMBOE negative revisions are associated with development plan changes and well performance.
Sales. In 2014, 2013 and 2012, we sold proved reserves associated with non-strategic assets and acreage trades.
NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES - UNAUDITED - (Continued)
Estimated Net Quantities of Proved Oil and Gas Reserves
The following table sets forth our total net proved reserves and our total net proved developed and undeveloped reserves as of December 31, 2011, 2012, 2013 and 2014 and the changes in our total net proved reserves during the three-year period ended December 31, 2014:
_________________
(1)
All of our reserves in China are associated with production sharing contracts and are calculated using the economic interest method. We used the economic interest method in Malaysia until we sold our Malaysia business in 2014.
NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES - UNAUDITED - (Continued)
Estimated Net Quantities of Proved Oil and Gas Reserves - (Continued)
_________________
(1)
All of our reserves in China are associated with production sharing contracts and are calculated using the economic interest method. We used the economic interest method in Malaysia until we sold our Malaysia business in 2014.
NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES - UNAUDITED - (Continued)
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The standardized measure of discounted future net cash flows from our estimated proved oil and gas reserves is as follows:
NEWFIELD EXPLORATION COMPANY
SUPPLEMENTARY FINANCIAL INFORMATION
SUPPLEMENTARY OIL AND GAS DISCLOSURES - UNAUDITED - (Continued)
Set forth in the table below is a summary of the changes in the standardized measure of discounted future net cash flows for our proved oil and gas reserves during each of the years in the three-year period ended December 31, 2014:

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2014.
Management’s Report on Internal Control over Financial Reporting and Report of Independent Registered Public Accounting Firm
The information required to be furnished pursuant to this item is set forth under the captions “Management’s Report on Internal Control over Financial Reporting” and “Report of Independent Registered Public Accounting Firm” in Item 8 of this report.
Changes in Internal Control over Financial Reporting
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and our Chief Financial Officer, of our internal control over financial reporting to determine whether any changes occurred during the fourth quarter of 2014 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Based on that evaluation, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
None.
PART III

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ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
Item 10. Directors, Executive Officers and Corporate Governance
The information appearing under the headings “Proposal 1: Election of Directors,” “Section 16(a) Beneficial Ownership Reporting Compliance,” “Corporate Governance - Board of Directors” and “Corporate Governance - Audit Committee” in our proxy statement for our 2015 annual meeting of stockholders to be held on May 15, 2015 (the “2015 Proxy Statement”) and the information set forth under the heading “Executive Officers of the Registrant” in this report are incorporated herein by reference.
Corporate Code of Business Conduct and Ethics
We have adopted a corporate code of business conduct and ethics for directors, officers (including our principal executive officer, principal financial officer and controller or principal accounting officer) and employees. In addition, we have adopted a financial code of ethics applicable to our Chief Executive Officer, Chief Financial Officer and Controller or Chief Accounting Officer. Both of these codes are available under the “Corporate Governance - Overview” tab on our website at www.newfield.com.
We intend to satisfy the disclosure requirements of Item 5.05 of Form 8-K regarding any amendment to, or waiver of, a provision of the corporate code of business conduct and ethics or the financial code of ethics that applies to our principal executive officer, principal financial officer, principal accounting officer or controller and relates to any element of the definition of code of ethics set forth in Item 406(b) of Regulation S-K by posting such information under the “Corporate Governance” tab of our website at www.newfield.com.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation
The information appearing in our 2015 Proxy Statement under the headings “Compensation & Management Development Committee Report” (which is furnished), “Executive Compensation,” “Non-Management Director Compensation” and “Compensation Committee Interlocks and Insider Participation” is incorporated herein by reference.

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ITEM 12. SECURITY OWNERSHIP
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information appearing in our 2015 Proxy Statement under the headings “Security Ownership of Certain Beneficial Owners and Management” and “Equity Compensation Plan Information” is incorporated herein by reference.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions, and Director Independence
The information appearing in our 2015 Proxy Statement under the headings “Corporate Governance - Board of Directors” and “Interests of Management and Others in Certain Transactions” is incorporated herein by reference.

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ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Item 14. Principal Accounting Fees and Services
The information appearing in our 2015 Proxy Statement under the heading “Principal Accounting Fees and Services” is incorporated herein by reference.
PART IV

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ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits and Financial Statement Schedules
Financial Statements
Reference is made to the table of contents set forth on page 64 of this report.
