SOUTHWESTERN ENERGY CO
ITEM 1. BUSINESS
﻿
Southwestern Energy Company (including its subsidiaries, collectively, “we”, “Southwestern” or the “Company”) is an independent natural gas and oil company engaged in development and production activities, including related natural gas gathering and marketing. Southwestern is a holding company whose assets consist of direct and indirect ownership interests in, and whose business is conducted substantially through, its subsidiaries. Currently we operate only in the United States. Southwestern’s common and preferred stock are listed and traded on the NYSE under the ticker symbols “SWN” and “SWNC”, respectively.
﻿
Southwestern, which was incorporated in Arkansas in 1929 and reincorporated in Delaware in 2006, has its executive offices located at 10000 Energy Drive, Spring, Texas 77389, and can be reached by phone at 832-796-1000. The Company also maintains offices in Conway, Arkansas; Tunkhannock, Pennsylvania; and Jane Lew, West Virginia.
﻿
Our Business Strategy
﻿
We aim to deliver sustainable and assured industry-leading returns through excellence in exploration and production and midstream performance from our extensive resource base and targeted expansion of our activities and assets along the hydrocarbon value chain. Our Company’s formula embodies our corporate philosophy and guides how we operate our business:
Our formula, “The Right People doing the Right Things, wisely investing the cash flow from our underlying Assets will create Value+,” also guides our business strategy. We always strive to attract and retain strong talent, to work safely and act ethically with unwavering vigilance for the environment and the communities in which we operate, and to creatively apply technical and financial skills, which we believe will grow long-term value. The arrow in our formula is not a straight line: we acknowledge that factors may adversely affect quarter-by-quarter results, but the path over time points to value creation.
In applying these core principles, we concentrate on:
·
Financial Strength. We are committed to rigorously managing our balance sheet and risks. We budget to invest only from our net cash flow (along with the remaining portion of proceeds from our equity issuance in 2016 that we previously earmarked for capital investment), protect our projected cash flows through hedging, and continue to ensure strong liquidity while de-levering the Company.
·
Increasing Margins. We apply strong technical, operational, commercial and marketing skills to reduce cost, improve the productivity of our wells and pursue commercial arrangements that extract greater value from them. We believe our demonstrated ability to improve margins, especially by levering the scale of our large assets, gives us a competitive advantage as we move into the future.
·
Dynamic Management of Assets Throughout Life Cycle. We own large-scale, long-life assets in various phases of development. In early stages, we ramp up development through technical, operational and commercial skills, and as they grow we look for ways to maximize their value, through efficient operating practices along with commercial and marketing expertise.
·
Deepening Our Inventory. We continue to expand the inventory of properties that we can develop profitably by converting our extensive resources into proved reserves, targeting additions whose productivity largely has been demonstrated and improving efficiencies in production.
·
The Hydrocarbon Value Chain. We often expand our activities vertically when we believe this will enhance our margins or otherwise provide us competitive advantages. For example, the Company developed and operates the largest gathering system in the Fayetteville Shale area. We operate drilling rigs and own a sand mine that provides a low cost proppant in hydraulic fracturing. These activities help protect our margin, minimize the risk of unavailability of these resources from third parties, diversify our cash flows and capture additional value.
·
The Next Chapter of Unconventionals. Our company grew dramatically in the 2000s by harnessing and enhancing the newfound combination of hydraulic fracturing and horizontal drilling technologies. Our people constantly search for the next revolutionary technology and other operational advancements to capture greater value in unconventional hydrocarbon resource development. These developments - whether single, step-changing technologies or a combination of several incremental ones - can reduce finding and development costs and thus increase our margins.
			
		
			
		
·
Innovative Environmental Solutions and Policy Formation. Our Company is a leader in identifying and implementing innovative solutions to unconventional hydrocarbon development to minimize the environmental and community impacts of our activities. We work extensively with governmental, non-governmental and industry stakeholders to develop responsible and cost-effective programs. We demonstrate that a company can operate responsibly and profitably, putting us in a better position to comply with new regulations as they evolve.
﻿
During 2016, we executed on our business strategy by:
·
Investing within our cash flow plus a portion of the proceeds from our successful equity offering earmarked for this purpose, with the remainder to debt reduction
·
Investing in only those projects that meet our rigorous economic hurdles at strip pricing
·
Rearranging and extending our bank credit facilities and successfully tendering for approximately $700 million of near-term senior notes, which enhanced and stabilized our liquidity and eliminated the overhang of near-term debt maturities
·
Generating cash flow from operations of about $500 million, which reflects the impact of an aggressive assault on costs and improved drilling and completion performance
·
Intelligently managing our portfolio, including disposing of acreage we were not planning to develop until well into the next decade and using the over $400 million of proceeds to reduce debt
﻿
Our predominant operations, which we refer to as Exploration and Production (“E&P”), are focused on the finding and development of natural gas, oil and natural gas liquid (“NGL”) reserves. We are also focused on creating and capturing additional value through our natural gas gathering and marketing segment, which we refer to as Midstream Services. We conduct substantially all of our business through subsidiaries.
﻿
Exploration and Production - Our largest business is the exploration for and production of natural gas, oil and NGLs, with our current operations principally focused within the United States on development of unconventional natural gas reservoirs located in Pennsylvania, West Virginia and Arkansas. Our operations in northeast Pennsylvania are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale (herein referred to as “Northeast Appalachia”), our operations in West Virginia are also focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas, oil and NGL reservoirs (herein referred to as “Southwest Appalachia”) and our operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale. Collectively, our properties located in Pennsylvania and West Virginia are herein referred to as the “Appalachian Basin.” We have smaller holdings in Colorado and Louisiana along with other areas in which we are testing potential new resources, including New Brunswick, Canada whose development is subject to a moratorium. We also have drilling rigs located in Pennsylvania, West Virginia and Arkansas and provide oilfield products and services, principally serving our production operations.
﻿
Midstream Services - Through our affiliated midstream subsidiaries, we engage in natural gas gathering activities in Arkansas and Louisiana. These activities primarily support our E&P operations and generate revenue from the gathering of natural gas. Our marketing activities capture opportunities that arise through the marketing and transportation of the natural gas, oil and NGLs produced in our E&P operations.
﻿
Historically, the vast majority of our cash flow from operations has been derived from our E&P business. In 2016 and 2015, depressed commodity prices significantly decreased our E&P results. In 2016, our E&P segment generated cash flow from operations of $297 million, which constituted 60% of our total cash flow from operations. This compares to E&P-generated cash flow from operations of $1.1 billion and $2.1 billion in 2015 and 2014, respectively. Our E&P segment constituted 71% and 89% of our total cash flow from operations in 2015 and 2014, respectively. The remainder of our consolidated cash flow from operations in each of these years was primarily generated from our Midstream Services segment.
﻿
			
		
			
		
Exploration and Production
﻿
Overview
﻿
Operations in our E&P segment are primarily in the Appalachian Basin and Arkansas. We also are conducting activities in other basins targeting various formations as potential new resources.
﻿
Our E&P segment recorded operating losses of $2.4 billion and $7.1 billion in 2016 and 2015, respectively, and operating income of $1.0 billion in 2014. The operating losses in 2016 and 2015 were primarily the result of $2.3 billion, or $1.4 billion net of taxes, and $7.0 billion, or $4.3 billion net of taxes, respectively, of non-cash impairments of natural gas and oil properties due to decreased commodity prices. In May 2015, we divested of our East Texas and Arkoma properties, previously referred to as the Ark-La-Tex division.
﻿
Cash flow from operations from our E&P segment was $297 million in 2016, compared to $1.1 billion in 2015 and $2.1 billion in 2014. Our cash flow from operations decreased in 2016 as the effects of lower realized natural gas prices and decreased natural gas production more than offset our reduction in operating expenses. Our cash flow from operations decreased in 2015 as lower realized natural gas prices and increased total operating costs and expenses, due to increased activity levels, more than offset the revenue impacts of higher production volumes.
﻿
Oilfield Services Vertical Integration
﻿
We provide some oilfield services that are strategic and economically beneficial for our E&P operations when our E&P activity levels and market pricing support these activities and we can do so more efficiently or cost-effectively. This vertical integration lowers our net well costs, allows us to operate efficiently and helps us to mitigate certain operational environmental risks. Among others, these services have included drilling, hydraulic fracturing and the mining of sand used as proppant for certain of our well completions in the Fayetteville Shale from a 570-acre complex in Arkansas.
﻿
We have conducted drilling operations for a majority of our operated wells. As of December 31, 2016, we had a total of five rigs drilling in Pennsylvania, West Virginia and Arkansas. In 2016, we provided drilling services for all of the wells that we operate in Northeast Appalachia, Southwest Appalachia and the Fayetteville Shale. Our drilling and completion services, along with our sand mine servicing our operated wells in the Fayetteville Shale, were inactive during our suspension of drilling and completion activities in the first half of 2016, but resumed, in part, as these activities were reinitiated during the third quarter of 2016.
﻿
We ceased providing hydraulic fracturing services in early 2016 at the same time as we suspended drilling and completion activities. To date, we have not resumed the provision of hydraulic fracturing services ourselves and instead are utilizing third parties who are offering lower costs. This may change as industry activity resumes, should that lead to higher prices or lower dependability from third-party providers of these services.
﻿
			
		
			
		
Our Proved Reserves
﻿
Our estimated proved natural gas, oil and NGL reserves were 5,253 Bcfe at year-end 2016, compared to 6,215 Bcfe at year-end 2015 and 10,747 Bcfe at year-end 2014. The decrease in our reserves in 2016 was primarily due to our production in 2016 and downward price revisions associated with decreased commodity prices, partially offset by upward performance revisions in Northeast Appalachia, Southwest Appalachia and the Fayetteville Shale. The significant decrease in our reserves in 2015 was primarily due to downward price revisions in our proved undeveloped reserves associated with decreased commodity prices and our production, partially offset by upward performance revisions in Northeast Appalachia and Southwest Appalachia and our successful development programs in the Northeast Appalachia, Southwest Appalachia and the Fayetteville Shale. The significant increase in our reserves in 2014 was primarily due to the acquisition of approximately 413,000 net acres in Southwest Appalachia, our successful development drilling programs in Northeast Appalachia and the Fayetteville Shale and upward performance revisions in Northeast Appalachia. Because our proved reserves are primarily natural gas, our reserve estimates and the after-tax PV-10 measure, or standardized measure of discounted future net cash flows relating to proved natural gas, oil and NGL reserve quantities, are highly dependent upon the natural gas price used in our reserve and after-tax PV-10 calculations. In order to value our estimated proved natural gas, oil and NGL reserves as of December 31, 2016, we utilized average prices from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.48 per MMBtu for natural gas, West Texas Intermediate oil of $39.25 per barrel for oil and $6.74 per barrel for NGLs, compared to $2.59 per MMBtu for natural gas, $46.79 per barrel for oil and $6.82 per barrel for NGLs at December 31, 2015 and $4.35 per MMBtu for natural gas, $91.48 per barrel for oil and $23.79 per barrel for NGLs at December 31, 2014.
﻿
Our after-tax PV-10 was $1.7 billion at year-end 2016, $2.4 billion at year-end 2015 and $7.5 billion at year-end 2014. The decrease in our after-tax PV-10 value in 2016 compared to 2015 was primarily due to lower reserve levels. The decrease in 2015 compared to 2014 was primarily due to comparatively lower average commodity prices. The difference in after-tax PV-10 and pre-tax PV-10 (a non-GAAP measure which is reconciled in the 2016 Proved Reserves by Category and Summary Operating Data table below) is the discounted value of future income taxes on the estimated cash flows. Our year-end 2016 estimated proved reserves had a present value of estimated future net cash flows before income tax, or pre-tax PV-10, of $1.7 billion, compared to $2.4 billion at year-end 2015 and $9.5 billion at year-end 2014. Our year-end 2016 and 2015 after-tax PV-10 computations do not have future income taxes because our tax basis in the associated oil and gas properties exceeded expected pre-tax cash inflows, and thus do not differ from the pre-tax values.
﻿
We believe that the pre-tax PV-10 value of the estimated cash flows related to our estimated proved reserves is a useful supplemental disclosure to the after-tax PV-10 value. Pre-tax PV-10 is based on prices, costs and discount factors that are comparable from company to company, while the after-tax PV-10 is dependent on the unique tax situation of each individual company. We understand that securities analysts use pre-tax PV-10 as one measure of the value of a company’s current proved reserves and to compare relative values among peer companies without regard to income taxes. We refer you to “Supplemental Oil and Gas Disclosures” in Item 8 of Part II of this Annual Report for a discussion of our standardized measure of discounted future cash flows related to our proved natural gas, oil and NGL reserves, to the risk factor “Our proved natural gas, oil and NGL reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated” in
ITEM 1A. RISK FACTORS
﻿
You should carefully consider the following risk factors in addition to the other information included in this Annual Report on Form 10-K. Each of these risk factors could adversely affect our business, operating results and financial condition, as well as adversely affect the value of an investment in our common stock.
﻿
Natural gas, oil and natural gas liquids prices greatly affect our business, including our revenues, profits, liquidity, growth, ability to repay our debt and the value of our assets.
﻿
Our revenues, profitability, liquidity, growth, ability to repay our debt and the value of our assets greatly depend on prices for natural gas, oil and natural gas liquids. The markets for these commodities have been volatile, and we expect that volatility to continue. The prices of natural gas, oil and natural gas liquids fluctuate in response to changes in supply and demand (global, regional and local), transportation costs, market uncertainty and other factors that are beyond our control. Short- and long-term prices are subject to a myriad of factors such as:
• overall demand, including the relative cost of competing sources of energy or fuel;
• overall supply, including costs of production;
• the availability, proximity and capacity of pipelines, other transportation facilities and gathering, processing and storage facilities;
• regional basis differentials;
• national and worldwide economic and political conditions;
• weather conditions and seasonal trends;
• government regulations, such as regulation of natural gas transportation and price controls;
• inventory levels; and
• market perceptions of future prices, whether due to the foregoing factors or others.
﻿
For example, in 2016 and 2015, our production was approximately 90% and 92% natural gas, respectively, and during this period spot prices ranged from a low of $1.49 per Mcf in March 2016 to a high of $3.80 per Mcf in December 2016.
﻿
In our exploration and production business, lower natural gas, oil and NGL prices directly reduce our revenues and thus our operating income and cash flow. Lower prices also reduce the projected profitability of further drilling and therefore are likely to reduce our drilling activity, which in turn means we will have fewer wells on production in the future. Lower prices also reduce the value of our assets, both by a direct reduction in what the production would be worth and by making some properties uneconomic, resulting in impairments to the recorded value of our reserves and non-cash charges to earnings. For example, in 2016, we reported non-cash impairment charges on our natural gas and oil properties totaling $2,321 million, primarily resulting from decreases in trailing 12-month average first-day-of-the-month natural gas prices throughout 2016, as compared to 2015, and the impairment of certain undeveloped leasehold interests. Further impairments in subsequent periods could occur if the trailing 12-month commodity prices continue to fall as compared to the average used in prior periods.
﻿
In our Midstream Services segment, lower production by us and others can mean reduced volumes being transported in the gathering systems we operate and thus lower revenues.
﻿
As of December 31, 2016, we had $4.7 billion of debt outstanding, consisting principally of $3.2 billion in senior notes maturing in various increments from 2017 to 2025 and $1.5 billion in term loans due in 2020. At current commodity price levels, our net cash flow from operations is substantially higher than our interest obligations under this debt, but significant drops in realized prices could affect our ability to pay our current obligations or refinance our debt as it becomes due.
﻿
Moreover, general industry conditions may make it difficult or costly to refinance increments of this debt as it matures. While our indentures do not contain significant covenants restricting our operations and other activities, our 2016 credit agreement contains financial covenants with which we must comply. We refer you to the risk factor “Our current and future levels of indebtedness may adversely affect our results and limit our growth.” Our inability to pay our current obligations or refinance our debt as it becomes due could have a material and adverse effect on our company. The drop in prices in the past three years has reduced our revenues, profits and cash flow, caused us to record significant asset impairments and led us to reduce both our level of capital investing and our workforce, which has caused us to incur significant expenses relating
			
		
			
		
to employee terminations. Further price decreases could have similar consequences. Similarly, a rise in prices to levels experienced into the middle of 2014 could significantly increase our revenues, profits and cash flow, which could be used to expand capital investments.
﻿
Significant capital investment is required to replace our reserves and conduct our business.
﻿
Our activities require substantial capital investment. We intend to fund our capital investing through net cash flows from operations, plus the uninvested amount of the proceeds from our July 2016 equity offering and West Virginia acreage sale earmarked for capital investment (approximately $200 million remaining as of December 31, 2016). Our ability to generate operating cash flow is subject to many of the risks and uncertainties that exist in our industry, some of which we may not be able to anticipate at this time. Future cash flows from operations are subject to a number of risks and variables, such as the level of production from existing wells, prices of natural gas, oil and natural gas liquids, our success in developing and producing new reserves and the other risk factors discussed herein. If we are unable to fund capital investing, we could experience a further reduction in drilling new wells and acquiring new acreage, a loss of properties and a decline in our cash flow from operations and natural gas, oil and natural gas liquids production and reserves.
﻿
If we are not able to replace reserves, we may not be able to grow or sustain production.
﻿
Our future success depends largely upon our ability to find, develop or acquire additional natural gas, oil and NGL reserves that are economically recoverable. Unless we replace the reserves we produce through successful exploration, development or acquisition activities, our proved reserves and production will decline over time. Recovery of such reserves will require significant capital investment and successful drilling operations. Thus, our future natural gas, oil and NGL reserves and production, and therefore our cash flow and income, are highly dependent on our level of capital investments, our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves.
﻿
A further downgrade in our credit rating could negatively impact our cost of and ability to access capital and our liquidity.
﻿
Actual or anticipated changes or downgrades in our credit ratings, including any announcement that our ratings are under further review for a downgrade, could impact our ability to access debt markets in the future, affect the market value of our senior notes and increase our corporate borrowing costs. Such ratings are limited in scope, and do not address all material risks relating to us, but rather reflect only the view of each rating agency at the time the rating is issued of the likelihood we will be able to repay our debt. An explanation of the significance of each rating may be obtained from the applicable rating agency. As of February 21, 2017, we were rated Ba3 by Moody’s, BB- by Standard and Poor’s and BB by Fitch Investor Services. There can be no assurance that such credit ratings will remain in effect for any given period of time or that such ratings will not be lowered, suspended or withdrawn entirely by the rating agencies, if, in each rating agency’s judgment, circumstances so warrant.
﻿
Actual downgrades in our credit ratings may also impact our liquidity. Many of our existing commercial contracts contain, and future commercial contracts may contain, provisions permitting the counterparty to require increased security upon the occurrence of a downgrade in our credit rating. Providing additional security, such as posting letters of credit, could reduce our available cash or our liquidity under our revolving credit facility for other purposes. We had $174 million of letters of credit outstanding at December 31, 2016. The amount of additional security would depend on the severity of the downgrade from the credit rating agencies, and a downgrade could result in a decrease in our liquidity.
﻿
Strategic determinations, including the allocation of capital and other resources to strategic opportunities, are challenging in the face of shifting market conditions, and our failure to appropriately allocate capital and resources among our strategic opportunities may adversely affect our financial condition and reduce our future growth rate.
﻿
We necessarily must consider future price and cost environments when deciding how much capital we are likely to have available from net cash flow and how best to allocate it. Our current philosophy is to generally operate within cash flow from operations and to invest capital in projects only if they are projected to generate a PVI of 1.3 or greater, allocating generally to the highest PVI projects. Volatility in prices and potential errors in estimating costs, reserves or timing of production of the reserves could result in uneconomic projects or economic projects generating less than 1.3 PVI.
﻿
Certain of our undeveloped assets are subject to leases that will expire over the next several years unless production is established on units containing the acreage.
﻿
Leases on approximately 159,176 net acres of our Fayetteville Shale acreage (including 158,231 net acres held on federal lands that are currently suspended by the Bureau of Land Management) will expire in the next three years if we do not drill
			
		
			
		
successful wells to develop the acreage or otherwise take action to extend the leases. Approximately 91,379 and 62,520 net acres of our Northeast Appalachia and Southwest Appalachia acreage, respectively, will expire in the next three years if we do not drill successful wells to develop the acreage or otherwise take action to extend the leases. Our ability to drill wells depends on a number of factors, including certain factors that are beyond our control, such as the ability to obtain permits on a timely basis or to compel landowners or lease holders on adjacent properties to cooperate. Further, we may not have sufficient capital to drill all the wells necessary to hold the acreage without increasing our debt levels, or given price projections at the time, drilling may not be estimated to achieve a PVI of at least 1.3. To the extent we do not drill the wells, our rights to acreage can be lost.
﻿
Natural gas and oil drilling and producing operations and midstream operation can be hazardous and may expose us to liabilities.
﻿
Exploration and production operations are subject to many risks, including well blowouts, cratering and explosions, pipe failures, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, severe weather, natural disasters, groundwater contamination and other environmental hazards and risks. 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 occurs, we could sustain substantial losses as a result of:
·
injury or loss of life;
·
severe damage to or destruction of property, natural resources or equipment;
·
pollution or other environmental damage;
·
clean-up responsibilities;
·
regulatory investigations and administrative, civil and criminal penalties; and
·
injunctions resulting in limitation or suspension of operations.
﻿
For our non-operated properties, we are dependent on the operator for operational and regulatory compliance.
﻿
Our midstream operations are subject to all of the risks and operational hazards inherent in transporting natural gas and ethane and natural gas compression, including:
·
damages to pipelines, facilities and surrounding properties caused by third parties, severe weather, natural disasters, including hurricanes, and acts of terrorism;
·
maintenance, repairs, mechanical or structural failures;
·
damages to, loss of availability of and delays in gaining access to interconnecting third-party pipelines;
·
disruption or failure of information technology systems and network infrastructure due to various causes, including unauthorized access or attack; and
·
leaks of natural gas or ethane as a result of the malfunction of equipment or facilities.
﻿
A material event such as those described above could expose us to liabilities, monetary penalties or interruptions in our business operations. Although we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be assessed by a governmental authority. Also, in the future we may not be able to obtain insurance at premium levels that justify its purchase.
﻿
Our current and future levels of indebtedness may adversely affect our results and limit our growth.
﻿
At December 31, 2016, we had long-term indebtedness of $4.6 billion, including borrowings of $327 million and $1.2 billion under our term loan credit agreements. The terms of the indentures relating to our outstanding senior notes, our credit facilities, and the master lease agreements relating to our drilling rigs and other equipment, which we collectively refer to as our “financing agreements,” impose restrictions on our ability and, in some cases, the ability of our subsidiaries to take a number of actions that we may otherwise desire to take, which may include, without limitation, one or more of the following:
·
incurring additional debt;
·
redeeming stock or redeeming certain debt;
·
making certain investments;
			
		
			