Financial Statement Schedules
Financial statement schedules listed under SEC rules but not included in this report are omitted because they are not applicable or the required information is provided in the notes to our consolidated financial statements.
Exhibits
Exhibit
Number
Title
3.1
-
Third Restated Certificate of Incorporation of Newfield dated December 14, 2011 (incorporated by reference to Exhibit 3.1 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2011 (File No. 1-12534))
3.2
-
Amended and Restated Bylaws of Newfield (incorporated by reference to Exhibit 3.2 to Newfield’s Current Report on Form 8-K filed with the SEC on July 25, 2013 (File No. 1-12534))
4.1
-
Senior Indenture dated as of February 28, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association (formerly First Union National Bank)), as Trustee (the “Senior Indenture”) (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on February 28, 2001 (File No. 1-12534))
4.1.1
-
First Supplemental Indenture, dated as of February 19, 2010, to Senior Indenture dated as of February 28, 2001 between Newfield and U.S. Bank National Association (as successor to First Union National Bank), as Trustee (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on February 19, 2010 (File No. 1-12534))
4.1.2
-
Second Supplemental Indenture, dated as of September 30, 2011, to Senior Indenture dated as of February 28, 2001 between Newfield and U.S. Bank National Association (as successor to First Union National Bank), as Trustee (incorporated by reference to Exhibit 4.2 to Newfield’s Current Report on Form 8-K filed with the SEC on September 30, 2011 (File No. 1-12534))
4.1.3
-
Third Supplemental Indenture, dated as of June 26, 2012, to Senior Indenture dated as of February 28, 2001 between Newfield and U.S. Bank National Association (as successor to First Union National Bank), as Trustee (incorporated by reference to Exhibit 4.2 to Newfield’s Current Report on Form 8-K filed with the SEC on June 26, 2012 (File No. 1-12534))
4.2
-
Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association (formerly First Union National Bank)), as Trustee (the “Subordinated Indenture”) (incorporated by reference to Exhibit 4.5 to Newfield’s Registration Statement on Form S-3/A filed with the SEC on December 13, 2001 (Registration No. 333-71348))
4.2.1
-
Second Supplemental Indenture, dated as of August 18, 2004, to Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.6.3 to Newfield’s Registration Statement on Form S-4 filed with the SEC on January 19, 2005 (Registration No. 333-122157))
4.2.2
-
Third Supplemental Indenture, dated as of April 3, 2006, to Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.4.3 to Newfield’s Current Report on Form 8-K filed with the SEC on April 3, 2006 (File No. 1-12534))
4.2.3
-
Fourth Supplemental Indenture, dated as of May 8, 2008, to Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on May 7, 2008 (File No. 1-12534))
4.2.4
-
Fifth Supplemental Indenture, dated as of January 25, 2010, to Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on January 26, 2010 (File No. 1-12534))
4.2.5
-
Sixth Supplemental Indenture, dated as of July 3, 2012, to the Subordinated Indenture dated as of December 10, 2001, between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on July 3, 2012 (File No. 1-12534))
†10.1
-
Newfield Exploration Company 2000 Omnibus Stock Plan (As Amended and Restated Effective February 14, 2002) (incorporated by reference to Exhibit 10.7.2 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 1-12534))
†10.1.1
-
First Amendment to Newfield Exploration Company 2000 Omnibus Stock Plan (As Amended and Restated Effective February 14, 2002) (incorporated by reference to Exhibit 10.3 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 (File No. 1-12534))
†10.1.2
-
Second Amendment to Newfield Exploration Company 2000 Omnibus Stock Plan (As Amended and Restated Effective February 14, 2002) (incorporated by reference to Exhibit 99.3 to Newfield’s Current Report on Form 8-K filed with the SEC on May 5, 2005 (File No. 1-12534))
†10.2
-
Newfield Exploration Company 2004 Omnibus Stock Plan (As Amended and Restated Effective February 7, 2007) (incorporated by reference to Exhibit 10.1 to Newfield’s Current Report on Form 8-K/A filed with the SEC on March 1, 2007 (File No. 1-12534))
†10.2.1
-
First Amendment to Newfield Exploration Company 2004 Omnibus Stock Plan (As Amended and Restated Effective February 7, 2007) (incorporated by reference to Exhibit 10.4.1 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 1-12534))
†10.3
-
Newfield Exploration Company 2009 Omnibus Stock Plan (incorporated by reference to Exhibit 99.1 to Newfield’s Registration Statement on Form S-8 filed with the SEC on May 4, 2009 (Registration No. 333-158961))
†10.4
-
Form of 2008 Stock Option Agreement between Newfield and each of Lee K. Boothby, Michael Van Horn, George T. Dunn, John H. Jasek, Gary D. Packer, James T. Zernell, Stephen C. Campbell, John D. Marziotti, Susan G. Riggs and Daryll T. Howard dated as of February 7, 2008 (incorporated by reference to Exhibit 10.3 to Newfield’s Current Report on Form 8-K filed with the SEC on February 14, 2008 (File No. 1-12534))