		
·
creating liens on our assets; and
·
selling assets.
Under the 2013 revolving credit facility, we must keep our total debt at or below 60% of our total adjusted book capital. This financial covenant with respect to capitalization percentages excludes the effects of any non-cash impacts from any full cost ceiling impairments, certain non-cash hedging activities and our pension and other post-retirement liabilities. Therefore, under the 2013 revolving credit facility, our adjusted capital structure as of December 31, 2016 was 34% debt and 66% equity. Under our 2016 credit agreement, we must maintain certain covenants, including, among others, the following financial covenants:
·
Minimum liquidity of $300 million, subject to increase up to $500 million upon certain conditions;
·
Minimum interest coverage ratio of no less than (i) with respect to any fiscal quarter ended on or before December 31, 2016, 0.75x, (ii) with respect to any fiscal quarter ending on or after March 31, 2017 and on or before December 31, 2017, 1.00x, (iii) with respect to any fiscal quarter ending on or after March 31, 2018 and on or before December 31, 2018, 1.25x and (iv) with respect to any fiscal quarter ending on or after March 31, 2019, 1.50x, commencing with the fiscal quarter ending June 30, 2016; and
·
With respect to the secured term loan, a minimum collateral coverage ratio of no less than 1.50x of the secured term loan. Currently this collateral consists of most of our interest in E&P properties in the Fayetteville Shale area, the equity in our subsidiaries and cash and marketable securities.
Although we do not anticipate any violations of our financial covenants, our ability to comply with these covenants are dependent upon the success of our exploration and development program and upon factors beyond our control, such as the market prices for natural gas, oil and NGLs.
﻿
Although the indentures governing the notes contain covenants that apply to us, covenants limiting liens and sale and leaseback covenants contain exceptions and limitations that would allow us, pursuant to the terms of the indenture, to create, grant or incur certain liens or security interests. Moreover, the indentures do not contain any limitations on the ability of us or our subsidiaries to incur debt, pay dividends, make investments, or limit the ability of our subsidiaries to make distributions to us. Such activities may, however, be limited by our other financing agreements in certain circumstances.
﻿
Our level of indebtedness and off-balance sheet obligations, and the covenants contained in our financing agreements, could have important consequences for our operations, including:
·
requiring us to dedicate a substantial portion of our cash flow from operations to required payments, thereby reducing the availability of cash flow for working capital, capital investing and other general business activities;
·
limiting our ability to obtain additional financing in the future for working capital, capital investing, acquisitions and general corporate and other activities;
·
limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and
·
detracting from our ability to successfully withstand a downturn in our business or the economy generally.
﻿
Our ability to comply with the covenants and other restrictions in our financing agreements may be affected by events beyond our control, including prevailing economic and financial conditions.
﻿
If we fail to comply with the covenants and other restrictions, it could lead to an event of default and the acceleration of our obligations under the notes or our other financing agreements, and in the case of the lease agreements for drilling rigs, loss of use of our drilling rigs. In particular, a significant or extended decline in natural gas, oil or NGL prices would have a material adverse effect on our results of operations, our access to capital and the quantities of natural gas, oil and NGLs that we can produce economically. For example, the New York Mercantile Exchange, or NYMEX, natural gas prices traded at a low of $1.71 in February 2016 and a high of $3.23 in December 2016 based on the settlement price of the monthly contract at expiration. If we are unable to satisfy our obligations with cash on hand, we could attempt to refinance such debt, sell assets or repay such debt with the proceeds from an equity offering. 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. The terms of our financing agreements may also prohibit us from taking such actions. Factors that will affect our ability to raise cash through an offering of our capital stock, a refinancing of our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offering or other financing. We cannot assure that any such proposed offering,
			
		
			
		
refinancing or sale of assets can be successfully completed or, if completed, that the terms will be favorable to us.
﻿
We have made significant investments in pipelines and gathering systems and contracts and in oilfield service businesses, including our drilling rigs, pressure pumping equipment and sand mine operations, to lower costs and secure inputs for our operations and transportation for our production. If our exploration and production activities are curtailed or disrupted, we may not recover our investment in these activities, which could adversely impact our results of operations. In addition, our continued expansion of these operations may adversely impact our relationships with third-party providers.
﻿
Through December 31, 2016, we had invested approximately $1.3 billion in our gas gathering system built for the Fayetteville Shale. We may make further substantial investments in the expansion of this system. Our ability to recover the costs of these investments depends on production from the Fayetteville Shale, and reduced production volumes, whether due to lower drilling activity due to lower prices or failure to produce significant quantities of gas in relevant timeframes, can adversely affect our ability to recover these investments.
﻿
We also have entered into gathering agreements in other producing areas and multiple long-term firm transportation agreements relating to natural gas volumes from all our producing areas. As of December 31, 2016, our aggregate demand charge commitments under these firm transportation agreements and gathering agreements were approximately $8.4 billion. If our development programs fail to produce sufficient quantities of natural gas and ethane within expected timeframes, we could be forced to pay demand or other charges for transportation on pipelines and gathering systems that we would not be using.
﻿
We also have made significant investments to meet certain of our field services’ needs, including establishing our own drilling rig operation, sand mine and pressure pumping capability. Reductions in our operating plans caused by the recent drop in commodity prices has caused us to take much of this equipment out of service and has reduced the need for sand and other services. If our level of operations is reduced for a long period, we may not be able to recover these investments. Further, our presence in these service and supply sectors, including competing with them for qualified personnel and supplies, may have an adverse effect on our relationships with our existing third-party service and resource providers or our ability to secure these services and resources from other providers.
Our business depends on access to natural gas, oil and NGL transportation systems and facilities.
The marketability of our natural gas, oil and NGL production depends in large part on the operation, availability, proximity, capacity and expansion of transportation systems and facilities owned by third parties. For example, we can provide no assurance that sufficient transportation capacity will exist for expected production from the Appalachian Basin or that we will be able to obtain sufficient transportation capacity on economic terms. During the past year, several planned pipelines intended to service production in the U.S. Northeast have had their in-service dates delayed due to regulatory delays and litigation.
Producers compete by lowering their sales prices, resulting in the locational differences from NYMEX pricing. Further, a lack of available capacity on transportation systems and facilities or delays in their planned expansions could result in the shut-in of producing wells or the delay or discontinuance of drilling plans for properties. A lack of availability of these systems and facilities for an extended period of time could negatively affect our revenues. In addition, we have entered into contracts for firm transportation and any failure to renew those contracts on the same or better commercial terms could increase our costs and our exposure to the risks described above.
﻿
Our business depends on the availability of water and the ability to dispose of water. Limitations or restrictions on our ability to obtain or dispose of water may have an adverse effect on our financial condition, results of operations and cash flows.
﻿
With current technology, water is an essential component of drilling and hydraulic fracturing processes. Limitations or restrictions on our ability to secure sufficient amounts of water, or to dispose of or recycle water after use, could adversely impact our operations. In some cases, water may need to be obtained from new sources and transported to drilling sites, resulting in increased costs. Moreover, the introduction of new environmental initiatives and regulations related to water acquisition or waste water disposal, including produced water, drilling fluids and other wastes associated with the exploration, development or production of hydrocarbons, could limit or prohibit our ability to utilize hydraulic fracturing or waste water injection control wells.
﻿
In addition, concerns have been raised about the potential for earthquakes to occur from the use of underground injection control wells, a predominant method for disposing of waste water from natural gas and oil activities. New rules and
			
		
			
		
regulations may be developed to address these concerns, possibly limiting or eliminating the ability to use disposal wells in certain locations and increasing the cost of disposal in others. We operate injection wells and utilize injection wells owned by third parties to dispose of waste water associated with our operations, subject to regulatory restrictions relating to seismic.
﻿
Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of water necessary for hydraulic fracturing of wells or the disposal of water may increase our operating costs or may cause us to delay, curtail or discontinue our exploration and development plans, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
﻿
Our producing properties are concentrated in two regions, the Appalachian Basin and the Fayetteville Shale, making us vulnerable to risks associated with operating in limited geographic areas.
﻿
Our producing properties are geographically concentrated in the Fayetteville Shale in Arkansas and the Appalachian Basin in Pennsylvania and West Virginia. At December 31, 2016, 43% of our total estimated proved reserves were attributable to properties located in the Appalachian Basin and 57% in the Fayetteville Shale. As a result of this concentration in two primary regions, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, state politics, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or interruption of the processing or transportation of natural gas, oil or natural gas liquids.
﻿
Competition in the oil and natural gas industry is intense, making it more difficult for us to market natural gas, oil and NGLs, to secure trained personnel and appropriate services, to obtain additional properties and to raise capital.
﻿
The cost of our operations is highly dependent on third-party services, and as activity in our industry increases, competition for these services may increase. Similarly, we must have trained, qualified personnel, and as commodity prices rise, competition for this talent also increases. Our ability to acquire and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing natural gas, oil and NGLs and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and gas industry. Certain of our competitors may possess and employ financial, technical and personnel resources greater than ours. Those companies may be able to pay more for personnel, property and services and to attract capital at lower rates. This may become more likely if prices for oil and NGLs recover faster than prices for natural gas, as natural gas comprises a far greater percentage of our overall production than it does for most of the companies with whom we compete for talent.
﻿
Volatility in the financial markets or in global economic factors could adversely impact our business and financial condition.
﻿
Our business may be negatively impacted by adverse economic conditions or future disruptions in global financial markets. Included among these potential negative impacts are reduced energy demand and lower commodity prices, increased difficulty in collecting amounts owed to us by our customers and reduced access to credit markets. Our ability to access the capital markets may be restricted at a time when we would like, or need, to raise financing. If financing is not available when needed, or is available only on unfavorable terms, we may be unable to implement our business plans or otherwise take advantage of business opportunities or respond to competitive pressures.
﻿
We are subject to complex federal, state and local laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.
﻿
Our natural gas and oil exploration and production operations are subject to complex and stringent federal, state and local laws and regulations, including those governing environmental protection, the occupational health and safety aspects of our operations, the discharge of materials into the environment, and the protection of certain plant and animal species. See “Other - Environmental Regulation” in Item 1 of Part I of this Annual Report for a description of the laws and regulations that affect us. In order to conduct operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Environmental regulations may restrict the types, quantities and concentration of materials that can be released into the environment in connection with drilling and production activities, limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, and impose substantial liabilities for pollution resulting from our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations and limit our growth and revenues.
Failure to comply with laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including investigatory actions, the assessment of monetary penalties, the imposition of remedial requirements, or
			
		
			
		
the issuance of orders or judgments limiting or enjoining future operations. Strict liability or joint and several liability may be imposed under certain laws, which could cause us to become liable for the conduct of others or for consequences of our own actions. Moreover, our costs of compliance with existing laws could be substantial and may increase or unforeseen liabilities could be imposed if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to our operations. If we are not able to recover the increased costs through insurance or increased revenues, our business, financial condition, results of operations and cash flows could be adversely affected.
﻿
Climate change legislation or regulations governing the emissions of “greenhouse gases” could result in increased operating costs and reduce demand for the natural gas, oil and NGLs we produce.
﻿
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to human health and the environment, the EPA has adopted regulations under existing provisions of the federal Clean Air Act that, among other things, establish Prevention of Significant Deterioration, or PSD, construction and Title V operating permit reviews for certain large stationary sources. Facilities required to obtain PSD permits for their greenhouse gas emissions also will be required to meet “best available control technology” standards that will be established on a case-by-case basis. One of our subsidiaries operates compressor stations, which are facilities that are required to adhere to the PSD or Title V permit requirements. EPA rulemakings related to greenhouse gas emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.
﻿
The EPA also has adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified onshore and offshore natural gas and oil production sources in the United States on an annual basis, which include certain of our operations. More recently, in May 2016, the EPA finalized additional regulations to control methane and volatile organic compound emissions from certain oil and gas equipment and operations.
﻿
Although Congress from time to time has considered legislation to reduce emissions of greenhouse gases, there has not been significant activity in the form of adopted legislation to reduce greenhouse gas emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of states, including states in which we operate, have enacted or passed measures to track and reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and regional greenhouse gas cap-and-trade programs. Most of these cap-and-trade programs require major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall greenhouse gas emission reduction goal is achieved. These reductions may cause the cost of allowances to escalate significantly over time.
﻿
The adoption and implementation of regulations that require reporting of greenhouse gases or otherwise limit emissions of greenhouse gases from our equipment and operations could require us to incur costs to monitor and report on greenhouse gas emissions or install new equipment to reduce emissions of greenhouse gases associated with our operations. In addition, these regulatory initiatives could drive down demand for our products by stimulating demand for alternative forms of energy that do not rely on combustion of fossil fuels that serve as a major source of greenhouse gas emissions, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. At the same time, new laws and regulations are prompting power producers to shift from coal to natural gas, which is increasing demand.
﻿
In December 2015, over 190 countries, including the United States, reached an agreement to reduce global greenhouse gas emissions. The agreement entered into force in November 2016 after more than 70 nations, including the United States, ratified or otherwise indicated their intent to be bound by the agreement. To the extent that the United States and other countries implement this agreement or impose other climate change regulations on the oil and natural gas industry, it could have an adverse effect on our business.
﻿
Our proved natural gas, oil and NGL reserves are estimates. Any material inaccuracies in our reserve estimates or underlying assumptions could cause the quantities and net present value of our reserves to be overstated or understated.
﻿
As described in more detail under “Critical Accounting Policies and Estimates - Natural Gas and Oil Properties” in Item 7 of Part II of this Annual Report, our reserve data represents the estimates of our reservoir engineers made under the supervision of our management, and our reserve estimates are audited each year by Netherland, Sewell & Associates, Inc., or NSAI, an independent petroleum engineering firm. Reserve engineering is a subjective process of estimating underground accumulations of natural gas, oil and NGLs that cannot be measured in an exact manner. The process of estimating quantities of proved reserves is complex and inherently imprecise, and the reserve data included in this document are only estimates. The process relies on interpretations of available geologic, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as natural gas, oil and NGL prices. Additional assumptions include drilling and operating expenses, capital investing, taxes and availability of funds. Furthermore, different reserve engineers may make different
			
		
			
		
estimates of reserves and cash flows based on the same data.
﻿
Results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates often vary from the quantities of natural gas, oil and NGLS that are ultimately recovered, and such variances may be material. Any significant variance could reduce the estimated quantities and present value of our reserves.
﻿
You should not assume that the present value of future net cash flows from our proved reserves is the current market value of our estimated natural gas, oil and NGL reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from our proved reserves on the 12-month average natural gas, oil and NGL index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month and costs in effect on the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than the current estimate. In addition, the 10% discount factor we use when calculating discounted future net cash flows for reporting requirements in compliance with the applicable accounting standards may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and gas industry in general.
﻿
Our commodity price risk management and measurement systems and economic hedging activities might not be effective and could increase the volatility of our results.
﻿
We currently seek to hedge the price of a significant portion of our estimated production, through swaps, collars, floors and other derivative instruments. The systems we use to quantify commodity price risk associated with our businesses might not always be followed or might not always be effective. Further, such systems do not in themselves manage risk, particularly risks outside of our control, and adverse changes in energy commodity market prices, volatility, adverse correlation of commodity prices, the liquidity of markets, changes in interest rates and other risks discussed in this report might still adversely affect our earnings, cash flows and balance sheet under applicable accounting rules, even if risks have been identified. Furthermore, no single hedging arrangement can adequately address all risks present in a given contract. For example, a forward contract that would be effective in hedging commodity price volatility risks would not hedge the contract’s counterparty credit or performance risk. Therefore, unhedged risks will always continue to exist.
﻿
Our use of derivatives, through which we attempt to reduce the economic risk of our participation in commodity markets could result in increased volatility of our reported results. Changes in the fair values (gains and losses) of derivatives that qualify as hedges under GAAP to the extent that such hedges are not fully effective in offsetting changes to the value of the hedged commodity, as well as changes in the fair value of derivatives that do not qualify or have not been designated as hedges under GAAP, must be recorded in our income. This creates the risk of volatility in earnings even if no economic impact to us has occurred during the applicable period.
﻿
The impact of changes in market prices for oil, natural gas and NGLs on the average prices paid or received by us may be reduced based on the level of our hedging activities. These hedging arrangements may limit or enhance our margins if the market prices for oil, natural gas or NGLs were to change substantially from the price established by the hedges. In addition, our hedging arrangements expose us to the risk of financial loss if our production volumes are less than expected.
﻿
We may be unable to dispose of assets on attractive terms, and may be required to retain liabilities for certain matters.
﻿
Various factors could materially affect our ability to dispose of assets or complete announced dispositions, including the availability of purchasers willing to purchase the assets at prices acceptable to us, particularly in times of reduced and volatile commodity prices. Sellers typically retain certain liabilities for certain matters. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a sale, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.
﻿
			
		
			
		
The implementation of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
﻿
The Dodd-Frank Act established federal oversight and regulation of the over-the-counter (“OTC”) derivatives market and entities, including us, which participate in that market. The Dodd-Frank Act requires the CFTC, the SEC, and other regulatory authorities to promulgate rules and regulations implementing the Dodd-Frank Act. Although the CFTC has finalized most of its regulations under the Dodd-Frank Act, it continues to review and refine its initial rulemakings through additional interpretations and supplemental rulemakings. As a result, it is not possible at this time to predict the ultimate effect of the rules and regulations on our business and while most of the regulations have been adopted, any new regulations or modifications to existing regulations may increase the cost of derivative contracts, limit the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and the regulations thereunder, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital investing.
﻿
In December 2016, the CFTC re-proposed new rules that would place federal limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions and finalized a companion rule on aggregation of positions among entities under common ownership or control. If finalized, the position limits rule may have an impact on our ability to hedge our exposure to certain enumerated commodities.
﻿
The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and mandatory trading on designated contract markets or swap execution facilities. The CFTC may designate additional classes of swaps as subject to the mandatory clearing requirement in the future, but has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. The CFTC and prudential banking regulators also adopted mandatory margin requirements on uncleared swaps between swap dealers and certain other counterparties. The margin requirements are currently effective with respect to certain market participants and will be phased in over time with respect to other market participants, based on the level of an entity’s swaps activity. We expect to qualify for and rely upon an end-user exception from the mandatory clearing and trade execution requirements for swaps entered to hedge our commercial risks. We also should qualify for an exception from the uncleared swaps margin requirements. However, the application of the mandatory clearing and trade execution requirements and the uncleared swaps margin requirement to other market participants, such as swap dealers, may adversely affect the cost and availability of the swaps that we use for hedging.
﻿
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.
﻿
The elimination of certain key U.S. federal income tax deductions currently available to oil and natural gas exploration and production companies has been proposed in recent years by members of the U.S. Congress and by former President Obama in his fiscal year 2017 budget proposal. These changes have included, among other proposals:
·
repeal of the percentage depletion allowance for natural gas and oil properties;
·
elimination of current deductions for intangible drilling and development costs;
·
elimination of the deduction for certain domestic production activities; and
·
extension of the amortization period for certain geological and geophysical expenditures.
﻿
It is unclear whether these or similar changes will be enacted. The passage of these or any similar changes in U.S. federal income tax laws to eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development could have an adverse effect on our financial position, results of operations and cash flows.
﻿
We may experience adverse or unforeseen tax consequences due to further developments affecting our deferred tax assets that could significantly affect our results.
﻿
Deferred tax assets, including net operating loss carryforwards, represent future savings of taxes that would otherwise be paid in cash. At December 31, 2016, the Company had substantial amounts of net operating loss carryforwards for U.S. federal and state income tax purposes. These loss carryforwards will eventually expire if not utilized. In addition, limitations may exist upon use of these carryforwards in the event that a change in control of the Company occurs. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. At December 31, 2016, the Company recorded a valuation allowance
			
		
			
		
against its entire deferred tax asset, including the portion related to the remaining net operating loss carryforwards. This allowance was recorded primarily as a result of cumulative book losses experienced over the three-year period ending December 31, 2016. If we experience additional book losses, we may be required to increase our valuation allowance against our deferred tax assets.
﻿
Our existing deferred tax asset valuation allowance may also be reversed if significant events occur or market conditions change materially, and our current or future earnings are, or are projected to be, significantly higher than we currently estimate. This reversal may result in a significant one-time favorable impact positively affecting our consolidated results of operations for the period of reversal and for the full fiscal year results.
﻿
A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
﻿
Our business has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data, analyze seismic and drilling information, conduct reservoir modeling and reserves estimation, communicate with employees and business associates, perform compliance reporting and in many other activities related to our business. Our business associates, including vendors, service providers, purchasers of our production, and financial institutions are also dependent on digital technology.
﻿
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. Our technologies, systems, networks, and those of our business associates may become the target of cyber-attacks or information security breaches, which could lead to disruptions in critical systems, unauthorized release of confidential or protected information, corruption of data or other disruptions of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
﻿
A cyber-attack involving our information systems and related infrastructure, or that of our business associates, could disrupt our business and negatively impact our operations in a variety of ways, including:
·
unauthorized access to seismic data, reserves information, strategic information or other sensitive or proprietary information could have a negative impact on our ability to compete for natural gas and oil resources;
·
unauthorized access to personal identifying information of royalty owners, employees and vendors, which could expose us to allegations that we did not sufficiently protect that information;
·
data corruption or operational disruption of production infrastructure could result in loss of production, or accidental discharge;
·
a cyber-attack on a vendor or service provider could result in supply chain disruptions which could delay or halt our major development projects; and
·
a cyber-attack on a third party gathering, pipeline or rail service provider could delay or prevent us from marketing our production, resulting in a loss of revenues.
﻿
These events could damage our reputation and lead to financial losses from remedial actions, loss of business or potential liability, which could have a material adverse effect on our financial condition, results of operations or cash flows.
﻿
To date we have not experienced any material losses relating to cyber-attacks; however, there can be no assurance that we will not suffer such losses in the future. 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.
﻿
Negative public perception regarding us and/or our industry could have an adverse effect on our operations.
﻿
Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, seismicity, oil spills and explosions of natural gas transmission lines, may lead to regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.
			