†10.5
-
Form of Restricted Stock Agreement dated as of February 4, 2009 between Newfield and its executive officers (incorporated by reference to Exhibit 10.15 to Newfield’s Current Report on Form 8-K filed with the SEC on February 6, 2009 (File No. 1-12534))
†10.6
-
Form of Restricted Stock Agreement between Newfield and each of Lee K. Boothby and Gary D. Packer dated as of May 7, 2009 (incorporated by reference to Exhibit 10.24 to Newfield’s Current Report on Form 8-K filed with the SEC on May 11, 2009 (File No. 1-12534))
†10.7
-
Form of 2010 TSR Restricted Stock Unit Agreement between Newfield and its executive officers dated as of February 4, 2010 (incorporated by reference to Exhibit 10.20 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2009 (File No. 1-12534))
†10.8
-
Form of 2010 Restricted Stock Unit Agreement between Newfield and its executive officers dated as of February 4, 2010 (incorporated by reference to Exhibit 10.21 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2009 (File No. 1-12534))
†10.9
-
Summary of Non-Employee Director Compensation Program (incorporated by reference to Exhibit 10.14 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2011 (File No. 1-12534))
†10.10
-
Second Amended and Restated Newfield Exploration Company 2003 Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 (File No. 1-12534))
†10.11
-
Newfield Exploration Company 2011 Annual Incentive Plan (incorporated by reference to Exhibit 10.25 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 1-12534))
†10.12
-
Newfield Exploration Company Deferred Compensation Plan as Amended and Restated as of November 6, 2008 (incorporated by reference to Exhibit 10.17.1 to Newfield’s Current Report on Form 8-K filed with the SEC on November 10, 2008 (File No. 1-12534))
†10.12.1
-
Amendment No. 1 to Newfield Exploration Company Deferred Compensation Plan and its related Non-Qualified Deferred Compensation Plan Trust Agreement (incorporated by reference to Exhibit 10.1 to Newfield’s Current Report on Form 8-K filed with the SEC on November 14, 2012 (File No. 1-12534))
†10.13
-
Fourth Amended and Restated Newfield Exploration Company Change of Control Severance Plan (incorporated by reference to Exhibit 10.18 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2012 (File No. 1-12534))
†10.14
-
Form of Third Amended and Restated Change of Control Severance Agreement between Newfield and Lee K. Boothby dated effective as of January 1, 2009 (incorporated by reference to Exhibit 10.31 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 1-12534))
†10.15
-
Form of Second Amended and Restated Change of Control Severance Agreement between Newfield and each of John H. Jasek and James T. Zernell dated effective as of January 1, 2009 (incorporated by reference to Exhibit 10.32 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 1-12534))
†10.16
-
Form of Fourth Amended and Restated Change of Control Severance Agreement between Newfield and each of George T. Dunn and Gary D. Packer dated effective as of January 1, 2009 (incorporated by reference to Exhibit 10.33 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 1-12534))
†10.17
-
Form of Indemnification Agreement between Newfield and each of its directors and executive officers (incorporated by reference to Exhibit 10.20 to Newfield’s Current Report on Form 8-K filed with the SEC on February 6, 2009 (File No. 1-12534))
†10.18
-
Form of 2011 Executive Officer Restricted Stock Unit Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2011 (File No. 1-12534))
†10.19
-
Form of 2011 Executive Officer TSR Restricted Stock Unit Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.2 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2011 (File No. 1-12534))
†10.20
-
Form of 2012 Executive Officer Restricted Stock Unit Award Agreement Under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2012 (File No. 1-12534))
†10.21
-
Form of 2012 Executive Officer TSR Restricted Stock Unit Award Agreement Under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.2 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2012 (File No. 1-12534))
†10.22
-
Newfield Exploration Company 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 99.1 to Newfield’s Registration Statement on Form S-8 filed with the SEC on May 5, 2011 (Registration No. 333-173964))
†10.22.1
-
Newfield Exploration Company Amended and Restated 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield’s Current Report on Form 8-K filed with the SEC on May 3, 2013 (File No. 1-12534))
†10.23
-
Form of Non-Employee Director Restricted Stock Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.5 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 (File No. 1-12534))
†10.24
-
Form of 2013 Executive Officer Restricted Stock Unit Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013 (File No. 1-12534))
†10.25
-
Form of 2013 Executive Officer TSR Restricted Stock Unit Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.2 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013 (File No. 1-12534))
†10.26
-
Form of 2014 Cash-Settled Restricted Stock Unit Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.3 to Newfield's Current Report on Form 8-K filed with the SEC on February 19, 2014 (File No. 1-12534))
†10.27
-
Form of 2014 Restricted Stock Unit Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield's Current Report on Form 8-K filed with the SEC on February 19, 2014 (File No. 1-12534))
†10.28
-
Amended Form of 2014 Executive Officer TSR Restricted Stock Unit Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2014 (File No. 1-12534))
†10.29
-
Newfield Exploration Company 2010 Employee Stock Purchase Plan (incorporated by reference to Exhibit 99.1 to Newfield's Registration Statement on Form S-8 filed with the SEC on May 10, 2010 (File No. 333-166672))
†10.29.1
-
Amendment No. 1 to the Newfield Exploration Company 2010 Employee Stock Purchase Plan (incorporated by reference to Exhibit 10.1to Newfield's Current Report on Form 8-K filed with the SEC on February 11, 2014 (File No. 1-12534))
10.30
-
Credit Agreement, dated as of June 2, 2011, by and among Newfield and JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, and BBVA Compass, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and DNB Nor Bank ASA, as Co-Documentation Agents, and other Lenders thereto (incorporated by reference to Exhibit 10.1 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011 (File No. 1-12534))
10.30.1
-
First Amendment to Credit Agreement, dated as of September 27, 2011, by and among Newfield and JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, and BBVA Compass, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and DNB Nor Bank ASA, as Co-Documentation Agents, and other Lenders thereto (incorporated by reference to Exhibit 10.2 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011 (File No. 1-12534))
10.30.2
-
Second Amendment to Credit Agreement, dated as of April 29, 2013, by and among Newfield and JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, and BBVA Compass, The Bank of Tokyo-Mitsubishi UFJ, Ltd., DNB Bank ASA, Sumitomo Mitsui Banking Corporation and U.S. Bank National Association, as Co-Documentation Agents, and other Lenders thereto (incorporated by reference to Exhibit 10.36.2 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 1-12534))
10.30.3
-
Third Amendment to Credit Agreement, dated as of June 25, 2013, by and among Newfield and JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, and BBVA Compass, The Bank of Tokyo-Mitsubishi UFJ, Ltd., DNB Bank ASA, Sumitomo Mitsui Banking Corporation and U.S. Bank National Association, as Co-Documentation Agents, and other Lenders thereto (incorporated by reference to Exhibit 10.2 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013 (File No. 1-12534))
10.31
-
Share Purchase Agreement between Newfield International Holdings Inc., as Seller, and SapuraKencana Petroleum Berhad, as Purchaser, dated as of October 22, 2013 (incorporated by reference to Exhibit 2.1 to Newfield’s Current Report on Form 8-K filed with the SEC on February 14, 2014 (File No. 1-12534))
10.31.1
-
Amendment to Share Purchase Agreement between Newfield International Holdings Inc., as Seller, and SapuraKencana Petroleum Berhad, as Purchaser, dated as of February 9, 2014 (incorporated by reference to Exhibit 2.2 to Newfield's Current Report on Form 8-K filed with the SEC on February 14, 2014 (File No. 1-12534))
†10.32
-
Retirement Agreement of Terry W. Rathert (incorporated by reference to Exhibit 10.1 to Newfield's Current Report on Form 8-K filed with the SEC on August 29, 2014 (File No. 1-12535))
†10.33
-
Form of Change of Control Severance Agreement by and between the Company and Lawrence S. Massaro (incorporated by reference to Exhibit 10.1 to Newfield's Current Report on Form 8-K filed with the SEC on December 23, 2014 (File No. 1-12535))
*21.1
-
List of Significant Subsidiaries
*23.1
-
Consent of PricewaterhouseCoopers LLP
*24.1
-
Power of Attorney
*31.1
-
Certification of Chief Executive Officer of Newfield Exploration Company pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.2
-
Certification of Chief Financial Officer of Newfield Exploration Company pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*32.1
-
Certification of Chief Executive Officer of Newfield Exploration Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*32.2
-
Certification of Chief Financial Officer of Newfield Exploration Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*101.INS
-
XBRL Instance Document
*101.SCH
-
XBRL Schema Document
*101.CAL
-
XBRL Calculation Linkbase Document
*101.LAB
-
XBRL Label Linkbase Document
*101.PRE
-
XBRL Presentation Linkbase Document
*101.DEF
-
XBRL Definition Linkbase Document
_________________
*
Filed or furnished herewith.