		
			
		
﻿
Common stockholders will be diluted if additional shares are issued.
﻿
In July 2016, we consummated an underwritten offering of 98.9 million shares of our common stock pursuant to an effective registration statement filed with the Securities and Exchange Commission, with net proceeds of the offering totaling approximately $1,247 million after underwriting discounts and offering expenses. The proceeds from the offering were used to repay $375 million of the $750 million term loan entered into in November 2015 and to settle certain tender offers by purchasing an aggregate principal amount of approximately $700 million of our outstanding senior notes due in the first quarter of 2018. The remaining net proceeds of the offering have been and will be used for general corporate purposes, including the completion of wells already drilled or the funding of other capital projects.
﻿
In January 2015, we issued 30.0 million shares of common stock and 34.5 million depositary shares representing the 1/20th interest in our 6.25% Series B Mandatory Preferred Stock, which will convert into a minimum of approximately 64 million or a maximum of 75 million shares of common stock by January 2018, to refinance a portion of the debt we incurred to purchase acreage in West Virginia and southwest Pennsylvania. Dividends on our 6.25% Series B Mandatory Preferred Stock are payable quarterly until they convert to common stock in January 2018, which dividends we may pay in cash or shares of our common stock. During 2016, we issued approximately 6.9 million shares of our common stock to satisfy our dividend obligations, and we may continue to issue common stock in satisfaction of our dividend obligation in 2017. We also issue restricted stock, options and performance share units to our employees and directors as part of their compensation. In addition, we may issue additional shares of common stock, additional notes or other securities or debt convertible into common stock, to extend maturities or fund capital expenditures. If we issue additional shares of our common stock in the future, it may have a dilutive effect on our current outstanding stockholders.
﻿
Anti-takeover provisions in our organizational documents and under Delaware law may impede or discourage a takeover, which could cause the market price of our common stock to decline.
﻿
We are a Delaware corporation, and the anti-takeover provisions of Delaware law impose various impediments to the ability of a third party to acquire control of us, even if a change in control would be beneficial to our existing stockholders, which, under certain circumstances, could reduce the market price of our common stock. In addition, protective provisions in our Amended and Restated Certificate of Incorporation and Amended and Restated Bylaws or the implementation by our board of directors of a stockholder rights plan that could deter a takeover.
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.
﻿
ITEM 2. PROPERTIES
﻿
The summary of our oil and natural gas reserves as of fiscal year-end 2016 based on average fiscal-year prices, as required by Item 1202 of Regulation S-K, is included in the table headed “2016 Proved Reserves by Category and Summary Operating Data” in “Business - Exploration and Production - Our Proved Reserves” in Item 1 of this Annual Report and incorporated by reference into this Item 2.
﻿
The information regarding our proved undeveloped reserves required by Item 1203 of Regulation S-K is included under the heading “Proved Undeveloped Reserves” in “Business - Exploration and Production - Our Proved Reserves” in Item 1 of this Annual Report.
﻿
The information regarding delivery commitments required by Item 1207 of Regulation S-K is included under the heading “Sales, Delivery Commitments and Customers” in the “Business - Exploration and Production - Our Operations” in Item 1 of this Annual Report and incorporated by reference into this Item 2. For additional information about our natural gas and oil operations, we refer you to “Supplemental Oil and Gas Disclosures” in Item 8 of Part II of this Annual Report. For information concerning capital investments, we refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Capital Investments.” We also refer you to Item 6, “Selected Financial Data” in Part II of this Annual Report for information concerning natural gas, oil and NGLs produced.
﻿
The information regarding natural gas and oil properties, wells, operations and acreage required by Item 1208 of Regulation S-K is set forth below:
﻿
Leasehold acreage as of December 31, 2016
﻿
﻿
﻿
(1)
Assuming successful wells are not drilled to develop the acreage and leases are not extended in Northeast Appalachia, leasehold expiring over the next three years will be 63,900 net acres in 2017, 16,066 net acres in 2018 and 11,413 net acres in 2019.
(2)
Assuming successful wells are not drilled to develop the acreage and leases are not extended in Southwest Appalachia, leasehold expiring over the next three years will be 39,429 net acres in 2017, 12,267 net acres in 2018 and 10,824 net acres in 2019. Of this acreage, 21,760 net acres in 2017, 3,767 net acres in 2018 and 8,150 net acres in 2019 can be extended for an average of 4.8 years.
(3)
Assuming successful wells are not drilled to develop the acreage and leases are not extended in the Fayetteville Shale, leasehold expiring over the next three years will be 453 net acres in 2017, 60 net acres in 2018 and 432 net acres in 2019 (excluding 158,231 net acres held on federal lands which are currently suspended by the Bureau of Land Management).
(4)
Assuming successful wells are not drilled to develop the acreage and leases are not extended in the Lower Smackover Brown Dense, leasehold expiring over the next three years will be 50,778 net acres in 2017, 83,021 net acres in 2018 and 5,793 net acres in 2019.
(5)
Assuming successful wells are not drilled to develop the acreage and leases are not extended in the Sand Wash Basin, leasehold expiring over the next three years will be 36,527 net acres in 2017, 51,260 net acres in 2018 and 12,810 net acres in 2019.
(6)
Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 68,556 net acres in 2017, 21,982 net acres in 2018 and 103,172 net acres in 2019.
(7)
Assuming successful wells are not drilled to develop the acreage and our exploration license agreements are not extended, the full acreage of 2,518,519 will expire in March 2021.
﻿
			
		
			
		
Producing wells as of December 31, 2016
﻿
﻿
﻿
The information regarding drilling and other exploratory and development activities required by Item 1205 of Regulation S-K is set forth below:
﻿
﻿
﻿
﻿
﻿
			
		
			
		
﻿
The following table presents the information regarding our present activities required by Item 1206 of Regulation S-K:
﻿
Wells in progress as of December 31, 2016
﻿
﻿
(1)
Includes 35 gross wells that are waiting on pipeline or production facilities.
﻿
			
		
			
		
The information regarding oil and gas production, production prices and production costs required by Item 1204 of Regulation S-K is set forth below:
﻿
Production, Average Sales Price and Average Production Cost
﻿
﻿
During 2016, we were required to file Form 23, “Annual Survey of Domestic Oil and Gas Reserves,” with the U.S. Department of Energy. The basis for reporting reserves on Form 23 is not comparable to the reserve data included in “Supplemental Oil and Gas Disclosures” in Item 8 of Part II of this Annual Report. The primary differences are that Form 23 reports gross reserves, including the royalty owners’ share, and includes reserves for only those properties of which we are the operator.
			
		
			
		
﻿
Miles of Pipe
﻿
As of December 31, 2016, our Midstream Services segment had 2,045 miles and 16 miles of pipe in its gathering systems located in Arkansas and Louisiana, respectively.
﻿
Title to Properties
﻿
We believe that we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and natural gas industry. Our properties are subject to customary royalty and overriding royalty interests, certain contracts relating to the exploration, development, operation and marketing of production from such properties, consents to assignment and preferential purchase rights, liens for current taxes, applicable laws and other burdens, encumbrances and irregularities in title, which we believe do not materially interfere with the use of or affect the value of such properties. Substantially all our Fayetteville Shale properties are subject to liens securing our 2016 credit facility. Prior to acquiring undeveloped properties, we endeavor to perform a title investigation that is thorough but less vigorous than that we endeavor to conduct prior to drilling, which is consistent with standard practice in the oil and natural gas industry. Generally, before we commence drilling operations on properties that we operate, we conduct a title examination and perform curative work with respect to significant defects that we identify. We believe that we have performed title examination with respect to substantially all of our active properties that we operate.
﻿
ITEM 3. LEGAL PROCEEDINGS
﻿
We are subject to litigation, claims and proceedings that arise in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties and pollution, contamination or nuisance. Management believes that such litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on our financial position, results of operations or cash flows. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and are all subject to inherent uncertainties; therefore, management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on our financial position, results of operations or cash flows for the period in which the effect becomes reasonably estimable. We accrue for such items when a liability is both probable and the amount can be reasonably estimated.
﻿
Berry-Helfand (Tovah Energy)
﻿
In February 2009, one of our subsidiaries was added as a defendant in a case then styled Tovah Energy, LLC and Toby Berry-Helfand v. David Michael Grimes, et al., then pending in the 273rd District Court in Shelby County, Texas. The plaintiff alleged that the subsidiary used information provided by the plaintiff under a confidentiality agreement, which she claimed, among other things, breached the agreement and constituted a trade secret. Following a trial in December 2010, the court awarded approximately $11 million in actual damages and approximately $24 million in disgorgement of profits, along with interest and attorneys’ fees. Both sides appealed, and in July 2013 the Texas Court of Appeals for the Twelfth District reversed on all claims except misappropriation of trade secrets, reduced the judgment to the actual damages award, along with interest and attorneys’ fees, and ordered the case remanded for an award of attorneys’ fees to our subsidiary on one of the claims on which judgment was reversed. Both parties petitioned the Supreme Court of Texas for review. In June 2016, the Supreme Court ruled that insufficient evidence supported the damage award and remanded the case for a new trial. The parties subsequently reached a settlement, the amount of which is reflected in our financial statements as of, and for the period ended, December 31, 2016.
We are also subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non-capital nature are accrued when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on our financial position or results of operations.
﻿
See “Litigation” in Note 8, “Commitments and Contingencies” in the consolidated financial statements for further details on our current legal proceedings.
ITEM 4. MINE SAFETY DISCLOSURES
Our sand mining operations in support of our E&P business are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations
			
		
			
		
or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95.1 to this Annual Report.
﻿
PART II
﻿
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
﻿
Our common stock is traded on the New York Stock Exchange (the “NYSE”) under the symbol “SWN.” On February 21, 2017, the closing price of our common stock trading under the symbol “SWN” was $8.59 and we had 3,283 stockholders of record. The following table presents, for each of the periods indicated, the high and low reported sales prices for our common stock trading under the symbol “SWN” as reported on the NYSE:
﻿
We do not currently pay dividends on our common stock.
﻿
Issuer Purchases of Equity Securities
﻿
The table below sets forth information with respect to purchases of our common stock made by us or on our behalf during the quarter ended December 31, 2016:
﻿
﻿
(1) Reflects shares retired by us to satisfy applicable tax withholding obligations due on employee stock plan share issuances. All changes in common stock in treasury in 2016 were due to purchases and sales of shares held on behalf of participants in a non-qualified deferred compensation supplemental retirement savings plan.
﻿
Recent Sales of Unregistered Equity Securities
﻿
We did not sell any unregistered equity securities during 2016, 2015 or 2014. See Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters,” in Part III of this Annual Report for information regarding our equity compensation plans as of December 31, 2016.
﻿
			
		
			
		
STOCK PERFORMANCE GRAPH
﻿
The following graph compares, for the last five years, the performance of our common stock to the S&P 500 Index and our peer group. Our peer group consists of Anadarko Petroleum Corporation, Apache Corporation, Cabot Oil & Gas Corporation, Chesapeake Energy Corporation, Cimarex Energy Co., Concho Resources Inc., Continental Resources Inc., Denbury Resources Inc., Devon Energy Corporation, EOG Resources, Inc., EQT Corporation, Newfield Exploration Company, Noble Energy, Inc., Pioneer Natural Resources Co., QEP Resources, Inc., Range Resources Corporation, Sandridge Energy, Inc., SM Energy Company, Ultra Petroleum Corp., Whiting Petroleum Corporation and WPX Energy, Inc. The chart assumes that the value of the investment in our common stock and each index was $100 at December 31, 2011, and that all dividends were reinvested. The stock performance shown on the graph below is not indicative of future price performance:
﻿
﻿
﻿
﻿
﻿
﻿
﻿
﻿
﻿
﻿
﻿
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth a summary of selected historical financial information for each of the years in the five-year period ended December 31, 2016. This information and the notes thereto are derived from our consolidated financial statements. We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Financial Statements and Supplementary Data.”
﻿
﻿
			
		
			
		
﻿
﻿
﻿
(1)
Capital investments include an increase of $43 million for 2016, a decrease of $33 million for 2015, an increase of $155 million for 2014, and decreases of $25 million and $37 million for 2013 and 2012, respectively, related to the change in accrued expenditures between years.
(2)
Excludes $83 million of restructuring and other one-time charges for 2016.
(3)
Excludes $3 million of restructuring charges for 2016.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
﻿
Management’s Discussion and Analysis is the Company’s analysis of its financial performance and of significant trends that may affect future performance. It should be read in conjunction with the financial statements and notes, and supplemental oil and gas disclosures included elsewhere in this report. It contains forward-looking statements including, without limitation, statements relating to the Company’s plans, strategies, objectives, expectations and intentions that are made pursuant to the “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995. The words “anticipate,” “intend,” “plan,” “project,” “estimate,” “continue,” “potential,” “should,” “could,” “may,” “will,” “objective,” “guidance,” “outlook,” “effort,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “forecast,” “target” or similar words identify forward-looking statements. The Company does not undertake to update, revise or correct any of the forward-looking information unless required to do so under the federal securities laws. Readers are cautioned that such forward-looking statements should be read in conjunction with the Company’s disclosures under the heading: “Cautionary Statement about Forward-Looking Statements.”
﻿
OVERVIEW
﻿
Background
﻿
Southwestern Energy Company (including its subsidiaries, collectively, “we”, “our”, “us” or “Southwestern”) is an independent energy company engaged in natural gas, oil and NGL exploration, development and production, which we refer to as “E&P.” We are also focused on creating and capturing additional value through our natural gas gathering and marketing businesses, which we refer to as “Midstream Services.” We conduct most of our businesses through subsidiaries and we operate principally in two segments: E&P and Midstream Services. Currently we operate only in the United States.
﻿
Exploration and Production. Our primary business is the exploration for and production of natural gas, oil and NGLs, with our current operations principally focused on the development of unconventional natural gas reservoirs located in Pennsylvania, West Virginia and Arkansas. Our operations in northeast Pennsylvania, which we refer to as “Northeast Appalachia,” are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale. Our operations in West Virginia and southwest Pennsylvania, which we refer to as “Southwest Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs. Collectively, we refer to our properties located in Pennsylvania and West Virginia as the “Appalachian Basin.” Our operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale. We have smaller holdings in Colorado and Louisiana, along with other areas in which we are testing potential new resources. We also have drilling rigs located in Pennsylvania, West Virginia and Arkansas and provide oilfield products and services, principally serving our E&P operations.
﻿
Midstream Services. Through our affiliated midstream subsidiaries, we engage in natural gas gathering activities in Arkansas and Louisiana. These activities primarily support our E&P operations and generate revenue from fees associated with the gathering of natural gas. Our marketing activities capture opportunities that arise through the marketing and transportation of natural gas, oil, and NGLs produced in our E&P operations.
﻿
We are focused on providing long-term growth in the net asset value per share of our business. Historically, the vast majority of our operating income and cash flow has been derived from the production associated with our E&P business. However, beginning in 2015 and continuing through 2016, depressed commodity prices significantly decreased our E&P results of operations. The price we expect to receive for our production is a critical factor in the capital investments we make to develop our properties. The current commodity price environment has resulted in the impairment of a significant portion of our natural gas and oil properties over recent reporting periods. Commodity prices fluctuate due to a variety of factors we cannot control or predict. These factors, which include increased supplies of natural gas, oil or NGLs due to greater exploration and development activities, weather conditions, political and economic events, and competition from other energy sources, impact supply and demand, which in turn determines the sales prices for our production. In addition to the factors identified above, the prices we realize for our production are affected by our hedging activities as well as locational differences in market prices, including basis differentials. Our 2016 results also reflect reduced costs of third-party services we were able to negotiate during the downturn in the industry. As industry activity increases, demand for these services also increases, and these service providers are likely to seek higher prices than we were able to obtain in 2016.
﻿
			
		
			
		
Beginning in the fourth quarter of 2015, we decreased activity in the Appalachian Basin and the Fayetteville Shale as a result of the lower commodity price environment. During the first half of 2016, we took steps to refocus the Company through a 40% reduction in our workforce, executive management restructuring and a commitment to strengthen our balance sheet by addressing potential near-term liquidity challenges, as we waited for commodity prices to recover. With the successful implementation of our debt reduction strategy, along with improving forward pricing, we began increasing our activity in the third quarter of 2016, and expect to continue these operations in 2017. During the second half of 2016, we increased our hedging activity designed to assure certain desired levels of cash flow.
﻿
Recent Financial and Operating Results
﻿
In 2016, our net loss attributable to common stock was $2,751 million, or ($6.32) per diluted share, a decrease from a net loss of $4,662 million, or ($12.25) per diluted share, in 2015. Our net income was $924 million, or $2.62 per diluted share, in 2014. We incurred non-cash impairments of our natural gas and oil properties totaling $2,321 million, or $1,444 million net of taxes, in 2016 and $6,950 million, or $4,287 million net of taxes, in 2015, which resulted primarily from the significant decline in natural gas prices.
﻿
In 2016, our natural gas and liquids production totaled 875 Bcfe, a decrease of 10% from 976 Bcfe in 2015. The 101 Bcfe decrease in our 2016 production resulted from a 96 Bcfe decrease in net production from our Fayetteville Shale and other properties and a 10 Bcf decrease in net production from our Northeast Appalachia properties, partially offset by a 5 Bcfe increase in net production from our Southwest Appalachia properties. The reductions resulted primarily from the suspension of drilling activities in the first half of 2016. Our 2015 total natural gas and liquids production of 976 Bcfe increased 27% from 768 Bcfe in 2014. The 208 Bcfe increase in our 2015 production resulted from a 140 Bcfe increase in net production from our Southwest Appalachia properties, a 106 Bcf increase in net production from our Northeast Appalachia properties and was partially offset by a 38 Bcfe decrease in net production from our Fayetteville Shale and other properties.
﻿
Our year-end reserves decreased 15% in 2016 to 5,253 Bcfe from 6,215 Bcfe at the end of 2015 and 10,747 Bcfe at the end of 2014. The overall decrease in total estimated proved reserves in 2016 was primarily due to production and downward price revisions associated with decreased commodity prices, partially offset by upward performance revisions in Northeast and Southwest Appalachia and the Fayetteville Shale. The overall decrease in total estimated proved reserves in 2015 was primarily due to downward revisions associated with decreased commodity prices, partially offset by upward performance revisions in Northeast and Southwest Appalachia.
﻿
Our E&P segment operating loss was $2,404 million in 2016, a decrease from an operating loss of $7,104 million in 2015. The operating loss in 2016 included non-cash impairments of natural gas and oil properties totaling $2,321 million. Excluding the non-cash impairments, our E&P segment operating loss decreased to $83 million in 2016 from $154 million in 2015 as the $732 million decrease in operating costs and expenses and $19 million increase in NGL revenues was only partially offset by a 31%, or $0.73 per Mcf, decrease in our average realized natural gas price, a 12%, or 111 Bcf, decrease in natural gas production and a $7 million decrease in oil revenues. Our E&P segment operating loss was $7,104 million in 2015, a decrease from operating income of $1,013 million in 2014. Excluding the non-cash impairments, operating income in 2015 decreased $1,167 million over 2014 as the revenue impact of our 27%, or 208 Bcfe, increase in production was more than offset by a 36%, or $1.35, decrease in our average realized natural gas price and a $379 million increase in operating costs and expenses that resulted from our production growth. In May 2015, we sold our conventional oil and gas assets located in East Texas and the Arkoma Basin that accounted for $27 million in operating income for the year ended December 31, 2014.
﻿
Operating income for our Midstream Services segment was $209 million in 2016, a decrease from $583 million in 2015 and $361 million in 2014. Operating income in 2015 includes a $277 million net gain related to the sale of our northeast Pennsylvania and East Texas gathering assets. Excluding the gain on sales, our Midstream Services segment operating income decreased $97 million primarily due to decreased volumes gathered and decreased marketing margin, partially offset by a $32 million decrease in operating costs and expenses, exclusive of marketing purchase costs. Volumes gathered decreased to 601 Bcf in 2016, compared to 799 Bcf in 2015. Excluding the gain on sales, operating income for our Midstream Services segment decreased in 2015 primarily due to a $71 million decrease in gathering revenues, which resulted from decreased volumes gathered, partially offset by a $13 million decrease in operating costs and expenses, exclusive of marketing purchase costs. Volumes gathered decreased to 799 Bcf in 2015, compared to 963 Bcf in 2014. In the second quarter of 2015, we sold our northeastern Pennsylvania and East Texas gathering assets that accounted for $13 million and $35 million in operating income for the years ended December 31, 2015 and 2014, respectively. A net gain of $277 million was recognized and is included in gain on sale of assets, net in the consolidated statement of operations.
﻿
			
		
			
		
We had total capital investments of $648 million in 2016, compared to $2.4 billion in 2015 and $7.4 billion in 2014. Of our total capital investments for 2016, $623 million was invested in our E&P segment, which included $152 million related to capitalized interest and $87 million in capitalized expenses. Of our total capital investments in 2015, $2.3 billion was invested in our E&P segment, which included $533 million related to acquisitions from WPX Energy, Inc. (“WPX” with acquisition called the “WPX Property Acquisition”) and Statoil ASA (“Statoil” with the acquisition called “Statoil Property Acquisition”), compared to $7.3 billion in 2014, which included $5.2 billion primarily related to the December 2014 acquisition of certain oil and natural gas assets in Southwest Appalachia from Chesapeake Energy Corporation (the “Chesapeake Property Acquisition”). Our Midstream Services capital investments for 2015 included $109 million related to the WPX Property Acquisition.
﻿
Outlook
﻿
We expect to continue to exercise capital discipline by aligning our 2017 capital investing program with our expected cash flow from operations and the remaining funds from our equity offering and sale of West Virginia assets. We will also look for opportunities to further strengthen our balance sheet, maximize margins in each core area of our business and further develop our knowledge of our asset base. We believe that 2017 will continue to be a challenging year for our business due to the commodity price environment and continued uncertainty of natural gas, oil and NGL prices in the United States. However, we expect that our resource base, financial flexibility and disciplined investment of capital will position us for success in the current environment and any improvements thereto.
﻿
RESULTS OF OPERATIONS
﻿
The following discussion of our results of operations for our segments is presented before intersegment eliminations. We evaluate our segments as if they were stand-alone operations and accordingly discuss their results prior to any intersegment eliminations. Interest expense and income tax expense are discussed on a consolidated basis.
﻿
Exploration and Production
﻿
﻿
(1)
Includes $86 million of restructuring and other one-time charges for the year ended December 31, 2016.
(2)
Represents the gain (loss) on settled commodity derivatives.
(3)
Includes the gain (loss) on settled commodity derivatives.
(4)
Excludes $83 million of restructuring and other one-time charges for the year ended December 31, 2016.
(5)
Excludes $3 million of restructuring charges for the year ended December 31, 2016.
﻿
			
		
			
		
Revenues
﻿
Revenues for our E&P segment were $1,413 million in 2016, a decrease of 32% compared to 2015. Revenues decreased by $248 million as a result of decreased realized natural gas pricing, excluding the effects of derivatives, $212 million as a result of decreased natural gas production, $209 million as a result of decreased derivative settlement proceeds, $7 million as a result of decreased oil production and realized price and $4 million as a result of decreased other operating revenue. These decreases were partially offset by an increase of $19 million in NGL sales resulting from increased production and realized price. Revenues for our E&P segment were $2,074 million in 2015, a decrease of 28% compared to 2014. A decrease in the price realized from the sale of our natural gas production decreased revenue by $1,647 million in 2015, partially offset by an increase of $497 million due to higher natural gas production volumes and an increase of $235 million in hedge settlement proceeds. Additionally, there was a $328 million increase due to increased net NGL and oil production related to our Southwest Appalachia property acquisition partially offset by a $201 million decrease due to decreased net NGL and oil pricing. Natural gas, oil and NGL prices are difficult to predict and are subject to wide price fluctuations. We refer you to Note 4 to the consolidated financial statements included in this Annual Report and to the discussion of “Commodity Prices” provided below for additional information. In May 2015, we sold our conventional oil and gas assets located in East Texas and the Arkoma Basin that accounted for $15 million and $70 million of our gas and oil revenues for the years ended December 31, 2015 and 2014, respectively.
﻿
Production
﻿
In 2016, our natural gas and liquids production totaled 875 Bcfe, a 10% decrease from 976 Bcfe in 2015, and was produced entirely by our properties in the United States. The 101 Bcfe decrease was primarily due to a 96 Bcfe decrease in net production from our Fayetteville Shale and other properties and a 10 Bcf decrease in net production from our Northeast Appalachia properties, partially offset by a 5 Bcfe increase in net production from our Southwest Appalachia properties. Net production from our Northeast Appalachia, Southwest Appalachia and Fayetteville Shale properties was 350 Bcf, 148 Bcfe and 375 Bcf, respectively, for the year ended 2016, compared to 360 Bcf, 143 Bcfe, and 465 Bcf, respectively, for 2015. The reductions resulted primarily from the suspension of drilling activities in the first half of 2016. Our 2015 total natural gas and liquids production of 976 Bcfe increased 27% from 768 Bcfe in 2014, and was also produced entirely by our properties in the United States. The 208 Bcfe increase in our 2015 production resulted from a 140 Bcfe increase in net production from our Southwest Appalachia properties and a 106 Bcf increase in net production from our Northeast Appalachia properties, partially offset by a 38 Bcfe decrease in net production in our Fayetteville Shale and other properties. Net production for 2014 from our Northeast Appalachia, Southwest Appalachia and Fayetteville Shale properties was 254 Bcf, 3 Bcfe and 494 Bcf, respectively.
﻿
Natural gas accounted for approximately 90%, 92% and 100% of our total production for the years ended December 31, 2016, 2015 and 2014, respectively. Oil accounted for 2% and 1% of our total production for the years ended December 31, 2016 and 2015, respectively. NGLs accounted for 8% and 7% of our total production for the years ended December 31, 2016 and 2015, respectively.
﻿
Our ability to identify, develop and produce reserves is dependent upon a number of factors, many of which are beyond our control, including the availability of capital, availability of transportation, weather, the timing and extent of changes in natural gas, oil and NGL prices and competition. There are also many risks inherent in the discovery, development and production of natural gas, oil and NGLs. We refer you to “Risk Factors” in Item 1A of Part I of this Annual Report for a discussion of these risks and the impact they could have on our financial condition and results of operations.
﻿
Commodity Prices
﻿
The average price realized for our natural gas production, after the effects of derivatives, decreased 31% to $1.64 per Mcf in 2016, compared to a decrease of 36% to $2.37 per Mcf in 2015 from 2014 levels. The decrease in 2016 was the result of a $0.32 per Mcf decrease in the average natural gas price, excluding derivatives, and lower proceeds from our hedging program in 2016 as compared to 2015. The decrease in 2015 was the result of a $1.83 per Mcf decrease in the average natural gas price, excluding derivatives, partially offset by higher proceeds from our hedging program in 2015 as compared to 2014. In 2016, our derivatives increased the average natural gas price we realized by $0.05 per Mcf, compared to an increase of $0.46 per Mcf in 2015 and a decrease of $0.02 per Mcf in 2014.
﻿
Our E&P segment receives a sales price for our natural gas at a discount to average monthly NYMEX settlement prices due to heating content of the gas, locational basis differentials, transportation charges and fuel charges. Additionally, we receive a sales price for our oil and NGLs at a difference to average monthly West Texas Intermediate settlement and Mont Belvieu NGL composite prices, respectively, due to a number of factors including product quality, composition, and types of NGLs sold, locational basis differentials, transportation and fuel charges.
			