†
Identifies management contracts and compensatory plans or arrangements.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 24th day of February 2015.
NEWFIELD EXPLORATION COMPANY
By:
/s/ LEE K. BOOTHBY
Lee K. Boothby
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated and on the 24th day of February 2015.
Signature
Title
/S/ LEE K. BOOTHBY
President, Chief Executive Officer and Chairman of the Board
Lee K. Boothby
(Principal Executive Officer)
/S/ LAWRENCE S. MASSARO
Executive Vice President and Chief Financial Officer
Lawrence S. Massaro
(Principal Financial Officer)
/S/ GEORGE W. FAIRCHILD, JR.
Chief Accounting Officer and Assistant Corporate Secretary
George W. Fairchild, Jr.
(Principal Accounting Officer)
/S/ PAMELA J. GARDNER*
Director
Pamela J. Gardner
/S/ JOHN R. KEMP III*
Director
John R. Kemp III
/S/ STEVEN W. NANCE*
Director
Steven W. Nance
/S/ HOWARD H. NEWMAN*
Director
Howard H. Newman
/S/ THOMAS G. RICKS*
Director
Thomas G. Ricks
/S/ JUANITA M. ROMANS*
Director
Juanita M. Romans
/S/ JOHN W. SCHANCK*
Director
John W. Schanck
/S/ C. E. SHULTZ*
Director
C. E. Shultz
/S/ RICHARD K. STONEBURNER*
Director
Richard K. Stoneburner
/S/ J. TERRY STRANGE*
Director
J. Terry Strange
*By:
/s/ GEORGE W. FAIRCHILD, JR.
George W. Fairchild, Jr.
as Attorney-in-Fact
EXHIBIT INDEX
Exhibit
Number
Title
3.1
-
Third Restated Certificate of Incorporation of Newfield dated December 14, 2011 (incorporated by reference to Exhibit 3.1 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2011 (File No. 1-12534))
3.2
-
Amended and Restated Bylaws of Newfield (incorporated by reference to Exhibit 3.2 to Newfield’s Current Report on Form 8-K filed with the SEC on July 25, 2013 (File No. 1-12534))
4.1
-
Senior Indenture dated as of February 28, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association (formerly First Union National Bank)), as Trustee (the “Senior Indenture”) (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on February 28, 2001 (File No. 1-12534))
4.1.1
-
First Supplemental Indenture, dated as of February 19, 2010, to Senior Indenture dated as of February 28, 2001 between Newfield and U.S. Bank National Association (as successor to First Union National Bank), as Trustee (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on February 19, 2010 (File No. 1-12534))
4.1.2
-
Second Supplemental Indenture, dated as of September 30, 2011, to Senior Indenture dated as of February 28, 2001 between Newfield and U.S. Bank National Association (as successor to First Union National Bank), as Trustee (incorporated by reference to Exhibit 4.2 to Newfield’s Current Report on Form 8-K filed with the SEC on September 30, 2011 (File No. 1-12534))
4.1.3
-
Third Supplemental Indenture, dated as of June 26, 2012, to Senior Indenture dated as of February 28, 2001 between Newfield and U.S. Bank National Association (as successor to First Union National Bank), as Trustee (incorporated by reference to Exhibit 4.2 to Newfield’s Current Report on Form 8-K filed with the SEC on June 26, 2012 (File No. 1-12534))
4.2
-
Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association (formerly First Union National Bank)), as Trustee (the “Subordinated Indenture”) (incorporated by reference to Exhibit 4.5 to Newfield’s Registration Statement on Form S-3/A filed with the SEC on December 13, 2001 (Registration No. 333-71348))
4.2.1
-
Second Supplemental Indenture, dated as of August 18, 2004, to Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.6.3 to Newfield’s Registration Statement on Form S-4 filed with the SEC on January 19, 2005 (Registration No. 333-122157))
4.2.2
-
Third Supplemental Indenture, dated as of April 3, 2006, to Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.4.3 to Newfield’s Current Report on Form 8-K filed with the SEC on April 3, 2006 (File No. 1-12534))
4.2.3
-
Fourth Supplemental Indenture, dated as of May 8, 2008, to Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on May 7, 2008 (File No. 1-12534))
4.2.4
-
Fifth Supplemental Indenture, dated as of January 25, 2010, to Subordinated Indenture dated as of December 10, 2001 between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on January 26, 2010 (File No. 1-12534))
4.2.5
-