		
			
		
We regularly enter into various hedging and other financial arrangements with respect to a portion of our projected natural gas production in order to ensure certain desired levels of cash flow and to minimize the impact of price fluctuations, including fluctuations in locational market differentials. We refer you to
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
﻿
Market risks relating to our operations result primarily from the volatility in commodity prices, basis differentials and interest rates, as well as service costs and credit risk concentrations. We use fixed price swap agreements, fixed price options, basis swaps and interest rate swaps to reduce the volatility of earnings and cash flow due to fluctuations in the prices of natural gas and interest rates. Our Board of Directors has approved risk management policies and procedures to utilize financial products for the reduction of defined commodity price risk. Utilization of financial products for the reduction of interest rate risks is also overseen by our Board of Directors. These policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings.
﻿
Credit Risk
﻿
Our financial instruments that are exposed to concentrations of credit risk consist primarily of trade receivables and derivative contracts associated with commodities trading. Concentrations of credit risk with respect to receivables are limited due to the large number of our purchasers and their dispersion across geographic areas. No single purchaser accounted for greater than 10% of revenues as of December 31, 2016. See “Commodities Risk” below for discussion of credit risk associated with commodities trading.
﻿
Interest Rate Risk
﻿
As of December 31, 2016, we had approximately $3.2 billion of outstanding senior notes with a weighted average interest rate of 5.68%, and $1.5 billion of term loan facility debt with a variable interest rate of 3.22%. We currently have an interest rate swap in effect to mitigate a portion of our exposure to volatility in interest rates.
﻿
﻿
﻿
﻿
﻿
(1) Excludes unamortized debt issuance costs and debt discounts.
(2) The maturity date will accelerate to October 2019 if, by that date, we have not amended, redeemed or refinanced at least $765 million of our 2020 Senior Notes.
﻿
Commodities Risk
﻿
We use over-the-counter fixed price swap agreements and options to protect sales of our production against the inherent risks of adverse price fluctuations or locational pricing differences between a published index and the NYMEX futures market. These swaps and options include transactions in which one party will pay a fixed price (or variable price) for a notional quantity in exchange for receiving a variable price (or fixed price) based on a published index (referred to as price swaps) and transactions in which parties agree to pay a price based on two different indices (referred to as basis swaps).
﻿
The primary market risks relating to our derivative contracts are the volatility in market prices and basis differentials for natural gas. However, the market price risk is offset by the gain or loss recognized upon the related sale or purchase of the natural gas that is financially protected. Credit risk relates to the risk of loss as a result of non-performance by our counterparties. The counterparties are primarily major banks and integrated energy companies that management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure we have to each counterparty are closely monitored to limit our credit risk exposure. Additionally, we perform both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. We have not incurred any counterparty losses related to non-performance and do not anticipate any losses given the information we have currently. However, we cannot be certain that we will not experience such losses in the future. We refer you to Note 4 of the consolidated financial statements included in this Annual Report for additional details about our derivative instruments.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
﻿
﻿
						
Page
﻿Management’s Report on Internal Control Over Financial Reporting
				
﻿Report of Independent Registered Public Accounting Firm
				
﻿Consolidated Statements of Operations for the three years ended December 31, 2016
				
﻿Consolidated Statements of Comprehensive Income (Loss) for the three years ended December 31, 2016
				
﻿Consolidated Balance Sheets as of December 31, 2016 and 2015
				
﻿Consolidated Statements of Cash Flows for the three years ended December 31, 2016
				
﻿Consolidated Statements of Equity for the three years ended December 31, 2016
				
﻿Notes to Consolidated Financial Statements
				
﻿Note 1 - Organization and Summary of Significant Accounting Policies
				
﻿Note 2 - Reduction in Workforce
				
﻿Note 3 - Acquisitions and Divestitures
				
﻿Note 4 - Derivatives and Risk Management
				
﻿Note 5 - Reclassifications from Accumulated Other Comprehensive Income (Loss)
				
﻿Note 6 - Fair Value Measurements
				
﻿Note 7 - Debt
				
﻿Note 8 - Commitments and Contingencies
				
﻿Note 9 - Income Taxes
				
﻿Note 10 - Asset Retirement Obligation
				
﻿Note 11 - Retirement and Employee Benefit Plans
				
﻿Note 12 - Stock-Based Compensation
				
﻿Note 13 - Segment Information
				
﻿Note 14 - Subsequent Events
				
﻿Supplemental Quarterly Results
				
﻿Supplemental Oil and Gas Disclosures
				
﻿
			
		
			
		
Management’s Report on Internal Control Over Financial Reporting
It is the responsibility of the management of Southwestern Energy Company to establish and maintain adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). Management has assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2016, utilizing the Committee of Sponsoring Organizations of the Treadway Commission’s Internal Control-Integrated Framework (2013).
Based on this evaluation, management has concluded the Company’s internal control over financial reporting was effective as of December 31, 2016.
The effectiveness of our internal control over financial reporting as of December 31, 2016 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report which appears herein.
			
		
			
		
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Southwestern Energy Company
﻿
In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Southwestern Energy Company and its subsidiaries at December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 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, 2016, 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 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.
/s/PRICEWATERHOUSECOOPERS LLP
﻿
﻿
Houston, TX
February 23, 2017
			
		
			
		
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
﻿
﻿
﻿
The accompanying notes are an integral part of these consolidated financial statements.
			
		
			
		
﻿
﻿
﻿
(1) Net of ($81) million and $10 million in taxes for the years ended December 31, 2015 and 2014, respectively.
(2) Net of $16 million and $49 million in taxes for the years ended December 31, 2015 and 2014, respectively.
(3) Net of $8 million in taxes for the year ended December 31, 2016.
(4) Net of ($4) million and ($10) million in taxes for the years ended December 31, 2016 and 2014, respectively.
﻿
The accompanying notes are an integral part of these consolidated financial statements.
			
		
			
		
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
﻿
﻿
The accompanying notes are an integral part of these consolidated financial statements.
			
		
			
		
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
﻿
﻿
﻿
The accompanying notes are an integral part of these consolidated financial statements.
			
		
			
		
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
﻿
﻿
﻿
﻿
﻿
(1) Does not include 2,751,410 shares issued on January 17, 2017 and distributed to holders of the Company’s mandatory convertible preferred stock.
﻿
The accompanying notes are an integral part of these consolidated financial statements.
			
		
			
		
SOUTHWESTERN ENERGY COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
﻿
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
﻿
Nature of Operations
﻿
Southwestern Energy Company (including its subsidiaries, collectively “Southwestern” or the “Company”) is an independent energy company engaged in natural gas, oil and NGL exploration, development and production (“E&P”). The Company is also focused on creating and capturing additional value through its natural gas gathering and marketing businesses (“Midstream Services”). Southwestern conducts most of its businesses through subsidiaries and operates principally in two segments: E&P and Midstream Services.
﻿
Exploration and Production. Southwestern’s primary business is the exploration for and production of natural gas, oil and NGLs, with current operations principally focused on the development of unconventional natural gas reservoirs located in Pennsylvania, West Virginia and Arkansas. The Company’s operations in northeast Pennsylvania, herein referred to as “Northeast Appalachia,” are primarily focused on the unconventional natural gas reservoir known as the Marcellus Shale. Operations in West Virginia and southwest Pennsylvania, herein referred to as “Southwest Appalachia,” are focused on the Marcellus Shale, the Utica and the Upper Devonian unconventional natural gas and oil reservoirs. Collectively, Southwestern refers to its properties located in Pennsylvania and West Virginia as the “Appalachian Basin.” The Company’s operations in Arkansas are primarily focused on an unconventional natural gas reservoir known as the Fayetteville Shale. Southwestern has activities ongoing in Colorado and Louisiana, along with other areas in which it is currently assessing new development opportunities. The Company also has drilling rigs located in Pennsylvania, West Virginia and Arkansas and provides oilfield products and services, principally serving its E&P operations.
﻿
Midstream Services. Through the Company’s affiliated midstream subsidiaries, Southwestern engages in natural gas gathering activities in Arkansas and Louisiana. These activities primarily support the Company’s E&P operations and generate revenue from fees associated with the gathering of natural gas. Southwestern’s marketing activities capture opportunities that arise through the marketing and transportation of the natural gas, oil and NGLs produced in its E&P operations.
﻿
Basis of Presentation
﻿
The consolidated financial statements included in this Annual Report present the Company’s financial position, results of operations and cash flows for the periods presented in accordance with accounting principles generally accepted in the United States (“GAAP”). The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the financial statements, and the amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. The Company evaluates subsequent events through the date the financial statements are issued. Certain reclassifications have been made to the prior year financial statements to conform to the 2016 presentation. The effects of the reclassifications were not material to the Company’s consolidated financial statements. See Note 1 - New Accounting Standards Implemented in this Report for additional information regarding the reclassifications.
﻿
Principles of Consolidation
﻿
The consolidated financial statements include the accounts of Southwestern and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated.
﻿
In 2015, the Company purchased an 86% ownership in a limited partnership which owns and operates a gathering system in Northeast Appalachia as part of the WPX Property Acquisition (as defined and discussed in Note 3). Because the Company owns a controlling interest in the partnership, the operating and financial results are consolidated with the Company’s E&P segment results. The investor’s share of the partnership activity is reported in retained earnings in the consolidated financial statements. Net income attributable to noncontrolling interest for the years ended December 31, 2016 and 2015 was insignificant.
﻿
Revenue Recognition
﻿
Natural gas and liquid sales. Natural gas and liquid sales are recognized when the products are sold to a purchaser at a fixed or determinable price, delivery has occurred, title has transferred and collectability of the revenue is reasonably assured. The Company uses the entitlement method that requires revenue recognition for the Company’s net revenue interest of sales
			
		
			
		
from its properties. Accordingly, natural gas and liquid sales are not recognized for deliveries in excess of the Company’s net revenue interest, while natural gas and liquid sales are recognized for any under-delivered volumes. Production imbalances are generally recorded at estimated sales prices of the anticipated future settlements of the imbalances. The Company had no significant production imbalances at December 31, 2016 or 2015.
﻿
Marketing. The Company generally markets its natural gas and liquids, as well as some products produced by third parties, to marketers, local distribution companies and end-users, pursuant to a variety of contracts. Marketing revenues are recognized when delivery has occurred, title has transferred, the price is fixed or determinable and collectability of the revenue is reasonably assured.
﻿
Gas gathering. In certain areas, the Company gathers its natural gas as well as some natural gas produced by third parties pursuant to a variety of contracts. Gas gathering revenues are recognized when the service is performed, the price is fixed or determinable and collectability of the revenue is reasonably assured.
﻿
Cash and Cash Equivalents
﻿
Cash and cash equivalents are defined by the Company as short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash. Management considers cash and cash equivalents to have minimal credit and market risk as the Company monitors the credit status of the financial institutions holding its cash and marketable securities. The following table presents a summary of cash and cash equivalents as of December 31, 2016 and December 31, 2015:
﻿
﻿
﻿
﻿
(1)
Consists of government stable value money market funds.
﻿
Certain of the Company’s cash accounts are zero-balance controlled disbursement accounts. The Company presents the outstanding checks written against these zero-balance accounts as a component of accounts payable in the accompanying consolidated balance sheets. Outstanding checks included as a component of accounts payable totaled $8 million and $29 million as of December 31, 2016 and 2015, respectively.
﻿
Property, Depreciation, Depletion and Amortization
﻿
Natural Gas and Oil Properties. The Company utilizes the full cost method of accounting for costs related to the exploration, development and acquisition of natural gas and oil properties. Under this method, all such costs (productive and nonproductive), including salaries, benefits and other internal costs directly attributable to these activities are capitalized on a country-by-country basis and amortized over the estimated lives of the properties using the units-of-production method. These capitalized costs are subject to a ceiling test that limits such pooled costs, net of applicable deferred taxes, to the aggregate of the present value of future net revenues attributable to proved natural gas, oil and NGL reserves discounted at 10% (standardized measure). Any costs in excess of the ceiling are written off as a non-cash expense. The expense may not be reversed in future periods, even though higher natural gas, oil and NGL prices may subsequently increase the ceiling. Companies using the full cost method are required to use the average quoted price from the first day of each month from the previous 12 months, including the impact of derivatives designated for hedge accounting, to calculate the ceiling value of their reserves. Decreases in market prices as well as changes in production rates, levels of reserves, evaluation of costs excluded from amortization, future development costs and production costs could result in future ceiling test impairments.
﻿
Costs associated with unevaluated properties are excluded from the amortization base until the properties are evaluated or impairment is indicated. The costs associated with unevaluated leasehold acreage and related seismic data, wells currently drilling and related capitalized interest are initially excluded from the amortization base. Leasehold costs are either transferred to the amortization base with the costs of drilling a well on the lease or are assessed at least annually for possible impairment or reduction in value. The Company’s decision to withhold costs from amortization and the timing of the transfer of those costs into the amortization base involves a significant amount of judgment and may be subject to changes over time based on several factors, including drilling plans, availability of capital, project economics and drilling results from adjacent acreage. At December 31, 2016, the Company had a total of $2,105 million of costs excluded from the amortization base,
			
		
			
		
all of which related to its properties in the United States. Inclusion of some or all of these costs in the Company’s United States properties in the future, without adding any associated reserves, could result in additional ceiling test impairments.
﻿
In the first, second, and third quarters of 2016, the Company’s net book value of its United States and Canada natural gas and oil properties exceeded the ceiling by approximately $641 million (net of tax) at March 31, 2016, $297 million (net of tax) at June 30, 2016 and $506 million (net of tax) at September 30, 2016, resulting in non-cash ceiling test impairments in each of those quarters. Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.48 per MMBtu, West Texas Intermediate oil of $39.25 per barrel and NGLs of $6.74 per barrel, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at December 31, 2016. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2016.
﻿
In the second and third quarters of 2015, the net book value of the Company’s United States natural gas and oil properties exceeded the ceiling by $944 million (net of tax) at June 30, 2015 and $1,746 million (net of tax) at September 30, 2015 and resulted in non-cash ceiling test impairments. Cash flow hedges of natural gas production in place increased the ceiling amount by approximately $60 million and $40 million as of June 30, 2015 and September 30, 2015, respectively. Using the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.59 per MMBtu, West Texas Intermediate oil of $46.79 per barrel and NGLs of $6.82 per barrel, adjusted for market differentials, the Company’s net book value of its United States natural gas and oil properties exceeded the ceiling by $1,586 million (net of tax) at December 31, 2015 and resulted in a non-cash ceiling test impairment. The Company had no derivative positions that were designated for hedge accounting as of December 31, 2015.
﻿
At December 31, 2014, the ceiling value of the Company’s reserves was calculated based upon the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $4.35 per MMBtu, for West Texas Intermediate oil of $91.48 per barrel and NGLs of $23.79 per barrel, adjusted for market differentials. The Company’s net book value of its natural gas and oil properties did not exceed the ceiling amount and did not result in a ceiling test impairment at December 31, 2014.
﻿
Gathering Systems. The Company’s investment in gathering systems is primarily in a system serving its Fayetteville Shale operations in Arkansas. These assets are being depreciated on a straight-line basis over 25 years.
﻿
Capitalized Interest. Interest is capitalized on the cost of unevaluated natural gas and oil properties that are excluded from amortization and are actively being evaluated.
﻿
Asset Retirement Obligations. The Company owns natural gas and oil properties, which require expenditures to plug and abandon the wells and reclaim the associated pads when the wells are no longer producing. An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred or when it becomes determinable, with an associated increase in the carrying amount of the related long-lived asset. The cost of the tangible asset, including the asset retirement cost, is depreciated over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value, and accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value.
﻿
Impairment of long-lived assets. The carrying value of non-full cost pool long-lived assets is evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable.
﻿
Intangible assets. The carrying value of intangible assets are evaluated for recoverability whenever events or changes in circumstances indicate that it may not be recoverable. Intangible assets are amortized over their useful life.
﻿
Income Taxes
﻿
The Company follows the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recorded for the estimated future tax consequences attributable to the differences between the financial carrying amounts of existing assets and liabilities and their respective tax basis. Deferred tax assets and liabilities are measured using the tax rate expected to be in effect for the year in which those temporary differences are expected to reverse. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change. Deferred income taxes are provided to recognize the income tax effect of reporting certain transactions in different years for income tax and financial reporting purposes. 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.
﻿
			
		
			
		
The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties. The Company recognizes penalties and interest related to uncertain tax positions within the provision (benefit) for income taxes line in the accompanying consolidated statements of operations. Additional information regarding uncertain tax positions can be found in Note 9 - Income Taxes.
﻿
Derivative Financial Instruments
﻿
The Company uses derivative financial instruments to manage defined commodity price risks and does not use them for speculative trading purposes. The Company uses fixed price swap agreements and options to financially protect sales of natural gas. Gains and losses resulting from the settlement of derivative contracts have been recognized in gas sales if designated for hedge accounting treatment or gain (loss) on derivatives if not designated for hedge accounting treatment in the consolidated statements of operations when the contracts expire and the related physical transactions of the commodity hedged are recognized. Changes in the fair value of derivative instruments designated as cash flow hedges and not settled are included in other comprehensive income (loss) to the extent that they are effective in offsetting the changes in the cash flows of the hedged item. In contrast, gains and losses from the ineffective portion of derivative contracts designated for hedge accounting treatment are recognized currently and have an inconsequential impact in the consolidated statement of operations. Gains and losses from the unsettled portion of derivative contracts not designated for hedge accounting treatment are recognized in gain (loss) on derivatives in the consolidated statement of operations. See Note 4 - Derivatives and Risk Management and Note 6 - Fair Value Measurements for a discussion of the Company’s hedging activities.
﻿
Earnings Per Share
﻿
Basic earnings per common share is computed by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during the reportable period. The diluted earnings per share calculation adds to the weighted average number of common shares outstanding: the incremental shares that would have been outstanding assuming the exercise of dilutive stock options, the vesting of unvested restricted shares of common stock, performance units, the assumed conversion of mandatory convertible preferred stock and the shares of common stock declared as a preferred stock dividend. An antidilutive impact is an increase in earnings per share or a reduction in net loss per share resulting from the conversion, exercise, or contingent issuance of certain securities.
﻿
In July 2016, the Company completed an underwritten public offering of 98,900,000 shares of its common stock, with an offering price to the public of $13.00 per share. Net proceeds from the common stock offering were approximately $1,247 million, after underwriting discount and offering expenses. The proceeds from the offering were used to repay $375 million of the $750 million term loan entered into in November 2015 and to settle certain tender offers by purchasing an aggregate principal amount of approximately $700 million of the Company’s outstanding senior notes due in the first quarter of 2018. The remaining proceeds of the offering have been or will be used for general corporate purposes.
﻿
In January 2015, the Company completed concurrent underwritten public offerings of 30,000,000 shares of its common stock and 34,500,000 depositary shares (both share counts include shares issued as a result of the underwriters exercising their options to purchase additional shares). The common stock offering was priced at $23.00 per share. Net proceeds from the common stock offering were approximately $669 million, after underwriting discount and offering expenses. Net proceeds from the depositary share offering were approximately $1.7 billion, after underwriting discount and offering expenses. Each depositary share represents a 1/20th interest in a share of the Company’s mandatory convertible preferred stock, with a liquidation preference of $1,000 per share (equivalent to a $50 liquidation preference per depositary share). The proceeds from the offerings were used to partially repay borrowings under the Company’s $4.5 billion 364-day bridge facility with the remaining balance of the bridge facility fully repaid with proceeds from the Company’s January 2015 public offering of $2.2 billion in long-term senior notes.
﻿
The mandatory convertible preferred stock entitles the holder to a proportional fractional interest in the rights and preferences of the convertible preferred stock, including conversion, dividend, liquidation and voting rights. Unless converted earlier at the option of the holders, on or around January 15, 2018 each share of convertible preferred stock will automatically convert into between 37.0028 and 43.4782 shares of the Company’s common stock (correspondingly, each depositary share will convert into between 1.85014 and 2.17391 shares of the Company’s common stock), subject to customary anti-dilution adjustments, depending on the volume-weighted average price of the Company’s common stock over a 20 trading day averaging period immediately prior to that date. The total potential shares of common stock resulting from the conversion will range from 63,829,830 to 74,999,895 shares.
			