Sixth Supplemental Indenture, dated as of July 3, 2012, to the Subordinated Indenture dated as of December 10, 2001, between Newfield and U.S. Bank National Association (as successor to Wachovia Bank, National Association), as Trustee (incorporated by reference to Exhibit 4.1 to Newfield’s Current Report on Form 8-K filed with the SEC on July 3, 2012 (File No. 1-12534))
†10.1
-
Newfield Exploration Company 2000 Omnibus Stock Plan (As Amended and Restated Effective February 14, 2002) (incorporated by reference to Exhibit 10.7.2 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 1-12534))
†10.1.1
-
First Amendment to Newfield Exploration Company 2000 Omnibus Stock Plan (As Amended and Restated Effective February 14, 2002) (incorporated by reference to Exhibit 10.3 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003 (File No. 1-12534))
†10.1.2
-
Second Amendment to Newfield Exploration Company 2000 Omnibus Stock Plan (As Amended and Restated Effective February 14, 2002) (incorporated by reference to Exhibit 99.3 to Newfield’s Current Report on Form 8-K filed with the SEC on May 5, 2005 (File No. 1-12534))
†10.2
-
Newfield Exploration Company 2004 Omnibus Stock Plan (As Amended and Restated Effective February 7, 2007) (incorporated by reference to Exhibit 10.1 to Newfield’s Current Report on Form 8-K/A filed with the SEC on March 1, 2007 (File No. 1-12534))
†10.2.1
-
First Amendment to Newfield Exploration Company 2004 Omnibus Stock Plan (As Amended and Restated Effective February 7, 2007) (incorporated by reference to Exhibit 10.4.1 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2007 (File No. 1-12534))
†10.3
-
Newfield Exploration Company 2009 Omnibus Stock Plan (incorporated by reference to Exhibit 99.1 to Newfield’s Registration Statement on Form S-8 filed with the SEC on May 4, 2009 (Registration No. 333-158961))
†10.4
-
Form of 2008 Stock Option Agreement between Newfield and each of Lee K. Boothby, Michael Van Horn, George T. Dunn, John H. Jasek, Gary D. Packer, James T. Zernell, Stephen C. Campbell, John D. Marziotti, Susan G. Riggs and Daryll T. Howard dated as of February 7, 2008 (incorporated by reference to Exhibit 10.3 to Newfield’s Current Report on Form 8-K filed with the SEC on February 14, 2008 (File No. 1-12534))
†10.5
-
Form of Restricted Stock Agreement dated as of February 4, 2009 between Newfield and its executive officers (incorporated by reference to Exhibit 10.15 to Newfield’s Current Report on Form 8-K filed with the SEC on February 6, 2009 (File No. 1-12534))
†10.6
-
Form of Restricted Stock Agreement between Newfield and each of Lee K. Boothby and Gary D. Packer dated as of May 7, 2009 (incorporated by reference to Exhibit 10.24 to Newfield’s Current Report on Form 8-K filed with the SEC on May 11, 2009 (File No. 1-12534))
†10.7
-
Form of 2010 TSR Restricted Stock Unit Agreement between Newfield and its executive officers dated as of February 4, 2010 (incorporated by reference to Exhibit 10.20 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2009 (File No. 1-12534))
†10.8
-
Form of 2010 Restricted Stock Unit Agreement between Newfield and its executive officers dated as of February 4, 2010 (incorporated by reference to Exhibit 10.21 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2009 (File No. 1-12534))
†10.9
-
Summary of Non-Employee Director Compensation Program (incorporated by reference to Exhibit 10.14 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2011 (File No. 1-12534))
†10.10
-
Second Amended and Restated Newfield Exploration Company 2003 Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2007 (File No. 1-12534))
†10.11
-
Newfield Exploration Company 2011 Annual Incentive Plan (incorporated by reference to Exhibit 10.25 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 1-12534))
†10.12
-
Newfield Exploration Company Deferred Compensation Plan as Amended and Restated as of November 6, 2008 (incorporated by reference to Exhibit 10.17.1 to Newfield’s Current Report on Form 8-K filed with the SEC on November 10, 2008 (File No. 1-12534))
†10.12.1
-
Amendment No. 1 to Newfield Exploration Company Deferred Compensation Plan and its related Non-Qualified Deferred Compensation Plan Trust Agreement (incorporated by reference to Exhibit 10.1 to Newfield’s Current Report on Form 8-K filed with the SEC on November 14, 2012 (File No. 1-12534))