		
			
		
﻿
The mandatory convertible preferred stock has the non-forfeitable right to participate on an as-converted basis at the conversion rate then in effect in any common stock dividends declared and as such, is considered a participating security. Accordingly, it is included in the computation of basic and diluted earnings per share, pursuant to the two-class method. In the calculation of basic earnings per share attributable to common shareholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common shareholders, if any, after recognizing distributed earnings. The Company’s participating securities do not participate in undistributed net losses because they are not contractually obligated to do so.
﻿
On December 12, 2016, the Company declared its quarterly dividend, payable to holders of the mandatory convertible preferred stock, and announced that it would pay the quarterly dividend in stock, in lieu of cash, to the extent permitted by the certificate of designations for the Series B preferred stock. The Company issued 2,751,410 shares of common stock on January 17, 2017 in payment for the dividend. Dividends declared in the first, second and third quarters of 2016 also were settled in common stock for a total of 7,166,389 shares, while the dividend declared in December 2015 was paid in cash in January 2016.
﻿
The following table presents the computation of earnings per share for the years ended December 31, 2016, 2015 and 2014:
﻿
﻿
﻿
The following table presents the common stock shares equivalent excluded from the calculation of diluted earnings per share for the years ended December 31, 2016, 2015 and 2014, as they would have had an antidilutive effect:
﻿
﻿
﻿
Supplemental Disclosures of Cash Flow Information
﻿
The following table provides additional information concerning interest and income taxes paid as well as changes in noncash investing activities for the years ended December 31, 2016, 2015, and 2014:
﻿
﻿
﻿
﻿
			
		
			
		
Stock-Based Compensation
﻿
The Company accounts for stock-based compensation transactions using a fair value method and recognizes an amount equal to the fair value of the stock options and stock-based payment cost in either the consolidated statement of operations or capitalizes the cost into natural gas and oil properties or gathering systems included in property and equipment. Costs are capitalized when they are directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to the construction of the Company’s gathering systems.
﻿
Treasury Stock
﻿
The Company maintains a non-qualified deferred compensation supplemental retirement savings plan for certain key employees whereby participants may elect to defer and contribute a portion of their compensation to a Rabbi Trust, as permitted by the plan. The Company includes the assets and liabilities of its supplemental retirement savings plan in its consolidated balance sheet. Shares of the Company’s common stock purchased under the non-qualified deferred compensation arrangement are held in the Rabbi Trust, are presented as treasury stock and are carried at cost. As of December 31, 2016, 31,269 shares were accounted for as treasury stock, compared to 47,149 shares at December 31, 2015.
﻿
Foreign Currency Translation
﻿
The Company has designated the Canadian dollar as the functional currency for our activities in Canada. The cumulative translation effects of translating the accounts from the functional currency into the U.S. dollar at current exchange rates are included as a separate component of other comprehensive income within stockholders’ equity.
﻿
New Accounting Standards Implemented in this Report
﻿
In September 2015, the FASB issued Accounting Standards Update No. 2015-16, Business Combinations (Topic 805) (“Update 2015-16”), which seeks to reduce the complexity of amounts recognized in a business combination. The amendments in Update 2015-16 require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in Update 2015-16 require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in Update 2015-16 require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The amendments in Update 2015-16 are effective for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The Company adopted this update in the first quarter of 2016 resulting in no impact on its consolidated results of operations, financial position and cash flows.
﻿
In May 2015, the FASB issued Accounting Standards Update No. 2015-07, Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (Or Its Equivalent) (“Update 2015-07”), which amends ASC 820, Fair Value Measurement. The standard removes the requirement to categorize within the fair value hierarchy investments for which fair value is measured using the net asset value per share practical expedient and removes certain related disclosure requirements. The amendments in Update 2015-07 are effective for reporting periods beginning after December 15, 2015, with early adoption permitted. The Company adopted this update in the first quarter of 2016 resulting in no impact on its consolidated results of operations, financial position and cash flows. As a result of adoption, certain of the Company’s pension plan assets measured using net asset value as a practical expedient have not been classified in the fair value hierarchy in Note 11 - Retirement and Employee Benefit Plans.
﻿
In April 2015, the FASB issued Accounting Standards Update No. 2015-03, Interest-Imputation of Interest (Subtopic 835-30) (“Update 2015-03”), in an effort to simplify presentation of debt issuance costs. Update 2015-03 required that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs was not affected by the amendments in this Update. Entities were required to apply the amendments in Update 2015-03 on a retrospective basis, with the balance sheet of each individual period presented adjusted to reflect the period-specific effects of applying the new guidance. In August 2015, the FASB issued Accounting Standards Update No. 2015-15, Interest-Imputation of Interest (Subtopic 835-30) (“Update 2015-15”), which addressed the presentation or subsequent measurement of debt issuance costs related to line-of-credit arrangements, given the absence of authoritative guidance within Update 2015-03 for debt issuance costs related to line-of-credit arrangements. For public entities, Update 2015-03 and Update 2015-15 are effective for annual reporting periods beginning after December 15, 2015, including interim periods within that reporting period. The Company adopted this update in the first quarter of 2016 resulting in an immaterial impact on its consolidated
			
		
			
		
financial position. The Company had $24 million in unamortized debt expense that was classified as a long-term asset at December 31, 2015, which is now presented as a contra-liability as a result of adoption.
﻿
In November 2014, the FASB issued Accounting Standards Update No. 2014-16, Derivatives and Hedging - Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity (Subtopic 815-15) (“Update 2014-16”), which addressed diversity in practice related to the determination of whether derivative features embedded in hybrid instruments issued in the form of a share should be bifurcated and accounted for separately. For public entities, Update 2014-16 was effective for annual reporting periods beginning after December 15, 2015 including interim periods within that reporting period. The Company adopted this update in the first quarter of 2016 resulting in no impact on its consolidated results of operations, financial position and cash flows.
﻿
In August 2014, the FASB issued Accounting Standards Update No. 2014-15, Disclosure of Uncertainties about an Entity’s Ability to Continue as a Going Concern (Subtopic 205-40) (“Update 2014-15”), which requires management to assess a company’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. For public entities, Update 2014-15 was effective for annual reporting periods ending after December 15, 2016. The Company adopted this update in the first quarter of 2016 resulting in no impact on its consolidated results of operations, financial position, cash flows and disclosures.
﻿
New Accounting Standards Not Yet Implemented in this Report
﻿
In August 2016, the FASB issued Accounting Standards Update No. 2016-15, Statement of Cash Flows (Topic 230) (“Update 2016-15”), which seeks to reduce the existing diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows. For public entities, Update 2016-15 becomes effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years, with early adoption permitted. The Company is currently evaluating the provisions of Update 2016-15 and assessing the impact, if any, it may have on its consolidated results of operations, financial position or cash flows.
﻿
In March 2016, the FASB issued Accounting Standards Update No. 2016-09, Compensation - Stock Compensation (Topic 718) (“Update 2016-09”), which seeks to simplify accounting for share-based payment transactions including income tax consequences, classification of awards as either equity or liabilities, and the classification on the statement of cash flows. For public entities, Update 2016-09 becomes effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years, with early adoption permitted. The Company expects to adopt this guidance effective January 1, 2017. The recognition of previously unrecognized windfall tax benefits is expected to result in a cumulative-effect adjustment of approximately $149 million, which would increase net deferred tax assets and increase the valuation allowance by the same amount as of the beginning of 2017. The remaining provisions of this amendment are not expected to have a material effect on the consolidated results of operations, financial position or cash flows.
﻿
In February 2016, the FASB issued Accounting Standards Update No. 2016-02, Leases (Topic 842) (“Update 2016-02”), which seeks to increase transparency and comparability among organizations by, among other things, recognizing lease assets and lease liabilities on the balance sheet for leases classified as operating leases under previous GAAP and disclosing key information about leasing arrangements. In 2016, the Company made progress on contract reviews, drafting its accounting policies and evaluating the new disclosure requirements. The Company will continue assessing the effect that the updated standard may have on its consolidated financial statements and related disclosures, and anticipates that its assessment will be complete in 2018. For public entities, Update 2016-02 becomes effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, with early adoption permitted.
﻿
In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers (Topic 606) (“Update 2014-09”), which seeks to provide clarity for recognizing revenue. The new standard removes inconsistencies in existing standards, changes the way companies recognize revenue from contracts with customers and increases disclosure requirements. The codification was amended through additional ASUs and, as amended, requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. The standard is required to be adopted using either the full retrospective approach, with all prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet. The Company has not yet selected a transition method. The Company has a team in place to analyze the impact of Update 2014-09, and the related ASU's, across all revenue streams to evaluate the impact of the new standard on revenue contracts. This includes reviewing current accounting policies and practices to identify potential differences that would result from applying the requirements under the new standard. In 2016, the Company made progress on contract reviews, drafting its accounting policies and evaluating the new disclosure requirements. The Company expects to complete its evaluations of the impacts of the accounting and
			
		
			
		
disclosure requirements on its business processes, controls and systems in the second half of 2017. For public entities, the new standard is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period.
﻿
(2) REDUCTION IN WORKFORCE
﻿
In January 2016, the Company announced a 40% workforce reduction as a result of lower anticipated drilling activity. This reduction was substantially completed in the first quarter of 2016. In April 2016, the Company also partially restructured executive management, which was substantially completed in the second quarter of 2016.
﻿
The following table presents a summary of the restructuring charges for the year ended December 31, 2016:
﻿
﻿
﻿
﻿
(1) Includes non-cash charges related to the curtailment and settlement of the pension and other postretirement benefit plans. See Note 11 for additional details regarding the Company’s retirement and employee benefit plans.
(2) Total restructuring charges were $75 million and $3 million for the Company’s E&P and Midstream Services segments, respectively.
﻿
The following table presents a summary of liabilities associated with the Company’s restructuring activities for the year ended December 31, 2016, which are reflected in accounts payable on the unaudited condensed consolidated balance sheet:
﻿
﻿
﻿
Severance payments and other separation costs related to restructuring were substantially completed by the end of 2016.
﻿
(3) ACQUISITIONS AND DIVESTITURES
﻿
In September 2016, the Company sold approximately 55,000 net acres in West Virginia for approximately $422 million, which reflects customary adjustments at closing and is subject to customary post-closing adjustments. The Company accounted for the sale of these natural gas and oil properties as adjustments to capitalized costs, with no recognition of gain or loss as the sales did not involve a significant change in proved reserves or significantly alter the relationship between costs and proved reserves. In September 2016, $48 million of the net proceeds was used to repay borrowings under the Company’s term loan entered into in November 2015. The Company intends to use the remaining net proceeds from the sale for general corporate purposes, including to fund capital projects.
﻿
In May 2015, the Company sold conventional oil and gas assets located in East Texas and the Arkoma Basin for approximately $211 million. The Company also accounted for the sale of these natural gas and oil properties as adjustments to capitalized costs, with no recognition of gain or loss as the sales did not involve a significant change in proved reserves or significantly alter the relationship between costs and proved reserves. The proceeds from the transaction were used to reduce the Company’s debt. Approximately $205 million of the proceeds received were recorded as a reduction of the capitalized costs of the Company’s natural gas and oil properties in the United States pursuant to the full cost method of accounting.
﻿
In April 2015, the Company sold its gathering assets located in Bradford and Lycoming counties in northeast Pennsylvania for an adjusted sales price of approximately $489 million. The net book value of these assets was $206 million and was held in the Midstream Services segment as of the closing date. A gain on sale of $283 million was recognized and was included in gain on sale of assets, net on the consolidated statement of operations. The assets included approximately 100 miles of natural gas gathering pipelines, with nearly 600 million cubic feet per day of capacity. The proceeds from the transaction were used to substantially repay borrowings under the Company’s $500 million term loan facility that would have matured in December 2016.
			
		
			
		
﻿
In January 2015, the Company completed an acquisition of certain natural gas and oil assets including approximately 46,700 net acres in northeast Pennsylvania from WPX Energy, Inc. for an adjusted purchase price of $270 million (the “WPX Property Acquisition”). This acreage was producing approximately 50 million net cubic feet of gas per day from 63 operated horizontal wells as of December 2014. As part of this transaction, the Company assumed firm transportation capacity of 260 million cubic feet of gas per day predominantly on the Millennium pipeline. The firm transport is being amortized over 19 years. As of December 31, 2016 and 2015 the Company has amortized $17 million and $8 million, respectively. This transaction was funded with the revolving credit facility and was accounted for as a business combination. The following table summarizes the consideration paid for the WPX Property Acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date:
﻿
﻿
In January 2015, the Company completed an acquisition of certain natural gas and oil assets from Statoil ASA including approximately 30,000 net acres in West Virginia and southwest Pennsylvania for $357 million, which was comprised of approximately 20% of Statoil’s interests in the properties, (the “Statoil Property Acquisition”). All of these assets were also assets in which the Company had acquired interests under the Chesapeake Property Acquisition as defined below. This transaction was funded with the revolving credit facility and was accounted for as a business combination. The Company allocated the purchase price to natural gas and oil properties, based on the respective fair values of the assets acquired.
﻿
In December 2014, the Company completed an acquisition of certain gas and oil assets from Chesapeake Energy Corporation covering approximately 413,000 net acres in West Virginia and southwest Pennsylvania targeting natural gas, oil and NGLs contained in the Upper Devonian, Marcellus and Utica Shales for approximately $5.0 billion (the “Chesapeake Property Acquisition”). The transaction was temporarily financed using a $4.5 billion 364-day senior unsecured bridge term loan credit facility and a $500 million two-year unsecured term loan. The Company repaid all principal and interest outstanding on the $4.5 billion bridge facility in January 2015 after permanent financing was finalized, and as a result expensed $47 million of short-term unamortized debt issuance costs related to the bridge facility in January 2015, recognized in other interest charges on the consolidated statement of operations. The term loan facility was repaid in full in April 2015 with proceeds from the divestiture of the Company’s northeastern Pennsylvania gathering assets and borrowings under the revolving credit facility.
﻿
			
		
			
		
The following table summarizes the consideration paid for the Chesapeake Property Acquisition and the fair value of the assets acquired and liabilities assumed as of the acquisition date, updated for subsequent customary post-closing adjustments:
﻿
﻿
The Company recorded the assets acquired and liabilities assumed in the Chesapeake Property Acquisition at their estimated fair value of approximately $5.0 billion, which the Company considered to be representative of the price paid by a typical market participant. This measurement resulted in no goodwill or bargain purchase being recognized. In addition, the Company included $1 million in general and administrative expenses and $5 million in interest expense for fees related to the Chesapeake Property Acquisition on its consolidated statement of operations for the year ended December 31, 2014. The Company included $47 million in other current assets and $1 million in other assets for unamortized fees related to the bridge facility and term loan facility, respectively, for the Chesapeake Property Acquisition on its consolidated balance sheet as of December 31, 2014.
﻿
The results of operations of the Chesapeake Property Acquisition have been included in the Company’s consolidated financial statements since the December 22, 2014 closing date, including approximately $10 million of total revenue and $2 million of operating income for the year ended December 31, 2014. Summarized below are the consolidated results of operations for the year ended December 31, 2014 on an unaudited pro forma basis, as if the acquisition and related financing had occurred on January 1, 2013. The unaudited pro forma financial information was derived from the historical consolidated statement of operations of the Company and the statement of revenues and direct operating expenses for the Chesapeake Property Acquisition properties. The unaudited pro forma financial information does not purport to be indicative of results of operations that would have occurred had the acquisition and related financing occurred on the basis assumed above, nor is such information indicative of the Company’s expected future results of operations. The unaudited pro forma financial information excludes the WPX Property and Statoil Property Acquisitions as the impacts are immaterial.
﻿
﻿
﻿
The above acquisitions qualified as business combinations, and as a result, the Company estimated the fair value of the assets acquired and liabilities assumed as of the acquisition date. The 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. Fair value measurements also utilize assumptions of market participants. The Company used a discounted cash flow model and made market assumptions as to future commodity prices, projections of estimated quantities of natural gas, oil and NGL reserves, expectations for timing and amount of future development and operating costs, projections of future rates of production, expected recovery rates and risk adjusted discount rates. These assumptions represent Level 3 inputs, as defined in Note 6 - Fair Value Measurements.
﻿
			
		
			
		
(4) DERIVATIVES AND RISK MANAGEMENT
﻿
The Company is exposed to volatility in market prices and basis differentials for natural gas, oil and NGLs which impacts the predictability of its cash flows related to the sale of those commodities. These risks are managed by the Company’s use of certain derivative financial instruments. As of December 31, 2016, the Company’s derivative financial instruments consisted of fixed price swaps, two-way costless collars, three-way costless collars, basis swaps, sold call options and interest rate swaps. During 2016, the Company settled all of its purchased put options. The Company had basis swaps and sold call options as of December 31, 2015. A description of the Company’s derivative financial instruments is provided below:
﻿
﻿
						
Fixed price swaps
The Company receives a fixed price for the contract and pays a floating market price to the counterparty.
Purchased put options
The Company purchases put options based on an index price from the counterparty by payment of a cash premium. If the index price is lower than the put’s strike price at the time of settlement, the Company receives from the counterparty such difference between the index price and the purchased put strike price. If the market price settles above the put’s strike price, no payment is due from either party.
Two-way costless collars
Arrangements that contain a fixed floor price (purchased put option) and a fixed ceiling price (sold call option) based on an index price which, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the ceiling price, the Company pays the counterparty the difference between the index price and ceiling price, (2) if the index price is between the floor and ceiling prices, no payments are due from either party, and (3) if the index price is below the floor price, the Company will receive the difference between the floor price and the index price.
Three-way costless collars
Arrangements that contain a purchased put option, a sold call option and a sold put option based on an index price which, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the sold call strike price, the Company pays the counterparty the difference between the index price and sold call strike price, (2) if the index price is between the purchased put strike price and the sold call strike price, no payments are due from either party, (3) if the index price is between the sold put strike price and the purchased put strike price, the Company will receive the difference between the purchased put strike price and the index price, and (4) if the index price is below the sold put strike price, the Company will receive the difference between the purchased put strike price and the sold put strike price.
Basis swaps
Arrangements that guarantee a price differential for natural gas from a specified delivery point. The Company receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract.
Sold call options
The Company sells call options in exchange for a premium. If the market price exceeds the strike price of the call option at the time of settlement, the Company pays the counterparty such excess on sold call options. If the market price settles below the call’s strike price, no payment is due from either party.
Interest rate swaps
Interest rate swaps are used to fix or float interest rates on existing or anticipated indebtedness. The purpose of these instruments is to manage the Company’s existing or anticipated exposure to unfavorable interest rate changes.
﻿
The Company utilizes counterparties for its derivative instruments that it believes are creditworthy at the time the transactions are entered into, and the Company closely monitors the credit ratings of these counterparties. Additionally, the Company performs both quantitative and qualitative assessments of these counterparties based on their credit ratings and credit default swap rates where applicable. However, the events in the financial markets in recent years demonstrate there can be no assurance that a counterparty will be able to meet its obligations to the Company.
﻿
The following table provides information about the Company’s financial instruments that are sensitive to changes in commodity prices and that are used to protect the Company’s exposure. None of the financial instruments below are designated for hedge accounting treatment. The table presents the notional amount in Bcf, the weighted average contract prices and the fair value by expected maturity dates as of December 31, 2016:
﻿
﻿
			
		
			
		
﻿
			
		
			
		
The balance sheet classification of the assets and liabilities related to derivative financial instruments (none of which are designated for hedge accounting treatment) are summarized below as of December 31, 2016 and 2015:
﻿
At December 31, 2016, the net fair value of the Company’s financial instruments related to natural gas was a $372 million liability. The net fair value of the Company’s interest rate swaps was a $3 million liability as of December 31, 2016.
﻿
Derivative Contracts Not Designated for Hedge Accounting
﻿
As of December 31, 2016, the Company had no positions designated for hedge accounting treatment. Gains and losses on derivatives that are not designated for hedge accounting treatment, or that do not meet hedge accounting requirements, are recorded as a component of gain (loss) on derivatives on the consolidated statements of operations. Accordingly, the gain (loss) on derivatives component of the statement of operations reflects the gains and losses on both settled and unsettled derivatives. The Company calculates gains and losses on settled derivatives as the summation of gains and losses on positions which have settled within the reporting period. Only the settled gains and losses are included in the Company’s realized commodity price calculations.
﻿
The Company is a party to interest rate swaps that were entered into to mitigate the Company’s exposure to volatility in interest rates. The interest rate swaps have a notional amount of $170 million and expire in June 2020. The Company did not designate the interest rate swaps for hedge accounting treatment. Changes in the fair value of the interest rate swaps are included in gain (loss) on derivatives on the consolidated statements of operations.
			
		
			
		
The following tables summarize the before-tax effect of fixed price swaps, purchased put options, two-way costless collars, three-way costless collars, basis swaps, sold call options and interest rate swaps not designated for hedge accounting on the consolidated statements of operations for the years ended December 31, 2016 and 2015:
﻿
(1)
The Company calculates gain (loss) on derivatives, settled, as the summation of gains and losses on positions that have settled within the period.
(2)
Excluding interest rate swaps, these amounts are included, along with gas sales revenues, in the calculation of the Company’s realized natural gas price.
﻿
Derivative Contracts Designated for Hedge Accounting
﻿
All derivatives are recognized in the balance sheet as either an asset or liability and are measured at fair value, other than transactions for which normal purchase/normal sale is applied. Certain criteria must be satisfied in order for derivative financial instruments to be designated for hedge accounting. Unrealized gains and losses related to unsettled derivatives that have been designated for hedge accounting are recorded in either earnings or as a component of other comprehensive income until settled. In the period of settlement, the Company recognizes the gains and losses from these qualifying hedges in gas sales revenues. As of December 31, 2016, the Company had no positions designated for hedge accounting treatment. In 2015, the Company had certain fixed price swaps that were designated for hedge accounting. For the year ended December 31, 2015, the Company reported pre-tax gains in other comprehensive income of $45 million related to the effective portion of the unsettled fixed price swaps. The ineffective portion of those fixed price swaps was recognized in earnings and had an inconsequential impact to the consolidated statement of operations for the year ended December 31, 2015. For the year ended December 31, 2015, pre-tax gains of $209 million on settled fixed price swaps were transferred from other comprehensive income into gas sales revenues in the consolidated statement of operations.
﻿
﻿
			
		
			
		
(5) RECLASSIFICATIONS FROM ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
﻿
The following tables detail the components of accumulated other comprehensive income (loss), net of related tax effects, for the year ended December 31, 2016:
﻿
﻿
(1) See separate table below for details about these reclassifications.
﻿
See Note 11 for additional details regarding the Company’s retirement and employee benefit plans.
﻿
(6) FAIR VALUE MEASUREMENTS
﻿
The carrying amounts and estimated fair values of the Company’s financial instruments as of December 31, 2016 and 2015 were as follows:
﻿
﻿
(1)
The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020.
﻿
The carrying values of cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities on the consolidated balance sheets approximate fair value because of their short-term nature. For debt and derivative instruments, the following methods and assumptions were used to estimate fair value:
﻿
Debt: The fair values of the Company’s senior notes were based on the market value of the Company’s publicly traded debt as determined based on the yield of the Company’s senior notes.
﻿
			
		
			
		
The carrying values of the borrowings under the Company’s term loan facilities and unsecured revolving credit facility approximate fair value because the interest rate is variable and reflective of market rates. The Company considers the fair value of its debt to be a Level 2 measurement on the fair value hierarchy.
﻿
Derivative Instruments: The fair value of all derivative instruments is the amount at which the instrument could be exchanged currently between willing parties. The amounts are based on quoted market prices, best estimates obtained from counterparties and an option pricing model, when necessary, for price option contracts.
﻿
The fair value hierarchy prioritizes the inputs to valuation techniques used to measure fair value. As presented in the tables below, this hierarchy consists of three broad levels:
﻿
﻿
						
Level 1 valuations -
Consist of unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority.
﻿
						
Level 2 valuations -
Consist of quoted market information for the calculation of fair market value.
﻿
						
Level 3 valuations -
Consist of internal estimates and have the lowest priority.
﻿
The Company has classified its derivatives into these levels depending upon the data utilized to determine their fair values. The Company’s fixed price swaps (Level 2) are estimated using third-party discounted cash flow calculations using the NYMEX futures index. The Company utilized discounted cash flow models for valuing its interest rate derivatives (Level 2). The net derivative values attributable to the Company’s interest rate derivative contracts as of December 31, 2016 are based on (i) the contracted notional amounts, (ii) active market-quoted London Interbank Offered Rate (“LIBOR”) yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company’s sold call options, purchased put options, two-way costless collars and three-way costless collars (Level 3) are valued using the Black-Scholes model, an industry standard option valuation model that takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the NYMEX futures index, interest rates, volatility and credit worthiness. The Company’s basis swaps (Level 3) are estimated using third-party calculations based upon forward commodity price curves.
﻿
Inputs to the Black-Scholes model, including the volatility input, which is the significant unobservable input for Level 3 fair value measurements, are obtained from a third-party pricing source, with independent verification of the most significant inputs on a monthly basis. An increase (decrease) in volatility would result in an increase (decrease) in fair value measurement, respectively.
﻿
Assets and liabilities measured at fair value on a recurring basis are summarized below (in millions):
﻿
			
		
			
		
﻿
The table below presents reconciliations for the change in net fair value of derivative assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs (Level 3) for the years ended December 31, 2016 and 2015. The fair values of Level 3 derivative instruments are estimated using proprietary valuation models that utilize both market observable and unobservable parameters. Level 3 instruments presented in the table consist of net derivatives valued using pricing models incorporating assumptions that, in the Company’s judgment, reflect reasonable assumptions a marketplace participant would have used as of December 31, 2016 and 2015.
﻿
﻿
See Note 11 - Retirement and Employee Benefit Plans for a discussion of the fair value measurement of the Company’s pension plan assets.
﻿
(7) DEBT
﻿
The components of debt as of December 31, 2016 and 2015 consisted of the following:
﻿
﻿
(1)
In July 2016, $375 million was repaid on the term loan facility, extending the maturity from November 2018 to December 2020, which will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020. In September 2016, an additional $48 million was repaid.
(2)
The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020.
(3)
In July 2016, the Company purchased approximately $312 million of the 3.30% Senior Notes due January 2018 and $388 million of the 7.50% Senior Notes due February 2018.
(4)
In February and June 2016, Moody’s and S&P downgraded certain senior notes, increasing the interest rates by 175 basis points effective July 2016. As a result of the downgrades, interest rates increased to 5.05% for the 2018 Notes, 5.80% for the 2020 Notes and 6.70% for the 2025 Notes.
﻿
﻿
						
						
						
						
						
						
						
						
						
						
						
						
﻿
						
						
						
						
						
						
						
						
						
						
						
						
			
		
			
		
﻿
The following is a summary of scheduled debt maturities by year as of December 31, 2016 (in millions):
﻿
﻿
2016 Credit Facility
﻿
In June 2016, the Company reduced its existing $2.0 billion unsecured revolving credit facility to $66 million and entered into a new credit agreement for $1,934 million, consisting of a $1,191 million secured term loan and a new $743 million unsecured revolving credit facility, which matures in December 2020. The maturity date will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due January 2020. The $1,191 million secured term loan is fully drawn, with approximately $285 million of this balance used to pay down the previous revolving credit facility balance in its entirety. As of December 31, 2016, there were no borrowings under either revolving credit facility; however, $174 million in letters of credit was outstanding against the 2016 revolving credit facility.
﻿
Loans under the 2016 credit agreement are subject to varying rates of interest based on whether the loan is a Eurodollar loan or an alternate base rate loan. Eurodollar loans bear interest at the Eurodollar rate, which is adjusted LIBOR plus applicable margins ranging from 1.750% to 2.500%. Alternate base rate loans bear interest at the alternate base rate plus the applicable margin ranging from 0.750% to 1.500%. The interest rate on the term loan facility is determined based upon the Company’s public debt ratings and was 250 basis points over LIBOR as of December 31, 2016.
﻿
The new term loan and revolving credit facility contain financial covenants that impose certain restrictions on the Company. Under the new credit agreement, the Company must maintain a minimum interest coverage of 0.75x in 2016, increasing by 0.25x increments per year to 1.50x in 2019 and 2020. The Company is also subject to a minimum liquidity requirement of $300 million, which could be increased up to $500 million upon certain conditions, as well as an anti-hoarding provision, requiring unrestricted cash in excess of $100 million to pay down any amounts borrowed under the new revolving credit facility. The financial covenant with respect to minimum interest coverage consists of EBITDAX divided by consolidated interest expense. EBITDAX, as defined in our 2016 credit agreement, excludes the effects of interest expense, income taxes, depreciation, depletion and amortization, any non-cash impacts from impairments, certain non-cash hedging activities, stock-based compensation expense, non-cash gains or losses on asset sales, unamortized issuance cost,
			
		
			
		
unamortized debt discount and certain restructuring costs. Collateral for the new secured term loan is principally the Company’s E&P properties in the Fayetteville Shale area, the equity of its subsidiaries and cash and marketable securities on hand, and the new credit agreement requires a minimum collateral coverage ratio of 1.50x for the 2016 secured term loan. This collateral also may support all or a part of revolving credit extensions depending on restrictions in the Company’s senior notes indentures.
﻿
As of December 31, 2016, the Company was in compliance with all of the covenants of this credit agreement. Although the Company does not anticipate any violations of the financial covenants, its ability to comply with these covenants is dependent upon the success of its exploration and development program and upon factors beyond the Company’s control, such as the market prices for natural gas, oil and NGLs.
﻿
2013 Credit Facility
﻿
In December 2013, the Company entered into a credit agreement that exchanged its previous revolving credit facility. Under the revolving credit facility, the Company had a borrowing capacity of $2.0 billion. The revolving credit facility was unsecured and was not guaranteed by any subsidiaries. In June 2016, this credit facility was substantially exchanged for a new credit facility comprised of a $1,191 million secured term loan and a new $743 million revolving credit facility. The borrowing capacity of the original 2013 credit agreement was reduced from $2.0 billion to $66 million, remains unsecured and the maturity remains December 2018. As of December 31, 2016, there were no borrowings under this facility.
﻿
The existing unsecured 2013 revolving credit facility includes a financial covenant under which the Company may not have total debt in excess of 60% of its total adjusted book capital. This financial covenant with respect to capitalization percentages excludes the effects of any full cost ceiling impairments, certain hedging activities and the Company’s pension and other postretirement liabilities. At December 31, 2016, the Company’s adjusted book capital was 34% debt and 66% equity.
﻿
2015 Term Facility
﻿
In November 2015, the Company entered into a $750 million unsecured three-year term loan credit agreement with various lenders that was utilized to repay borrowings under the revolving credit facility. The interest rate on the term loan facility is determined based upon the Company’s public debt ratings from Moody’s and S&P and was 250 basis points over LIBOR as of December 31, 2016. The term loan facility requires prepayment under certain circumstances from the net cash proceeds of sales of equity or certain assets and borrowings outside the ordinary course of business. In June 2016, this term loan agreement was amended to extend the maturity date upon a repayment threshold. From the net proceeds of the July 2016 equity offering, the Company repaid $375 million of the $750 million unsecured term loan, which had the effect of extending the term loan maturity from November 2018 to December 2020, which will accelerate to October 2019 if, by that date, the Company has not amended, redeemed or refinanced at least $765 million of its senior notes due in January 2020. As a result of the repayment, the Company expensed $3 million of unamortized debt issuance costs, recognized in other interest charges on the consolidated statement of operations for the year ended December 31, 2016. In September 2016, the Company repaid an additional $48 million from the proceeds received from the closing of the sale of approximately 55,000 net acres in West Virginia to Antero Resources Corporation, resulting in an additional $0.4 million of interest expense related to unamortized debt issuance costs.
﻿
Commercial Paper
﻿
In April 2015, the Company entered into a commercial paper program which allowed it to issue up to $2.0 billion in commercial paper, provided that outstanding borrowings from its commercial paper program, combined with outstanding borrowings under our revolving credit facility, not exceed $2.0 billion. The commercial paper issuance had terms of up to 397 days and carried interest at rates agreed upon at the time of each issuance. As of December 31, 2016 and 2015, the Company had no outstanding issuances under its commercial paper program, respectively, and had no current plans of further utilizing the commercial paper market.
﻿
Senior Notes
﻿
In July 2016, the Company used a portion of the proceeds from the July 2016 equity offering to settle certain tender offers by purchasing an aggregate principal amount of approximately $700 million of the Company’s outstanding senior notes due in the first quarter of 2018, resulting in a loss of $51 million for the early retirement and redemption of these senior notes including $50 million of premiums paid. Additionally, the Company expensed $2 million of unamortized debt issuance costs and debt discounts, recognized in other interest charges.
﻿
			
		
			
		
In January 2015, the Company completed a public offering of $350 million aggregate principal amount of its 3.30% senior notes due 2018 (the “2018 Notes”), $850 million aggregate principal amount of its 4.05% senior notes due 2020 (the “2020 Notes”) and $1.0 billion aggregate principal amount of its 4.95% senior notes due 2025 (the “2025 Notes” together with the 2018 and 2020 Notes, the “Notes”), with net proceeds from the offering totaling approximately $2.2 billion after underwriting discounts and offering expenses. The proceeds from this offering were used to repay the remaining principal and interest outstanding under the Company’s $4.5 billion 364-day bridge term loan facility, which was first reduced with proceeds from the Company’s concurrent underwritten public offerings of common and preferred stock, and were also used to repay a portion of amounts outstanding under the Company’s revolving credit facility. As a result of this repayment, the Company expensed $47 million of short-term unamortized debt issuance costs related to the bridge facility in January 2015, recognized in other interest charges on the consolidated statement of operations for the year ended December 31, 2016. The Notes were sold to the public at a price of 99.949% of their face value for the 2018 Notes, 99.897% of their face value for the 2020 Notes and 99.782% of their face value for the 2025 Notes. The interest rates on the Notes are determined based upon the public bond ratings from Moody’s and S&P. Downgrades on the Notes from either rating agency increase interest costs by 25 basis points per downgrade level and upgrades decrease interest costs by 25 basis points per upgrade level, up to the stated coupon rate, on the following semi-annual bond interest payment. In February and June 2016, Moody’s and S&P downgraded the Notes, increasing the interest rates by 175 basis points effective July 2016. As a result of these downgrades, interest rates increased to 5.05% for the 2018 Notes, 5.80% for the 2020 Notes and 6.70% for the 2025 Notes. In the event of future downgrades, the coupons for this series of notes are capped at 5.30%, 6.05% and 6.95%, respectively. The first coupon payment to the bondholders at the higher interest rates was paid in January 2017.
﻿
Chesapeake Property Acquisition Financing
On December 19, 2014, the Company entered into a $4.5 billion unsecured 364-day bridge term loan credit agreement with various lenders. The bridge facility required prepayments under certain circumstances from the net cash proceeds of sales of equity or certain assets and borrowings outside the ordinary course of business or for specified uses. The Company repaid the $4.5 billion outstanding and terminated the bridge facility in January 2015 with net proceeds of $669 million and $1.7 billion from common stock and depositary share offerings, respectively, and $2.2 billion from senior note offerings with the difference utilized to pay down amounts under the revolving credit facility.
﻿
(8) COMMITMENTS AND CONTINGENCIES
﻿
Operating Commitments and Contingencies
﻿
As of December 31, 2016, the Company’s contractual obligations for demand and similar charges under firm transportation and gathering agreements to guarantee access capacity on natural gas and liquids pipelines and gathering systems totaled approximately $8.4 billion, $3.4 billion of which related to access capacity on future pipeline and gathering infrastructure projects that still require the granting of regulatory approvals and additional construction efforts. The Company also had guarantee obligations of up to $862 million of that amount. As of December 31, 2016, future payments under non-cancelable firm transportation and gathering agreements are as follows:
﻿
﻿
﻿
(1)
Based on the estimated in-service dates as of December 31, 2016.
﻿
The Company has 13 leases for pressure pumping equipment for its E&P operations under leases that expire between December 2017 and January 2018. The Company’s current aggregate annual payment under the leases is approximately $8 million. Certain of these leases provide for a residual value guarantee for any deficiency if the equipment is sold for less than the sale option amount (recognized as a liability of approximately $4 million at December 31, 2016). The Company has 7 leases for drilling rigs for its E&P operations that expire through 2021 with a current aggregate annual payment of approximately $13 million. The lease payments for the pressure pumping equipment, as well as other operating expenses for the Company’s drilling operations, are capitalized to natural gas and oil properties and are partially offset by billings to third-party working interest owners for their share of fracture stage charges.
﻿
			
		
			
		
The Company leases compressors, aircraft, vehicles, office space and equipment under non-cancelable operating leases expiring through 2027. As of December 31, 2016, future minimum payments under these non-cancelable leases accounted for as operating leases are approximately $66 million in 2017, $52 million in 2018, $45 million in 2019, $35 million in 2020, $17 million in 2021 and $14 million thereafter.
﻿
The Company also has commitments for compression services related to its Midstream Services and E&P segments. As of December 31, 2016, future minimum payments under these non-cancelable agreements are approximately $16 million in 2017, $7 million in 2018 and $3 million in 2019.
﻿
Environmental Risk
﻿
The Company is subject to laws and regulations relating to the protection of the environment. Environmental and cleanup related costs of a non-capital nature are accrued when it is both probable that a liability has been incurred and when the amount can be reasonably estimated. Management believes any future remediation or other compliance related costs will not have a material effect on the financial position or results of operations of the Company.
﻿
Litigation
﻿
The Company is subject to various litigation, claims and proceedings that have arisen in the ordinary course of business, such as for alleged breaches of contract, miscalculation of royalties, and pollution, contamination or nuisance. Management believes that such litigation, claims and proceedings, individually or in aggregate and after taking into account insurance, are not likely to have a material adverse impact on the Company’s financial position, results of operations or cash flows. Many of these matters are in early stages, so the allegations and the damage theories have not been fully developed, and are all subject to inherent uncertainties; therefore, management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on the Company’s financial position, results of operations or cash flows for the period in which the effect becomes reasonably estimable. The Company accrues for such items when a liability is both probable and the amount can be reasonably estimated.
﻿
Berry-Helfand (Tovah Energy)
﻿
In February 2009, one of the Company’s subsidiaries was added as a defendant in a case then styled Tovah Energy, LLC and Toby Berry-Helfand v. David Michael Grimes, et al., then pending in the 273rd District Court in Shelby County, Texas. The plaintiff alleged that the subsidiary used information provided by the plaintiff under a confidentiality agreement, which she claimed, among other things, breached the agreement and constituted a trade secret. Following a trial in December 2010, the court awarded approximately $11 million in actual damages and approximately $24 million in disgorgement of profits, along with interest and attorneys’ fees. Both sides appealed, and in July 2013 the Texas Court of Appeals for the Twelfth District reversed on all claims except misappropriation of trade secrets, reduced the judgment to the actual damages award, along with interest and attorneys’ fees, and ordered the case remanded for an award of attorneys’ fees to the Company’s subsidiary on one of the claims on which judgment was reversed. Both parties petitioned the Supreme Court of Texas for review. In June 2016, the Supreme Court ruled that insufficient evidence supported the damage award and remanded the case for a new trial. The parties subsequently reached a settlement, the amount of which is reflected in the Company’s financial statements as of, and for the period ended, December 31, 2016.
﻿
Arkansas Royalty Litigation
﻿
Certain of the Company’s subsidiaries are defendants in three cases, two filed in Arkansas state court in 2010 and 2013 and one in federal court in 2014, on behalf of putative classes of royalty owners on some of the Company’s leases located in Arkansas. The chief complaint in all three cases is that one of the Company’s subsidiaries underpaid the royalty owners by, among other things, deducting from royalty payments costs for gathering, transportation, and compression of natural gas in excess of what is permitted by the relevant leases. In September and October 2014 the judges in the two Arkansas state actions entered orders certifying classes of royalty owners who are citizens of Arkansas.
﻿
In November 2015, the court in the federal case denied the plaintiff’s motion to certify a class of royalty owners not included in either of the two state cases. In April 2016, the court certified a broader class that includes Arkansas residents and citizens. Class members were notified of the pending action in late 2016, and the period to “opt out” of the class has expired. The plaintiff in the federal case presented two alternative damages theories. Under one theory, plaintiffs have asserted that obligations to affiliates are not “incurred” and therefore the exploration and production subsidiary was not entitled to deduct any post-production costs; the federal court has granted partial summary judgment for the Company’s subsidiaries on this theory. Under another theory, plaintiffs assert that the gathering and treating rates the Company deducted from royalty payments exceeded the affiliates’ actual costs or otherwise were not reasonable. The plaintiffs have not
			
		
			
		
disclosed a specific damage calculation for any putative class, but based on the class representative’s disclosure regarding the calculation of claimed damages, class-wide damages could exceed $100 million. The court has set a trial date in the second quarter of 2017. The Company has moved for summary judgment on all claims, which remains pending before the trial judge.
﻿
The Company’s subsidiaries appealed the class certification orders in the state cases. In December 2016 the Arkansas Supreme Court affirmed the certifications. These cases are now before the Arkansas trial judges. The precise configuration of the classes has not been determined, particularly in light of the overlapping composition of the class in the federal case. No date for trial has been set.
﻿
In addition, in September 2015 three cases were filed in Arkansas state court on behalf of a total of 248 individually named plaintiffs. Each case asserts complaints that are in substance virtually identical to the above-described case. The Company and its subsidiaries have removed two of the cases to federal court, and those cases have been assigned to the court in which the above-described federal case is pending. All three cases have been stayed.
﻿
Management believes that, in all of the above cases, the deductions from royalty payments as calculated are permitted and intends to defend the cases vigorously. The Company’s assessment may change in the future due to the occurrence of certain events, such as adverse judgments, and such a re-assessment could lead to the determination that the potential liability is probable and could be material to the Company’s results of operations, financial position or cash flows.
﻿
Indemnifications
﻿
The Company provides certain indemnifications in relation to dispositions of assets. These indemnifications typically relate to disputes, litigation or tax matters existing at the date of disposition. No liability has been recognized in connection with these indemnifications.
(9) INCOME TAXES
﻿
The provision (benefit) for income taxes included the following components:
﻿
﻿
The provision for income taxes was an effective rate of 1% in 2016, 31% in 2015 and 36% in 2014. The following reconciles the provision for income taxes included in the consolidated statements of operations with the provision which would result from application of the statutory federal tax rate to pre-tax financial income:
﻿
﻿
﻿
Our effective tax rate decreased in 2016, as compared with 2015, primarily due to the recognition of a valuation
			
		
			
		
allowance in the fourth quarter of 2015 that persisted throughout 2016.
﻿
The components of the Company’s deferred tax balances as of December 31, 2016 and 2015 were as follows:
﻿
﻿
In 2016, the Company paid less than $1 million in state income taxes and received $15 million in federal income tax refunds. In 2015, the Company paid less than $1 million in state income taxes and did not pay federal income taxes. The Company’s net operating loss carryforward as of December 31, 2016 was $3.2 billion and $2.2 billion for federal and state reporting purposes, respectively, the majority of which will expire between 2029 and 2036. Additionally, the Company has an income tax net operating loss carryforward related to its Canadian operations of $35 million, with expiration dates of 2030 through 2036. The Company also had an alternative minimum tax credit carryforward of $100 million and a statutory depletion carryforward of $13 million as of December 31, 2016.
﻿
A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess the likelihood, the Company uses estimates and judgment regarding future taxable income, and considers the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include current financial position, results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as current and forecasted business economics of the oil and gas industry.
﻿
Due to the continued write-downs of the carrying value of natural gas and oil properties, the Company maintained its net deferred tax asset position at December 31, 2016. The Company believes it is more likely than not that these deferred tax assets will not be realized and recorded a $983 million increase in valuation allowance for the year ended December 31, 2016, reflected as a component of income tax expense. Management assesses available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. In management’s view, the cumulative loss incurred over the three-year period ending December 31, 2016, outweighs any positive factors, such as the possibility of future growth. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income are increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as future expected growth.
Deferred tax assets relating to tax benefits of employee stock option grants have been reduced to reflect exercises. Some exercises resulted in tax deductions in excess of previously recorded benefits based on the option value at the time of the grant (“windfalls”). Although these additional tax benefits or “windfalls” are reflected in net operating loss carryforwards, the additional tax benefit associated with the windfall is not recognized until the deduction reduces taxes payable. Accordingly, since the tax benefit does not reduce the Company’s current taxes payable in 2016 due to net operating loss carryforwards, these “windfall” tax benefits are not reflected in its net operating losses in deferred tax assets for 2016. Windfalls included in net operating loss carryforwards but not reflected in deferred tax assets for 2016 were $149 million.
﻿
A tax position must meet certain thresholds for any of the benefit of the uncertain tax position to be recognized in the financial statements. As of December 31, 2016, the amount of unrecognized tax benefits related to alternative minimum tax was $17 million. The uncertain tax position identified would not have a material effect on the effective tax rate. No material changes to the current uncertain tax position are expected within the next 12 months. As of December 31, 2016, the Company had accrued a liability of less than $1 million of interest related to this uncertain tax position. The Company recognizes
			
		
			
		
penalties and interest related to uncertain tax positions in income tax expense.
﻿
A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:
﻿
The Internal Revenue Service is currently auditing the Company’s federal income tax return for 2014. The income tax years 2013 to 2016 remain open to examination by the major taxing jurisdictions to which the Company is subject.
﻿
(10) ASSET RETIREMENT OBLIGATIONS
﻿
The following table summarizes the Company’s 2016 and 2015 activity related to asset retirement obligations:
﻿
﻿
(1)
Obligations settled/removed include $35 million and $25 million related to asset divestitures in 2016 and 2015, respectively.
(2)
Estimates in the costs to retire wells and well pads were revised downward based on internal estimates of future obligation requirements and updated third-party cost quotes.
﻿
﻿
(11) RETIREMENT AND EMPLOYEE BENEFIT PLANS
﻿
401(k) Defined Contribution Plan
﻿
The Company has a 401(k) defined contribution plan covering eligible employees. The Company expensed $4 million, $3 million and $3 million of contribution expense in 2016, 2015 and 2014, respectively. Additionally, the Company capitalized $2 million, $4 million and $3 million of contributions in 2016, 2015 and 2014, respectively, directly related to the acquisition, exploration and development activities of the Company’s natural gas and oil properties or directly related to the construction of the Company’s gathering systems.
﻿
Defined Benefit Pension and Other Postretirement Plans
﻿
Prior to January 1, 1998, the Company maintained a traditional defined benefit plan with benefits payable based upon average final compensation and years of service. Effective January 1, 1998, the Company amended its pension plan to become a “cash balance” plan on a prospective basis for its non-bargaining employees. A cash balance plan provides benefits based upon a fixed percentage of an employee’s annual compensation. The Company’s funding policy is to contribute amounts which are actuarially determined to provide the plans with sufficient assets to meet future benefit payment requirements and which are tax deductible.
﻿
The postretirement benefit plan provides contributory health care and life insurance benefits. Employees become eligible for these benefits if they meet age and service requirements. Generally, the benefits paid are a stated percentage of medical expenses reduced by deductibles and other coverages.
﻿
Substantially all employees are covered by the Company’s defined benefit pension and postretirement benefit plans. The Company accounts for its defined benefit pension and other postretirement plans by recognizing the funded status of each
			
		
			
		
defined pension benefit plan and other postretirement benefit plan on the Company’s balance sheet. In the event a plan is overfunded, the Company recognizes an asset. Conversely, if a plan is underfunded, the Company recognizes a liability.
﻿
In January 2016, the Company initiated a reduction in workforce that was effectively completed by the end of the first quarter. As a result of the workforce reduction, the Company recognized a $1 million non-cash curtailment loss related to its pension plan for both the curtailment-related decrease to the benefit obligation and the recognition of the proportionate share of unrecognized prior service cost and net loss from other comprehensive income (loss) in the second quarter of 2016. For the year ended December 31, 2016, the Company recognized a non-cash settlement loss of $11 million related to a total of $37 million of lump sum payments from the pension plan. Additionally, the Company recognized a non-cash curtailment gain of $6 million related to its other postretirement benefit plan in the first quarter of 2016.
﻿
The following provides a reconciliation of the changes in the plans’ benefit obligations, fair value of assets and funded status as of December 31, 2016 and 2015:
﻿
﻿
﻿
﻿
The Company uses a December 31 measurement date for all of its plans and had liabilities recorded for the underfunded status for each period as presented above.
﻿
The change in accumulated other comprehensive income related to the pension plans was a gain of $7 million ($4 million after tax) for the year ended December 31, 2016 and a loss of $2 million ($2 million after tax) for the year ended December 31, 2015. The change in accumulated other comprehensive income related to the other postretirement benefit plan was a gain of $3 million ($2 million after tax) for the year ended December 31, 2016 and a gain of $1 million ($1 million after tax) for the year ended December 31, 2015. Included in accumulated other comprehensive income as of December 31, 2016 and 2015 was a $31 million loss ($19 million net of tax) and a $42 million loss ($25 million net of tax), respectively, related to the Company’s pension and other postretirement benefit plans. For the year ended December 31, 2016, $6 million was classified to accumulated other comprehensive income, primarily driven by actuarial loss adjustments. Amortization of prior period service cost reclassified from accumulated other comprehensive income to general and administrative expenses for the year was immaterial.
﻿
The amount in accumulated other comprehensive income that is expected to be recognized as a component of net periodic benefit cost during 2017 is a $1 million net loss.
			