†10.13
-
Fourth Amended and Restated Newfield Exploration Company Change of Control Severance Plan (incorporated by reference to Exhibit 10.18 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2012 (File No. 1-12534))
†10.14
-
Form of Third Amended and Restated Change of Control Severance Agreement between Newfield and Lee K. Boothby dated effective as of January 1, 2009 (incorporated by reference to Exhibit 10.31 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 1-12534))
†10.15
-
Form of Second Amended and Restated Change of Control Severance Agreement between Newfield and each of John H. Jasek and James T. Zernell dated effective as of January 1, 2009 (incorporated by reference to Exhibit 10.32 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 1-12534))
†10.16
-
Form of Fourth Amended and Restated Change of Control Severance Agreement between Newfield and each of George T. Dunn and Gary D. Packer dated effective as of January 1, 2009 (incorporated by reference to Exhibit 10.33 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2010 (File No. 1-12534))
†10.17
-
Form of Indemnification Agreement between Newfield and each of its directors and executive officers (incorporated by reference to Exhibit 10.20 to Newfield’s Current Report on Form 8-K filed with the SEC on February 6, 2009 (File No. 1-12534))
†10.18
-
Form of 2011 Executive Officer Restricted Stock Unit Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2011 (File No. 1-12534))
†10.19
-
Form of 2011 Executive Officer TSR Restricted Stock Unit Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.2 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2011 (File No. 1-12534))
†10.20
-
Form of 2012 Executive Officer Restricted Stock Unit Award Agreement Under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2012 (File No. 1-12534))
†10.21
-
Form of 2012 Executive Officer TSR Restricted Stock Unit Award Agreement Under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.2 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2012 (File No. 1-12534))
†10.22
-
Newfield Exploration Company 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 99.1 to Newfield’s Registration Statement on Form S-8 filed with the SEC on May 5, 2011 (Registration No. 333-173964))
†10.22.1
-
Newfield Exploration Company Amended and Restated 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield’s Current Report on Form 8-K filed with the SEC on May 3, 2013 (File No. 1-12534))
†10.23
-
Form of Non-Employee Director Restricted Stock Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.5 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2011 (File No. 1-12534))
†10.24
-
Form of 2013 Executive Officer Restricted Stock Unit Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013 (File No. 1-12534))
†10.25
-
Form of 2013 Executive Officer TSR Restricted Stock Unit Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.2 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2013 (File No. 1-12534))
†10.26
-
Form of 2014 Cash-Settled Restricted Stock Unit Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.3 to Newfield's Current Report on Form 8-K filed with the SEC on February 19, 2014 (File No. 1-12534))
†10.27
-
Form of 2014 Restricted Stock Unit Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield's Current Report on Form 8-K filed with the SEC on February 19, 2014 (File No. 1-12534))
†10.28
-
Amended Form of 2014 Executive Officer TSR Restricted Stock Unit Award Agreement under 2011 Omnibus Stock Plan (incorporated by reference to Exhibit 10.1 to Newfield's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2014 (File No. 1-12534))
†10.29
-
Newfield Exploration Company 2010 Employee Stock Purchase Plan (incorporated by reference to Exhibit 99.1 to Newfield's Registration Statement on Form S-8 filed with the SEC on May 10, 2010 (File No. 333-166672))
†10.29.1
-
Amendment No. 1 to the Newfield Exploration Company 2010 Employee Stock Purchase Plan (incorporated by reference to Exhibit 10.1to Newfield's Current Report on Form 8-K filed with the SEC on February 11, 2014 (File No. 1-12534))
10.30
-