		
			
		
The pension plans’ projected benefit obligation, accumulated benefit obligation and fair value of plan assets as of December 31, 2016 and 2015 are as follows:
﻿
﻿
﻿
Pension and other postretirement benefit costs include the following components for 2016, 2015 and 2014:
﻿
﻿
Amounts recognized in other comprehensive income for the year ended December 31, 2016 were as follows:
﻿
﻿
The assumptions used in the measurement of the Company’s benefit obligations as of December 31, 2016 and 2015 are as follows:
﻿
﻿
The assumptions used in the measurement of the Company’s net periodic benefit cost for 2016, 2015 and 2014 are as follows:
﻿
﻿
The expected return on plan assets for the various benefit plans is based upon a review of the historical returns experienced, combined with the future expected returns based upon the asset allocation strategy employed. The plans seek to achieve an adequate return to fund the obligations in a manner consistent with the federal standards of the Employee Retirement Income Security Act and with a prudent level of diversification.
			
		
			
		
﻿
For measurement purposes, the following trend rates were assumed for 2016 and 2015:
﻿
﻿
Assumed health care cost trend rates have a significant effect on the amounts for the health care plans. A one percentage point change in assumed health care cost trend rates would have the following effects:
﻿
﻿
Pension Payments and Asset Management
﻿
In 2016, the Company contributed $10 million to its pension plans and $1 million to its other postretirement benefit plan. The Company expects to contribute $15 million to its pension and other postretirement benefit plans in 2017.
﻿
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
﻿
The Company’s overall investment strategy is to provide an adequate pool of assets to support both the long-term growth of plan assets and to ensure adequate liquidity exists for the near-term payment of benefit obligations to participants, retirees and beneficiaries. The Benefits Administration Committee of the Company administers the Company’s pension plan assets. The Benefits Administration Committee believes long-term investment performance is a function of asset-class mix and restricts the composition of pension plan assets to a combination of cash and cash equivalents, domestic equity markets, international equity markets or investment grade fixed income assets.
﻿
			
		
			
		
The table below presents the allocations targeted by the Benefits Administration Committee and the actual weighted-average asset allocation of the Company’s pension plan as of December 31, 2016, by asset category. The asset allocation targets are subject to change and the Benefits Administration Committee allows for its actual allocations to deviate from target as a result of current and anticipated market conditions. Plan assets are periodically balanced whenever the allocation to any asset class falls outside of the specified range.
﻿
﻿
(1) Includes the following equity securities in the table below: U.S. large cap growth equity, U.S. large cap value equity, U.S. large cap core equity, and U.S. small cap equity.
(2) Includes Non-U.S. equity securities in the table below.
(3) Includes emerging markets equity securities below.
(4) Includes none of the securities in the table below.
(5) Includes fixed income pension plan assets in the table below.
(6) Includes Cash and cash equivalents pension plan assets in the table below.
﻿
Utilizing the fair value hierarchy described in Note 6 - Fair Value Measurements, the Company’s fair value measurement of pension plan assets as of December 31, 2016 is as follows:
﻿
﻿
(1)
Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.
(2)
Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income.
(3)
Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.
(4)
Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets.
(5)
An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets.
(6)
Institutional funds that seek an investment return that approximates, as closely as practicable, before expenses, the performance of the Barclays U.S. Intermediate Credit Bond Index over the long term and the Barclays Long U.S. Corporate Bond Index over the long-term.
(7)
Plan assets for which fair value was measured using net asset value as a practical expedient.
(8)
An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.
			
		
			
		
Utilizing the fair value hierarchy described in Note 6 - Fair Value Measurements, the Company’s fair value measurement of pension plan assets at December 31, 2015 is as follows:
﻿
﻿
(1)
Mutual fund that seeks to invest in a diversified portfolio of stocks with price appreciation growth opportunities.
(2)
Mutual fund that seeks to invest in a diversified portfolio of stocks that will increase in value over the long-term as well as provide current income.
(3)
Mutual fund that seeks to invest in a diversified portfolio of stocks with small market capitalizations.
(4)
Mutual funds that invest primarily in equity securities of companies domiciled outside of the United States, primarily in developed markets.
(5)
An institutional fund that invests primarily in the equity securities of companies domiciled in emerging markets.
(6)
Plan assets for which fair value was measured using net asset value as a practical expedient.
(7)
An institutional fund that seeks to replicate the performance of the S&P 500 Index before fees.
(8)
An institutional fund that seeks an investment return that approximates, as closely as practicable, before expenses, the performance of the Barclays U.S. Intermediate Credit Bond Index over the long term and the Barclays Long U.S. Corporate Bond Index over the long-term.
﻿
The Company’s pension plan assets that are classified as Level 1 are the investments comprised of either cash or investments in open-ended mutual funds which produce a daily net asset value that is validated with a sufficient level of observable activity to support classification of the fair value measurement as Level 1. Due to the Company’s implementation of Accounting Standards Update No. 2015-07, assets measured using net asset value as a practical expedient have not been classified in the fair value hierarchy. No concentration of risk arising within or across categories of plan assets exists due to any significant investments in a single entity, industry, country or investment fund.
(12) STOCK-BASED COMPENSATION
﻿
The Southwestern Energy Company 2013 Incentive Plan was adopted in February 2013, approved by stockholders in May 2013 and amended and restated per stockholders’ approval in May 2016 (the “2013 Plan”). The 2013 Plan provides for the compensation of officers, key employees and eligible non-employee directors of the Company and its subsidiaries. The 2013 Plan replaced the Southwestern Energy Company 2004 Stock Incentive Plan, the Southwestern Energy Company 2000 Stock Incentive Plan (“2000 Plan”) and the Southwestern Energy Company 2002 Employee Stock Incentive Plan (“2002 Plan”) but did not affect prior awards under those plans which remained valid and some of which are still outstanding. The awards under the prior plans have been adjusted for stock splits as permitted under such plans.
﻿
The 2013 Plan provides for grants of options, stock appreciation rights, and shares of restricted stock and restricted stock units to employees, officers and directors that, in the aggregate, do not exceed 33,850,000 shares. The types of incentives that may be awarded are comprehensive and are intended to enable the Company’s board of directors to structure the most appropriate incentives and to address changes in income tax laws which may be enacted over the term of the 2013 Plan.
﻿
As initially adopted, the 2004 Plan, the 2000 Plan and the 2002 Plan provided for grants of options, stock appreciation rights, shares of phantom stock and shares of restricted stock that, in the aggregate, did not exceed 16,800,000, 1,250,000 and 300,000 shares, respectively, to employees who are not officers or directors of the Company under provisions of Section 16 of the Securities Exchange Act of 1934, as amended. The Company may utilize treasury shares, if available, or authorized but unissued shares when a stock option is exercised or when restricted stock is granted.
			
		
			
		
﻿
The Company measures the cost of employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. All options are issued at fair market value at the date of grant and expire seven years from the date of grant for awards under both the 2013 Plan and the 2004 Plan and ten years from the date of grant for awards under all other plans. Generally, stock options granted to employees and directors vest ratably over three years from the grant date. The Company issues shares of restricted stock to employees and directors which generally vest over four years. The Company recognizes stock-based compensation expense on a straight-line basis over the requisite service period of the individual grants with the exception of awards granted to participants who have reached retirement age or will reach retirement age during the vesting period. Restricted stock and stock options granted to participants on or after December 6, 2013 immediately vest upon death, disability or retirement (subject to a minimum of three years of service).
﻿
In January 2016, the Company announced a 40% workforce reduction that was substantially concluded by the end of March 2016. In April 2016, the Company also partially restructured executive management, which was substantially completed in the second quarter of 2016. Affected employees were offered a severance package that included, if applicable, amendments to certain outstanding equity awards that modified forfeiture provisions upon separation from the Company. As a result, certain unvested stock-based equity awards became fully vested at the time of separation. These shares were revalued and recognized immediately as a component of restructuring charges on the Company’s unaudited consolidated statement of operations. The unvested portion of equity-based performance units was forfeited upon separation from the Company.
﻿
Stock Options
﻿
The Company recorded the following compensation costs related to stock options for the years ended December 31, 2016, 2015 and 2014:
﻿
﻿
(1)
Includes less than $1 million and $1 million related to the reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016.
﻿
The Company also recorded a deferred tax asset of $2 million, $2 million and $3 million related to stock options in 2016, 2015 and 2014, respectively. Unrecognized compensation cost related to the Company’s unvested stock options totaled $4 million at December 31, 2016. This cost is expected to be recognized over a weighted-average period of 2 years.
﻿
The fair value of stock options is estimated on the date of the grant using a Black-Scholes valuation model that uses the weighted average assumptions noted in the following table. Expected volatility is based on historical volatility of the Company’s common stock and other factors. The Company uses historical data on the exercise of stock options, post-vesting forfeitures and other factors to estimate the expected term of the stock-based payments granted. The risk-free interest rate is based on the U.S. Treasury yield curve in effect at the time of grant.
﻿
﻿
			
		
			
		
The following tables summarize stock option activity for the years 2016, 2015 and 2014, and provide information for options outstanding at December 31 of each year:
﻿
﻿
﻿
(1)
Shares granted in 2016 are considerably lower than historical norms. In 2016, the Company changed the grant date of its annual stock option awards from December to the following February.
﻿
﻿
﻿
﻿
The weighted-average grant date fair value of options granted during the years 2016, 2015 and 2014 was $3.22, $3.16 and $10.16, respectively. The total intrinsic value of options exercised during 2016 and 2014 was less than $1 million and $4 million, respectively. There were no options exercised in 2015.
﻿
Restricted Stock
﻿
The Company recorded the following compensation costs related to restricted stock grants for the years ended December 31, 2016, 2015 and 2014:
﻿
(1)
Includes $16 million and $1 million related to the reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016.
﻿
The Company also recorded a deferred tax asset of $12 million related to restricted stock for the year ended December 31, 2016, compared to a deferred tax asset of $11 million for 2015 and a deferred tax liability of $10 million for 2014. As of December 31, 2016, there was $37 million of total unrecognized compensation cost related to unvested shares of restricted stock that is expected to be recognized over a weighted-average period of 2 years.
﻿
			
		
			
		
The following table summarizes the restricted stock activity for the years 2016, 2015 and 2014, and provides information for restricted stock outstanding at December 31 of each year:
﻿
﻿
﻿
﻿
﻿
(1)
Shares granted in 2016 are considerably lower than historical norms. In 2016, the Company changed the grant date of its annual restricted stock awards from December to the following February.
(2)
Includes 2,059,626 shares and 151,575 shares related to reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016.
﻿
The fair values of the grants were $1 million for 2016, $47 million for 2015 and $40 million for 2014. The total fair value of shares vested were $43 million for 2016, $29 million for 2015 and $20 million for 2014.
﻿
Equity-Classified Performance Units
﻿
The Company recorded compensation costs related to equity-classified performance units for the years ended December 31, 2016, 2015 and 2014. The performance units awarded in 2013 and 2014 included a market condition based on relative Total Shareholder Return (“TSR”) and a performance condition based on the Company’s Present Value Index (“PVI”), collectively the “Performance Measures.” The fair value of the TSR market condition is based on a Monte Carlo model and is amortized to compensation expense on a straight-line basis over the vesting period of the award. The fair value of the PVI performance condition is based on economic analysis for each investment opportunity based upon the expected present value added for each dollar to be invested and amortized to compensation expense on a straight line basis over the vesting period of the award. The performance units awarded in 2016 and 2015 are based exclusively on TSR. The grant date fair value is calculated using the applicable Performance Measures and the closing price of the Company’s common stock at the grant date.
﻿
﻿
﻿
(1)
Includes less than $1 million and $1 million related to reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016.
﻿
The Company also recorded a deferred tax asset of $4 million related to equity-based performance units for the year ended December 31, 2016, compared to deferred tax assets of $4 million and $2 million in 2015 and 2014, respectively. As of December 31, 2016, there was $9 million of total unrecognized compensation cost related to unvested equity-based performance units that is expected to be recognized over a weighted-average period of 2 years.
﻿
			
		
			
		
The following table summarizes performance unit activity to be paid out in Company stock for the years ended December 31, 2016, 2015 and 2014, and provides information for unvested units as of December 31, 2016, 2015 and 2014:
﻿
﻿
﻿
(1) These amounts reflect the number of performance units granted in thousands. The actual payout in shares may range from a minimum of zero shares to a maximum of two shares contingent upon the actual performance against the Performance Measures. The performance units have a three-year vesting term and the actual disbursement of shares, if any, is not determined until March following the end of the three-year vesting period.
(2) Includes 22,918 units and 37,590 units related to the reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016.
(3) Includes 87,595 units and 195,834 units related to the reduction in workforce and executive management restructuring, respectively, for the year ended December 31, 2016.
﻿
Liability-Classified Performance Units
﻿
Prior to 2013, certain employees were provided performance units vesting equally over three years that were settled in cash. The payout of these units was based on certain metrics, such as total shareholder return and reserve replacement efficiency, compared to a predetermined group of peer companies and Company goals. At the end of each performance period, the value of the vested performance units, if any, would be paid in cash. In the first quarter of 2016, the Company completed the final payout under these performance unit agreements.
﻿
(13) SEGMENT INFORMATION
﻿
The Company’s reportable business segments have been identified based on the differences in products or services provided. Revenues for the E&P segment are derived from the production and sale of natural gas and liquids. The Midstream Services segment generates revenue through the marketing of both Company and third-party produced natural gas and liquids volumes and through gathering fees associated with the transportation of natural gas to market.
﻿
Summarized financial information for the Company’s reportable segments is shown in the following table. The accounting policies of the segments are the same as those described in Note 1 - Organization and Summary of Significant Accounting Policies. Management evaluates the performance of its segments based on operating income, defined as operating revenues less operating costs. Income before income taxes, for the purpose of reconciling the operating income amount shown below to consolidated income before income taxes, is the sum of operating income, interest expense, gain (loss) on derivatives, loss on early extinguishment of debt and other income (loss). The “Other” column includes items not related to the Company’s reportable segments, including real estate and corporate items.
			
		
			
		
﻿
﻿
(1)
Operating loss for the E&P segment includes $86 million related to restructuring and other one-time charges for the year ended December 31, 2016.
(2)
Operating income for the Midstream Services segment includes $3 million related to restructuring charges for the year ended December 31, 2016.
(3)
Interest expense and the provision (benefit) for income taxes by segment are an allocation of corporate amounts as they are incurred at the corporate level.
(4)
Includes office, technology, drilling rigs and other ancillary equipment not directly related to natural gas and oil property acquisition, exploration and development activities.
(5)
Other assets represent corporate assets not allocated to segments and assets for non-reportable segments. At December 31, 2016, other assets includes approximately $1.4 billion in cash and cash equivalents.
(6)
Capital investments include an increase of $43 million for 2016, a decrease of $33 million for 2015 and an increase of $155 million for 2014 related to the change in accrued expenditures between years.
(7)
Operating income (loss) for the Midstream Services segment includes a $277 million gain on sale of assets for the year ended December 31, 2015.
﻿
Included in intersegment revenues of the Midstream Services segment are $1.3 billion, $1.8 billion and $2.8 billion for 2016, 2015 and 2014, respectively, for marketing of the Company’s E&P sales. Corporate assets include cash and cash equivalents, furniture and fixtures and other costs. Corporate general and administrative costs, depreciation expense and taxes other than income are allocated to the segments.
﻿
			
		
			
		
(14) SUBSEQUENT EVENTS
﻿
None.
﻿
﻿
SUPPLEMENTAL QUARTERLY RESULTS (UNAUDITED)
﻿
The following is a summary of the quarterly results of operations for the years ended December 31, 2016 and 2015:
﻿
﻿
(1) The operating losses for the first, second and third quarters of 2016 included non-cash full cost impairments of natural gas and oil properties of $1,034 million, $470 million, and $817 million, respectively. There was no full cost impairment in the fourth quarter of 2016. The operating losses for the second, third and fourth quarters of 2015 included non-cash full cost impairments of natural gas and oil properties of $1,535 million, $2,839 million and $2,576 million, respectively.
(2) Net income attributable to common stock was reduced by $7 million in the first quarter of 2015 to recognize the portion of the Company’s net income that would be distributed to the holders of preferred securities (mandatory convertible preferred stock) at year-end. However, as a result of the Company’s net loss in the second quarter that persisted for the year ended December 31, 2015, participating securities were ultimately not entitled to receive a distribution.
﻿
﻿
﻿
SUPPLEMENTAL OIL AND GAS DISCLOSURES (UNAUDITED)
﻿
The Company’s operating natural gas and oil properties are located solely in the United States. The Company also has licenses to properties in Canada, the development of which is subject to an indefinite moratorium. See “Our Operations - Other - New Brunswick, Canada” in Item 1 of Part 1 of this Annual Report.
﻿
Net Capitalized Costs
﻿
The following table shows the capitalized costs of natural gas and oil properties and the related accumulated depreciation, depletion and amortization as of December 31, 2016 and 2015:
﻿
﻿
﻿
			
		
			
		
Natural gas and oil properties not subject to amortization represent investments in unproved properties and major development projects in which the Company owns an interest. These unproved property costs include unevaluated costs associated with leasehold or drilling interests and unevaluated costs associated with wells in progress. The table below sets forth the composition of net unevaluated costs excluded from amortization as of December 31, 2016:
﻿
﻿
Of the total net unevaluated costs excluded from amortization as of December 31, 2016, approximately $1.6 billion is related to the Chesapeake and Statoil Property Acquisitions, approximately $100 million is related to the acquisition of undeveloped properties outside the Appalachian Basin and the Fayetteville Shale, excluding licenses in Canada subject to an indefinite moratorium, and approximately $94 million is related to the acquisition of the Company’s undeveloped properties in Northeast Appalachia. Additionally, the Company has approximately $113 million of unevaluated costs related to costs of wells in progress. The remaining costs excluded from amortization are related to properties which are not individually significant and on which the evaluation process has not been completed. The timing and amount of property acquisition and seismic costs included in the amortization computation will depend on the location and timing of drilling wells, results of drilling and other assessments. The Company is, therefore, unable to estimate when these costs will be included in the amortization computation.
﻿
Costs Incurred in Natural Gas and Oil Exploration and Development
﻿
The table below sets forth capitalized costs incurred in natural gas and oil property acquisition, exploration and development activities:
﻿
﻿
Capitalized interest is included as part of the cost of natural gas and oil properties. The Company capitalized $152 million, $204 million and $55 million during 2016, 2015 and 2014, respectively, based on the Company’s weighted average cost of borrowings used to finance expenditures.
﻿
In addition to capitalized interest, the Company capitalized internal costs totaling $112 million, $307 million and $320 million during 2016, 2015 and 2014, respectively, which were directly related to the acquisition, exploration and development of the Company’s natural gas and oil properties. Included in these amounts are internal costs from the Company’s subsidiaries involved with vertical integration of the Company’s exploration and development activities, which totaled $19 million, $118 million and $123 million during 2016, 2015 and 2014, respectively. All internal costs are included in the Company’s cost of natural gas and oil properties.
﻿
			
		
			
		
Results of Operations from Natural Gas and Oil Producing Activities
﻿
The table below sets forth the results of operations from natural gas and oil producing activities:
﻿
﻿
(1) Prior to the Company’s recognition of a valuation allowance in 2016, the Company recognized an income tax benefit of $805 million.
(2) Results of operations exclude the gain (loss) on unsettled commodity derivative instruments. See Note 4 - Derivatives and Risk Management
﻿
The results of operations shown above exclude general and administrative expenses and interest expense and are not necessarily indicative of the contribution made by the Company’s natural gas and oil operations to its consolidated operating results. Income tax expense is calculated by applying the statutory tax rates to the revenues less costs, including depreciation, depletion and amortization, and after giving effect to permanent differences and tax credits.
﻿
Natural Gas and Oil Reserve Quantities
﻿
The Company engaged the services of Netherland, Sewell & Associates, Inc., or NSAI, an independent petroleum engineering firm, to audit the reserves estimated by the Company’s reservoir engineers. In conducting its audit, the engineers and geologists of NSAI studied the Company’s major properties in detail and independently developed reserve estimates. NSAI’s audit consists primarily of substantive testing, which includes a detailed review of the Company’s major properties, and accounted for approximately 99%, 100% and 97% of the present worth of the Company’s total proved reserves as of December 31, 2016, 2015 and 2014, respectively. A reserve audit is not the same as a financial audit, and a reserve audit is less rigorous in nature than a reserve report prepared by an independent petroleum engineering firm containing its own estimate of reserves. Reserve estimates are inherently imprecise, and the Company’s reserve estimates are generally based upon extrapolation of historical production trends, historical prices of natural gas and crude oil and analogy to similar properties and volumetric calculations. Accordingly, the Company’s estimates are expected to change, and such changes could be material and occur in the near term as future information becomes available. For more information over reserves, refer to the table titled “Changes in Proved Undeveloped Reserves (Bcfe)” in “Business - Exploration and Production” in Item 1 of this Annual Report.
﻿
The following table summarizes the changes in the Company’s proved natural gas, oil and NGL reserves for 2016, 2015 and 2014, all of which were located in the United States:
﻿
﻿
			
		
			
		
The Company’s estimated proved natural gas, oil and NGL reserves were 5,253 Bcfe at December 31, 2016, compared to 6,215 Bcfe at December 31, 2015. The decrease in the Company's reserves in 2016 was primarily due to the decrease in commodity prices. The significant decrease in the Company's reserves in 2015 was primarily due to the decrease in commodity prices. The significant increase in the Company's reserves in 2014 was primarily due to the acquisition of approximately 413,000 net acres in Southwest Appalachia, successful development drilling programs in the Fayetteville Shale and Northeast Appalachia and upward performance revisions in Northeast Appalachia. In 2014, the Company replaced 550% of its production volumes with proved reserve additions and proved reserve additions as a result of acquisitions primarily associated with acreage in Southwest Appalachia. The following table summarizes the changes in reserves for 2014, 2015 and 2016:
﻿
(1)
Other includes properties outside of the Appalachian Basin and Fayetteville Shale along with Ark-La-Tex properties divested in May 2015.
﻿
The Company's December 31, 2016 proved reserves included 77 Bcfe of proved undeveloped reserves from 15 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but do not have a positive present value when discounted at 10%. These properties had a negative present value of $11 million when discounted at 10%. The Company made a final investment decision and is committed to developing these reserves within the next five years from the date of initial booking. The Company's December 31, 2015 proved reserves included 217 Bcfe of proved undeveloped reserves from 75 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but that have a negative $34 million present value when discounted at 10%. The Company's December 31, 2014 proved reserves included 181 Bcfe of proved undeveloped reserves from 60 locations that had a positive present value on an undiscounted basis in compliance with proved reserve requirements, but that have a negative $28 million present value when discounted at 10%.
			
		
			
		
The Company has no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic gas or oil. The Company used standard engineering and geoscience methods, or a combination of methodologies in determining estimates of material properties, including performance and test date analysis, offset statistical analogy of performance data, volumetric evaluation, including analysis of petrophysical parameters (including porosity, net pay, fluid saturations (i.e., water, oil and gas) and permeability) in combination with estimated reservoir parameters (including reservoir temperature and pressure, formation depth and formation volume factors), geological analysis, including structure and isopach maps and seismic analysis, including review of 2-D and 3-D data to ascertain faults, closure and other factors.
﻿
Standardized Measure of Discounted Future Net Cash Flows
﻿
The following standardized measures of discounted future net cash flows relating to proved natural gas, oil and NGL reserves as of December 31, 2016, 2015 and 2014 are calculated after income taxes, discounted using a 10% annual discount rate and do not purport to present the fair market value the Company’s proved gas, oil and NGL reserves:
﻿
﻿
(1) Includes abandonment costs.
(2) The December 31, 2016 and 2015 standardized measure computation does not have future income taxes because the Company’s tax basis in the associated oil and gas properties exceeded expected pre-tax cash inflows. Future net cash flows are not permitted to be increased by excess tax basis.
﻿
Under the standardized measure, future cash inflows were estimated by applying an average price from the first day of each month from the previous 12 months, adjusted for known contractual changes, to the estimated future production of year-end proved reserves. Prices used for the standardized measure above were $2.48 per MMBtu for natural gas, $39.25 per barrel for oil and $6.74 per barrel for NGLs in 2016, $2.59 per MMBtu for natural gas, $46.79 per barrel for oil and $6.82 per barrel for NGLs in 2015, and $4.35 per MMBtu for natural gas, $91.48 per barrel for oil and $23.79 per barrel for NGLs in 2014. Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the year-end statutory rate to the excess of pre-tax cash inflows over the Company’s tax basis in the associated proved gas and oil properties after giving effect to permanent differences and tax credits.
﻿
Following is an analysis of changes in the standardized measure during 2016, 2015 and 2014:
﻿
﻿
﻿
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
﻿
None.
﻿
ITEM 9A. CONTROLS AND PROCEDURES
﻿
Disclosure Controls and Procedures
﻿
We have performed an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of our disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act. Our disclosure controls and procedures are the controls and other procedures that we have designed to ensure that we record, process, accumulate and communicate information to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures and submission within the time periods specified in the SEC’s rules and forms. All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those determined to be effective can provide only a level of reasonable assurance with respect to financial statement preparation and presentation. Based on the evaluation, our management, including our Chief Executive Officer and Chief Financial Officer, concluded that our disclosure controls and procedures were effective as of December 31, 2016 at a reasonable assurance level.
﻿
There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the quarter ended December 31, 2016, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
﻿
Management’s Report on Internal Control Over Financial Reporting is included on page 69 of this Annual Report.
﻿
PricewaterhouseCoopers LLP’s report on Southwestern Energy’s internal control over financial reporting is included in its Report of Independent Registered Public Accounting Firm on page 70 of this Annual Report.
﻿
ITEM 9B. OTHER INFORMATION
﻿
Election of Director
﻿
On February 21, 2017, the Board of Directors elected Jon A. Marshall, 65, as a director of the Company effective February 27, 2017, for a term expiring at the 2017 annual meeting of stockholders. With the election of Mr. Marshall, the Board of Directors has nine members.
﻿
Mr. Marshall served as President and Chief Operating Officer of Transocean Ltd. from 2007 to 2008 and as the Chief Executive Officer and President of GlobalSantaFe Corporation from 2003 to 2007, when it merged with Transocean. He also served on the boards of directors of those companies. Currently he is a director of Noble Corporation plc (chairman of its HSE & Engineering Committee and member of its Audit and Finance Committees) and of Cobalt International Energy, Inc. (chairman of its Compensation Committee). He is a former chairman of the board of directors of the National Ocean Industries Association. Mr. Marshall received a bachelor of science degree from the United States Military Academy.
﻿
The selection of Mr. Marshall was not pursuant to any arrangement or understanding between him and any other person. Mr. Marshall has not been appointed to serve on any standing committees of the Board of Directors and is not expected to be so appointed at this time.
﻿
There are no transactions between Mr. Marshall and the Company that are required to be reported under Item 404(a) of Regulation S-K.
﻿
In connection with his election, Mr. Marshall will receive a pro rata portion of the annual cash compensation, the equity compensation and the additional compensation amounts received by non-employee directors, which are described in the Company’s definitive proxy statement delivered to its stockholders in connection with the 2016 annual meeting of stockholders and filed with the Securities and Exchange Commission on April 6, 2016.
﻿
			
		
			
		
Appointment of Vice President and Controller
﻿
On February 21, 2017, effective as of that date, the Board of Directors promoted Colin O’Beirne, 41, to the position of Vice President and Controller and designated him as our principal accounting officer, to serve until the next annual meeting of stockholders and/or until his successor shall be duly elected and shall qualify. In his capacity as the Company’s principal accounting officer, Mr. O’Beirne will report to R. Craig Owen, Senior Vice President and Chief Financial Officer, who had reassumed the duties of principal accounting officer on an interim basis beginning in July 2017. Mr. O’Beirne joined the Company in October 2010 as a senior manager over the Company’s internal controls and compliance team and, since 2012, has served as a director over various groups within the accounting function. Immediately prior to joining the Company, Mr. O’Beirne was a senior manager at PricewaterhouseCoopers LLP in Houston with over twelve years of accounting and financial reporting experience in the energy industry. Mr. O’Beirne holds a master of science in accounting from Texas A&M University. He is a Certified Public Accountant.
﻿
The selection of Mr. O’Beirne was not pursuant to any arrangement or understanding between him and any other person. There is no family relationship between Mr. O’Beirne and any director or executive officer of the Company.
﻿
There are no transactions between Mr. O’Beirne and the Company that are required to be reported under Item 404(a) of Regulation S-K.
﻿
Other than as disclosed below, we do not have any agreement with Mr. O’Beirne, either written or oral, that guarantees salaries, salary increases, bonuses or benefits. Mr. O’Beirne and the Company will enter into an indemnity agreement and an executive severance agreement to be effective as of the date of his promotion, the forms of which are expected to be consistent with the forms of indemnity agreement incorporated by reference as Exhibit 10.1 to this annual report on Form 10-K and executive severance agreement incorporated by reference as Exhibit 10.2 to this annual report on Form 10-K (as amended by Exhibits 10.3 and 10.4 to this annual report on Form 10-K). The executive severance agreement will entitle him to receive a payment if, within three years after a “Change in Control,” (i) his employment is terminated without “Cause” or (ii) he voluntarily terminates employment with the Company for “Good Reason.” The severance payment for Mr. O’Beirne will be equal to the product of 2.0 and the sum of base salary as of his termination date plus the maximum bonus opportunity available to him. Mr. O’Beirne also is eligible to participate in the Company’s compensation and benefit plans available to executives.
﻿
PART III
﻿
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
﻿
The definitive proxy statement to holders of the Company’s common stock in connection with the solicitation of proxies to be used in voting at the Annual Meeting of Stockholders to be held on or about May 23, 2017 (the “Proxy Statement”), is hereby incorporated by reference for the purpose of providing information about the Company’s directors, and for discussion of its audit committee and its audit committee financial expert. Refer to the sections “Proposal No. 1: Election of Directors” and “Share Ownership of Management, Directors and Nominees” in the Proxy Statement for information concerning our directors. Refer to the section “Corporate Governance - Committees of the Board of Directors” in the 2017 Proxy Statement for discussion of its audit committee and its audit committee financial expert. Information concerning the Company’s executive officers is presented in Part I of this Annual Report. The Company refers you to the section “Section 16(a) Beneficial Ownership Reporting Compliance” in the Proxy Statement for information relating to compliance with Section 16(a) of the Exchange Act.
﻿
Code of Business Ethics and Conduct for Directors and Employees
﻿
The Company has adopted a code of ethics that applies to its Chief Executive Officer, Chief Financial Officer and Controller as well as other officers and employees. We have posted a copy of our code of ethics on the “Corporate Governance” section of our website at www.swn.com, and it is available free of charge in print to any stockholder who requests it. Requests for copies should be addressed to the Secretary at 10000 Energy Drive, Spring, Texas 77389. Any amendments to, or waivers from, our code of ethics that apply to our executive officers and directors will be posted on the “Corporate Governance” section of our website.
﻿
ITEM 11. EXECUTIVE COMPENSATION
﻿
Information required by Item 11 of Part III will be included in our Proxy Statement relating to our 2017 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before May 23, 2017, and is incorporated herein by reference.*
﻿
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
﻿
Information required by Item 12 of Part III will be included in our Proxy Statement relating to our 2017 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before May 23, 2017, and is incorporated herein by reference.*
﻿
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
﻿
Information required by Item 13 of Part III will be included in our Proxy Statement relating to our 2017 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before May 23, 2017, and is incorporated herein by reference.*
﻿
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
﻿
Information required by Item 14 of Part III will be included in our Proxy Statement relating to our 2017 Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before May 23, 2017, and is incorporated herein by reference.*
﻿
*
Except for information or data specifically incorporated by reference under Items 10 through 14, all other information in our 2017 Proxy Statement is not deemed to be a part of this Annual Report on Form 10-K or deemed to be filed with the Commission as part of this report.
﻿
PART IV
﻿
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
﻿
(a) (1)The consolidated financial statements of Southwestern Energy Company and its subsidiaries and the report of independent registered public accounting firm are included in Item 8 of this Annual Report.
(2)The consolidated financial statement schedules have been omitted because they are not required under the related instructions, or are not applicable.
(3)The exhibits listed on the accompanying Exhibit Index are filed as part of, or incorporated by reference into, this Annual Report.
﻿
ITEM 16. SUMMARY
None.
			
		
			
		
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused the report to be signed on its behalf by the undersigned, thereunto duly authorized.
﻿
						
﻿
SOUTHWESTERN ENERGY COMPANY
Dated: February 23, 2017
By: /s/ R. CRAIG OWEN
﻿
R. Craig Owen
﻿
Senior Vice President
﻿
and Chief Financial Officer
﻿
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed, as of February 23, 2017, on behalf of the Registrant below by the following officers and by a majority of the directors.
﻿
. CRAIG OWEN
						
/s/ WILLIAM J. WAY
Director, President and Chief Executive Officer
William J. Way
(Principal executive officer)
﻿
						
/s/ R. CRAIG OWEN
Senior Vice President and Chief Financial Officer
R. Craig Owen
(Principal financial officer)
﻿
						
/s/ COLIN P. O’BEIRNE
Vice President, Controller
Colin P. O’Beirne
(Principal accounting officer)
﻿
						
/s/ JOHN D. GASS
Director
John D. Gass
						
﻿
						
/s/ CATHERINE A. KEHR
Director
Catherine A. Kehr
						
﻿
						
/s/ GREG D. KERLEY
Director
Greg D. Kerley
						
﻿
						
/s/ KENNETH R. MOURTON
Director
Kenneth R. Mourton
						
﻿
						
/s/ ELLIOTT PEW
Director
Elliott Pew
						
﻿
						
/s/ TERRY W. RATHERT
Director
Terry W. Rathert
						
﻿
						
/s/ ALAN H. STEVENS
Director
Alan H. Stevens
						
﻿
						
﻿
			
		
			
		
EXHIBIT INDEX
﻿
﻿
						
Exhibit Number
Description
﻿
						
2.1
Purchase Agreement dated as of October 14, 2014 between Southwestern Energy Production Company and Chesapeake Appalachia, L.L.C. (Incorporated by reference to Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed on October 17, 2014)
3.1
Amended and Restated Certificate of Incorporation of Southwestern Energy Company. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed May 24, 2010)
3.2
Amended and Restated Bylaws of Southwestern Energy Company, as amended on November 9, 2015. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed November 13, 2015)
3.3
Certificate of Designations of 6.25% Series B Mandatory Convertible Preferred Stock (including form of stock certificate). (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on January 21, 2015)
3.4
Certificate of Designation, Preferences and Rights of Series A Junior Participating Preferred Stock, dated April 9, 2009. (Incorporated by reference to Exhibit 3.1 to the Registrant’s Current Report on Form 8-K filed on April 9, 2009)
4.1
Form of Common Stock Certificate. (Incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
4.2
Indenture, dated as of December 1, 1995 between Southwestern Energy Company and The First National Bank of Chicago, as trustee. (Incorporated by reference to Exhibit 4 to Amendment No. 1 to the Registrant’s Registration Statement on Form S-3 (File No. 33-63895) filed on November 17, 1995)
4.3
First Supplemental Indenture between Southwestern Energy Company and J.P. Morgan Trust Company, N.A. (as successor to the First National Bank of Chicago) dated June 30, 2006. (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
4.4
Second Supplemental Indenture by and among Southwestern Energy Company, SEECO, Inc., Southwestern Energy Production Company, Southwestern Energy Services Company and The Bank of New York Trust Company, N.A., as trustee (as successor to J.P. Morgan Trust Company, N.A.), dated as of May 2, 2008. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K/A filed on May 8, 2008)
4.5
Indenture dated June 1, 1998 by and among NOARK Pipeline Finance, L.L.C. and The Bank of New York. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed May 4, 2006)
4.6
First Supplemental Indenture dated May 2, 2006 by and among Southwestern Energy Company, NOARK Pipeline Finance, L.L.C., and UMB Bank, N.A., as trustee (as successor to the Bank of New York). (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed May 4, 2006)
4.7
Second Supplemental Indenture between Southwestern Energy Company and UMB Bank, N.A., as trustee, dated June 30, 2006. (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
4.8
Third Supplemental Indenture by and among Southwestern Energy Company, SEECO, Inc., Southwestern Energy Production Company, Southwestern Energy Services Company and UMB Bank, N.A., as trustee, dated as of May 2, 2008. (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K/A filed on May 8, 2008)
4.9
Guaranty dated June 1, 1998 by Southwestern Energy Company in favor of The Bank of New York, as trustee, under the Indenture dated as of June 1, 1998 between NOARK Pipeline Finance L.L.C. and such trustee. (Incorporated by reference to Exhibit 4.6 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2005)
4.10
Indenture dated January 16, 2008 among Southwestern Energy Company, the Guarantors named therein and The Bank of New York Trust Company, N.A., as trustee. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed January 16, 2008)
			
		
			
		
4.11
Indenture by and among Southwestern Energy Company, SEECO, Inc., Southwestern Energy Production Company, Southwestern Energy Services Company and The Bank of New York Trust Company, N.A., as trustee, dated as of March 5, 2012. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed March 6, 2012)
4.12
Policy on Confidential Voting of Southwestern Energy Company. (Incorporated by reference to the Appendix of the Registrant’s Definitive Proxy Statement (Commission File No. 1-08246) for the 2006 Annual Meeting of Stockholders)
4.13
Credit Agreement dated December 16, 2013 among Southwestern Energy Company, JPMorgan Chase Bank, NA, Bank of America, N.A., Wells Fargo N.A., The Royal Bank of Scotland PLC, Citibank, N.A. and the other lenders named therein, JPMorgan Chase Bank, NA, as administrative agent. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed December 17, 2013)
4.14
Commitment Letter dated October 14, 2014 between Southwestern Energy Company, Merrill Lynch, Pierce, Fenner & Smith Incorporated and Bank of America, N.A. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on October 17, 2014)
4.15
Bridge Term Loan Credit Agreement, dated December 19, 2014, among Southwestern Energy Company, Bank of America, N.A., as Administrative Agent, Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association and The Royal Bank of Scotland plc, as Co-Syndication Agents, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Sole Lead Arranger and Sole Bookrunner, and the lenders from time to time party thereto (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 23, 2014)
4.16
Term Loan Credit Agreement, dated December 19, 2014, among Southwestern Energy Company, Bank of America, N.A., as Administrative Agent, and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as Sole Lead Arranger and Sole Bookrunner, and the lenders from time to time party thereto (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on December 23, 2014)
4.17
Form of certificate for the 6.25% Series B Mandatory Convertible Preferred Stock. (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on January 21, 2015)
4.18
Deposit Agreement, dated as of January 21, 2015, between Southwestern Energy Company and Computershare Trust Company, N.A., as depositary, on behalf of all holders from time to time of the receipts issued thereunder (including form of Depositary Receipt). (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on January 21, 2015)
4.19
Form of Depositary Receipt for the Depositary Shares. (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed on January 21, 2015)
4.20
Indenture, dated as of January 23, 2015 between Southwestern Energy Company and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.1 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
4.21
First Supplemental Indenture, dated as of January 23, 2015 between Southwestern Energy Company and U.S. Bank National Association, as trustee (Incorporated by reference to Exhibit 4.2 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
4.22
Form of 3.300% Notes due 2018. (Incorporated by reference to Exhibit 4.3 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
4.23
Form of 4.050% Notes due 2020. (Incorporated by reference to Exhibit 4.4 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
4.24
Form of 4.95% Notes due 2025. (Incorporated by reference to Exhibit 4.5 to the Registrant’s Current Report on Form 8-K filed on January 23, 2015)
10.1
Form of Second Amended and Restated Indemnity Agreement between Southwestern Energy Company and each Executive Officer and Director of the Registrant. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K/A filed August 3, 2006)
			
		
			
		
10.2
Form of Executive Severance Agreement between Southwestern Energy Company and each of the Executive Officers of Southwestern Energy Company, effective February 17, 1999. (Incorporated by reference to Exhibit 10.12 of the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1998)
10.3
Form of Amendment to Executive Severance Agreement between Southwestern Energy Company and each of the Executive Officers of Southwestern Energy Company prior to 2011. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2008)
10.4
Form of Executive Severance Agreement between Southwestern Energy Company and Executive Officers Post 2011. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K (Commission File No.1-08426) for the year ended December 31, 2012)
10.5
Southwestern Energy Company Incentive Compensation Plan. (Incorporated by reference to Exhibit 10.2(b) to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 1998)
10.6
Amendment to Southwestern Energy Company Incentive Compensation Plan. (Incorporated by reference to Exhibit 10.5 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2008)
10.7
Second Amendment to Southwestern Energy Company Incentive Compensation Plan (Incorporated by reference to Exhibit 10.6 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2009)
10.8
Southwestern Energy Company Supplemental Retirement Plan as amended. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on February 19, 2008)
10.9
Southwestern Energy Company Non-Qualified Retirement Plan as amended. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on February 19, 2008)
10.10
Amendment One to the Southwestern Energy Company Non-Qualified Retirement Plan (Incorporated by reference to Exhibit 10.9 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2009)
10.11
Southwestern Energy Company 2000 Stock Incentive Plan dated February 18, 2000. (Incorporated by reference to the Appendix of the Registrant’s Definitive Proxy Statement (Commission File No. 1-08246) for the 2000 Annual Meeting of Stockholders)
10.12
Southwestern Energy Company 2002 Employee Stock Incentive Plan, effective October 23, 2002. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)
10.13
Southwestern Energy Company 2002 Performance Unit Plan, as amended, effective December 8, 2011. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2012)
10.14
Southwestern Energy Company 2004 Stock Incentive Plan. (Incorporated by reference to Appendix A to the Registrant’s Proxy Statement dated March 29, 2004)
10.15
Southwestern Energy Company 2013 Incentive Plan. (Incorporated by reference to Annex A of the Registrant’s Proxy Statement filed April 8, 2013)
10.16
First Amendment to Southwestern Energy Company 2013 Incentive Plan. (Incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K filed on May 20, 2016)
10.17
Southwestern Energy Company 2013 Incentive Plan Form of Performance Unit Award Agreement. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2016)
10.18
Southwestern Energy Company 2013 Incentive Plan Guidelines for Annual Incentive Awards. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.19
Southwestern Energy Company 2013 Incentive Plan Form of Incentive Stock Option Award Agreement. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
			
		
			
		
10.20
Southwestern Energy Company 2013 Incentive Plan Form of Non-Qualified Stock Option Award Agreement. (Incorporated by reference to Exhibit 10.5 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.21
Southwestern Energy Company 2013 Incentive Plan Form of Non-Qualified Stock Option Award Agreement for Directors. (Incorporated by reference to Exhibit 10.6 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.22
Southwestern Energy Company 2013 Incentive Plan Form of Restricted Stock Award Agreement. (Incorporated by reference to Exhibit 10.7 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.23
Southwestern Energy Company 2013 Incentive Plan Form of Restricted Stock Award Agreement for Directors. (Incorporated by reference to Exhibit 10.8 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.24
Southwestern Energy Company 2013 Incentive Plan Form of Restricted Stock Unit Award Agreement. (Incorporated by reference to Exhibit 10.9 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.25
Southwestern Energy Company 2013 Incentive Plan Form of Restricted Stock Unit Award Agreement for Directors. (Incorporated by reference to Exhibit 10.10 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2013)
10.26
Form of Incentive Stock Option Agreement for awards prior to December 8, 2005. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on December 20, 2004)
10.27
Form of Non-Qualified Stock Option Agreement for non-employee directors for awards prior to December 8, 2005. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on December 20, 2004)
10.28
Form of Incentive Stock Option for awards granted on or after December 8, 2005. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)
10.29
Form of Restricted Stock Agreement for awards granted on or after December 8, 2005. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)
10.30
Form of Non-Qualified Stock Option Agreement for awards granted on or after December 8, 2005 and through December 8, 2011 (Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on December 13, 2005)
10.31
Form of Non-Qualified Stock Option Agreement for awards granted on or after December 8, 2011. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08426) for the year ended December 31, 2012)
10.32
Master Lease Agreement by and between Southwestern Energy Company and SunTrust Leasing Corporation dated December 29, 2006. (Incorporated by reference to Exhibit 10.22 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2006)
10.33
Guaranty by and between Southwestern Energy Company and Texas Gas Transmission, LLC, dated as of October 27, 2008. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q (Commission File No. 1-08246) for the period ended September 30, 2008)
10.34
Guaranty by and between Southwestern Energy Company and Fayetteville Express Pipeline, LLC dated September 30, 2008 (Incorporated by reference to Exhibit 10.22 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2008)
10.35
Retirement Letter Agreement dated February 24, 2012 between Southwestern Energy Company and Gene A. Hammons. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed February 27, 2012)
10.36
Retirement Agreement dated August 11, 2009 between Southwestern Energy Company and Harold M. Korell. (Incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed on August 14, 2009)
			
		
			
		
10.37
Settlement Agreement, dated December 22, 2014, between Chesapeake Appalachia, L.L.C. and SWN Production Company, LLC (Incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on December 23, 2014)
10.38
Retirement Agreement dated January 11, 2016 between Southwestern Energy Company and Steven L. Mueller. (Incorporated by reference to Exhibit 10.38 to the Registrant’s Annual Report on Form 10-K (Commission File No. 1-08246) for the year ended December 31, 2015)
10.39
Retirement Agreement dated May 19, 2016 between Southwestern Energy Company and Jeffrey B. Sherrick. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016)
10.40
Amendment to Awards Agreement dated May 19, 2016 between Southwestern Energy Company and Jeffrey B. Sherrick. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016)
10.41
Amended and Restated Term Loan Credit Agreement, dated June 27, 2016 among Southwestern Energy Company, Bank of America, N.A., as Administrative Agent, and the lenders from time to time party thereto. (Incorporated by reference to Exhibit A to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on June 27, 2016)
10.42
Credit Agreement, dated June 27, 2016 among Southwestern Energy Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders from time to time party thereto. (Incorporated by reference to Exhibit 10.2 to the Registrant’s Current Report on Form 8-K filed on June 27, 2016)
10.43
Amendment and Restatement Agreement, dated as of June 27, 2016 among Southwestern Energy Company, Bank of America, N.A., as Administrative Agent, and the lenders party thereto, giving effect to the Amended and Restated Term Loan Credit Agreement. (Incorporated by reference to Exhibit 10.3 to the Registrant’s Current Report on Form 8-K filed on June 27, 2016)
10.44
Amendment No. 1 to Credit Agreement, dated as of June 27, 2016 among Southwestern Energy Company, JPMorgan Chase Bank, N.A., as Administrative Agent, and the lenders party thereto. (Incorporated by reference to Exhibit 10.4 to the Registrant’s Current Report on Form 8-K filed on June 27, 2016)
21.1*
List of Subsidiaries
23.1*
Consent of PricewaterhouseCoopers LLP
23.2*
Consent of Netherland, Sewell & Associates, Inc.
31.1*
Certification of CEO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*
Certification of CFO filed pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*
Certification of CEO furnished 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 CFO furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
95.1*
Mine Safety Disclosure
99.1*
Reserve Audit Report of Netherland, Sewell & Associates, Inc., dated January 15, 2016
101.INS*
Interactive Data File Instance Document
101.SCH*
Interactive Data File Schema Document
101.CAL*
Interactive Data File Calculation Linkbase Document
101.LAB*
Interactive Data File Label Linkbase Document
101.PRE*
Interactive Data File Presentation Linkbase Document
101.DEF*
Interactive Data File Definition Linkbase Document
____________
*Filed herewith
﻿