Credit Agreement, dated as of June 2, 2011, by and among Newfield and JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, and BBVA Compass, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and DNB Nor Bank ASA, as Co-Documentation Agents, and other Lenders thereto (incorporated by reference to Exhibit 10.1 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011 (File No. 1-12534))
10.30.1
-
First Amendment to Credit Agreement, dated as of September 27, 2011, by and among Newfield and JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, and BBVA Compass, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and DNB Nor Bank ASA, as Co-Documentation Agents, and other Lenders thereto (incorporated by reference to Exhibit 10.2 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011 (File No. 1-12534))
10.30.2
-
Second Amendment to Credit Agreement, dated as of April 29, 2013, by and among Newfield and JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, and BBVA Compass, The Bank of Tokyo-Mitsubishi UFJ, Ltd., DNB Bank ASA, Sumitomo Mitsui Banking Corporation and U.S. Bank National Association, as Co-Documentation Agents, and other Lenders thereto (incorporated by reference to Exhibit 10.36.2 to Newfield’s Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 1-12534))
10.30.3
-
Third Amendment to Credit Agreement, dated as of June 25, 2013, by and among Newfield and JPMorgan Chase Bank, N.A., as Administrative Agent, Wells Fargo Bank, N.A., as Syndication Agent, and BBVA Compass, The Bank of Tokyo-Mitsubishi UFJ, Ltd., DNB Bank ASA, Sumitomo Mitsui Banking Corporation and U.S. Bank National Association, as Co-Documentation Agents, and other Lenders thereto (incorporated by reference to Exhibit 10.2 to Newfield’s Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2013 (File No. 1-12534))
10.31
-
Share Purchase Agreement between Newfield International Holdings Inc., as Seller, and SapuraKencana Petroleum Berhad, as Purchaser, dated as of October 22, 2013 (incorporated by reference to Exhibit 2.1 to Newfield’s Current Report on Form 8-K filed with the SEC on February 14, 2014 (File No. 1-12534))
10.31.1
-
Amendment to Share Purchase Agreement between Newfield International Holdings Inc., as Seller, and SapuraKencana Petroleum Berhad, as Purchaser, dated as of February 9, 2014 (incorporated by reference to Exhibit 2.2 to Newfield's Current Report on Form 8-K filed with the SEC on February 14, 2014 (File No. 1-12534))
†10.32
-
Retirement Agreement of Terry W. Rathert (incorporated by reference to Exhibit 10.1 to Newfield's Current Report on Form 8-K filed with the SEC on August 29, 2014 (File No. 1-12535))
†10.33
-
Form of Change of Control Severance Agreement by and between the Company and Lawrence S. Massaro (incorporated by reference to Exhibit 10.1 to Newfield's Current Report on Form 8-K filed with the SEC on December 23, 2014 (File No. 1-12535))
*21.1
-
List of Significant Subsidiaries
*23.1
-
Consent of PricewaterhouseCoopers LLP
*24.1
-
Power of Attorney
*31.1
-
Certification of Chief Executive Officer of Newfield Exploration Company pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*31.2
-
Certification of Chief Financial Officer of Newfield Exploration Company pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
*32.1
-
Certification of Chief Executive Officer of Newfield Exploration Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*32.2
-
Certification of Chief Financial Officer of Newfield Exploration Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*101.INS
-
XBRL Instance Document
*101.SCH
-
XBRL Schema Document
*101.CAL
-
XBRL Calculation Linkbase Document
*101.LAB
-
XBRL Label Linkbase Document
*101.PRE
-
XBRL Presentation Linkbase Document
*101.DEF
-
XBRL Definition Linkbase Document
_________________
*
Filed or furnished herewith.
†
Identifies management contracts and compensatory plans or arrangements.

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Stock Performance Metrics:
Return: -0.001261400524526834
1-Day Return: $1_day_return
3-Day Return: $3_day_return
5-Day Return: $5_day_return
10-Day Return: $10_day_return
20-Day Return: $20_day_return
40-Day Return: $40_day_return
60-Day Return: $60_day_return
80-Day Return: $80_day_return
100-Day Return: $100_day_return
150-Day Return: $150_day_return
252-Day Return: $252_day_return